Siemens Aktiengesellschaft Buch-Nr. C53000–G1176–C148–1
Copyright
Copyright © SIEMENS AG 2002. All rights reserved.
Copying of this document and giving it to others and the use or
communication of the contents thereof, are forbidden without ex-
press authority. Offenders are liable to the payment of damages. All
rights are reserved, especially in the event or grant of a patent or
registration of a utility model or design.
Registered trademarks
SIPROTEC, SINAUT, SICAM, and DIGSI are registered trade-
marks of SIEMENS AG. Other names and terms can be trade-
marks the use of which may violate the rights of thirds.
Liability statement
We have checked the contents of this manual against the
described hardware and software. Nevertheless, deviations
may occur so that we cannot guarantee the entire harmony
with the product.
The contents of this manual will be checked in periodical in-
tervals, corrections will be made in the following editions.
We look forward to your suggestions for improvement.
We reserve the right to make technical improvements with-
out notice.
4.00.01
i7UT612 Manual
C53000–G1176–C148–1
Preface
Aim of This Manual This manual describes the functions, operation, installation, and commissioning of the
device. In particularly, you will find:
•Description of the device functions and setting facilities → Chapter 2,
•Instruction for installation and commissioning → Chapter 3,
•List of the technical data → Chapter 4,
•As well as a compilation of the most significant data for experienced users in the
Appendix.
General information about design, configuration, and operation of SIPROTEC® devic-
es are laid down in the SIPROTEC® 4 system manual, order no. E50417–H1176–
C151.
Target Audience Protection engineers, commissioning engineers, persons who are involved in setting,
testing and service of protection, automation, and control devices, as well as operation
personnel in electrical plants and power stations.
Applicability of this
Manual This manual is valid for SIPROTEC® 7UT612 differential protection; firmware version
4.0.
Further Standards ANSI C37.90.* .
Indication of Conformity
This product complies with the directive of the Council of the European Communities
on the approximation of the laws of the member states relating to electromagnetic
compatibility (EMC Council Directive 89/336/EEC) and concerning electrical equip-
ment for use within specified voltage limits (Low-voltage Directive 73/23/EEC).
This conformity has been proved by tests conducted by Siemens AG in accordance
with Article 10 of the Council Directive in agreement with the generic standards
EN 50081 and EN 50082 (for EMC directive) and the standards EN 60255-6 (for low-
voltage directive).
This product is designed and manufactured for application in industrial environment.
The product conforms with the international standards of IEC 60255 and the German
standards DIN 57435 part 303 (corresponding to VDE 0435 part 303).
Preface
ii 7UT612 Manual
C53000–G1176–C148–1
Additional Support Should further information be desired or should particular problems arise which are
not covered sufficiently for the purchaser’s purpose, the matter should be referred to
the loca l Siemens representative.
Training Courses Individual course offerings may be found in our T raining Catalogue, or questions may
be directed to our training center. Please contact your Siemens representative.
Instructions and
Warnings The warnings and notes contained in this manual serve for your own safety and for an
appropriate lifetime of the device. Please observe them!
The following terms are used:
DANGER
indicates that death, severe personal injury or substantial property damage will result
if proper precautions are not taken.
Warning
indicates that death, severe personal injury or substantial property damage can result
if proper precautions are not taken.
Caution
indicates that minor personal injury or property damage can result if proper precau-
tions are not taken. This particularly applies to damage on or in the device itself and
consequential damage thereof.
Note
indicates information about the device or respective part of the instruction manual
which is essential to highlight.
QUALIFIED PERSONNE L
For the purpose of this instruction manual and product labels, a qualified person is one
who is familiar with the installation, construction and operation of the equipment and
the hazards involved. In addition, he has the following qualifications:
•Is trained and authorized to energize, de-energize, clear, ground and tag circuits
and equipment in accordance with established safety practices.
Warning!
Hazardous voltages are present in this electrical equipment during operation. Non–
observance of the safety rules can result in severe personal injury or property dam-
age.
Only qualified personnel shall work on and around this equipment after becoming thor-
oughly familiar with all warnings and safety notices of this manual as well as with the
applicable safety regulations.
The successful and safe operation of this device is dependent on proper handling, in-
stallation, operation, and maintenance by qualified personnel under observance of all
warnings and hints contained in this manual.
In particular the general erection and safety regulations (e.g. IEC, DIN, VDE, EN or
other national and international standards) regarding the correct use of hoisting gear
must be observed. Non–observance can result in death, personal injury or substantial
property damage.
Preface
iii7UT612 Manu al
C53000–G1176–C148–1
•Is trained in the proper care and use of protective equipment in accordance with es-
tablished safety practices.
•Is trained in rendering first aid.
Typographic and
Symbol Conven-
tions
The following text formats are used when literal information from the device or to the
device appear in the text flow:
3DUDPHWHUQDPHV, i.e. designators of configuration or function parameters which
may appear word-for-word in the display of the device or on the screen of a personal
computer (with operation software DIGSI®4), are marked in bold letters of a mono-
space type style.
3DUDPHWHURSWLRQV, i.e. possible settings of text parameters, which may appear
word-for-word in the display of the device or on the screen of a personal computer
(with operation software DIGSI®4), are written in italic style, additionally.
“$QQXQFLDWLRQV”, i.e. designators for information, which may be output by the relay
or required from other devices or from the switch gear, are marked in a monospace
type style in quotation marks.
Deviations may be permitted in drawings when the type of designator can be obviously
derived from the illustration.
The following symbols are used in drawings:
Besides these, graphical symbols are used according to IEC 60617–12 and
IEC 60617–13 or similar. Some of the most frequently used are listed below:
address and the possible settings 2Q and 2II
UL1–L2
Earth fault device-internal logical input signal
Earth fault device-internal logical output signal
internal input signal of an analogue quantity
>Release external binary input signal with function number Fno
Dev. Trip
external binary output signal with function number Fno
2Q
2II
)81&7,21
Parameter address
Parameter name
Parameter options
example of a parameter switch designated )81&7,21 with the
FNo 567
FNo 5432
Input signal of an analogue quantity
≥1OR gate
Preface
iv 7UT612 Manual
C53000–G1176–C148–1
Furthermore, the graphic symbols according IEC 60617–12 and IEC 60617–13 or
similar are used in most cases.
n
&AND gate
signal inversion
=1 Exclusive –OR gate (antivalence): ou tput is active, if only
one
of the inputs is active
=Coincidence gate (equivalence): output is active, if
both
input are
active or inactive at the same time
≥1Dynamic inputs (edge–triggered)
above w ith pos iti ve , belo w with neg ati ve edg e
Formation of one analogue output signal from
a number of analogue input signals (example: 3)
Iph>
,SK!!
Limit stage with setting address and parameter designator (name)
0T
7,SK!!
Timer (pickup delay T, example adjustable)
with setting address and parameter designator (name)
0T Timer (dropout delay T, example non-adjustable)
TDynamic triggered pulse timer T (monoflop)
S
R
QStatic memory (RS–flipflop) with setting input (S),
resetting input (R), output (Q) and inverted output (Q)
Q
v7UT612 Manual
C53000–G1176–C148–1
Table of Contents
Preface................................................................................................................................................... i
Table of Contents ................................................................................................................................ v
1 Introduction.......................................................................................................................................... 1
1.1 Overall Operation ................................................................................................................... 2
1.2 Applications............................................................................................................................ 5
1.3 Features ................................................................................................................................. 7
2 Functions............................................................................................................................................ 13
2.1 General................................................................................................................................. 14
2.1.1 Configuration of the Scope of Functions .............................................................................. 14
2.1.2 Power System Data 1........................................................................................................... 20
2.1.2.1 Setting Overview .................................................................................................................. 28
2.1.2.2 Information Overview............................................................................................................ 30
2.1.3 Setting Groups ..................................................................................................................... 30
2.1.3.1 Setting Overview .................................................................................................................. 31
2.1.3.2 Information Overview............................................................................................................ 31
2.1.4 General Protection Data (Power System Data 2)................................................................. 32
2.1.4.1 Information Overview............................................................................................................ 32
2.2 Differential Protection........................................................................................................... 33
2.2.1 Fundamentals of Differential Protection ............................................................................... 33
2.2.2 Differential Protection for Transformers................................................................................ 42
2.2.3 Differential Protection for Generators, Motors, and Series Reactors ................................... 48
2.2.4 Differential Protection for Shunt Reactors............................................................................ 49
2.2.5 Differential Protection for Mini-Busbars, Branch-Points and Short Lines............................. 50
2.2.6 Single-Phase Differential Protection for Busbars ................................................................. 52
2.2.7 Setting the Function Parameters.......................................................................................... 56
2.2.8 Setting Overview .................................................................................................................. 61
2.2.9 Information Overview............................................................................................................ 62
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vi 7UT612 Manual
C53000–G1176–C148–1
2.3 Restricted Earth Fault Protection.......................................................................................... 64
2.3.1 Function Description.............................................................................................................66
2.3.2 Setting the Function Parameters..........................................................................................71
2.3.3 Setting Overview................................................................................................................... 72
2.3.4 Information Overview............................................................................................................ 72
2.4 Time Overcurrent Protection for Phase and Residual Currents ...........................................73
2.4.1 Function Description.............................................................................................................73
2.4.1.1 Definite Time Overcurrent Protection ................................................................................... 73
2.4.1.2 Inverse Time Overcurrent Protection.................................................................................... 76
2.4.1.3 Manual Close Command......................................................................................................79
2.4.1.4 Dynamic Cold Load Pickup................................................................................................... 79
2.4.1.5 Inrush Restraint ....................................................................................................................79
2.4.1.6 Fast Busbar Protection Using Reverse Interlocking............................................................. 81
2.4.2 Setting the Function Parameters..........................................................................................82
2.4.2.1 Phase Current Stages ..........................................................................................................82
2.4.2.2 Residual Current Stages....................................................................................................... 88
2.4.3 Setting Overview................................................................................................................... 92
2.4.4 Information Overview............................................................................................................ 94
2.5 Time Overcurrent Protection for Earth Current..................................................................... 97
2.5.1 Function Description.............................................................................................................97
2.5.1.1 Definite Time Overcurrent Protection ................................................................................... 97
2.5.1.2 Inverse Time Overcurrent Protection.................................................................................... 99
2.5.1.3 Manual Close Command....................................................................................................101
2.5.1.4 Dynamic Cold Load Pickup.................................................................................................101
2.5.1.5 Inrush Restraint ..................................................................................................................101
2.5.2 Setting the Function Parameters........................................................................................102
2.5.3 Setting Overview................................................................................................................. 106
2.5.4 Information Overview.......................................................................................................... 107
2.6 Dynamic Cold Load Pickup for Time Overcurrent Protection.............................................108
2.6.1 Function Description...........................................................................................................108
2.6.2 Setting the Function Parameters........................................................................................111
2.6.3 Setting Overview................................................................................................................. 111
2.6.4 Information Overview.......................................................................................................... 112
2.7 Single-Phase Time Overcurrent Protection........................................................................113
2.7.1 Function Description...........................................................................................................113
2.7.2 High-Impedance Differential Protection..............................................................................115
2.7.3 Tank Leakage Protection....................................................................................................117
2.7.4 Setting the Function Parameters........................................................................................118
2.7.5 Setting Overview................................................................................................................. 121
2.7.6 Information Overview.......................................................................................................... 122
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vii7UT612 Manual
C53000–G1176–C148–1
2.8 Unbalanced Load Protection.............................................................................................. 123
2.8.1 Function Description........................................................................................................... 123
2.8.1.1 Definite Time Stages.......................................................................................................... 123
2.8.1.2 Inverse Time Stage ............................................................................................................ 124
2.8.2 Setting the Function Parameters........................................................................................ 126
2.8.3 Setting Overview ................................................................................................................ 129
2.8.4 Information Overview.......................................................................................................... 130
2.9 Thermal Overload Protection.............................................................................................. 131
2.9.1 Overload Protection Using a Thermal Replica ................................................................... 131
2.9.2 Hot-Spot Calculation and Determination of the Ageing Rate ............................................. 133
2.9.3 Setting the Function Parameters........................................................................................ 137
2.9.4 Setting Overview ................................................................................................................ 141
2.9.5 Information Overview.......................................................................................................... 142
2.10 Thermoboxes for Overload Pr ote ction .... ....... ...... ................... ....... ...... ....... ...... ....... ...... ..... 143
2.10.1 Function Description........................................................................................................... 143
2.10.2 Setting the Function Parameters........................................................................................ 143
2.10.3 Setting Overview ................................................................................................................ 145
2.10.4 Information Overview.......................................................................................................... 150
2.11 Circuit Breaker Failure Protection....................................................................................... 152
2.11.1 Function Description........................................................................................................... 152
2.11.2 Setting the Function Parameters........................................................................................ 155
2.11.3 Setting Overview ................................................................................................................ 156
2.11.4 Information Overview.......................................................................................................... 156
2.12 Processing of External Signals........................................................................................... 157
2.12.1 Function Description........................................................................................................... 157
2.12.2 Setting the Function Parameters........................................................................................ 158
2.12.3 Setting Overview ................................................................................................................ 158
2.12.4 Information Overview.......................................................................................................... 159
2.13 Monitoring Functions.......................................................................................................... 160
2.13.1 Function Description........................................................................................................... 160
2.13.1.1 Hardware Monitoring.......................................................................................................... 160
2.13.1.2 Software Monitoring............................................................................................................ 161
2.13.1.3 Monitoring of Measured Quantities..................................................................................... 161
2.13.1.4 Trip Circuit Supervision ...................................................................................................... 162
2.13.1.5 Fault Reactions .................................................................................................................. 165
2.13.1.6 Group Alarms ......... ...... ....... ...... ....... ...... ................... ....... ...... ....... ...... ....... ...... ....... . ..... ..... 166
2.13.1.7 Setting Errors ..................................................................................................................... 167
2.13.2 Setting the Function Parameters........................................................................................ 167
2.13.3 Setting Overview ................................................................................................................ 168
2.13.4 Information Overview ......................................................................................................... 169
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viii 7UT612 Manual
C53000–G1176–C148–1
2.14 Protection Function Control................................................................................................ 171
2.14.1 Fault Detection Logic of the Entire Device..........................................................................171
2.14.2 Tripping Logic of the Entire Device.....................................................................................172
2.14.3 Setting the Function Parameters........................................................................................ 173
2.14.4 Setting Overview.................................................................................................................174
2.14.5 Information Overview..........................................................................................................174
2.15 Ancillary Functions.............................................................................................................. 175
2.15.1 Processing of Messages.....................................................................................................175
2.15.1.1 General...............................................................................................................................175
2.15.1.2 Event Log (Operating Messages)....................................................................................... 177
2.15.1.3 Trip Log (Fault Messages).................................................................................................. 177
2.15.1.4 Spontaneous Annunciations...............................................................................................178
2.15.1.5 General Interrogation.......................................................................................................... 178
2.15.1.6 Switching Statistics.............................................................................................................178
2.15.2 Measurement during Operation.......................................................................................... 179
2.15.3 Fault Recording ..................................................................................................................183
2.15.4 Setting the Function Parameters........................................................................................ 183
2.15.5 Setting Overview.................................................................................................................184
2.15.6 Information Overview..........................................................................................................185
2.16 Processing of Commands...................................................................................................189
2.16.1 Types of Commands .. ....... ...... ....... ...... ....... ...... ....... ...... ................... ....... ...... ....... ...... ........189
2.16.2 Steps in the Command Sequence...................................................................................... 190
2.16.3 Interlocking ......................................................................................................................... 191
2.16.3.1 Interlocked/Non-Interlocked Switching ............................................................................... 191
2.16.4 Recording and Acknowledgement of Commands...............................................................194
2.16.5 Information Overview..........................................................................................................195
3 Installation and Commissioning.....................................................................................................197
3.1 Mounting and Connections.................................................................................................198
3.1.1 Installation ..........................................................................................................................198
3.1.2 Termination Vari ants............... ....... ...... ....... ...... ....... ...... ...... ....... ...... ....... ................... ... .... .201
3.1.3 Hardware Modifications......................................................................................................205
3.1.3.1 General...............................................................................................................................205
3.1.3.2 Disassembling the Device ..................................................................................................207
3.1.3.3 Jumper Setting s on Print ed Circu it Board s.................... ...... .................... ...... ....... ...... ....... . 209
3.1.3.4 Interface Modules...............................................................................................................213
3.1.3.5 To Reassemble the Device.................................................................................................217
3.2 Checking the Connections..................................................................................................218
3.2.1 Data Connections of the Serial Interfaces.......................................................................... 218
3.2.2 Checking Power Plant Connections ................................................................................... 220
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ix7UT612 Manual
C53000–G1176–C148–1
3.3 Commissioning................................................................................................................... 222
3.3.1 Testing Mode and Transmission Blocking.......................................................................... 223
3.3.2 Checking the System (SCADA) Interface........................................................................... 223
3.3.3 Checking the Binary Inputs and Outputs............................................................................ 225
3.3.4 Checking the Setting Consistency...................................................................................... 227
3.3.5 Checking for Breaker Failure Protection............................................................................. 228
3.3.6 Symmetrical Current Tests on the Protected Object.......................................................... 230
3.3.7 Zero Sequence Current Tests on the Protected Object ..................................................... 236
3.3.8 Checkin g for Busba r Protection.............. ....... ................... ...... ....... ...... ....... ...... ....... ...... ..... 240
3.3.9 Checking for Current Input I8 ............................................................................................. 242
3.3.10 Testing User Specified Functions....................................................................................... 243
3.3.11 Stability Check and Triggering Oscillographic Recordings................................................. 243
3.4 Final Preparation of the Device.......................................................................................... 245
4 Technical Data ................................................................................................................................. 247
4.1 General Device Data.......................................................................................................... 248
4.1.1 Analog Inputs ..................................................................................................................... 248
4.1.2 Power Supply ..................................................................................................................... 248
4.1.3 Binary Inputs and Outputs.................................................................................................. 249
4.1.4 Communications Interfaces................................................................................................ 250
4.1.5 Electrical Tests................................................................................................................... 253
4.1.6 Mechanical Stress Tests .................................................................................................... 255
4.1.7 Climatic Stress Tests.......................................................................................................... 256
4.1.8 Service Conditions.............................................................................................................. 256
4.1.9 Construction ....................................................................................................................... 257
4.2 Differential Protection......................................................................................................... 258
4.2.1 General............................................................................................................................... 258
4.2.2 Transformers...................................................................................................................... 259
4.2.3 Generators, Motors, Reactors............................................................................................ 261
4.2.4 Busbars, Branch-Points, Short Lines.................................................................................. 262
4.3 Restricted Earth Fault Protection........................................................................................ 263
4.4 Time Overcurrent Protection for Phase and Residual Currents......................................... 264
4.5 Time Overcurrent Protection for Earth Current................................................................... 271
4.6 Dynamic Cold Load Pickup for Time Overcurrent Protection............................................. 272
4.7 Single-Phase Time Overcurrent Protection........................................................................ 273
4.8 Unbalanced Load Protection.............................................................................................. 274
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x7UT612 Manual
C53000–G1176–C148–1
4.9 Thermal Overload Protection..............................................................................................275
4.9.1 Overload Protection Using a Thermal Replica.................................................................... 275
4.9.2 Hot Spot Calculation and Determination of the Ageing Rate..............................................277
4.10 Thermoboxes for Overload Protection................................................................................277
4.11 Circuit Breaker Failure Protection.......................................................................................278
4.12 External Trip Commands.................................................................................................... 278
4.13 Monitoring Func tio ns ........ ...... ....... ...... ....... ...... ....... ................... ...... ....... ...... ....... ...... ........279
4.14 Ancillary Functions.............................................................................................................. 280
4.15 Dimensions......................................................................................................................... 282
A Appendix........................................................................................................................................... 285
A.1 Ordering Information and Accessories ............................................................................... 286
A.1.1 Accessories ........................................................................................................................ 288
A.2 General Diagrams............................................................................................................... 291
A.2.1 Panel Flush Mounting or Cubicle Mounting........................................................................ 291
A.2.2 Panel Surface Mounting .....................................................................................................292
A.3 Connection Examples......................................................................................................... 293
A.4 Assignment of the Protection Functions to Protected Objects............................................304
A.5 Preset Configuratio ns....... ...... ....... ...... ....... ...... ....... ...... ...... ....... ...... .................... ...... ...... ..305
A.6 Protocol Dependent Functions ..........................................................................................307
A.7 List of Settings....................................................................................................................308
A.8 List of Information...............................................................................................................323
A.9 List of Measured Values ....................................................................................................340
Index.................................................................................................................................................. 343
n
1 Introduction
27UT612 Manual
C53000–G1176–C148–1
1.1 Overall Operation
The numerical dif f erent ial prote ction devi ce SIPR OT EC® 7UT612 is equipped with a
powerful microcomputer system. This provides fully numerical processing of all func-
tions in the device, from the acquisition of the measured values up to the output of
commands to the circuit breakers. Figure 1-1 shows the basic structure of the device.
Ana log In pu ts The measuring inputs “MI” transform the currents derived from the instrument trans-
formers and match them to the internal signal levels for processing in the device. The
device includes 8 current inputs.
Display on
the front panel
µC
∩
#
ERROR
RUN
Output relays
user-
programmable
LEDs
on the front
panel, user-
programmable
Front serial
operating interface to PC
Time
synchronization radio
clock
IL1S1
IL2S1
IL3S1
I7
I8
789
456
123
.0+/-
(6&
(17(5
Operator
control panel
Uaux
Binary inputs, programmable
Power supply
MI IA AD µC OA
to
SCADA
PC/modem/
thermobox
Rear serial
service interface
Serial system
interface
PS
IL1S2
IL2S2
IL3S2
-
Figure 1-1 Har dware structure of the n umerical di fferential protecti on 7UT612 — example for a two-
winding transformer with sides S1 an d S2
1.1 Overal l Op erati on
37UT612 Manual
C53000–G1176–C148–1
Three current inputs are provided for the input of the phase currents at each end of
the protected zone, a further measuring input (I7) may be used for any desired current,
e.g. the earth current measured between the starpoint of a transformer winding and
ground. The input I8 is designed for highly sensitive current detection thus allowing,
for example, the detection of small tank leakage currents of power transformers or re-
actors, or — with an external series resistor — processing of a voltage (e.g. for high-
impedanc e uni t protect ion ).
The analog signals are then routed to the input amplifier group “IA”.
The input amplifier group “IA” ensures a high impedance termination for the measured
signals. It contains filters which are optimized in terms of band width and speed with
regard to the signal processing.
The analog/digital converter group “AD” has a multiplexer, analog/digital converters
and memory modules for the data transfer to the microcomputer system “µC”.
Microcomputer
System Apart from processing the measured values, the microcomputer system “µC” also ex-
ecutes the actual protection and control functions. In particular, the following are in-
cluded:
−Filtering and conditioning of measured signals.
−Continuous supervision of measured signals.
−Monitoring of the pickup conditions of each protection function.
−Conditioning of the measured signals, i.e. conversion of currents according to the
connection group of the protected transformer (when used for transformer differen-
tial protection) and matching of the current amplitudes.
−Formation of the differential and restraint quantities.
−Frequency analysis of the phase currents and restraint quantities.
−Calculation of the RMS-values of the currents for thermal replica and scanning of
the temperature rise of the protected object.
−Interrogation of threshold values and time sequences.
−Processing of signals for the logic functions.
−Reaching trip command decisions.
−Storage of fault messages, fault annunciations as well as oscillographic fault data
for system fault analysis.
−Operating system and related function management such as e.g. data recording,
real time clock, communication, interfaces etc.
The information is provided via output amplifier “OA”.
Binary Inputs and
Outputs The microcomputer system obtains external information through binary inputs such as
remote resetting or blocking commands for protective elements. The “µC” issues in-
formation to external equipment via the output contacts. These outputs include, in par-
ticular, trip commands to circuit breakers and signals for remote annunciation of im-
portant events and conditions.
1 Introduction
47UT612 Manual
C53000–G1176–C148–1
Front Elements Light-emitting diodes (LEDs) and a display screen (LCD) on the front panel provide
information such as targets, measured values, messages related to events or faults,
status, and functional status of the 7UT612.
Integrated control and numeric keys in conjunction with the LCD facilitate local inter-
action with the 7UT612. All information of the device can be accessed using the inte-
grated control and numeric keys. The information includes protective and control set-
tings, operating and fault messages, and measured values (see also SIPROTEC®
System Manual, order-no. E50417–H1176–C151). The settings can be modified as
are discussed in Chapter 2.
If the device incorporates switchgear control functions, the control of circuit breakers
and other equipment is possible from the 7UT612 front panel.
Serial Interfaces A serial operating interface on the front panel is provided for local communications
with the 7UT612 through a personal computer. Convenient operation of all functions
of the device is possible using the SIPROTEC® 4 operating program DIGSI®4.
A separate serial service interface is provided for remote communications via a mo-
dem, or local communications via a substation master computer that is permanently
connected to the 7UT612. DIGSI®4 is required.
All 7UT612 data can be transferred to a central master or main control system through
the serial system (SCADA) interface. Various protocols and physical arrangements
are available for this interface to suit the particular application.
Another interface is provided for the time synchronization of the internal clock via ex-
tern al synchronization sources.
Via additional interface modules further communication protocols may be created.
The service interface may be used, alternatively, for connection of a thermobox in or-
der to process external temperatures, e.g. in overload protection.
Power Supply The 7UT612 can be supplied with any of the common power supply voltages. Tran-
sient dips of the supply voltage which may occur during short-circuit in the power sup-
ply system, are bridged by a capacitor (see Technical Data, Subsection 4.1.2).
1.2 Applications
57UT612 Manual
C53000–G1176–C148–1
1.2 Applications
The numerical differential protection 7UT612 is a fast and selective short-circuit pro-
tection for transformers of all voltage levels, for rotating machines, for series and shunt
reactors, or for short lines and mini-busbars with two feeders. It can also be used as
a single-phase protection for busbars with up to seven feeders. The individual appli-
cation can be configured, which ensures optimum matching to the protected object.
The device is also suited for two-phase connection for use in systems with 162/3Hz
rated frequency.
A major advantage of the differential protection principle is the instantaneous tripping
in the event of a short-circuit at any point within the entire protected zone. The current
transformers limit the protected zone at the ends towards the network. This rigid limit
is the reason why the differential protection scheme shows such an ideal selectivity.
For use as transformer protection, the device is normally connected to the current
transformer sets at the higher voltage side and the lower voltage side of the power
transformer. The phase displacement and the interlinkage of the currents due to the
winding connection of the transformer are matched in the device by calculation algo-
rithms. The earthing conditions of the starpoint(s) can be adapted to the user’s re-
quirements and are automatically considered in the matching algorithms.
For use as generator or motor protection, the currents in the starpoint leads of the ma-
chine and at its terminals are compared. Similar applies for series reactors.
Short lines or mini-busbars with two feeders can be protected either. “Short” means
that the connection from the CTs to the device do not cause an impermissible burden
for the current transformers.
For transformers, generators, motors, or shunt reactors with earthed starpoint, the cur-
rent between the starpoint and earth can be measured and used for highly sensitive
earth fault protection.
The seven measured current inputs of the device allow for a single-phase protection
for busbars with up to seven feeders. One 7UT612 is used per phase in this case. Al-
ternatively, (external) summation transformers can be installed in order to allow a bus-
bar protection for up to seven feeders with
one
single 7UT612 relay.
An additional current input I8 is designed for very high sensitivity. This may be used
e.g. for detection of small leakage currents between the tank of transformers or reac-
tors and earth thus recognizing even high-resistance faults.
For transformers (including auto-transformers), generators, and shunt reactors, a
high-impedance unit protection system can be formed using 7UT612. In this case, the
currents of all current transformers (of equal design) at the ends of the protected zone
feed a common (external) high-ohmic resistor the current of which is measured using
the high-sensitive current input I8 of 7UT612.
The device provides backup time overcurrent protection functions for all types of pro-
tected objects. The functions can be enabled for any side.
A thermal overload protection is available for any type of machine. This can be com-
plemented by the evaluation of the hot-spot temperature and ageing rate, using an ex-
ternal thermobox to allow for the inclusion of the oil temperature.
1 Introduction
67UT612 Manual
C53000–G1176–C148–1
An unbalanced load protection enables the detection of unsymmetrical currents.
Phase failures and unbalanced loads which are especially dangerous for rotating ma-
chines can thus be detected.
A version for 162/3 Hz two-phase application is available for traction supply (transform-
ers or generators) which provides all functions suited for this application (differential
protection, restricted earth fault protection, overcurrent protection, overload protec-
tion).
A circuit breaker failure protection checks the reaction of one circuit breaker after a trip
command. It can be assigned to any of the sides of the protected object.
1.3 Feature s
77UT612 Manual
C53000–G1176–C148–1
1.3 Features
•Powerful 32-bit microprocessor system.
•Complete numerical processing of measured values and control, from sampling
and digitizing of the analog input values up to tripping commands to the circuit
breakers.
•Complete galvanic and reliable separation between internal processing circuits of
the 7UT612 and external measurement, control, and power supply circuits because
of the design of the analog input transducers, binary inputs and outputs, and the
DC/DC or AC/DC converters.
•Suited for power transformers, generators, motors, branch-points, or smaller bus-
bar arrangements.
•Simple device operation using the integrated operator panel or a connected person-
al computer running DIGSI®4.
Differential Prot ec -
tion for Trans-
formers
•Current restraint tripping characteristic.
•Stabilized against in-rush currents using the second harmonic.
•Stabilized against transient and steady-state fault currents caused e.g. by overex-
citation of transformers, using a further harmonic: optionally the third or fifth har-
monic.
•Insensitive against DC offset currents and current transformer saturation.
•High stability also for different current transformer saturation.
•High-speed instantaneous trip on high-current transformer faults.
•Independent of the conditioning of the starpoint(s) of the power transformer.
•High earth-fault sensitivity by detection of the starpoint current of an earthed trans-
former winding.
•Integrated matching of the transformer connection group.
•Integrated matching of the transformation ratio including different rated currents of
the transformer windings.
Differential Prot ec -
tion for Generators
and Motors
•Current restraint tripping characteristic.
•High sensitivity.
•Short tripping time.
•Insensitive against DC offset currents and current transformer saturation.
•High stability also for different current transformer saturation.
•Independent of the conditioning of the starpoint.
Differential Prot ec -
tion for Mini-
Busbars and Short
Lines
•Current restraint tripping characteristic.
•Short tripping time.
•Insensitive against DC offset currents and current transformer saturation.
1 Introduction
87UT612 Manual
C53000–G1176–C148–1
•High stability also for different current transformer saturation.
•Monitoring of the current connections with operation currents.
Bus-Bar Protection •Single-phase differential protection for up to seven feeders of a busbar.
•Either one relay per phase or one relay connected via interposed summation cur-
rent transformers.
•Current restraint tripping characteristic.
•Short tripping time.
•Insensitive against DC offset currents and current transformer saturation.
•High stability also for different current transformer saturation.
•Monitoring of the current connections with operation currents.
Restricted Ear th
Fault Protection •Earth fault protection for earthed transformer windings, generators, motors, shunt
reactors, or starpoint for mers.
•Short tripping time.
•High sensitivity for earth faults within the protected zone.
•High stability against external earth faults using the magnitude and phase relation-
ship of through-flowing earth current.
High-Impedance
Unit Protection •Highly sensitive fault current detection using a common (external) burden resistor.
•Short tripping time.
•Insensitive against DC offset currents and current transformer saturation.
•high stability with optimum matching.
•Suitable for earth fault detection on earthed generators, motors, shunt reactors, and
transformers, including auto-transformers.
•Suitable for any voltage measurement (via the resistor current) for application of
high-impedance unit protection.
Tank Leakage
Protection •For transformers or reactors the tank of which is installed isolated or high resistive
against ground.
•Monitoring of the leakage current flowing between the tank and ground.
•Can be connected via a “normal” current input of the device or the special highly
sensitive current input (3 mA smallest setting).
Time Overcurrent
Protection for
Phase Currents and
Residual Current
•Two definite time delayed overcurrent stages for each of the phase currents and the
residual (threefold zero sequence) current, can be assigned to any of the sides of
the protected object.
•Additionally, one inverse time delayed overcurrent stage for each of the phase cur-
rents and the residual current.
•Selection of various inverse time characteristics of different standards is possible,
alternatively a user defined characteristic can be specified.
1.3 Feature s
97UT612 Manual
C53000–G1176–C148–1
•All stages can be combined as desired; different characteristics can be selected for
phase currents on the one hand and the residual current on the other.
•External blocking facility for any desired stage (e.g. for reverse interlocking).
•Instantaneous trip when switching on a dead fault with any desired stage.
•Inrush restraint using the second harmonic of the measured currents.
•Dynamic switchover of the time overcurrent parameters, e.g. during cold-load start-
up of the power plant.
Time Overcurrent
Protection for Earth
Current
•Two definite time delayed overcurrent stages for the earth current connected at cur-
rent input I7 (e.g. current between starpoint and earth).
•Additionally, one inverse time delayed overcurrent stage for the earth current.
•Selection of various inverse time characteristics of different standards is possible,
alternatively a user defined characteristic can be specified.
•The stages can be combined as desired.
•External blocking facility for any desired stage (e.g. for reverse interlocking).
•Instantaneous trip when switching on a dead fault with any desired stage.
•Inrush restraint using the second harmonic of the measured current.
•Dynamic switchover of the time overcurrent parameters, e.g. during cold-load start-
up of the power plant.
Single-Phase Time
Overcurrent
Protection
•Two definite time delayed overcurrent stages can be combined as desired.
•For any desired single-phase overcurrent detection.
•Can be assigned to the current input I7 or the highly sensitive current input I8.
•Suitable for detection of very small current (e.g. for high-impedance unit protection
or tank leakage protection, see above).
•Suitable for detection of any desired AC voltage using an external series resistor
(e.g. for high-impedance unit protection, see above).
•External blocking facility for any desired stage.
Unbalanced Load
Protection •Processing of the negative sequence current of any desired side of the protected
object.
•Two definite time delayed negative sequence current stages and one additional in-
verse time delayed negative sequence current stage.
•Selection of various inverse time characteristics of different standards is possible,
alternatively a user defined characteristic can be specified.
•The stages can be combined as desired.
Thermal Overload
Protection •Thermal replica of current-initiated heat losses.
•True RMS current calculation.
•Can be assigned to any desired side of the protected object.
1 Introduction
10 7UT612 Manual
C53000–G1176–C148–1
•Adjustable thermal warning stage.
•Adjustable current warning stage.
•Alternatively evaluation of the hot-spot temperature according to IEC 60354 with
calculation of the reserve power and ageing rate (by means of external temperature
sensors via thermobox).
Circuit Breaker
Failure Protection •With monitoring of current flow through each breaker pole of the assigned side of
the protected object.
•Supervision of the breaker position possible (if breaker auxiliary contacts available).
•Initiation by each of the internal protection functions.
•Initiation by external trip functions possible via binary input.
External Direct Trip •Tripping of either circuit breaker by an external device via binary inputs.
•Inclusion of external commands into the internal processing of information and trip
commands.
•With or without trip time delay.
Processing of
External
Information
•Combining of external signals (user defined information) into the internal informa-
tion processing.
•Pre-defined transformer annunciations for Buchholz protection and oil gassing.
•Connection to output relays, LEDs, and via the serial system interface to a central
computer station.
User Defined Logic
Functions (CFC) •Freely programmable linkage between internal and external signals for the imple-
mentation of user defined logic functions.
•All usual logic functions.
•Time delays and measured value set point interrogation.
Commissioning;
Operation •Comprehensive support facilities for operation and commissioning.
•Indication of all measured values, amplitudes and phase relation.
•Indication of the calculated differential and restraint currents.
•Integrated help tools can be visualized by means of a standard browser: Phasor di-
agrams of all currents at all ends of the protected object are displayed as a graph.
•Connection and direction checks as well as interface check.
1.3 Feature s
117UT612 Manu al
C53000–G1176–C148–1
Monitoring
Functions •Monitoring of the internal measuring circuits, the auxiliary voltage supply, as well as
the hard- and software, resulting in increased reliability.
•Supervision of the current transformer secondary circuits by means of symmetry
checks.
•Check of the consistency of protection settings as to the protected object and the
assignment of the current inputs: blocking of the differential protection system in
case of inconsistent settings which could lead to a malfunction.
•Trip circuit supervision is possible.
Further Functions •Battery buffered real time clock, which may be sychronized via a synchronization
signal (e.g. DCF77, IRIG B via satellite receiver), binary input or system interface.
•Continuous calculation and display of measured quantities on the front of the de-
vice. Indication of measured quantities of all sides of the protected object.
•Fault event memory (trip log) for the last 8 network faults (faults in the power sys-
tem), with real time stamps (ms-resolution).
•Fault recording memory and data transfer for analog and user configurable binary
signal traces with a maximum time range of 5 s.
•Switching statistics: counter with the trip commands issued by the device, as well
as record of the fault current and accumulation of the interrupted fault currents;
•Communication with central control and data storage equipment via serial interfac-
es through the choice of data cable, modem, or optical fibres, as an option.
n
1 Introduction
12 7UT612 Manual
C53000–G1176–C148–1
137UT612 Manu al
C53000–G1176–C148–1
Functions 2
This chapter describes the numerous functions available on the SIPROTEC® 7UT612
relay. The setting options for each function are explained, including instructions to de-
termine setting values and formulae where required.
2.1 General 14
2.2 Differential Protection 33
2.3 Restricted Earth Fault Protection 64
2.4 Time Overcurrent Protection for Phase and Residual Currents 73
2.5 Time Overcurrent Protection for Earth Current 97
2.6 Dynamic Cold Load Pickup for Time Overcurrent Protection 108
2.7 Single-Phase T ime Overcurrent Pr otection 113
2.8 Unbalanced Load Protection 123
2.9 Thermal Overload Protection 131
2.10 Thermoboxes for Overload Protection 143
2.11 Circuit Br eaker Fa ilure Protection 152
2.12 Processing of External Signals 157
2.13 Monitoring Functions 160
2.14 Protection Function Control 171
2.15 Ancill ary Functions 175
2.16 Processing of Commands 189
2 Functions
14 7UT612 Manual
C53000–G1176–C148–1
2.1 General
A few seconds after the device is switched on, the initial display appears in the LCD.
In the 7UT612 the measured values are displayed.
Configuration settings (Subsection 2.1.1) may be entered using a PC and the software
program DIGSI®4 and transferred via the operating interface on the device front, or
via the serial service interface. Operation via DIGSI®4 is described in the
SIPROTEC®4 System Manual, order no. E50417–H1176–C151. Entry of password
No. 7 (for setting modification) is required to modify configuration settings. Without the
password, the settings may be read, but cannot be modified and transmitted to the de-
vice.
The function parameters, i.e. settings of function options, threshold values, etc., can
be entered via the keypad and display on the front of the device, or by means of a per-
sonal computer connected to the front or service interface of the device utilising the
DIGSI®4 software package. The level 5 password (individual parameters) is required.
2.1.1 Configuratio n of the Scope of Functions
General The 7UT612 relay contains a series of protective and additional functions. The scope
of hardware and firmware is matched to these functions. Furthermore, commands
(control actions) can be suited to individual needs of the protected object. In addition,
individual functions may be enabled or disabled during configuration, or interaction be-
tween functions may be adjusted.
Example for the configuration of the scope of functions:
7UT612 devices should be intended to be used for busbars and transformers. Over-
load protection should only be applied on transformers. If the device is used for bus-
bars this function is set to 'LVDEOHG and if used for transformers this function is set
to (QDEOHG.
The available function are configured (QDEOHG or 'LVDEOHG. For some functions, a
choice may be presented between several options which are explained below.
Functions configured as 'LVDEOHG are not processed by the 7UT612. There are no
messages, and associated settings (functions, limit values, etc.) are not displayed dur-
ing detailed settings.
Determination of
Functional Scope Configuration settings may be entered using a PC and the software program DIGSI®4
and transferred via the operating interface on the device front, or via the serial service
interface. Operation via DIGSI®4 i s descr ibed i n the SI PROTEC® system manual, or-
der number E50417–H1176–C151 (Section 5.3).
Note:
Available functions and default settings are depending on the ordering code of the re-
lay (see ordering code in the Appendix for details).
2.1 General
157UT612 Manu al
C53000–G1176–C148–1
Entry of password No. 7 (for setting modification) is required to modify configuration
settings. Without the password, the settings may be read, but cannot be modified and
transmitted to the device.
Special Cases Many of the settings are self-explanatory. The special cases are described below. Ap-
pendix A.4 includes a list of the functions with the suitable protected objects.
First determine which side of the protected object will be named
side 1
and which one
will be named
side 2
. Determination is up to you. If several 7UT612 are used, the sides
should be denominated consistently to be able to assign them more easily later on.
For
side 1
we recommend the following:
−for transformers the upper voltage side, but, if the starpoint of the lower voltage side
is earthed this side is preferred as side 1 (reference side);
−for generators the terminal side;
−for motor s and sh unt reac tor s the current supply side;
−for series reactors, lines and busbars there is no side which is preferred.
Side determination plays a role for some of the following configuration settings.
If the setting group change-over function is to be used, the setting in address *US
&KJH237,21 must be set to (QDEOHG. In this case, it is possible to apply up to four
different groups of settings for the function parameters. During normal operation, a
convenient and fast switch-over between these setting groups is possible. The setting
'LVDEOHG implies that only one function parameter setting group can be applied and
used.
The definition of the protected object (address 35272%-(&7) is decisive for the
possible setting parameters and for the assignment of the inputs and outputs of the
device to the protection functions:
−For normal power transformers with isolated windings set 35272%-(&7 =
SKDVHWUDQVI regardless of the connection group (winding interconnection) and
the earthing conditions of the starpoint(s). This is even valid if an earthing reactor is
situated within the protected zone (cf. Figure 2-18, page 45).
−The option $XWRWUDQVI is selected for auto-transformers. This option is also ap-
plicable for sh unt reactors if current transformers are installed at both sides of the
connection points (cf. Figure 2-25 right side, page 50).
−For a SKDVHWUDQVI, the phase input L2 is not connected. This option is suited
especially to single-phase power transformers with 162/3Hz (traction transformers).
−Equal setting is valid for generators and motors. The option *HQHUDWRU0RWRU
also applies for series reactors and shunt reactors which latter are equipped with
current transformers at both sides.
−Select the option SK%XVEDU if the device is used for mini-busbars or branch-
points with two ends. This setting applies also for short lines which are terminated
by two sets of current transformers. “Short” means that the current transformer
leads between the CTs and the device do not form an impermissible burden for the
CTs .
−The device can be used as single-phase differential protection for busbars with up
to 7 feeders, either using one device per phase or one device connected via exter-
nal summation CTs. Select the option SK%XVEDU in this case. You must inform
the device about the number of feeders under address 180%(52)(1'6.
2 Functions
16 7UT612 Manual
C53000–G1176–C148–1
The measuring input I7 serves often to acquire a starpoint current. Carrying out con-
figurations in address ,&7&211(&7 the de vice w ill be in fo rmed on the side
the current is assigned to. For transformers select the side where the starpoint is
earthed and where the starpoint current is to be measured. For earthed generators
and motors it is the side which is looking towards the earthed starpoint. For auto-trans-
formers any side can be selected since there is only one starpoint current for both
sides. If the starpoint current is not used for differential protection or for restricted earth
fault prote ction, pre-set the following: QRWXVHG.
If restricted earth fault protection is applied, it must be assigned to an earthed side in
address 5()3527. Otherwise this protection function has to be set to 'LVD
EOHG. For auto-transformers any side can be used.
The overcurrent time protection functions must also be assigned to a specific side of
the protected object.
−For ph a se ov er cu r re n t ti me protecti on se lect t h e s id e rel e va nt for this pr ote c ti on in
address '07,'073KDVH. For generators usually the starpoint side is select-
ed, for motors the terminal side. Otherwise, for single-side infeed we recommend
the feeding side. Often, however, an external overcurrent time protection is used for
the feeding side. The internal overcurrent time protection of 7UT612 should then be
activated for the outgoing side. It is then used as backup protection for faults be-
yond the outgoing side.
−To select the characteristic group according to which the phase overcurrent time
protection is to operate use address '07,'073+&+. If it is only used as
definite time overcurrent protection (DMT), set 'HILQLWH7LPH. In addition to the
definite time overcurrent protection an inverse time overcurrent protection may be
configured, if required. The latter operates according to an IEC-characteristic (72&
,(&), to an ANSI-characteristic (72&$16,) or to a user-defined characteristic. In
the latter case the trip time characteristic (8VHU'HILQHG38) or both the trip time
characteristic and the reset time characteristic (8VHUGHI5HVHW) are config-
ured. For the characteristics please refer to the Technical Data.
−In address the zero sequence (residual) current time overcurrent protection
'07,'07, can be assigned to any side of the protected object. This does not
have to be the same side as for phase overcurrent protection (address , see
above). For characteristics the same options are available as for the phase over-
current pr otecti on usi ng addre ss '07,'07,&+. However, for zero se-
quence current time overcurrent protection the settings may be different to the set-
tings selected for phase time overcurrent protection. This protection function always
acquires the residual current 3I0 of the supervised side. This current is calculated
from the sum of the corresponding phase currents.
−There is another earth current time overcurrent protection which is independent
from the before-described zero sequence time overcurrent protection. This protec-
tion, to be configured in address '07,'07(DUWK, acquires the current con-
nected to the current measuring input I7. In most cases, it is the starpoint current of
an earthed starpoint (for transformers, generators, motors or shunt reactors). No
assignment to a specific side is necessary since this type of protection always ac-
quires the I7 current, no matter where it originates from. For this protection you may
select one of the characteristic groups using address '07,'07(&+5, the
same way as for the phase time overcurrent protection. No matter which character-
istic has been selected for the latter.
A single-phase definite-time overcurrent protection '073+$6( for different user-
requirements is available in address . The protection function offers two options.
2.1 General
177UT612 Manu al
C53000–G1176–C148–1
It either acquires the measured current at the “normal” input I7 (XQVHQV&7) or at
highly sensitive input I8 (VHQV&7). The latter case is very interesting since input
I8 is able to detect even very small currents (from 3 mA at the input). This protection
function is very suited e.g. for highly sensitive tank leakage protection (see also Sub-
section 2.7.3) or high-impedance unit protection (see also Subsection 2.7.2). This pro-
tection is not bound to a specific side or application. Usage is up to the user’s require-
ments.
In address 81%$/$1&(/2$' the unbalanced load protection can be assigned
to a specific side of the protected object, i.e. it supervises the negative sequence cur-
rent and checks if there is any unbalanced load. The trip time characteristics can be
set to definite time ('HILQLWH7LPH) according to address 81%$//2$'&+5,
additionally operate according to an IEC–characteristic (72&,(&) or to an ANSI–
characteristic (72&$16,).
For overload protection select the side whose currents are relevant for overload de-
tection. Use address 7KHUP2YHUORDG. Since the cause for overload comes
from outside of the protected object, the overload current is a traversing current.
Therefore it does not necessarily have to be effective at the infeeding side.
−For transformers with tap changer the overload protection is assigned to the non-
regulated side as it is the only side where we have a defined relation between rated
current and rated power.
−For generators the overload protection usually is on the starpoint side.
−For motors and shunt reactors the overload protection is connected to the current
transformers of the feeding side.
−For series reactors, lines and busbars there any side can be selected.
−Busbars and sections of overhead lines usually do not require overload protection
since it is not reasonable to calculate the temperature rise. Climate and weather
conditions (temperature, wind) change to quick. On the other hand, the current
alarm stage is able to warn of menacing overload.
In address 7KHUP2/&+5 the user can additionally choose between two
methods of overload detection:
−Overload protection with thermal replica according to IEC 60255-8 (FODVVLFDO),
−Overload protection with calculation of hot-spot temperature and the aging rate ac-
cording to IEC 60354 (,(&),
The first method is characterized by its easy handling and a low number of setting val-
ues. The second method requires detailed knowledge about the protected object, the
environment it is located in and cooling. The latter one is useful for transformers with
integrated temperature detectors. For more information see also Section 2.9.
If overload protection with calculation of hot-spot temperature is used according to IEC
60354 (address 7KHUP2/&+5 = ,(&), at least one thermobox must be
connected to the service interface. The thermobox informs the device about the tem-
perature of the coolant. The interface is set in address 57'%2;,1387. For
7UT612 this is 3RUW&. The number of resistance temperature detectors and the way
the thermobox(es) transmit information is set in address 57'&211(&7,21:
57'VLPSOH[ or 57'+'; (with 1 thermobox) or 57'+'; (with 2 thermobox-
es). This must comply with the settings at the thermobox(es).
Note:
The temperature measuring point relevant for the calculation of the hot-spot
temperature should be fed via the first thermobox.
2 Functions
18 7UT612 Manual
C53000–G1176–C148–1
For the circuit breaker failure protection set in address %5($.(5)$,/85( which
side is to be monitored. This has to be the side feeding onto an internal fault.
For the trip circuit supervision select in address 7ULS&LU6XS whether it
shall operate with 2 (%LQDU\,QSXWV) o r only 1 bina ry i npu t ( %LQDU\,QSXW).
The inputs have to be isolated.
Addr. Setting Title Setting Options Default Setting Comments
103 Grp Chge OPTION Disabled
Enabled Disabled Setting Group Change Option
105 PROT. OBJECT 3 phase Transformer
1 phase Tran sformer
Autotransformer
Generator/Motor
3 phase Busbar
1 phase Busbar
3 phase Transfor-
mer Protection Object
106 NUMBER OF
SIDES 2 2 Number o f Side s for Mult i Phas e
Object
107 NUMBER OF ENDS 3
4
5
6
7
7 Number of Ends for 1 Phase
Busbar
108 I7-CT CONNECT. not used
Side 1
Side 2
not used I7-CT connected to
112 DIFF. PROT. Disabled
Enabled Enabled Differential Protection
113 REF PROT. Disabled
Side 1
Side 2
Disabled Restricted earth fault protection
117 Coldload Pickup Disabled
Enabled Disabled Cold Load Pickup
120 DMT/IDMT Phase Disabled
Side 1
Side 2
Disabled DMT / IDMT Phase
121 DMT/IDMT PH. CH Definite Time only
Time Overcurrent Curve IEC
Time Overcurrent Curve ANSI
User Defined Pickup Curve
User Defined Pickup and Reset
Curve
Definite Time only DMT / IDMT Phase Pick Up
Characteristic
122 DMT/IDMT 3I0 Disabled
Side 1
Side 2
Disabled DMT / IDMT 3I0
2.1 General
197UT612 Manu al
C53000–G1176–C148–1
123 DMT/IDMT 3I0 CH Definite Time only
Time Overcurrent Curve IEC
Time Overcurrent Curve ANSI
User Defined Pickup Curve
User Defined Pickup and Reset
Curve
Definite Time only DMT / IDMT 3I0 Pick Up Cha-
racteristic
124 DMT/IDMT Earth Disabled
unsensitive Current Transformer
I7
Disabled DMT / IDMT Earth
125 DMT/IDMT E CHR. Definite Time only
Time Overcurrent Curve IEC
Time Overcurrent Curve ANSI
User Defined Pickup Curve
User Defined Pickup and Reset
Curve
Definite Time only DMT / IDMT Earth Pick Up Cha-
racteristic
127 DMT 1PHASE Disabled
unsensitive Current Transformer
I7
sensitive Current Transformer I8
Disabled DMT 1Phase
140 UNBALANCE LOAD Disabled
Side 1
Side 2
Disabled Unbalance Load (Negative
Sequence)
141 UNBAL. LOAD CHR Definite Time only
Time Overcurrent Curve IEC
Time Overcurrent Curve ANSI
Definite Time only Unbalance Load (Neg. Sequ.)
Characteris.
142 Therm.Overload Disabled
Side 1
Side 2
Disabled Thermal Overload Protection
143 Therm.O/L CHR. classical (according IEC60255)
accordi ng IEC354 classical (accor-
ding IEC60255) Thermal Overload Protec. Cha-
racteristic
170 BREAKER
FAILURE Disabled
Side 1
Side 2
Disabled Breaker Failure Protect ion
181 M.V. SUPERV Disabled
Enabled Enabled Measured Values Supervision
182 Trip Cir. Sup. Disabled
with 2 Binary Inputs
with 1 Binary Input
Disabled Trip Circuit Supervision
186 EXT. TRIP 1 Disabled
Enabled Disabled External Trip Function 1
187 EXT. TRIP 2 Disabled
Enabled Disabled External Trip Function 2
190 RTD-BOX INPUT Disabled
Port C Disabled External Temperature Input
191 RTD CONNECTION 6 RTD simplex operation
6 RTD half duplex operation
12 RTD half duplex operation
6 RTD simplex
operation Ext. Temperature Input Connec-
tion Type
Addr. Setting Title Setting Options Default Setting Comments
2 Functions
20 7UT612 Manual
C53000–G1176–C148–1
2.1.2 Power System Data 1
General The device requires some plant and power system data in order to be able to adapt its
functions accordingly, dependent on the actual application. The data required include
for instance rated data of the substation and the measuring transformers, polarity and
connection of the measured quantities, if necessary features of the circuit breakers,
and others. These data can only be changed from a PC running DIGSI®4 and are dis-
cussed in this Subsection.
Rated Frequency The rated frequency of the power system is set under address 5DWHG)UHTXHQ
F\. The default setting is made in the factory in accordance with the design variant
and needs to be changed only if the device is to be used for a different purpose than
ordered for.
Phase sequence Ad dr ess 3+$6(6(4 is used to establish the phase sequence. The preset
phase sequence is /// for clockwise phase rotation. For systems with counter-
clockwise phase rotation, set ///. This setting is irrelevant for single-phase ap-
plication.
Figure 2-1 Phase sequence
Temperature Unit The temperature of the hot-spot temperature calculation can be expressed in degrees
&HOVLXV or )DKUHQKHLW. If overload protection with hot-spot temperature is used,
set the desired temperature unit in address 7(0381,7. Otherwise this setting
can be ignored. Changing temperature units does not mean that setting values which
are linked to these temperature units will automatically be converted. They have to be
re-entered into their corresponding addresses.
Object Data with
Transformers Transformer data are required if the device is used for differential protection for trans-
formers, i.e. if the following was set with the configuration of the protection functions
(Subsection 2.1.1, margin heading “Special Cases”): 35272%-(&7 (address )
SKDVHWUDQVI or $XWRWUDQVI or SKDVHWUDQVI. In cases other than
that, these settings are not available.
Please observe the assignment of the sides when determining winding 1, as above-
mentioned (Subsection 2.1.1, margin heading “Special Cases”). Generally, side 1 is
the reference winding having a current phase angle of 0° and no vector group indica-
tor. Usually this is the higher voltage winding of the transformer.
L1
L3L2
L1
L2L3
Clockwise
///
Counter-clockwise
///
2.1 General
217UT612 Manu al
C53000–G1176–C148–1
The device needs the following information:
•The rated voltage UN in kV (phase-to-phase) under address 8135,6,'(.
•The starpoint condition under address 67$53176,'(: 6ROLG(DUWKHG
or ,VRODWHG. If the starpoint is earthed via a current-limiting circuit (e.g. low-resis-
tive) or via a Petersen-coil (high-reactive), set 6ROLG(DUWKHG, too.
•The mode of connection of the transformer windings under address &211(&
7,216. This is normally the capital letter of the vector group according to IEC.
If the transformer winding is regulated then the actual rated voltage of the winding is
not used as UN but rather the voltage which corresponds to the average current of the
regulated range. The following applies:
where Umax, Umin are the voltages at the limits of the regulated range.
Calculation example:
Transformer YNd5
35 MVA
110 kV/20 kV
Y–winding with tap changer ±20 %
This results for the regulated winding (110 kV) in:
maxim um vo ltage Umax = 132 kV
mini mum voltage Umin = 88 k V
Setting voltage (address )
For the side 2, the same considerations apply as for the side 1: The rated voltage UN
in kV (phase-to-phase) under address 8135,6,'(, the starpoint condition
under address 67$53176,'(, and the mode of connection of the transformer
windings under address &211(&7,216.
Additionally, the vector group numeral is set under address 9(&725*536
which states the phase displacement of side 2 against the reference winding, side 1.
It is defined according to IEC as the multiple of 30°. If the higher voltage side is the
reference (side 1), you may set the numeral directly, e.g. for vector group Yd5 or
Dy5. Every vector group from 0 to 11 can be set provided it is possible (for instance,
Yy, Dd and Dz allow only even, Yd, Yz and Dy allow only odd numerals).
If not the higher voltage side is used as reference winding (side 1) it must be consid-
ered that the vector group changes: e.g. a Yd5 transformer is regarded from the lower
voltage side as Dy7 (Figure 2-2).
UN2Umax Umin
⋅
Umax Umin
+
--------------------------------
⋅2
1
Umax
------------- 1
Umin
------------+
--------------------------------==
UN-PRI SIDE 1 2
1
Umax
------------- 1
Umin
------------+
-------------------------------- 2
1
132 kV
------------------ 1
88 kV
---------------+
----------------------------------------- 105.6 kV
== =
2 Functions
22 7UT612 Manual
C53000–G1176–C148–1
Figure 2-2 Change of the transformer vector group if the lower voltage side is the reference side — example
The primary rated power 6175$16)250(5 (address ) is the direct primary rated
apparent power for transformers. The power must always be entered as a primary val-
ue, even if the device is generally configured in secondary values. The device calcu-
lates the rated current of the protected winding from this power. This is the reference
for all referred values.
The device automatically computes from the rated data of the protected transformer
the current-matching formulae which are required to match the vector group and the
different rated winding currents. The currents are converted such that the sensitivity
of the protection always refers to the power rating of the transformer. Therefore, no
circuity is required for matching of the vector group and no manual calculations for
converting of rated current are normally necessary.
Object Data with
Generators, Motors
and Reactors
Using the 7UT612 for protection of generators or motors, the following must have
been set when configuring the protection functions (see Subsection 2.1.1, address
): 35272%-(&7 = *HQHUDWRU0RWRU. These settings also go for series and
shunt reactors if a complete set of current transformers is connected to both sides. In
cases other than that, these settings are not available.
With address 81*(102725 you inform the device of the primary rated voltage
(phase-to-phase) of the machine to be protected.
The primary rated power 61*(102725 (address ) is the direct primary rated
apparent power of the machine. The power must always be entered as a primary
value, even if the device is generally configured in secondary values. The device cal-
culates the rated current of the protected object from this power and the rated voltage.
This is the reference for all referred values.
Object Data with
Mini-Busbars,
Branch-Points,
Short Lines
These data are only required if the device is used for differential protection of mini bus-
bars or short lines with two ends. When configuring the protection functions (see Sub-
section 2.1.1, address ) the following must have been set: 35272%-(&7 = SK
%XVEDU. In cases other than that, these settings are not available.
With address 81%86%$5 you inform the device of the primary rated voltage
(phase-to-phase). This setting has no effect on the protective functions but influences
the display of the operational measured values.
UL1N
L1L2L3
Winding 1
Winding 2
uL12
uL23
uL31
uL1N
UL2N
UL3N
Winding 2
Winding 1
L1L2L3
Yd5 Dy7
uL1N
UL12
UL23
UL1N
uL2N
uL3N
UL31
N
N
2.1 General
237UT612 Manu al
C53000–G1176–C148–1
Since both sides or feeders may be equipped with current transformers of different rat-
ed primary currents, a uniform rated operational current ,35,0$5<23 is defined
as rated object current (address ) which will then be considered as a reference val-
ue for all currents. The currents are converted such that the settings of the protection
function always refer to the rated operational current. In general, if current transform-
ers differ, the higher rated primary current is selected for operational rated current.
Object Data with
Busbars with up to
7 Feeders
Busbar data are only required if the device is used for single-phase busbar differential
protection for up to 7 feeders. When configuring the protection functions (see Subsec-
tion 2.1.1, address ) following must have been set: 35272%-(&7 = SK%XV
EDU. In cases other than that, these settings are not available.
With address 81%86%$5 you inform the device of the primary rated voltage
(phase-to-phase). This setting has no effect on the protective functions but influences
the displays of the operational measured values.
Since the feeders of a busbar may be equipped with current transformers of different
rated primary currents, a uniform operational nominal current ,35,0$5<23 is de-
fined as rated busbar current (address ) which will then be considered as a refer-
ence value for all currents. The feeder currents are converted such that the settings of
the protection functions always refer to the rated operational current. Usually no exter-
nal matching equipment is required. In general, if current transformers differ, the high-
er rated primary current of the feeders is selected for rated operational current.
If the device is connected via summation transformers, the latter are to be connected
between the current transformer set of each feeder and the device inputs. In this case
the summation transformers can also be used for matching of currents. For the rated
operational current of the busbar also use the highest of the rated primary currents of
the feeders. Rated currents of each individual feeder are matched later on.
If one 7UT612 is used per phase, set the same currents and voltages for all three de-
vices. For the identification of the phases for fault annunciations and measured values
each device is to be informed on the phase it is assigned to. This is to be set in address
3+$6(6(/(&7,21, address .
Current
Transformer Data
for 2 Sides
The rated primary operational currents for the protected object derive from the object
data before-described. The data of the current transformer sets at the sides of the pro-
tected object generally differ slightly from the object data before-described. They can
also be completely different. Currents have to have a clear polarity to ensure that the
differential protection applies the correct function.
Therefore the device must be informed on the current transformer data. If there are 2
sides (i.e. all applications, except for single-phase busbar protection for up to 7 feed-
ers), this is ensured by indication of rated currents and the secondary starpoint forma-
tion of the current transformer sets.
In address ,135,&76 the rated primary current of the current transformer
set of side 1 of the protected object is set. In address ,16(&&76 the rated
secondary current is set. Please make sure that the sides were defined correctly (see
Subsection 2.1.1, margin heading “Special Cases”, page 15). Please also make sure
that the rated secondary transformer currents match the setting for the rated currents
of the device (see also Subsection 3.1.3.3, margin heading “Input/Output Board A–I/
O–3”. Otherwise the device will calculate incorrect primary data, and malfunction of
the differential protection may occur.
2 Functions
24 7UT612 Manual
C53000–G1176–C148–1
Indication of the starpoint position of the current transformers determines the polarity
of the current transformers. To inform the device on the location of the starpoint in re-
lation to the protected object use address 675317!2%-6. Figure 2-3 shows
some examples for this setting.
Figure 2-3 Position of the CT starpoints — example
For side 2 of the protected object the same applies. For side 2 set the nominal primary
current ,135,&76 (address ), nominal secondary current ,16(&&76
(address ) and the position of the current transformer starpoint 675317!2%-6
(address ). Side 2 requires the same considerations as side 1.
If the device is applied as transverse differential protection for generators or motors,
special considerations must be observed for the CT connections: In a healthy opera-
tional state all currents flow into the protected object, i.e. in contrast to the other appli-
cations. Therefore you have to set a “wrong” polarity for
one
of the current transformer
sets. The part windings of the machine windings correspond to the “sides”.
L1
L2
L3
L1
L2
L3
675317!2%-6
= 12
Side 1 Side 2
675317!2%-6
= <(6
G
675317!2%-6
= <(6
675317!2%-6
= 12
Side 1 Side 2 L1
L2
L3
M
675317!2%-6
= <(6
675317!2%-6
= <(6
Side 1 Side 2 L1
L2
L3
2.1 General
257UT612 Manu al
C53000–G1176–C148–1
Figure 2-4 gives you an example: Although the starpoints of both current transformer
sets are looking towards the protected object, the opposite setting is to be selected for
“side 2”: 675317!2%-6 = 12.
Figure 2-4 Definition of current direction for transverse differential protection - example
Current
Transformer Data
for Single-phase
Busbar Protection
Current transformer sets in the feeders of a busbar can have different rated currents.
Therefore, a uniform rated operational object current has been determined in the be-
fore-described paragraph “Object Data with Busbars with up to 7 Feeders”. The cur-
rents of each individual feeder have to be matched to this rated operational current.
Indicate the rated primary transformer current for each feeder. The interrogation only
applies to data of the number of feeders determined during the configuration accord-
ing to 2.1.1 (address 180%(52)(1'6).
If rated currents have already been matched by external equipment (e.g. by matching
transformers), the rated current value, used as a base value for the calculation of the
external matching transformers, is to be indicated uniform. Normally, it is the rated op-
erational current. The same applies if external summation transformers are used.
Hereinafter the parameters for rated primary currents:
Address ,135,&7,= rated primary transformer current for feeder 1,
Address ,135,&7,= rated primary transformer current for feeder 2,
Address ,135,&7,= rated primary transformer current for feeder 3,
Address ,135,&7,= rated primary transformer current for fe eder 4,
Address ,135,&7,= rated primary transformer current for feeder 5,
Address ,135,&7,= rated primary transformer current for feeder 6,
Address ,135,&7,= rated primary transformer current for fe eder 7.
For rated secondary currents please make sure that rated secondary transformer cur-
rents match with the rated currents of the corresponding current input of the device.
Rated secondary currents of a device can be matched according to 3.1.3.3 (see mar-
gin heading “Input/Output Board A–I/O–3”).
If summation transformers are used, the rated current at the outgoing side is usually
100 mA. For rated secondary currents a value of A is therefore set for all feeders.
Hereinafter the parameters for rated secondary currents:
Address ,16(&&7,= rated secondary transformer current for feeder 1,
Address ,16(&&7,= rated secondary transformer current for feeder 2,
L1
L2
L3
675317!2%-6
= <(6
”Side 1”
”Side 2”
675317!2%-6
= 12
2 Functions
26 7UT612 Manual
C53000–G1176–C148–1
Address ,16(&&7,= rated secondary transformer current for feeder 3,
Address ,16(&&7,= rated secondary transformer current for feeder 4,
Address ,16(&&7,= rated secondary transformer current for feeder 5,
Address ,16(&&7,= rated secondary transformer current for feeder 6,
Address ,16(&&7,= rated secondary transformer current for feeder 7.
Indication of the starpoint position of the current transformers determines the polarity
of the current transformers. Set for each feeder if the starpoint is looking towards the
busbar or not. Figure 2-5 shows an example of 3 feeders in which the transformer star-
point in feeder 1 and feeder 3 are looking towards the busbar, unlike feeder 2.
Figure 2-5 Position of the CT starpoints — example for phase L1 of a busbar with 3 feeders
Hereinafter the parameters for the polarity:
Address 675317!%86, = transformer starpoint versus busbar for feeder 1,
Address 675317!%86, = transformer starpoint versus busbar for feeder 2,
Address 675317!%86, = transformer starpoint versus busbar for feeder 3,
Address 675317!%86, = transformer starpoint versus busbar for feeder 4,
Address 675317!%86, = transformer starpoint versus busbar for feeder 5,
Address 675317!%86, = transformer starpoint versus busbar for feeder 6,
Address 675317!%86, = transformer starpoint versus busbar for feeder 7.
Current
Transformer Data
for Current Input I7
The current measuring input I7 is normally used for the detection of the starpoint cur-
rent of an earthed winding of a transformer, shunt reactor, generator or motor. Only
for single-phase busbar protection this is not available since I7 is reserved for feeder
curre nts.
I7 can be used for zero sequence current compensation when performing differential
protection for transformers and/or restricted earth fault protection. It can be processed
by the earth current time overcurrent protection, as an alternative or additionally.
For matching the current magnitude set in address ,135,&7, the rated
primary current of the current transformer which is powered at this measuring input.
The rated secondary current of this current transformer in address ,16(&&7
, has to be in correspondence with the rated device current for this measuring input.
7UT612
L1
L2
L3
Feeder 1 Feeder 3Feeder 2
for L1
675317!%86,
= <(6 675317!%86,
= 12 675317!%86,
= <(6
I3
I2
I1
2.1 General
277UT612 Manu al
C53000–G1176–C148–1
Address ($57+(/(&752' is relevant for the polarity of the current. In this ad-
dress, set to which device terminal the side of the current transformer facing the earth
electrode is connected, i.e. not the side facing the starpoint itself. Figure 2-6 shows
the alternatives using an earthed transformer winding as an example.
Figure 2-6 Polarity setting for the measured current input I7
Current
Transformer Data
for Curre nt Input I8
The current measuring input I8 is a very sensitive input which enables to also acquire
very weak currents (beginning with 3 mA at input).
To also be able to indicate primary values for this measuring input (e. g. for setting
in primary currents, for output of primary measured values), the conversion factor
INprim/INsec of the current transformer connected is set in address )DFWRU,.
Trip Command
Duration The minimum trip command duration 70LQ75,3&0' is set in address $. This
duration is valid for all protection functions which can issue a trip command. This pa-
rameter can only be changed with DIGSI® 4 under “Additional Settings”.
Circuit Breaker
Status Various protection and ancillary functions require information on the status of the cir-
cuit breaker for faultless operation.
For the circuit breaker of side 1 of the protected object a current threshold %UHDNHU
6,! is to be s e t in ad dress . When the circuit breaker is open, this threshold is
likely to be undershot. The threshold may be very small if stray currents (e. g. due to
induction) are excluded when the protected object is switched off. Otherwise the
thr eshold value must be increased. No rmally the pre-setting is sufficient.
For the circuit breaker of side 2 of the protected object setting is done in address
%UHDNHU6,!.
7UT612
IL1
IL2
IL3
L1
L2
L3
Q8
Q7 7UT612
IL1
IL2
IL3
L1
L2
L3
Q7
Q8
K
Ll
k
K
Ll
kI
7I
7
($57+(/(&752'
= 7HUPLQDO4 ($57+(/(&752'
= 7HUPLQDO4
Note:
For devices in panel surface mounted case:
Terminal Q7 corresponds to housing terminal 12
Terminal Q8 corresponds to housing terminal 27
2 Functions
28 7UT612 Manual
C53000–G1176–C148–1
2.1.2.1 Setting Overview
Note:
The setting ranges and presettings listed in this table refer to a nominal current
value IN = 1 A. For a secondary nominal current value IN = 5 A the current values are
to be multiplied by 5. For setting primary values, the transformation ratio of the trans-
formers must also be taken into consideration.
The presetting of the nominal frequency corresponds to the nominal frequency ac-
cording to the device version.
Addr. Setting Title Setting Options Default Setting Comments
270 Rated Frequency 50 Hz
60 Hz
16 2/3 Hz
50 Hz Rated Frequency
271 PHASE SEQ. L1 L2 L3
L1 L3 L2 L1 L2 L3 Phase Sequence
276 TEMP. UNIT Degree Celsius
Degree Fahrenheit Degree Celsius Unit of temparature measurement
240 UN-PRI SIDE 1 0.4..800.0 kV 110.0 kV Rated Primary Voltage Side 1
241 STARPNT SIDE 1 Solid Earthed
Isolated Solid Earthed Starpoint of Side 1 is
242 CONNECTION S1 Y (Wye)
D (Delta)
Z (Zig-Zag)
Y (Wye) Transf. Winding Connection Side 1
243 UN-PRI SIDE 2 0.4..800.0 kV 11.0 kV Rated Primary Voltage side 2
244 STARPNT SIDE 2 Solid Earthed
Isolated Solid Earthed Starpoint of side 2 is
245 CONNECTION S2 Y (Wye)
D (Delta)
Z (Zig-Zag)
Y (Wye) Transf. Winding Connection Side 2
246 VECTOR GRP S2 0..11 0 Vector Group Numeral of Side 2
249 SN TRANSFOR-
MER 0.20..5000.00 MVA 38.10 MVA Rated Apparent Power of the Transfor-
mer
251 UN GEN/MOTOR 0.4..800.0 kV 21.0 kV Rated Primary Voltage Generator/
Motor
252 SN GEN/MOTOR 0.20..5000.00 MVA 70.00 MVA Rated Apparent Power of the Genera-
tor
261 UN BUSBAR 0.4..800.0 kV 110.0 kV Rated Primary Voltage Busbar
265 I PRIMARY OP. 1..100000 A 200 A Primary Operating Current
266 PHASE SELEC-
TION Phase 1
Phase 2
Phase 3
Phase 1 P hase selection
201 STRPNT->OBJ S1 YES
NO YES CT-Strpnt. Side1 in Direct. of Object
202 IN-PRI CT S1 1..100000 A 200 A CT Rated Primary Current Side 1
2.1 General
297UT612 Manu al
C53000–G1176–C148–1
203 IN-SEC CT S1 1A
5A 1A CT Rated Secondary Current Side 1
206 STRPNT->OBJ S2 YES
NO YES CT-Strpnt. Side2 in Direc t. of Object
207 IN-PRI CT S2 1..100000 A 2000 A CT Rated Primary Current Side 2
208 IN-SEC CT S2 1A
5A 1A CT Rated Secondary Current Side 2
211 STRPNT->BUS I1 YES
NO YES CT-Starpoint I1 in Direction of Busbar
212 IN-PRI CT I1 1..100000 A 200 A CT Rated Primary Current I1
213 IN-SEC CT I1 1A
5A
0.1A
1A CT Rated Secondary Current I1
214 STRPNT->BUS I2 YES
NO YES CT-Starpoint I2 in Direction of Busbar
215 IN-PRI CT I2 1..100000 A 200 A CT Rated Primary Current I2
216 IN-SEC CT I2 1A
5A
0.1A
1A CT Rated Secondary Current I2
217 STRPNT->BUS I3 YES
NO YES CT-Starpoint I3 in Direction of Busbar
218 IN-PRI CT I3 1..100000 A 200 A CT Rated Primary Current I3
219 IN-SEC CT I3 1A
5A
0.1A
1A CT Rated Secondary Current I3
221 STRPNT->BUS I4 YES
NO YES CT-Starpoint I4 in Direction of Busbar
222 IN-PRI CT I4 1..100000 A 200 A CT Rated Primary Current I4
223 IN-SEC CT I4 1A
5A
0.1A
1A CT Rated Secondary Current I4
224 STRPNT->BUS I5 YES
NO YES CT-Starpoint I5 in Direction of Busbar
225 IN-PRI CT I5 1..100000 A 200 A CT Rated Primary Current I5
226 IN-SEC CT I5 1A
5A
0.1A
1A CT Rated Secondary Current I5
227 STRPNT->BUS I6 YES
NO YES CT-Starpoint I6 in Direction of Busbar
228 IN-PRI CT I6 1..100000 A 200 A CT Rated Primary Current I6
229 IN-SEC CT I6 1A
5A
0.1A
1A CT Rated Secondary Current I6
Addr. Setting Title Setting Options Default Setting Comments
2 Functions
30 7UT612 Manual
C53000–G1176–C148–1
2.1.2.2 Information Overview
2.1.3 Setting Groups
Purpose of Setting
Groups In the 7UT612 relay, four independent setting groups (A to D) are possible. The user
can switch between setting groups locally, via binary inputs (if so configured), via the
operator or service interface using a personal computer, or via the system interface.
A setting group includes the setting values for all functions that have been selected as
(QDEOHG during configuration (see Subsection 2.1.1). Whilst setting values may vary
among the four setting groups, the scope of functions of each setting group remains
the same.
Multiple setting groups allows a specific relay to be used for more than one application.
While all setting groups are stored in the relay, only one setting group may be active
at a given time.
230 EARTH. ELEC-
TROD Terminal Q7
Terminal Q8 Terminal Q7 Earthing Electrod versus
231 STRPNT->BUS I7 YES
NO YES CT-Starpoint I7 in Direction of Busbar
232 IN-PRI CT I7 1..100000 A 200 A CT Rated Primary Current I7
233 IN-SEC CT I7 1A
5A
0.1A
1A CT Rated Secondary Current I7
235 Factor I8 1.0..300 .0 60.0 Factor: P rim. Current o ver Sek. Curr. I8
280A TMin TRIP CMD 0.01..32.00 sec 0.15 sec Minimum TRIP Command Duration
283 Breaker S1 I> 0.04..1.00 A 0.04 A Clos . Breaker Min. Current Thresh. S1
284 Breaker S2 I> 0.04..1.00 A 0.04 A Clos . Breaker Min. Current Thresh. S2
285 Breaker I7 I> 0.04..1.00 A 0.04 A Clos. Breaker Min. Current Thresh. I7
Addr. Setting Title Setting Options Default Setting Comments
F.No. Alarm Comments
05145 >Reverse Rot. >Reverse Phase Rotation
05147 Rotation L1L2L3 Phase Rotation L1L2L3
05148 Rotation L1L3L2 Phase Rotation L1L3L2
2.1 General
317UT612 Manu al
C53000–G1176–C148–1
If multiple setting groups are not required, Group A is the default selection, and the
rest of this subsection is of no importance.
If multiple setting groups are desired, address *US&KJH237,21 must have
been set to (QDEOHG in the relay configuration. Refer to Subsection 2.1.1. Each of
these sets (A to D) is adjusted one after the other. You will find more details how to
navigate between the setting groups, to copy and reset setting groups, and how to
switch over between the setting groups during operation, in the SIPROTEC® System
Manual, order number E50417–H1176–C151.
The preconditions to switch from one setting group to another via binary inputs is de-
scribed in Sub se ction 3.1.2.
2.1.3.1 Setting Overview
2.1.3.2 Information Overview
Addr. Setting Title Setting Options Default Setting Comments
302 CHANGE Group A
Group B
Group C
Group D
Binary Input
Protocol
Group A Change to Another Setting
Group
F.No. Alarm Comments
00007 >Set Group Bit0 >Setting Group Select Bit 0
00008 >Set Group Bit1 >Setting Group Select Bit 1
Group A Group A
Group B Group B
Group C Group C
Group D Group D
2 Functions
32 7UT612 Manual
C53000–G1176–C148–1
2.1.4 General Protection Data (Power System Data 2)
No settings are necessary for the general protection data in 7UT612. The following
table shows the possible information. Only the applicable information can appear, de-
pending on the version and the selected protected object.
2.1.4.1 Information Overview
F.No. Alarm Comments
00311 Fault Configur. Fault in configuration of the Protection
00356 >Manual Close >Manual close signal
00561 Man.Clos.Detect Manual close signal detected
00410 >CB1 3p Closed >CB1 aux. 3p Closed
00411 >CB1 3p Open >CB1 aux. 3p Open
00413 >CB2 3p Closed >CB2 aux. 3p Closed
00414 >CB2 3p Open >CB2 aux. 3p Open
00501 Relay PICKUP Relay PICKUP
00511 Relay TRIP Relay GENERAL TRIP command
>QuitG-TRP >Quitt Lock Out: General Trip
G-TRP Quit Lock Out: General TRIP
00126 ProtON/OFF Protection ON/OFF (via system port)
00576 IL1S1: Primary fault current IL1 side1
00577 IL2S1: Primary fault current IL2 side1
00578 IL3S1: Primary fault current IL3 side1
00579 IL1S2: Primary fault current IL1 side2
00580 IL2S2: Primary fault current IL2 side2
00581 IL3S2: Primary fault current IL3 side2
00582 I1: Primary fault current I1
00583 I2: Primary fault current I2
00584 I3: Primary fault current I3
00585 I4: Primary fault current I4
00586 I5: Primary fault current I5
00587 I6: Primary fault current I6
00588 I7: Primary fault current I7
2.2 Differential Protection
337UT612 Manu al
C53000–G1176–C148–1
2.2 Differential Protection
The differential protection represents the main feature of the device. It is based on cur-
rent comparison. 7UT612 is suitable for unit protection of transformers, generators,
motors, reactors, short lines, and (under observance of the available number of analog
current inputs) for branch points (smaller busbar arrangements). Generator/transform-
er units may also be protected.
7UT612 can be used as a single-phase differential protection relay for protected ob-
jects with up to 7 sides, e.g. as busbars protection with up to 7 feeders.
The protected zone is limited selectively by the current transformer sets.
2.2.1 Fundamentals of Differential Protection
The formation of the measured quantities depends on the application of the differential
protection. This subsection describes the general method of operation of the differen-
tial protection, independent of the type of protected object. The illustrations are based
on single-line diagrams. The special features necessary for the various types of pro-
tected object are covered in the following subsections.
Basic Principle with
Two Sides Differential protection is based on current comparison. It makes use of the fact that a
protected object (Figure 2-7) carries always the same current i (d ashed l ine) at it s two
sides in healthy operation. This current flows into one side of the considered zone and
leaves it again on the other side. A difference in current marks is a clear indication of
a fault within this section. If the actual current transformation ratio is the same, the sec-
ondary windings of the current transformers CT1 and CT2 at the line ends can be con-
nected to form a closed electric circuit with a secondary current I; a measuring ele-
ment M which is connected to the electrical balance point remains at zero current in
healthy operation.
Figure 2-7 Basic principle of differential protection for two ends (single-line illustration)
I
I1
I
I2
i i1i2 i
I1 + I2
M
i1 + i2
CT1 CT2
Protec ted
object
2 Functions
34 7UT612 Manual
C53000–G1176–C148–1
When a fault occurs in the zone limited by the transformers, a current I1 + I2 which is
proportional to the fault currents i1 + i2 flowing in from both sides is fed to the meas-
uring element. As a result, the simple circuit shown in Figure 2-7 ensures a reliable
tripping of the protection if the fault current flowing into the protected zone during a
fault is high enough for the measuring element M to respond.
Basic Principle with
more than Two
Sides
For protected objects with three or more sides or for busbars, the principle of differen-
tial protection is extended in that the total of all currents flowing into the protected ob-
ject is zero in healthy operation, whereas in case of a fault the total is equal to the fault
current (see Figure 2-8 as an example for four ends).
Figure 2-8 Basic principle of differential protection for four ends (single-line illustration)
Current Restraint When an external fault causes a heavy current to flow through the protected zone, dif-
ferences in the magnetic characteristics of the current transformers CT1 and CT2 un-
der conditions of saturation may cause a significant current to flow through the meas-
uring element M. If the magnitude of this current lies above the response threshold,
the protection would issue a trip signal. Current restraint prevents such erroneous op-
eration.
In differential protection systems for protected objects with two terminals, a restraining
quantity is normally derived from the current difference | I1 – I2| or from the arithmetical
sum |I1| + |I2|. Both methods are equal in the relevant ranges of the stabilization char-
acteristics. The latter method is used in 7UT612 for all protected objects. The following
definitions apply:
a tripping effect or differential current
IDiff = |I1 + I2|
and a stabilization or restraining current
IRest = |I1| + |I2|
IDiff is calculated from the fundamental wave of the measured currents and produces
the tripping effect quantity, IRest counteracts this effect.
To clarify the situation, three important operating conditions should be examined (refer
also to Figure 2-9):
I2
i1
I1 + I2
+ I3 + I4
M
CT1 CT2 CT3 CT4
I1I3I4
Protected obj ec t
i2i3i4
2.2 Differential Protection
357UT612 Manu al
C53000–G1176–C148–1
Figure 2-9 Definition of current direction
a) Through-fault current under healthy conditions or on an external fault:
I2 reverses its direction i.e. thus changes its sign, i.e. I2 = –I1, and consequently
|I2| = |I1|
IDiff = |I1 + I2| = |I1 – I1| = 0
IRest = |I1| + |I2| = |I1| + |I1| = 2·|I1|
no tripping effect (IDiff = 0); restraint (IRest) corresponds to twice the through
flowing current .
b) Internal fault, fed from each end e.g. with equal currents:
In this case, I2 = I1, and consequently |I2| = |I1|
IDiff = |I1 + I2| = |I1 + I1| = 2·|I1|
IRest = |I1| + |I2| = |I1| + |I1| = 2·|I1|
tripping effect (IDiff) and restraining (IRest) quantities are equal and correspond to
the total fault current.
c) Internal fault, fed from one end only:
In this case, I2 = 0
IDiff = |I1 + I2| = |I1 + 0| = |I1|
IRest = |I1| + |I2| = |I1| + 0 = |I1|
tripping effect (IDiff) and restraining (IRest) quantities are equal and correspond to
the fault current fed from one side.
This result shows that for internal fault IDiff = IRest. Thu s, th e characteri st i c of i nte r nal
faults is a straight line with the slope 1 (45°) in the operation diagram as illustrated in
Figure 2-10 (dash-dotted line).
Protected
M
CT1 CT2
i1i2
I1 + I2
I1I2
object
2 Functions
36 7UT612 Manual
C53000–G1176–C148–1
Figure 2-10 Operation characteristic of differential protection and fault characteristic
Add-on
Stabilization during
External Fault
Saturation of the current transformers caused by high fault currents and/or long sys-
tem time constants are uncritical for internal faults (fault in the protected zone), since
the measured value deformation is found in the differential current as well in the re-
straint current, to the same extent. The fault characteristic as illustrated in Figure 2-10
is principally valid in this case, too. Of course, the fundamental wave of the current
must exceed at least the pickup threshold (branch a in Figure 2-10).
During an external fault which produces a high through-flowing fault current causing
current transformer saturation, a considerable differential current can be simulated,
especially when the degree of saturation is different at the two sides. If the quantities
IDiff/IRest result in an operating point which lies in the trip area of the operating char-
acteristic (Figure 2-10), trip signal would be the consequence if there were no special
measures.
7UT612 provides a saturation indicator which detects such phenomena and initiates
add-on stabilization measures. The saturation indicator considers the dynamic behav-
iour of the differential and restraint quantity.
The dashed line in Figure 2-10 shows an example of the shape of the instantaneous
quantities during a through-fault current with current transformer saturation at one
side.
Immediately after fault inception (A) the fault currents increase severely thus produc-
ing a high restraint quantity (twice the through-flowing current). At the instant of CT
saturation (B) a differential quantity is produced and the restraint quantity is reduced.
In consequence, the operating point IDiff/IRest may move into the tripping area (C).
In contrast, the operating point moves immediately along the fault characteristic (D)
when an internal fault occurs sinc e the restraint current will barely be high er then the
differential current.
1 2 3 4 5 6 7 8 9 101112131415161718
1
2
3
4
5
6
7
8
9
10
Tripping
Blocking
IRest
IN
-----------------
IDiff
IN
--------------
a
Fault char acter istic
AB
C
D
aAdd-on stabilization
Saturation in ception
2.2 Differential Protection
377UT612 Manu al
C53000–G1176–C148–1
Current transformer saturation during external faults is detected by the high initial re-
straining current which moves the operating point briefly into the “add-on stabilization”
area (Figure 2-10). The saturation indicator makes its decision within the first quarter
cycle after fault inception. When an external fault is detected, the differential protection
is blocked for an adjustable time. This blocking is cancelled as soon as the operation
point moves steadily (i.e. over at least one cycle) near the fault characteristic. This
allows to detect evolving faults in the protected zone reliably even after an external
fault with current transformer saturation.
Harmonic Restraint When switching unloaded transformers or shunt reactors on a live busbar, high mag-
netizing (inrush) currents may occur. These inrush currents produce differential quan-
tities as they seem like single-end fed fault currents. Also during paralleling of trans-
formers, or an overexcitation of a power transformer, differential quantities may occur
due to magnetizing currents cause by increased voltage and/or decreased frequency.
The inrush current can amount to a multiple of the rated current and is characterized
by a considerable 2nd harmonic content (double rated frequency) which is practically
absent in the case of a short-circuit. If the second harmonic content exceeds a select-
able threshold, trip is blocked.
Besides the second harmonic, another harmonic can be selected to cause blocking.
A choice can be made between the third and fifth harmonic.
Overexcitation of the transformer iron is characterized by the presence of odd harmon-
ics in the current. Thus, the third or fifth harmonic are suitable to detect such phenom-
ena. But, as the third harmonic is often eliminated in power transformers (e.g. by the
delta winding), the use of the fifth is more common.
Furthermore, in case of converter transformers odd harmonics are found which are not
present during internal transformer faults.
The differential quantities are examined as to their harmonic content. Numerical filters
are used to perform a Fourier analysis of the differential currents. As soon as the har-
monic contents exceed the set values, a restraint of the respective phase evaluation
is introduced. The filter algorithms are optimized with regard to their transient behav-
iour such that additional measures for stabilization during dynamic conditions are not
necessary.
Since the harmonic restraint operates individually per phase, the protection is fully op-
erative even when e.g. the transformer is switched onto a single-phase fault, whereby
inrush currents may possibly be present in one of the healthy phases. However, it is
also possible to set the protection such that not only the phase with inrush current ex-
hibiting harmonic content in excess of the permissible value is restrained but also the
other phases of the differential stage are blocked (so called “crossblock function”).
This crossblock can be limited to a selectable duration.
Fast Unstabilized
Trip with High-
Current Faults
High-current faults in the protected zone may be cleared instantaneously without re-
gard of the magnitude of the restraining current, when the magnitude of the differential
currents can exclude that it is an external fault. In case of protected objects with high
direct impedance (transformers, generators, series reactors), a threshold can be
found above which a through-fault current never can increase. This threshold (prima-
ry) is, e.g. for a power transformer, .
The differential protection 7UT612 provides such unstabilized high-current trip stage.
This can operate even when, for example, a considerable second harmonic is present
in the differential current caused by current transformer saturation by a DC component
1
usc transf
----------------------------- I
1
t
UD
nsf
⋅
2 Functions
38 7UT612 Manual
C53000–G1176–C148–1
in the fault current which could be interpreted by the inrush restraint function as an in-
rush current.
This high-current stage evaluates the fundamental wave of the currents as well as the
instantaneous values. Instantaneous value processing ensures fast tripping even in
case the fundamental wave of the current is strongly reduced by current transformer
saturation. Because of the possible DC offset after fault inception, the instantaneous
value stage operates only above twice the set threshold.
Increase of Pickup
Value on Startup The increase of pickup value is especially suited for motors. In contrast to the inrush
current of transformers the inrush current of motors is a traversing current. Differential
currents, however, can emerge if current transformers still contain different remanent
magnetization before energization. Therefore, the transformers are energized from
different operation points of their hysteresis. Although differential currents are usually
small, they can be harmful if differential protection is set very sensitive.
An increase of the pickup value on startup provides additional security against over-
functioning when a non-energized protected object is switched in. As soon as the re-
straining current of one phase has dropped below a settable value ,5(67
67$5783, the pickup value increase is activated. The restraint current is twice the tra-
versing current in normal operation. Undershooting of the restraint current is therefore
a criterion for the non-energized protected object. The pickup value ,',))! is now
increased by a settable factor (see Figure 2-11). The other branches of the IDiff> stage
are shifted proportionally.
The return of the restraint current indicates the startup. After a settable time 767$57
0$; the increase of the characteristic is undone.
Figure 2-11 Increase of pickup value of the stage on startup
123456789101112131415161718
1
2
3
4
5
6
7
8
9
10
,',))!!
,',))!
IDiff
INobj
-------------
IRest
INobj
-------------
Tripping
Star tup c haracteristic
Increase of pickup
Steady-state
characteristic
Blocking
2.2 Differential Protection
397UT612 Manu al
C53000–G1176–C148–1
Tripping
Characteristic Figure 2-12 illustrates the complete tripping characteristic of the differential protection.
The branch a represents the sensitivity threshold of the differential protection (setting
,',))!) and considers constant error current, e.g. magnetizing currents.
Branch b takes into consideration current-proportional errors which may result from
transformation errors of the main CTs, the input CTs of the relay, or from erroneous
current caused by the position of the tap changer of the voltage regulator.
In the range of high currents which may give rise to current transformer saturation,
branch c causes stronger stabilization.
Differential currents above the branch d cause immediate trip regardless of the re-
straining quantity and harmonic content (setting ,',))!!). This is the area of “Fast
Unstabilized Trip with High-Current Faults” (see above).
The area of “Add-on stabilization” is the operation area of the saturation indicator as
described above under margin “Add-on Stabilization during External Fault”.
Figure 2-12 Tripping characteristic of differential protection
The quantities IDiff and IRest are compared by the differential protection with the oper-
ating characteristic according to Figure 2-12. If the quantities result into a locus in the
tripping area, trip signal is given.
Fault Detection,
Drop-off Normally, a differential protection does not need a “pickup” or “fault detection” function
since the condition for a fault detection is identical to the trip condition. But, 7UT612
provides like all SIPROTEC® 4 devices a fault detection function which has the task
to define the fault inception instant for a number of further features: Fault detection in-
dicates the beginning of a fault event in the system. This is necessary to open the trip
log buffer and the memory for oscillographic fault record data. But, also internal func-
tions need the instant of fault inception even in case of an external fault, e.g. the sat-
uration indicator which has to operate right in case of an external fault.
1 2 3 4 5 6 7 8 9 101112131415161718
1
2
3
4
5
6
7
8
9
10
,',))!!
,',))!
%$6(32,17
%$6(32,17
Tripping
b
c
d
IRest
IN
-----------------
IDiff
IN
--------------
a
Fault characteristic
Add-on stabilization
6/23(
6/23(
Blocking
,²$''2167$%
2 Functions
40 7UT612 Manual
C53000–G1176–C148–1
As soon as the fundamental wave of the differential current exceeds 70 % of the set
value or the restraining current reaches 70 % of the add-on stabilization area, the pro-
tection picks up (Figure 2-13). Pickup of the fast high-current stage causes a fault de-
tection, too.
Figure 2-1 3 Fault detection area of the differential protectio n
If the harmonic restraint is effective, the harmonic analysis is carried out (approx. one
AC cycle) in order to examine the stabilizing conditions. Otherwise, tripping occurs as
soon as the tripping conditions are fulfilled (tripping area in Figure 2-12).
For special cases, the trip command can be delayed.
Figure 2-14 shows a simplified tripping logic.
Reset of pickup is initiated when, during 2 AC cycles, pickup is no longer recognized
in the differential values, i.e. the differential current has fallen below 70 % of the set
value, and no further trip conditions are present.
If a trip command has not been initiated, the fault is considered to be over after reset.
If a trip command has been formed, this is sealed for at least the minimum trip duration
which is set under the general protection data, common for all protection function (re-
fer to Subsection 2.1.2 under margin header “Trip Command Duration”, page 27).
0.7
Steady-state
characteristic
IDiff
INObj
----------------
Fault detection
IRest
INObj
-----------------
,²',))!
0.7 ·
,²',))!
,²$''2167$%
Start of
add-on stabilization
2.2 Differential Protection
417UT612 Manu al
C53000–G1176–C148–1
Figure 2-14 Tripping logic of the differential protection
L3
L2
L1
≥1
&
>Diff BLOCK
FNo 05603
',))3527
FNo 05616
Diff BLOCKED
FNo 05617
Diff ACTIVE
FNo 05615
Diff OFF
”1”
FNo 05631
Diff picked up
Diff> L3
≥
1
Diff> L2
FNo 056 81. ..05 68 3
Diff> L1
7,',))!
FNo 05691
Dif f> TRIP
≥
1
≥
1
FNo 05672
Diff TRIP
FNo 056 92
Diff>>
FNo 056 71
Diff TRIP
Character.
Inrush
restraint
(2nd harmon.)
Harmonic
restraint
(3rd or 5th)
Add-on
stabilization
(ext. fault)
Fast trip
(high current)
FNo 05651...05653
Diff Bl. exF.L1
Diff Bl. exF.L2
Diff Bl. exF.L3
≥
1
FNo 05673
Diff TRIP
≥
1
FNo 05674
Diff TRIP
Diff>> L3
Diff>> L2
FNo 05684...05686
Diff>> L1
7,',))!!
T
≥
1
≥
1
1
)
only for transformer
1
)
1
)
Meas. release
Meas. release
Meas. release
Diff current
monitor
&
2
)
T
2
)
only for line/busbar
&
FNo 05647...05649
Diff n.Harm L1
Diff n.Harm L2
Diff n.Harm L3
FNo 05644...05646
Diff 2.Harm L1
Diff 2.Harm L2
Diff 2.Harm L3
1
)
1
)
FNo 05662...05664
Block Iflt.L1
Block Iflt.L2
Block Iflt.L3
2
)
21
%ORFNUHOD\
2))
&
2 Functions
42 7UT612 Manual
C53000–G1176–C148–1
2.2.2 Differential Protection for Transformers
Matching of the
Measured Values In power transformers, generally, the secondary currents of the current transformers
are not equal when a current flows through the power transformer, but depend on the
transformation ratio and the connection group of the protected power transformer, and
the rated currents of the current transformers at both sides of the power transformer.
The currents must, therefore, be matched in order to become comparable.
Matching to the various power transformer and current transformer ratios and of the
phase displacement according to the vector group of the protected transformer is per-
formed purely mathematically. As a rule, external matching transformers are not re-
quired.
The input currents are converted in relation to the power transformer rated current.
This is achieved by entering the rated transformer data, such as rated power, rated
voltage and rated primary current of the current transformers, into the protection de-
vice.
Once the vector group has been entered, the protection is capable of performing the
current comparison according to fixed formulae.
Conversion of the currents is performed by programmed coefficient matrices which
simulate the difference currents in the transformer windings. All conceivable vector
groups (including phase exchange) are possible. In this aspect, the conditioning of the
starpoint(s) of the power transformer is essential, too.
Isolated Starpoint Figure 2-15 illustrates an example for a power transformer Yd5 (wye-delta with 150 °
phase displacement) without any earthed starpoint. The figure shows the windings
and the phasor diagrams of symmetrical currents and, at the bottom, the matrix equa-
tions. The general form of these equations is
where
(Im) – matrix of the matched currents IA, IB, IC,
k – constant factor,
(K) – coefficient matrix, dependent on the vector group,
(In) – matrix of the phase currents IL1, IL2, IL3.
On the left (delta) winding, the matched currents IA, IB, IC are derived from the differ-
ence of the phase currents IL1, IL2, IL3. On the right (wye) side, the matched currents
are equal to the phase currents (magnitude matching not considered).
Im
() kK() I
n
()⋅⋅
=
2.2 Differential Protection
437UT612 Manu al
C53000–G1176–C148–1
Figure 2-15 Matching the transformer vector group, example Yd5
(magnitudes not considered)
Ear th ed Starpoi nt Figure 2-16 illustrates an example for a transformer YNd5 with an earthed starpoint on
the Y–side.
In this case, the zero sequence currents are eliminated. On the left side, the zero se-
quence currents cancel each other because of the calculation of the current differenc-
es. This complies with the fact that zero sequence current is not possible outside of
the delta winding. On the right side, the zero sequence current is eliminated by the cal-
culation rule of the matrix, e.g.
1/3 · (2 IL1 – 1 IL2 – 1 IL3) = 1/3 · (3 IL1 – IL1 – IL2 – IL3) = 1/3 · (3 IL1 – 3 I0) = (IL1 – I0).
Zero sequence current elimination achieves that fault currents which flow via the
transformer during earth faults in the network in case of an earth point in the protected
zone (transformer starpoint or starpoint former by neutral earth reactor) are rendered
harmless without any special external measures. Refer e.g. to Figure 2-17: Because
of th e earthe d starpo int, a zer o sequenc e curren t occur s on the ri ght side during a ne t-
work fault but not on the left side. Comparison of the phase currents, without zero se-
quence current elimination, would cause a wrong result (current difference in spite of
an external fault).
L1
L2
L3
L1
L2
L3
Winding 1Winding 2
IL1
IL2
IL3
IA
IA
IL1
IL2
IL3
IA
IB
IC
1100
010
001
I
L1
IL2
IL3
⋅⋅
=
I
A
I
B
I
C
1
3
------- 1
–01
11
–0
01 1
–
I
L1
IL2
IL3
⋅⋅
=
2 Functions
44 7UT612 Manual
C53000–G1176–C148–1
Figure 2-16 Matching the transformer vector group, example YNd5 (magnitudes not
considered)
Figure 2-1 7 Exampl e of an earth fault outsi de the protected transformer and current
distribution
Figure 2-18 shows an example of an earth fault on the delta side
outside
the protected
zone if an earthed starpoint former (zigzag winding) is installed
within
the protected
zone. In this arrangement, a zero sequence current occurs on the right side but not on
the left, as above. If the starpoint former were
outside
the protected zone (i.e. CTs be-
tween power transformer and starpoint former) the zero sequence current would not
pass through the measuring point (CTs) and would not have any harmful effect.
The disadvantage of elimination of the zero sequence current is that the protection be-
comes less sensitive (factor 2/3 because the zero sequence current amounts to 1/3) in
case of an earth fault in the protected area. Therefore, elimination is suppressed in
case the starpoint is not earthed (see above, Figure 2-15).
L1
L2
L3
L1
L2
L3
Winding 1Winding 2
IL1
IL2
IL3
IA
IA
IL1
IL2
IL3
IA
IB
IC
1
3
--- 21
–1
–
1
–21
–
1
–1
–2
I
L1
IL2
IL3
⋅⋅
=
I
A
I
B
I
C
1
3
------- 1
–01
11
–0
01 1
–
I
L1
IL2
IL3
⋅⋅
=
L
1
L
2
L
3
L
1
L
2
L
3
2.2 Differential Protection
457UT612 Manu al
C53000–G1176–C148–1
Figure 2-18 Example of an earth fault outside the protected transformer with a neutral
earthing reactor within the protected zone
Increasing the
Ground Fault
Sensitivity
Higher earth fault sensitivity in case of an earthed winding can be achieved if the star-
point current is available, i.e. if a current transformer is installed in the starpoint con-
nection to earth and this current is fed to the device (current input I7).
Figure 2-19 shows an example of a power transformer the starpoint of which is earthed
on the Y–side. In this case, the zero sequence current is not eliminated. Instead of this,
1/3 of the starpoint current ISP is added for each phase.
Figure 2-19 Example of a earth fault outside the transformer with current distribution
The matrix equation is in this case:
ISP corresponds to –3I0 but is measured in the starpoint connection of the winding and
not in the phase lines. The effect is that the zero sequence current is considered in
case of an
internal
fault (from I0 = –1/3ISP), whilst the zero sequence current is elimi-
nated in case of an
external
fault because the zero sequence current on the terminal
side I0 = 1/3 · (IL1 + IL2 + IL3) compensates for the starpoint current. In this way, full
sensitivity (with zero sequence current) is achieved for internal earth faults and full
elimination of the zero sequence current in case of external earth faults.
L1
L2
L3
L1
L2
L3
L1
L2
L3
L1
L2
L3
ISP IL3
IA
IB
IC
1100
010
001
I
L1
IL2
IL3
1
3
---
ISP
ISP
ISP
⋅
+
⋅⋅
=
2 Functions
46 7UT612 Manual
C53000–G1176–C148–1
Even higher earth fault sensitivity during internal earth fault is possible by means of
the restricted earth fault protection as described in Section 2.3.
Use on Auto-
Transformers Auto-transformers can only be connected Y(N)y0. If the starpoint is earthed this is
effective for both the system parts (higher and lower voltage system). The zero
sequence system of both system parts is coupled because of the common starpoint.
In case of an earth fault, the distribution of the fault currents is not unequivocal and
cannot be derived from the transformer properties. Current magnitude and distribution
is also dependent on whether or not the transformer is provided with a stabilizing
winding.
Figure 2-20 Auto-transformer with earthed starpoint
The zero sequence current must be eliminated for the differential protection. This is
achieved by the application of the matrices with zero sequence current elimination.
The decreased sensitivity due to zero sequence current elimination cannot be com-
pensated by consideration of the starpoint current. This current cannot be assigned to
a certain phase nor to a certain side of the transformer.
Increased earth fault sensitivity during internal earth fault can be achieved by using
the restricted earth fault protection as described in Section 2.3 and/or by the high-
impedance differential protection described in Subsection 2.7.2.
Use on Single-
Phase
Transformers
Single-phase transformers can be designed with one or two windings per side; in the
latter case, the winding phases can be wound on one or two iron cores. In order to
ensure that optimum matching of the currents would be possible, always two meas-
ured current inputs shall be used even if only one current transformer is installed on
one phase. The currents are to be connected to the inputs L1 and L3 of the device;
they are designated IL1 and IL3 in the following.
If two winding phases are available, they may be connected either in series (which
corresponds to a wye-winding) or in parallel (which corresponds to a delta-winding).
The phase displacement between the windings can only be 0° or 180°. Figure 2-21
shows an example of a single-phase power transformer with two phases per side with
the definition of the direction of the currents.
L1
L2
L3
L1
L2
L3
2.2 Differential Protection
477UT612 Manu al
C53000–G1176–C148–1
Figure 2-21 Example of a single-phase transformer with current definition
Like with three-phase power transformers, the currents are matched by programmed
coefficient matrices which simulate the difference currents in the transformer wind-
ings. The common form of these equations is
where
(Im)– matrix of the matched currents IA, IC,
k – constant factor,
(K) – coefficient matrix,
(In) – matrix of the phase currents IL1, IL3.
Since the phase displacement between the windings can only be 0° or 180°, matching
is relevant only with respect to the treatment of the zero sequence current (besides
magnitude matching). If the “starpoint” of the protected transformer winding is not
earthed (Figure 2-21 left side), the phase currents can directly be used.
If a “starpoint” is earthed (Figure 2-21 right side), the zero sequence current must be
eliminated by forming the current differences. Thus, fault currents which flow through
the transformer during earth faults in the network in case of an earth point in the pro-
tected zone (transformer “starpoint”) are rendered harmless without any special exter-
nal measures.
The matrices are (Figure 2-21):
The disadvantage of elimination of the zero sequence current is that the protection be-
comes less sensitive (factor 1/2 because the zero sequence current amounts to 1/2) in
case of an earth fault in the protected area. Higher earth fault sensitivity can be
achieved if the “starpoint” current is available, i.e. if a CT is installed in the “starpoint”
connection to earth and this current is fed to the device (current input I7).
Figure 2-22 Example of an earth fault outside a single-phase transformer with current
distribution
L1
L3
L1
L3
Im
() kK() I
n
()⋅⋅
=
I
A
I
C
110
01
I
L1
IL3
⋅⋅
=I
A
I
C
1
2
--- 11
–
1
–1
I
L1
IL3
⋅⋅
=
I
SP
L1
L3
L1
L3
2 Functions
48 7UT612 Manual
C53000–G1176–C148–1
The matrices are in this case:
where ISP is the current measured in the “starpoint” connection.
The zero sequence current is not eliminated. Instead of this, for each phase 1/2 of the
starpoint current ISP is added. The effect is that the zero sequence current is consid-
ered in case of an
internal
fault (from I0 = –1/2ISP), whilst the zero sequence current
is eliminated in case of an
external
fault because the zero sequence current on the
terminal side I0 = 1/2 · (IL1 + IL3) compensates for the “starpoint” current. In this way,
full sensitivity (with zero sequence current) is achieved for internal earth faults and full
elimination of the zero sequence current in case of external earth faults.
2.2.3 Differential Protection for Generators, Motors, and Series Reactors
Matching of the
Measured Values Equal conditions apply for generators, motors, and series reactors. The protected
zone is limited by the sets of current transformers at each side of the protected object.
On generators and motors, the CTs are installed in the starpoint connections and at
the terminal side (Figure 2-23). Since the current direction is normally defined as pos-
itive in the direction of the protected object, for differential protection schemes, the def-
initions of Figure 2-23 apply.
Figure 2-23 Definition of current directio n with longitudinal differential protection
In 7UT612, all measured quantities are referred to the rated values of the protected
object. The device is informed about the rated machine data during setting: the rated
apparent power, the rated voltage, and the rated currents of the current transformers.
Measured value matching is reduced to magnitude factors, therefore.
A special case is the use as transverse differential protection. The definition of the cur-
rent direction is shown in Figure 2-24 for this application.
For use as a transverse differential protection, the protected zone is limited by the end
of the parallel phases. A differential current always and exclusively occurs when the
currents of two parallel windings differ from each other. This indicates a fault current
in one of the parallel phases.
IA
IC
110
01
I
L1
IL3
⋅⋅
=I
A
I
C
110
01
I
L1
IL3
1
2
--- ISP
ISP
⋅
+
⋅⋅
=
L
1
L
2
L
3
2.2 Differential Protection
497UT612 Manu al
C53000–G1176–C148–1
Figure 2-24 Definition of current direction with transverse differential protection
The currents flow into the protected object even in case of healthy operation, in con-
trast to all other applications. For this reason, the polarity of
one
current transformer
set must be reversed, i.e. you must set a “wrong” polarity, as described in Subsection
2.1.2 under “Current Transformer Data for 2 Sides”, page 23.
Starpoint
Conditioning If the differential protection is used as generator or motor protection, the starpoint con-
dition need not be considered even if the starpoint of the machine is earthed (high- or
low-resistant). The phase currents are always equal at both measuring points in case
of an external fault. With internal faults, the fault current results always in a differential
current.
Nevertheless, increased earth fault sensitivity can be achieved by the restricted earth
fault protection as described in Section 2.3 and/or by the high-impedance differential
protection described in Subsection 2.7.2.
2.2.4 Different ial Protection for Shunt Reactors
If current transformers are available for each phase at both side of a shunt reactor, the
same considerations apply as for series reactors (see Subsection 2.2.3).
In most cases, current transformers are installed in the lead phases and in the star-
point connection (Figure 2-25 left graph). In this case, comparison of the zero se-
quence currents is reasonable. The restricted earth fault protection is most suitable for
this application, refer to Section 2.3.
If current transformers are installed in the line at both sides of the connection point of
the reactor (Figure 2-25 right graph) the same conditions apply as for auto-transform-
ers.
A neutral earthing reactor (starpoint former) outside the protected zone of a power
transformer can be treated as a separate protected object provided it is equipped with
current transformers like a shunt reactor. The difference is that the starpoint former
has a low impedance for zero sequence currents.
L1
L2
L3
2 Functions
50 7UT612 Manual
C53000–G1176–C148–1
Figure 2-25 Definition of current directio n on a shunt reactor
2.2.5 Differential Protection for Mini-Busbars, Branch-Points and Short Lines
A branch-point is defined here as a three-phase, coherent piece of conductor which is
limited by sets of current transformers (even this is, strictly speaking, no branch point).
Examples are short stubs or mini-busbars (Figure 2-26). The differential protection in
this operation mode is not suited to transformers; use the function “Differential Protec-
tion for Transformers” for this application (refer to Subsection 2.2.2). Even for other
inductances, like series or shunt reactors, the branch point differential protection
should not be used because of its lower sensitivity.
This operation mode is also suitable for short lines or cables. “Short” means that the
current transformer connections from the CTs to the device cause no impermissible
burden for the current transformers. On the other hand, capacitive charging current do
not harm this operation because the protection is normally less sensitive with this ap-
plication.
Since the current direction is normally defined as positive in the direction of the pro-
tected object, for differential protection schemes, the definitions of Figures 2-26 and
2-27 apply .
If 7UT612 is used as differential protection for mini-busbars or short lines, all currents
are referred to the nominal current of the protected busbars or line. The device is in-
formed about this during setting. Measured value matching is reduced to magnitude
factors, therefore. No external matching devices are necessary if the current trans-
former sets at the ends of the protected zone have different primary current.
L1
L2
L3
L1
L2
L3
ISP
L1
L2
L3
L1
L2
L3
ISP
2.2 Differential Protection
517UT612 Manu al
C53000–G1176–C148–1
Figure 2-26 Definition of current direction at a branch-point (busbar with 2 feeders)
Figure 2-27 Definition of current direction at short lines
Differential Current
Monitoring Whereas a high sensitivity of the differential protection is normally required for trans-
formers, reactors, and rotating machines in order to detect even small fault currents,
high fault currents are expected in case of faults on a busbar or a short line so that a
higher pickup threshold (above rated current) is conceded here. This allows for a con-
tinuous monitoring of the differential currents on a low level. A small differential current
in the range of operational currents indicates a fault in the secondary circuit of the cur-
rent transformers.
This monitor operates phase segregated. When, during normal load conditions, a dif-
ferential current is detected in the order of the load current of a feeder, this indicates
a missing secondary current, i.e. a fault in the secondary current leads (short-circuit or
open-circuit). This condition is annunciated with time delay. The differential protection
is blocked in the associated phase at the same time.
Feeder Current
Guard Another feature is provided for protection of mini-busbars or short lines. This feeder
current guard monitors the currents of each phase of each side of the protected object.
It provides an additional trip condition. Trip command is allowed only when at least one
of these currents exceeds a certain (settable) threshold.
L1
L2
L3
Busbar
L1
L2
L3
2 Functions
52 7UT612 Manual
C53000–G1176–C148–1
2.2.6 Single-Phase Differential Protec tion for Busbars
Besides the high-sensitivity current input I8, 7UT612 provides 7 current inputs of equal
design. This allows for a single-phase busbar protection for up to 7 feeders.
Two possibilities exist:
1. One 7UT612 is used for each phase (Figure 2-28). Each phase of all busbar
feeders is connected to one phase dedicated device.
2. The phase currents of each feeder are summarized into a single-phase
summation current (Figure 2-29). These currents are fed to one 7UT612.
Phase Dedicated
Connection For each of the phases, a 7UT612 is used in case of single-phase connection. The
fault current sensitivity is equal for all types of fault.
The differential protection refers all measured quantities to the nominal current of the
protected object. Therefore, a common nominal current must be defined for the entire
busbar even if the feeder CTs have different nominal currents. The nominal busbar
current and the nominal currents of all feeder CTs must be set on the relay. Matching
of the current magnitudes is performed in the device. No external matching devices
are necessary even if the current transformer sets at the ends of the protected zone
have different primary current.
Figure 2-28 Single-phase busbar protection, illustrated for phase L1
Connection via
Summation CT’s One single device 7UT612 is sufficient for a busbar with up to 7 feeders if the device
is connected via summation current transformers. The phase currents of each feeder
are converted into single-phase current by means of the summation CTs (Figure 2-
29). Current summation is unsymmetrical; thus, different sensitivity is valid for different
type of fault.
A common nominal current must be defined for the entire busbar. Matching of the cur-
rents can be performed in the summation transformer connections if the feeder CTs
have different nominal currents. The output of the summation transformers is normally
designed for IM = 100 mA at symmetrical nominal busbar current.
7UT612
L1
L2
L3
Feeder 1 Feeder 7Feeder 2
Phase L1
I1
I2
I7
2.2 Differential Protection
537UT612 Manu al
C53000–G1176–C148–1
Figure 2-29 Busbar protection with connection via summation current transformers (SCT)
Different schemes are possible for the connection of the current transformers. The
same CT connection method must be used for all feeders of a busbar.
The scheme shown in Figure 2-30 is the most common. The input windings of the
summation transformer are connected to the CT currents IL1, IL3, and IE (residual cur-
rent). This connection is suitable for all kinds of systems regardless of the conditioning
of the system neutral. It is characterized by an increased sensitivity for earth faults.
For a symmetrical three-phase fault (where the earth residual component, IE = 0) the
single-phase summation current is, as illustrated in Figure 2-30, √3 times the winding
unit value. That is, the summation flux (ampere turns) is the same as it would be for
single-phase current √3 times the value flowing through the winding with the least
number of turns (ratio 1). For three-phase symmetrical fault currents equal to rated
current IN, the secondary single-phase current is IM = 100 mA. All relay characteristic
operating values are based on this type of fault and these currents.
Figure 2-30 CT connection L1–L3–E
7UT612
L1
L2
L3
Feeder 1 Feeder 7
L1L2L3E
Feeder 2
L1L2L3E L1L2L3E
SCT SCT SCT
I1
I2
I7
IL3
L1
7UT612
IL1 SCT IM
IE
1
2
3
L2L3
2 Functions
54 7UT612 Manual
C53000–G1176–C148–1
Figure 2-31 Summation of the currents L1–L3–E in the summation transformer
For the connection shown in Figure 2-30, the weighting factors W of the summation
currents IM for the various fault conditions and the ratios to that given by the three-
phase symmetrical faults are shown in Table 2-1. On the right hand side is the com-
plementary multiple of rated current which W/√3 would ha ve to be , in order to give th e
summation current IM = 100 mA in the secondary circuit. If the current setting values
are multiplied with this factor, the actual pickup values result.
The table shows that 7UT612 is more sensitive to earth faults than to those without
earth path component. This increased sensitivity is due to the fact that the summation
transformer winding in the CT starpoint connection (IE, residual current, refer to Figure
2-30) has the largest number of turns, and thus, the weighting factor W = 3.
If the higher earth current sensitivity is not necessary, connection according to Figure
2-32 can be used. This is reasonable in earthed systems with particularly low zero se-
quence impedance where earth fault currents may be larger than those under two-
phase fault conditions. With this connection, the values given in Table 2-2 can be re-
calculated for the seven possible fault conditions in solidly earthed networks.
Table 2-1 Fault types and weighting factor for CT connection L1–L3–E
Fault type W W/√3I1 for IM = 100 mA
L1–L2–L3 (sym.)
L1–L2
L2–L3
L3–L1
L1–E
L2–E
L3–E
√3
2
1
1
5
3
4
1,00
1,15
0,58
0,58
2,89
1,73
2,31
1.00 · IN
0.87 · IN
1.73 · IN
1.73 · IN
0.35 · IN
0.58 · IN
0.43 · IN
IL1
IL3 IL2
IL3
IM
60°
90°
30°
2 · IL1
IM = 2 IL1 + IL3
= √3 · |I|
2.2 Differential Protection
557UT612 Manu al
C53000–G1176–C148–1
Figure 2-32 CT connection L1–L2–L3 with decreased earth fault sensitivity
Figure 2-33 Summation of the currents L1–L2–L3 in the summation transformer
Comparison with Table 2-1 shows that under earth fault conditions the weighting fac-
tor W is less than with the standard connection. Thus the thermal loading is reduced
to 36 %, i.e. (1.73/2.89)2.
The described connection possibilities are examples. Certain phase preferences
(especially in systems with non-earthed neutral) can be obtained by cyclic or acyclic
exchange of the phases. Further increase of the earth current can be performed by
introducing an auto-CT in the residual path, as a further possibility.
The type 4AM5120 is recommended for summation current transformer. These trans-
formers have different input windings which allow for summation of the currents with
th e ratio 2:1:3 as w ell as matching of different prim ary currents of the main CTs to an
certain extent. Figure 2-34 shows the winding arrangement.
Table 2-2 Fault types and weighting factor for CT connection L1–L2–L3
Fault type W W/√3I1 for IM = 100 mA
L1–L2–L3 (sym.)
L1–L2
L2–L3
L3–L1
L1–E
L2–E
L3–E
√3
1
2
1
2
1
3
1,00
0,58
1,15
0,58
1,15
0,58
1,73
1.00 · IN
1.73 · IN
0.87 · IN
1.73 · IN
0.87 · IN
1.73 · IN
0.58 · IN
IL2
L1
7UT612
IL1 SCT IM
IL3
1
2
3
L2L3
IL1
IL3 IL2 IM
60°
2 · IL1
IM = 2 IL1 + IL2 + 3 IL3
= √3 · |I|3 · IL3
IL2
2 Functions
56 7UT612 Manual
C53000–G1176–C148–1
The nominal input current of each summation CT must match the nominal secondary
current of the connected main CT set. The output current of the summation CT (= input
current of the 7UT612) amounts to IN = 0.1 A at nominal conditions, with correct
matching.
Figure 2-34 Winding arrangement of summation and matching transformers 4AM5120
Differential Current
Monitoring Whereas a high sensitivity of the differential protection is normally required for trans-
formers, reactors, and rotating machines in order to detect even small fault currents,
high fault currents are expected in case of faults on a busbar so that a higher pickup
threshold (above rated current) is conceded here. This allows for a continuous moni-
toring of the differential currents on a low level.
When, during normal load conditions, a differential current is detected in the order of
the load current of a feeder, this indicates a missing secondary current, i.e. a fault in
the secondary current leads (short-circuit or open-circuit). This condition is annunciat-
ed with time delay. The differential protection is blocked at the same time.
Feeder Current
Guard Another feature is provided for protection of busbars. This feeder current guard mon-
itors the currents of each feeder of the busbar. It provides an additional trip condition.
Trip command is allowed only when at least one of these currents exceeds a certain
(settable) threshold.
2.2.7 Setting the Function Parameters
General The differential protection can only operate if this function is set ',))3527 = (Q
DEOHG during configuration (refer to Subsection 2.1.1, address ). If it not used,
'LVDEOHG is configured; in this case the associated setting are not accessible.
Additionally, the type of protected object must be decided during configuration (ad-
dress 35272%-(&7, Subsection 2.1.1). Only those parameters are offered
which are reasonable for the selected type of protected object; all remaining are sup-
pressed.
4AM5120–3DA00–0AN2
IN = 1 A
4AM5120–4DA00–0AN2
IN = 5 A
3
AB90
NO
6
CD9
EF36
LM
24
JK
18
GH
500
YZ
1
A
B
12
NO
2
CD3
EF8
LM
6
JK
4
GH
500
YZ
2.2 Differential Protection
577UT612 Manu al
C53000–G1176–C148–1
The differential protection can be switched 21 or 2)) in address ',))3527;
the option %ORFNUHOD\ allows to op era ted the pr ot ect ion but t he t rip ou tput re lay i s
blocked.
Starpoint
Conditioning If there is a current transformer in the starpoint connection of an earthed transformer
winding, i. e. between starpoint and earth electrode, the starpoint current may be
taken into consideration for calculations of the differential protection (see also Subsec-
tion 2.2.2, margin heading “Increasing the Ground Fault Sensitivity”, page 45). Thus,
the earth fault sensitivity is increased.
In address es $ ',))Z,(0($6 for side 1 or $ ',))Z,(0($6 for
side 2 the user informs the device on whether the earth current of the earthed starpoint
is included or not. This parameter can only be changed with DIGSI® 4 under “Addi-
tional Settings”.
With setting <(6 the corresponding earth current will be considered by the differential
protection. This setting only applies for transformers with two separate windings. Its
use only makes sense if the corresponding starpoint current actually is connected to
the device (current input I7). When configuring the protection functions (see Subsec-
tion 2.1.1, page 16) address must have been set accordingly. In addition to that,
the starpoint of the corresponding side has to be earthed (Subsection 2.1.2 under mar-
gin heading “Object Data with Transformers”, page 20, addresses and/or ).
Differential Current
Monitoring With busbar protection differential current can be monitored (see Subsection 2.2.5 and
2.2.6). This function can be set to 21 and 2)) in address ,',))!021. Its
use only makes sense if one can distinguish clearly between operational error currents
caused by missing transformer currents and fault currents caused by a fault in the pro-
tected object.
The pickup value ,',))!021 (addr es s ) must be high enough to avoid a
pickup caused by a transformation error of the current transformers and by minimum
mismatching of different current transformers. The pickup value is referred to the rated
current of the protected object. Time delay 7,',))!021 (address ) applies
to the annunciation and blocking of the differential protection. This setting ensures that
blocking with the presence of faults (even of external ones) is avoided. The time delay
is usually about some seconds.
Feeder Current
Guard With busbars and short lines a release of the trip command can be set if one of the
incoming currents is exceeded. The differential protection only trips if one of the meas-
ured currents exceeds the threshold ,!&855*8$5' (address ). The pick up
value is referred to the rated current of the protected object. With setting (pre-setting)
this release criterion will not be used.
Note:
When delivered from factory, the differential protection is switched 2)). The reason
is that the protection must not be in operation unless at least the connection group (of
a transformer) and the matching factors have been set before. Without proper set-
tings, the device may show unexpected reactions (incl. tripping)!
2 Functions
58 7UT612 Manual
C53000–G1176–C148–1
If the feeder current guard is set (i. e. to a value of > 0), the differential protection will
not trip before the release criterion is given. This is also the case if, in conjunction with
very high differential currents, the extremely fast instantaneous value scheme (see
Subsection 2.2.1, margin heading “Fast Unstabilized Trip with High-Current Faults”)
has detected the fault already after a few milliseconds.
Trip Characteri stic
Differential Current The parameters of the trip characteristic are set in addresses to $. Figure
2-35 illustrates the meaning of the different settings. The numbers signify the address-
es of the settings.
,',))! (address ) is the pickup value of the differential current. This is the total
fault current into the pr otected object, regardless of the way this is distributed betwee n
the sides. The pickup value is referred to the rated current of the protected object. You
may select a high sensitivity (small pickup value) for transformers, reactors, genera-
tors, or motors, (presetting 0.2 · INObj). A higher value (above nominal current) should
be selected for lines and busbars. Higher measuring tolerances must be expected if
the nominal currents of the current transformers differ extensively from the nominal
current of the protected object.
In addition to the pickup limit ,',))!, the differential current is subjected to a second
pickup threshold. If this threshold ,',))!! (address ) is exceeded then trip-
ping is initiated regardless of the magnitude of the restraint current or the harmonic
content (unstabilized high-current trip). This stage must be set higher than ,',))!.
If the protected object has a high direct impedance (transformers, generators, series
reactors), a threshold can be found above which a through-fault current never can in-
crease. This threshold (primary) is, e.g. for a power transformer, .
Figure 2-35 Tripping characteristic of the differential protection
1
usc transf
----------------------------- I
1
t
UD
nsf
⋅
1 2 3 4 5 6 7 8 9 101112131415161718
1
2
3
4
5
6
7
8
9
10
,²',))!!
,²',))!
%$6(32,17
%$6(32,17
Tripping
IRest
INObj
-----------------
IDiff
INObj
---------------
Blocking
6/23(
6/23(
,²$''2167$%
Add-on stabilization
2.2 Differential Protection
597UT612 Manu al
C53000–G1176–C148–1
The tripping characteristic forms two more branches (Figure 2-35) The slope of the
first branch is determined by the address $ 6/23(, its base point by the ad-
dress $ %$6(32,17. This parameter can only be changed with DIGSI® 4
under “Additional Settings”. This branch covers current-proportional errors. These
are mainly errors of the main current transformers and, in case of power transformers
with tap changers, differential currents which occur due to the transformer regulating
range.
The percentage of this differential current is equal to the percentage of the regulating
range provided the rated voltage is corrected according to Subsection 2.1.2 under
margin “Object Data with Transformers” (page 20).
The second branch produces a higher stabilization in the range of high currents which
may lead to current transformer saturation. Its base point is set under address $
%$6(32,17 and is referred to the rated object current. The slope is set under ad-
dress $ 6/23(. The stability of the protection can be influenced by these set-
tings. A higher slope results in a higher stability. This parameter can only be changed
with DIGSI® 4 under “Additional Settings”.
Delay times In special cases it may be advantageous to delay the trip signal of the protection. For.
this, an additional delay can be set. The timer $ 7,',))! is started when an
internal fault is detected by the IDiff>–stage and the trip characteristic. $ 7,
',))!! is the delay for the IDiff>>–stage. This parameter can only be changed with
DIGSI® 4 under “Additional Settings”. These settings are pure delay times which do
not include the inherent operating time of the protection.
Increase of Pickup
Value on Startup The increase of the pickup value on startup serves as an additional safety against
overfunctioning when a non-energized protection object is switched in. This function
can be set to 21 or 2)) in address ,1&&+$567$57. Especially for motors or
motor/transformer in block connection it should be set to 21.
The restraint current value ,5(6767$5783 (addr ess $) is the value of the
restraining current which is likely to be undershot before startup of the protected object
takes place (i.e. in case of standstill). This parameter can only be changed with
DIGSI® 4 under “Additional Settings”. Please be aware of the fact that the restraint
current is twice the traversing operational current. The pre-set value of 0.1 represents
0.05 times the rated current of the protected object.
Address $ 67$57)$&725 determines by which factor the pickup value of the
IDiff>–stage is to be increased on startup. The characteristic of this stage increases by
the same value. The IDiff>>–stage is not affected. For motors or motor/transformer in
block connection, a value of 2 is normally adequate. This parameter can only be
changed with DIGSI® 4 under “Additional Settings”.
The increase of the pickup value is set back to its original value after time period 7
67$570$; (address ) has passed .
Add-on
Stabilization In systems with very high traversing currents a dynamic add-on stabilization is being
enabled for external faults (Figure 2-35). The initial value is set in address $ ,
$''2167$%. The value is referred to the rated current of the protected object. The
slope is the same as for characteristic branch b (6/23(, address $). This pa-
rameter can only be changed with DIGSI® 4 under “Additional Settings”. Please be
aware of the fact that the restraint current is the arithmetical sum of the currents flow-
ing into the protected object, i. e. it is twice the traversing current.
2 Functions
60 7UT612 Manual
C53000–G1176–C148–1
The maximum duration of the add-on stabilization after detection of an external fault
is set to multiples of an AC-cycle (address $ 7$''2167$%). This parameter
can only be changed with DIGSI® 4 under “Additional Settings”. The add-on stabili-
zation is disabled automatically even before the set time period expires as soon as the
device has detected that the operation point IDiff/IRest is located steadily (i. e. via at
least one cycle) within the tripping zone.
Harmonic Restraint Stabilization with harmonic content is available only when the device is used as trans-
former protection, i.e. 35272%-(&7 (address ) is set to SKDVHWUDQVI or
$XWRWUDQVI or SKDVHWUDQVI. It is used also for shunt reactors if current
transformers are installed at both sides of the connection points of the reactor (cf. ex-
ample in Figure 2-25, right graph).
The inrush restraint function can be switched 2)) or 21 under address ,1586+
+$50. It is based on the evaluation of the 2nd harmonic content of the inrush cur-
rent. The ratio of the 2nd harmonic to the fundamental frequency +$5021,& (ad-
dress ) is preset to I2fN/IfN = % and can, as a rule, be retained without change.
This ratio can be decreased in order to provide for a more stable setting in exceptional
cases under especially unfavourable switch-on conditions
The inrush restraint can be extended by the “Crossblock” function. This means that
not only the phase with inrush current exhibiting harmonic content in excess of the per-
missible value is stabilized but also the other phases of the differential stage IDiff> are
blocked. The duration for which the crossblock function is active can be limited under
address $ &5266%+$50. Setting is in multiple of the AC-cycle. This pa-
rameter can only be changed with DIGSI® 4 under “Additional Settings”. If set to
(presetting) the protection can trip when the transformer is switched on a single-phase
fault even while the other phases carry inrush current. If set to ∞ the crossblock func-
tion remains active as long as harmonic content is registered in any phase.
Besides the 2nd harmonic, 7UT612 provides stabilization with a further harmonic: the
n-th harmonic. Address 5(675Q+$50 allows to select the +DUPRQLF
or the +DUPRQLF, or to switch this n-th harmonic restraint 2)).
Steady-state overexcitation of transformers is characterized by odd harmonic content.
The 3rd or 5th harmonic is suitable to detect overexcitation. As the 3rd harmonic is of-
ten eliminated in the transformer windings (e.g. in a delta connected winding group),
the 5th harmonic is usually used.
Converter transformers also produce odd harmonic content.
The harmonic content which blocks the differential stage IDiff> is set under address
Q+$5021,&. For example, if the 5th harmonic restraint is used to avoid trip
during overexcitation, 30 % (presetting) is convenient.
Harmonic restraint with the n-th harmonic operates individual per phase. But possibil-
ity exists — as with the inrush restraint — to set the protection such that not only the
phase with harmonic content in excess of the permissible value is stabilized but also
the other phases of the differential stage IDiff> are blocked (crossblock function). The
duration for which the crossblock function is active can be limited under address
$ &5266%Q+$50. Setting is in multiple of the AC-cycle. This parameter can
only be changed with DIGSI® 4 under “Additional Settings”. If set to (presetting)
the crossblock function is ineffective, if set to ∞ the crossblock function remains active
as long as harmonic content is registered in any phase.
2.2 Differential Protection
617UT612 Manu al
C53000–G1176–C148–1
If the differential current exceeds the magnitude set in address $ ,',))PD[
Q+0 no n-th harmonic restraint takes place. This parameter can only be changed with
DIGSI® 4 under “Additional Settings”.
2.2.8 Setting Overview
Note:
Addresses which have an “A” attached to its end can only be changed in
DIGSI®4, under “Additional Settings”.
Addr. Setting Title Setting Options Default Setting Comments
1201 DIFF. PROT. OFF
ON
Block relay for trip com-
mands
OFF Differential Protection
1205 INC.CHAR.START OFF
ON OFF Increase of Trip Char. During Start
1206 INRUSH 2.HARM. OFF
ON ON Inrush with 2. Harmonic Restraint
1207 RESTR. n.HARM. OFF
3. Harmonic
5. Harmonic
OFF n-th Harmonic Restraint
1208 I-DIFF> MO N. O FF
ON ON Differential Current monitoring
1210 I> CURR. GUARD 0.20..2.00 I/InO; 0 0.00 I/InO I> for Current Guard
1211A DIFFw.IE1-MEAS NO
YES NO Diff-Prot. with meas. Earth Current
S1
1212A DIFFw.IE2-MEAS NO
YES NO Diff-Prot. with meas. Earth Current
S2
1221 I-DIFF> 0.05..2.00 I/InO 0.20 I/InO Pickup Value of Differential Curr.
1226A T I-DIFF> 0.00..60.00 sec; ∞ 0 .00 se c T I-DIFF> Time Delay
1231 I-DIFF>> 0.5..35.0 I/InO; ∞ 7.5 I/InO Pickup Value of High Set Trip
1236A T I-DIFF>> 0.00..60.00 se c; ∞ 0.00 sec T I-DIFF>> Time Delay
1241A SLOPE 1 0.10..0.50 0.25 Slope 1 of Tripping Characteristic
1242A BASE POINT 1 0.00..2.00 I/InO 0.00 I/InO Base Point for Slope 1 of Charac.
1243A SLOPE 2 0.25..0.95 0.50 Slope 2 of Tripping Characteristic
1244A BASE POINT 2 0.00..10.00 I/InO 2.50 I/InO Base Point for Slope 2 of Charac.
1251A I-REST. STARTUP 0.00..2.00 I/InO 0.10 I/InO I-RESTRAINT for Start Detection
1252A START-FACTOR 1.0..2.0 1.0 Factor for Increasing of Char. at
Start
2 Functions
62 7UT612 Manual
C53000–G1176–C148–1
2.2.9 Information Overview
1253 T START MAX 0.0..180.0 sec 5.0 sec Maximum Permissible Starting
Time
1256A I-ADD ON STAB. 2.00..15.00 I/InO 4.00 I/InO Pickup for Add-on Stabilization
1257A T ADD ON-STAB. 2..250 Cycle; ∞ 15 Cycle Duration of Add-on Stabilization
1261 2. HARMONIC 10..80 % 15 % 2nd Harmonic Conten t in I-DIFF
1262A CROSSB. 2. HARM 2..1000 Cyc le; 0; ∞ 3 Cycle Time for Cross-blocking 2nd Harm.
1271 n. HARMONIC 10..80 % 30 % n-th Harmonic Content in I-D IFF
1272A CROSSB. n.HARM 2..1000 Cyc le; 0; ∞ 0 Cycle Time for Cross-blocking n-th Harm.
1273A IDIFFmax n.HM 0.5..20.0 I/InO 1.5 I/InO Limit IDIFFmax of n-th Harm.Res-
traint
1281 I-DIFF> MON. 0.15..0.80 I/InO 0.20 I/InO Pickup Value of diff. Current Moni-
toring
1282 T I-DIFF> MON. 1..10 sec 2 sec T I-DIFF> Monitoring Time Delay
Addr. Setting Title Setting Options Default Setting Comments
F.No. Alarm Comments
05603 >Diff BLOCK >BLOCK differential protection
05615 Diff OFF Differential protection is switched OFF
05616 Diff BLOCKED Differential protection is BLOCKED
05617 Diff ACTIVE Differential protection is ACTIVE
05620 Diff Adap.fact. Diff: adverse Adaption factor CT
05631 Diff picked up Differential protection picked up
05644 Diff 2.Harm L1 Diff: Blocked by 2.Harmon. L1
05645 Diff 2.Harm L2 Diff: Blocked by 2.Harmon. L2
05646 Diff 2.Harm L3 Diff: Blocked by 2.Harmon. L3
05647 Diff n.Harm L1 Diff: Blocked by n.Harmon. L1
05648 Diff n.Harm L2 Diff: Blocked by n.Harmon. L2
05649 Diff n.Harm L3 Diff: Blocked by n.Harmon. L3
05651 Diff Bl. exF.L1 Diff. prot.: Blocked by ext. fault L1
05652 Diff Bl. exF.L2 Diff. prot.: Blocked by ext. fault L2
05653 Diff Bl. exF.L3 Diff. prot.: Blocked by ext. fault.L3
05657 DiffCrosBlk2HM Diff: Crossblock by 2.Harmonic
2.2 Differential Protection
637UT612 Manu al
C53000–G1176–C148–1
05658 DiffCrosBlknHM Diff: Crossblock by n.Harmonic
05662 Block Iflt.L1 Diff. prot.: Blocked by CT fault L1
05663 Block Iflt.L2 Diff. prot.: Blocked by CT fault L2
05664 Block Iflt.L3 Diff. prot.: Blocked by CT fault L3
05666 Diff in.char.L1 Diff: Increase of char. phase L1
05667 Diff in.char.L2 Diff: Increase of char. phase L2
05668 Diff in.char.L3 Diff: Increase of char. phase L3
05670 Diff I-Release Diff: Curr-Release for Trip
05671 Diff TRIP Differential protection TRIP
05672 Diff TRIP L1 Differential protection: TRIP L1
05673 Diff TRIP L2 Differential protection: TRIP L2
05674 Diff TRIP L3 Differential protection: TRIP L3
05681 Diff> L1 Diff. prot.: IDIFF> L1 (without Tdelay)
05682 Diff> L2 Diff. prot.: IDIFF> L2 (without Tdelay)
05683 Diff> L3 Diff. prot.: IDIFF> L3 (without Tdelay)
05684 Diff>> L1 Diff. prot: IDIFF>> L1 (without Tdelay)
05685 Diff>> L2 Diff. prot: IDIFF>> L2 (without Tdelay)
05686 Diff>> L3 Diff. prot: IDIFF>> L3 (without Tdelay)
05691 Diff> TRIP Differential prot.: TRIP by IDIFF>
05692 Diff>> TRIP Differential prot.: TRIP by IDIFF>>
05701 Dif L1 : Diff. curr. in L1 at trip without Tdelay
05702 Dif L2 : Diff. curr. in L2 at trip without Tdelay
05703 Dif L3 : Diff. curr. in L3 at trip without Tdelay
05704 Res L1 : Restr.curr. in L1 at trip without Tdelay
05705 Res L2 : Restr.curr. in L2 at trip without Tdelay
05706 Res L3 : Restr.curr. in L3 at trip without Tdelay
F.No. Alarm Comments
2 Functions
64 7UT612 Manual
C53000–G1176–C148–1
2.3 R estricted Earth Fault Protection
The restricted earth fault protection detects earth faults in power transformers, shunt
reactors, neutral grounding transformers/reactors, or rotating machines, the starpoint
of which is led to earth. It is also suitable when a starpoint former is installed within a
protected zone of a non-earthed power transformer. A precondition is that a current
transformer is installed in the starpoint connection, i.e. between the starpoint and
earth. The starpoint CT and the three phase CTs define the limits of the protected zone
exactly.
Examples are illustrated in the Figures 2-36 to 2-40.
Figure 2-36 Restricted earth fault protection on an earthed transformer winding
Figure 2-37 Restricted earth fault protection on a non-earthed transformer winding with
neutral reactor (starpoint former) within the protected zone
ISP 7UT612
IL1
IL2
IL3
L1
L2
L3
3I0" = IL1 + IL2 + IL3
3I0’ = ISP
L1
L2
L3
L1
L2
L3
L1
L2
L3
7UT612
IL1
IL2
IL3
3I0" = IL1 + IL2 + IL3
3I0’ = ISP
ISP
2.3 Restricted Earth Fault Protection
657UT612 Manu al
C53000–G1176–C148–1
Figure 2-38 Restricted earth fault protection on an earthed shunt reactor with CTs in the
reactor leads
Figure 2-39 Restricted earth fault protection on an earthed shunt reactor with 2 CT sets
(treated like an auto-trans former)
L1
L2
L3
L1
L2
L3
7UT612
3I0" = IL1 + IL2 + IL3
3I0’ = ISP
ISP
L1
L2
L3
L1
L2
L3
7UT612
IL1
IL2
IL3
3I0’ = ISP
ISP
IL1
IL2
IL3
IL1 + IL2 + IL3
Side 1
IL1 + IL2 + IL3
Side 2
2 Functions
66 7UT612 Manual
C53000–G1176–C148–1
Figure 2-40 Restricted earth fault protection on an earthed auto-transformer
2.3.1 Function Description
Basic Principle During healthy operation, no starpoint current ISP flows through the starpoint lead, the
sum of the phase currents 3I0 = IL1 + IL2 + IL3 is zero, too.
When an earth fault occurs in the protected zone (Figure 2-41), a starpoint current ISP
will flow; depending on the earthing conditions of the power system a further earth cur-
rent may be recognized in the residual current path of the phase current transformers.
Since all currents which flow into the protected zone are defined positive, the residual
current from the system will be more or less in phase with the starpoint current.
Figure 2-4 1 Exampl e for an eart h fault in a transformer with current distribution
When an earth fault occurs outside the protected zone (Figure 2-42), a starpoint cur-
rent ISP will flow equally; but the residual current of the phase current transformers 3I0
is now of equal magnitu de and in phas e opp osi ti on with the sta rpoi nt curr ent.
L1
L2
L3
L1
L2
L3
7UT612
IL1
IL2
IL3
3I0’ = ISP
ISP
IL1
IL2
IL3
IL1 + IL2 + IL3
Side 1
IL1 + IL2 + IL3
Side 2
L1
L2
L3
L1
L2
L3
ISP
IL3
2.3 Restricted Earth Fault Protection
677UT612 Manu al
C53000–G1176–C148–1
Figure 2-42 Example for an earth fault outside a transformer with current distribution
When a fault without earth connection occurs outside the protected zone, a residual
current may occur in the residual current path of the phase current transformers which
is caused by different saturation of the phase current transformers under strong
through-current conditions. This current could simulate a fault in the protected zone.
Wrong tripping must be avoided under such condition. For this, the restricted earth
fault protection provides stabilization methods which differ strongly from the usual sta-
bilization methods of differential protection schemes since it uses, besides the magni-
tude of the measured currents, the phase relationship, too.
Evaluation of the
Measured
Quantities
The restricted earth fault protection compares the fundamental wave of the current
flowing in the starpoint connection, which is designated as 3I0’ in the following, with
the fundamental wave of the sum of the phase currents, which should be designated
in the following as 3I0". Thus, the following applies (Figure 2-43):
3I0' = ISP
3I0" = IL1 + IL2 + IL3
Only 3I0' acts as the tripping effect quantity, during a fault within the protected zone
this current is always present.
Figure 2-43 Principle of restricted earth fault protection
When an earth fault occurs outside the protected zone, another earth current 3I0"
flows though the phase current transformers. This is, on the primary side, in counter-
phase with the starpoint 3I0' current and has equal magnitude. The maximum informa-
L1
L2
L3
L1
L2
L3
ISP
–IL3
ISP 7UT612
IL1
IL2
IL3
3I0" = IL1 + IL2 + IL3
3I0’ = ISP
L1
L2
L3
2 Functions
68 7UT612 Manual
C53000–G1176–C148–1
tion of the currents is evaluated for stabilization: the magnitude of the currents and
their phase position. The following is defined:
A tripping effect current
IREF = |3I0’|
and the stabilization or restraining current
IRest = k · (|3I0' – 3 I0"| – |3I0' + 3I0"|)
where k is a stabilization factor which will be explained below, at first we assume k = 1.
IREF is derived from the fundamental wave and produces the tripping effect quantity,
IRest counteracts this effect.
To clarify the situation, three important operating conditions should be examined:
a) Through-fault current on an external earth fault:
3I0" is in phase opposition with 3I0' and of equal magnitude i.e. 3I0" = –3I0'
IREF = |3I0'|
IRest = |3I0' + 3I0"| – |3I0' – 3I0"| = 2·|3I0'|
The tripping effect current (IREF) equals the starpoint current; restraint (IRest)
corresponds to twice the tripping effect current.
b) Internal earth fault, fed only from the starpoint:
In this case, 3I0" = 0
IREF = |3I0'|
IRest = |3I0' – 0| – |3I0' + 0| = 0
The tripping effect current (IREF) equals the starpoint current; restraint (IRest) is
zero, i.e. full sensitivity during internal earth fault.
c) Internal earth fault, fed from the starpoint and from the system, e.g. with equal earth
current mag nit ude :
In this case, 3I0" = 3I0'
IREF = |3I0'|
IRest = |3I0' – 3I0'| – |3I0' + 3I0'| = –2 · |3I0'|
The tripping effect current (IREF) equals the starpoint current; the restraining
quantity (IRest) is negative and, therefore, set to zero, i.e. full sensitivity during
internal earth fault.
This result shows that for internal fault no stabilization is effective since the restraint
quantity is either zero or negative. Thus, small earth current can cause tripping. In con-
trast, strong restraint becomes effective for external earth faults. Figure 2-44 shows
that the restraint is the strongest when the residual current from the phase current
transformers is high (area with negative 3I0"/3I0'). With ideal current transformers,
3I0"/3I0' would be –1.
If the starpoint current transformer is designed weaker than the phase current trans-
formers (e.g. by selection of a smaller accuracy limit factor or by higher secondary bur-
den), no trip will be possible under through-fault condition even in case of severe sat-
uration as the mag nit ude of 3I0" is always higher than that of 3I0'.
2.3 Restricted Earth Fault Protection
697UT612 Manu al
C53000–G1176–C148–1
Figure 2- 44 Tripping characterist ic of the restricted ear th fault protect ion de pending on the
earth current ratio 3I0"/3I0' (both currents in phase + or counter-phase –);
IREF = tripping effect current; IREF> = setting value
It was assumed in the above examples that the currents 3I0" and 3I0’ are in counter-
phase for external earth faults which is only true for the primary measured quantities.
Current trans form er saturati on may cause phas e sh ifti ng betw een the fund ame ntal
waves of the secondary currents which reduces the restraint quantity. If the phase dis-
placement ϕ(3I0"; 3I0') = 90° then the restraint quantity is zero. This corresponds to
the conventional method of direction determination by use of the vectorial sum and dif-
ference comparison (Figure 2-45).
Figure 2-45 Phasor diagram of the restraint quantity during external fault
-0.3 -0.2 -0.1 0.0 0.1 0.2 0.3
4
3
2
1
IREF
IREF>
3Io"
3Io’
Tripping
Blocking
+3I0"
–3I0"
3I0' + 3I0"
3I0' – 3I0"
3I0'IRest for k = 1
2 Functions
70 7UT612 Manual
C53000–G1176–C148–1
The restraint quantity can be influenced by means of a factor k. This factor has a cer-
tain relationship to the limit angle ϕlimit. This limit angle determines, for which phase
displacement between 3I0" and 3I0’ the pickup value grows to infinity when 3I0" = 3I0’,
i.e. no pickup occurs. In 7UT612 is k = 2, i.e. the restraint quantity in the above ex-
ample a) is redoubled once more: the restraint quantity IRest is 4 times the tripping ef-
fect quantity IREF. The limit angle is ϕlimit = 110°. That means no trip is possible for
phase displacement ϕ(3I0"; 3I0') ≥ 110°.
Figure 2-46 shows the operating characteristics of the restricted earth fault protection
dependent of the phase displacement between 3I0" and 3I0', for a constant infeed ratio
|3I0"| = |3I0'|.
Figure 2-46 Tripping characteristic of the restricted earth fault protection depending on the
phase displacement between 3I0" and 3I0’ at 3I0" = 3I0' (180° = external fault)
It is possible to increase the tripping value in the tripping area proportional to the arith-
metic sum of all currents, i.e. with the sum of the magnitudes Σ|I| = |IL1| + |IL2| + |IL3|
+ |ISP| (Figure 2-47). The slope of this stabilization can be set.
Figure 2-47 Increasing the pickup value
120° 110° 100° 90° 80° 70°
4
3
2
1
IREF
IREF>
Tripping
Blocking
ϕ(3Io";3Io')
Σ|I|
I
5()
6/23(
2.3 Restricted Earth Fault Protection
717UT612 Manu al
C53000–G1176–C148–1
Figure 2- 48 Logic d iagram of the restricted earth fault protection
2.3.2 Setting th e Function Parameters
The restricted earth fault protection can only operate if this function is assigned during
configuration (refer to Subsection 2.1.1, address ) 5()3527 to one of the s ides
of the protected object. Additionally, the measured current input I7 must be assigned
to the same side (address ). The restricted earth fault protection can be set effec-
tive (21) or ineffective (2))) in address 5()3527. When set to %ORFNUH
OD\, the protection function operates but no trip command is issued.
The sensitivity of the restricted earth fault protection is determined by the pickup value
,5()! (address ). The earth fault current which flows through the starpoint lead
of the protected object (transformer, generator, motor, shunt reactor) is decisive. A fur-
ther earth current which may be supplied from the network does not influence the sen-
sitivity. The setting value is referred to the nominal current of the protected side.
The set value can be increased in the tripping quadrant depending on the arithmetic
sum of the currents (stabilization by the sum of all current magnitudes) which is set
under address $ 6/23(. This parameter can only be changed with DIGSI® 4 un-
der “Additional Settings”. The preset value is normally adequate.
In special cases it may be advantageous to delay the trip signal of the protection. For.
this, an additional delay can be set. The timer $ 7,5()! is started when an
internal fault is detected. This setting is a pure delay time which does not include the
inherent operating time of the protection.
7,²('6!
T0
REF BLOCKED
REF OFF
REF TRIP
>BLOCK REF
Meas. release
,5()!
I
7
REF ACTIVE
|3I0'| > k·(|3I0'–3I0"| – |3I0'+3I0"|)
|IL1| + |IL2| + |IL3| + |ISt|
I
L1
I
L1
I
L1
REF T start
FNo 05817
REF picked up
&
6/23(
21
%ORFNUHOD\
≥
1&
5()3527
”1”
2))
&
FNo 05816
FNo 05821
FNo 05812
FNo 05813
FNo 05811
FNo 05803
Note:
When delivered from factory, the restricted earth fault protection is switched 2)). The
reason is that the protection must not be in operation unless at least the assigned side
and the CT polarity have been set before. Without proper settings, the device may
show unexpected reactions (incl. tripping)!
2 Functions
72 7UT612 Manual
C53000–G1176–C148–1
2.3.3 Setting Overview
Note:
Addresses which have an “A” attached to its end can only be changed in
DIGSI®4, under “Additional Settings”.
2.3.4 Information Overview
Addr. Set ting Title Setting Options Default Setting Comments
1301 REF PROT. OFF
ON
Block relay for trip commands
OFF Restricted Earth Fault Protection
1311 I-REF> 0.05..2.00 I / In 0.15 I / In Pick up value I REF>
1312A T I-REF> 0.00..60.00 sec; ∞ 0.00 sec T I-REF> Time Delay
1313A SLOPE 0.00..0.95 0.00 Slope of Charac. I-REF> = f(I-SUM)
F.No. Alarm Comments
05803 >BLOCK REF >BLOCK restricted earth fault prot.
05811 REF OFF Restricted earth fault is switched OFF
05812 REF BLOCKED Restricted earth fault is BLOCKED
05813 REF ACTIVE Restricted earth fault is ACTIVE
05836 REF Adap.fact. REF: adverse Adaption factor CT
05817 REF picked up Restr. earth flt.: picked up
05816 REF T start Restr. earth flt.: Time delay started
05821 REF TRIP Restr. earth flt.: TRIP
05826 REF D: REF: Value D at trip (without Tdelay)
05827 REF S: REF: Value S at trip (without Tdelay)
05830 REF Err CTstar REF err.: No starpoint CT
05835 REF Not avalia. REF err: Not avaliable for this objekt
2.4 Time Overcurrent Protection for Phase and Residual Currents
737UT612 Manu al
C53000–G1176–C148–1
2.4 Time Overcurrent Protection for Phase and Residual Currents
General The time overcurrent protection is used as backup protection for the short-circuit pro-
tection of the protected object and provides backup protection for external faults which
are not promptly disconnected and thus may endanger the protected object.
Information on the connection and viewpoints for the assignment to the sides of the
protected object are given in Subsection 2.1.1 under “Special Cases” (page 15). The
assigned side and the type of characteristics have been decided under addresses
to .
The time overcurrent protection for phase currents takes its currents from the side to
which it is assigned. The time overcurrent protection for residual current always uses
the sum of the current of that side to which it is assigned. The side for the phase cur-
rents may be different from that of the residual current.
If the protected object is 35272%-(&7 = SK%XVEDU (address , see Subsec-
tion 2.1.1), the time overcurrent protection is ineffective.
The time overcurrent protection provides two definite time stages and one inverse time
stage for each the phase currents and the residual current. The inverse time stages
may operate according an IEC or an ANSI, or an user defined characteristic.
2.4.1 Function Description
2.4.1.1 Definite Time Overcurrent Protection
The definite time stages for phase currents and residual current are always available
even if an inverse time characteristic has been configured according to Subsection
2.1.1 (addresses and/or ).
Pickup, Trip Two definite time stages are available for each the phase currents and the residual
current (3·I0).
Each phase current and the residual current 3·I0 are compared with the setting value
,!! (common setting for the three phase currents) and ,!! (independent setting
for 3·I0). Currents above the associated pickup value are detected and annunciated.
When the respective delay time 7,!! or 7,!! is expired, tripping command is
issued. The reset value is approximately 5 % below the pickup value for currents
>0.3·I
N
.
Figure 2-49 shows the logic diagram for the high-current stages I>> and 3I0>>.
2 Functions
74 7UT612 Manual
C53000–G1176–C148–1
Figure 2-49 Logic diagram of the high-set stages I>> for phase currents and residual current
„1“
Man. Close &
T0
L1L2
L3
I>> picked up
I>> Time Out
21
2))
„1“
>BLOCK I>>
>BLK Phase O/C O/C Phase BLK
≥1
O/C Phase OFF
I>> BLOCKED
FNo 1800
FNo 1804
FNo 185 2
FNo 1752
FNo 1751
FNo 1704
Release meas.
FNo 172 1
(s. Fig. 2-54)
,!!
I
L1
I
L2
I
L3
&
&
≥
1
≥
1
≥
1
≥
1
O/C Phase ACT
FNo 1753
FNo 1762 ... 1764
O/C Ph L3 PU
O/C Ph L2 PU
O/C Ph L1 PU
FNo 1805
I>> TRIP
„1“
Man. Close &
3I0>> Time Out
21
2))
„1“
>BLOCK 3I0>>
>BLK 3I0 O/C O/C 3I0 BLK
≥1
O/C 3I0 OFF
3I0> BLOCKED
FNo 190 1
FNo 190 2
FNo 185 7
FNo 174 9
FNo 174 8
FNo 1741
Release meas.
FNo 174 2
(s. Fig. 2-54)
,!!
3
I
0
FNo 176 6
&
&3I0>> TRIP
FNo 190 3
≥
1
O/C 3I0 ACTIVE
FNo 175 0
3I0>> picked up
O/C 3I0 PU
I>>
I>>
T0
Relea se me as.
Relea se me as.
,QDFWLYH
,!!LQVWDQW
,SLQVWDQW
,!LQVWDQW
,QDFWLYH
,!!LQVWDQW
,SLQVWDQW
,!LQVWDQW
0$18$/&/26(
,0$1&/26(
3+$6(2&
,2&
,!!
7,!!
7,!!
2.4 Time Overcurrent Protection for Phase and Residual Currents
757UT612 Manu al
C53000–G1176–C148–1
Each phase current and the residual current 3·I0 are, additionally, compared with the
setting val ue ,! (common setting for the three phase currents) and ,! (independ-
ent setting for 3·I0). When the set thresholds are exceeded, pickup is annunciated.
But if inrush restraint is used (cf. Subsection 2.4.1.5), a frequency analysis is per-
formed first (Subsection 2.4.1.5). If an inrush condition is detected, pickup annuncia-
tion is suppressed and an inrush message is output instead. When, after pickup with-
out inrush recognition, the relevant delay times 7,! or 7,! are ex pire d, tri ppi ng
command is issued. During inrush condition no trip is possible but expiry of the timer
is annunciated. The reset value is approximately 5 % below the pickup value for cur-
rents > 0,3·IN.
Figure 2-50 shows the logic diagram of the stages I> for phase currents, Figure 2-51
for residual current.
The pick up v alu es f or e ach of the stag es, I> (phase currents), 3I0> (residu al curren t),
I>> (phase currents), 3I0>> (residual current) and the delay times can be set individ-
ually.
Figure 2-50 Logic di agram of the overcurrent stages I> for phase currents
„1“
Man. Close &
L1L2
L3
I> picked up
I> Time Out
21
2))
„1“
>BLOCK I>
>BLK Phase O/C O/C Phase BLK
≥1
O/C Phase OFF
I> BLOCKED
I> InRush PU
FNo 1810
FNo 7551
FNo 1814
FNo 185 1
FNo 1752
FNo 1751
FNo 1704
Meas. release
FNo 1722
(s. Fig. 2-54)
I>
,!
I
L1
I
L2
I
L3
&
&
Rush Blk L1
(s. Fi g. 2-56)
≥
1
≥
1
≥
1
≥
1
≥
1
O/C Phase ACT
FNo 1753
FNo 7565 ... 7567
L3 InRush PU
L2 InRush PU
L1 InRush PU
FNo 1762 ... 1764
O/C Ph L3 PU
O/C Ph L2 PU
O/C Ph L1 PU
FNo 1815
I> TR IP
&
&
T0
&
≥
1
Meas. release
Meas. release
,QDFWLYH
,!!LQVWDQW
,SLQVWDQW
,!LQVWDQW
0$18$/&/26(
3+$6(2&
7,!
2 Functions
76 7UT612 Manual
C53000–G1176–C148–1
Figure 2-51 Logic diagram of the overcurrent stage 3I0> for residual current
2.4.1.2 Inverse Time Overcurrent Protection
The inverse time overcurrent stages operate with a characteristic either according to
the IEC- or the ANSI-standard or with a user-defined characteristic. The characteristic
curves and their equations are represented in Technical Data (Figures 4-7 to 4-9 in
Section 4.4). When configuring one of the inverse time characteristics, definite time
stages I>> and I> are also enabled (see Section 2.4.1.1).
Pickup, Trip Each phase current and the residual current (sum of phase currents) are compared,
one by one, to a common setting value ,S and a separate setting ,S. If a current
exceeds 1.1 times the setting value, the corresponding stage picks up and is signalled
selectively. But if inrush restraint is used (cf. Subsection 2.4.1.5), a frequency analysis
is performed first (Subsection 2.4.1.5). If an inrush condition is detected, pickup an-
nunciation is suppressed and an inrush message is output instead. The RMS values
of the basic oscillations are used for pickup. During the pickup of an Ip stage, the trip-
ping time is calculated from the flowing fault current by means of an integrating meas-
uring procedure, depending on the selected tripping characteristic. After the expiration
of this period, a trip command is transmitted as long as no inrush current is detected
or inrush restraint is disabled. If inrush restraint is enabled and inrush current is de-
„1“
Man. Close &
3I0> Time Out
21
2))
„1“
>BLOCK 3I0>
>BLK 3I0 O/C O/C 3I0 BLK
≥1
O/C 3I0 OFF
3I0> BLOCKED
FNo 190 4
FNo 190 5
FNo 185 7
FNo 174 9
FNo 174 8
FNo 1741
Meas. release
FNo 174 3
(s. Fig 2-54)
I>
,!
3
I
0
&
&
Rush Blk 3I0
FNo 176 6
3I0> TRIP
FNo 190 6
≥
1
O/C 3I0 ACTIVE
FNo 175 0
FNo 756 8
3I0 InRush PU
3I0> picked up
O/C 3I0 PU
FNo 756 9
3I0> InRush PU
&
&&
T0
,QDFWLYH
,!!LQVWDQW
,SLQVWDQW
,!LQVWDQW
,0$1&/26(
,2&
7,!
2.4 Time Overcurrent Protection for Phase and Residual Currents
777UT612 Manu al
C53000–G1176–C148–1
tected, there will be no tripping. Nevertheless, an annunciation is generated indicating
that the time has expired.
For the residual current ,S the characteristic can be selected independent from the
characteristic used for the phase currents.
The pickup values for the stages Ip (phase currents), 3I0p (residual current) and the
delay times for each of these stages can be set individually.
Figure 2-52 shows the logic diagram of the inverse time stages for phase currents,
Figure 2-53 for residual current.
Dropout for IEC
Curves Dropout of a stage using an IEC curves occurs when the respective current decreases
below about 95 % of the pickup value. A renewed pickup will cause a renewed start of
the delay timers.
Dropout for ANSI
Curves Using the ANSI-characteristics you can determine whether the dropout of a stage is
to follow right after the threshold undershot or whether it is evoked by disk emulation.
“Right after” means that the pickup drops out when the pickup value of approx. 95 %
is undershot. For a new pickup the time counter starts at zero.
Figure 2-52 Logic diagram of the inverse time overcurrent stages Ip for phase currents — example for IEC–curves
„1“
Man. Close &
L1
L2L3
Ip picked up
Ip Time Out
21
2))
„1“
>BLOCK Ip
>BLK Phase O/C O/C Phase BLK
≥1
O/C Phase OFF
Ip BLOCKED
Ip InR u sh PU
FNo 1820
FNo 7553
FNo 1824
FNo 185 5
FNo 1752
FNo 1751
FNo 1704
Meas. release
FNo 172 3
(s. Fig. 2-54)
1,1 Ip
,S
I
L1
I
L2
I
L3
&
&
Rush Blk L1
(s. Fi g. 2-56)
≥
1
≥
1
≥
1
≥
1
≥
1
O/C Phase ACT
FNo 1753
FNo 7565 ... 7567
L3 InRush PU
L2 InRush PU
L1 InRush PU
FNo 1762 ... 1764
O/C Ph L3 PU
O/C Ph L2 PU
O/C Ph L1 PU
FNo 1825
Ip TR IP
&
&
≥
1
t
I
&
Meas. release
Meas. release
,QDFWLYH
,!!LQVWDQW
,SLQVWDQW
,!LQVWDQW
0$18$/&/26(
3+$6(2&
7,S
,(&&859(
2 Functions
78 7UT612 Manual
C53000–G1176–C148–1
Figure 2-53 Logic diagram of the inverse time overcurrent stage for residual current — example for IEC–curves
The disk emulation evokes a dropout process (time counter is decrementing) which
begins after de-energization. This process corresponds to the back turn of a Ferraris-
disk (explaining its denomination “disk emulation”). In case several faults occur suc-
cessively, it is ensured that due to the inertia of the Ferraris-disk the “history” is taken
into consideration and the time behaviour is adapted. The reset begins as soon as
90 % of the setting value is undershot, in correspondence to the dropout curve of the
selected characteristic. Within the range of the dropout value (95 % of the pickup val-
ue) and 90 % of the setting value, the incrementing and the decrementing processes
are in idle state. If 5 % of the setting value is undershot, the dropout process is being
finished, i.e. when a new pickup is evoked, the timer starts again at zero.
The disk emulation offers its advantages when the grading coordination chart of the
time overcurrent protection is combined with other devices (on electro-mechanical or
induction base) connected to the system.
User-Specified
Curves The tripping characteristic of the user-configurable curves can be defined via several
points. Up to 20 pairs of current and time values can be entered. With these values
the device approximates a characteristic by linear interpolation.
If required, the dropout characteristic can also be defined. For the functional descrip-
tion see “Dropout for ANSI Curves”. If no user-configurable dropout characteristic is
desired, dropout is initiated when approx. a 95 % of the pickup value is undershot;
when a new pickup is evoked, the timer starts again at zero.
„1“
Man. Close &
3I0p TimeOut
21
2))
„1“
>BLOCK 3I0p
>BLK 3I0 O/C O/C 3I0 BLK
≥1
O/C 3I0 OFF
3I0p BLOCKED
FNo 190 7
FNo 190 8
FNo 185 9
FNo 174 9
FNo 174 8
FNo 1741
Meas. release
FNo 174 4
(s. Fig. 2-54)
1,1I>
,S
3
I
0
&
&
Rush Blk 3I0
FNo 176 6
3I0p TRIP
FNo 190 9
≥
1
O/C 3I0 ACTIVE
FNo 175 0
FNo 756 8
3I0 InRush PU
3I0p picked up
O/C 3I0 PU
FNo 7570
3I0p InRush PU
&
&t
I
&
,QDFWLYH
,!!LQVWDQW
,SLQVWDQW
,!LQVWDQW
,0$1&/26(
,2&
7,S
,(&&859(
2.4 Time Overcurrent Protection for Phase and Residual Currents
797UT612 Manu al
C53000–G1176–C148–1
2.4.1.3 Manual Close Command
When a circuit breaker is closed onto a faulted protected object, a high speed re-trip
by the breaker is often desired. The manual closing feature is designed to remove the
delay from one of the time overcurrent stages when the breaker is manually closed
onto a fault. The time delay is then bypassed via an impulse from the external control
switch. This impulse is prolonged by a period of at least 300 ms (Figure 2-54). Ad-
dresses $0$18$/&/26( and/or $ ,0$1&/26( determine for
which stages the delay is defeated under manual close condition.
Figure 2-54 Manual close processing
2.4.1.4 Dynamic Cold Load Pickup
With the dynamic cold load pickup feature, it is possible to dynamically increase the
pickup values of the time overcurrent protection stages when dynamic cold load over-
current conditions are anticipated, i.e. when consumers have increased power con-
sumption after a longer period of dead condition, e.g. in air conditioning systems, heat-
ing systems, motors, etc. By allowing pickup values and the associated time delays to
increase dynamically, it is not necessary to incorporate cold load capability in the nor-
mal settings.
Processing of the dynamic cold load pickup conditions is common for all time overcur-
rent stages, and is explained in Section 2.6 (page 108). The alternative values them-
selves are set for each of the stages.
2.4.1.5 Inrush Restraint
When switching unloaded transformers or shunt reactors on a live busbar, high mag-
netizing (inrush) currents may occur. They can amount to a multiple of the rated cur-
rent and, dependent on the transformer size and design, may last from several milli-
seconds to several seconds.
Although overcurrent detection is based only on the fundamental harmonic compo-
nent of the measured currents, false pickup due to inrush might occur since the inrush
current may even comprise a considerable component of fundamental harmonic.
The time overcurrent protection provides an integrated inrush restraint function which
blocks the overcurrent stages I> and Ip (not I>>) for phase and residual currents in
case of inrush detection. After detection of inrush currents above a pickup value spe-
cial inrush signals are generated. These signals also initiate fault annunciations and
>Manual Close
FNo 003 56 FNo 00561
Man.Clos.
50 ms 0
Man. Close (internal)
300 ms
2 Functions
80 7UT612 Manual
C53000–G1176–C148–1
start the assigned trip delay time. If inrush current is still detected after expiration of
the delay time, an annunciation is output. Tripping is suppressed.
The inrush current is characterized by a considerable 2nd harmonic content (double
rated frequency) which is practically absent in the case of a short-circuit. If the second
harmonic content of a phase current exceeds a selectable threshold, trip is blocked for
this phase. Similar applies for the residual current stages.
The inrush restraint feature has an upper operation limit. Above this (adjustable) cur-
rent blocking is suppressed since a high-current fault is assumed in this case. The low-
er limit is the operating limit of the harmonic filters (0.2 IN).
Figure 2-55 shows a simplified logic diagram.
Figure 2-55 Logic diagram of the inrush restraint feature — example for phase currents
Figure 2-56 Logic diagram of the crossblock function for the phase currents
Since the harmonic restraint operates individually per phase, the protection is fully op-
erative even when e.g. the transformer is switched onto a single-phase fault, whereby
inrush currents may possibly be present in one of the healthy phases. However, it is
&
fN
2fN
21
2))
„1“
>BLK Ph.O/C Inr
Meas. release
≥
1
FNo 07571
FNo 07581 ... 07583
,Q5XVK5HVW3K
+$503KDVH
,0D[,Q5U3K
IL3
IL2
IL1
L1
L2L3 Meas. release
Meas. release
Inrush det.. L3
L3 InRush det.
Inrush det.. L2
Inrush det. L1
L2 InRush det.
L1 InRush det.
≥1
T
≥1
≥1
≥1
12
<(6
„1“ &
Inrush det.. L1
Inrush det.. L2
Inrush det.. L3
FNo 01843
INRUSH X-BLK
Rush Blk L3
Rush Blk L2
Rush Blk L1
7&5266%/.3K
&5266%/.3KDVH
2.4 Time Overcurrent Protection for Phase and Residual Currents
817UT612 Manu al
C53000–G1176–C148–1
also possible to set the protection such that not only the phase with inrush current ex-
hibiting harmonic content in excess of the permissible value is blocked but also the
other phases of the associated stage are blocked (so called “cross-block function”).
This cross-block can be limited to a selectable duration. Figure 2-56 shows the logic
diagram.
Crossblock refers only to the phase current stages against each other. Phase inrush
currents do not block the residual current stages nor vice versa.
2.4.1.6 Fast Busbar Protection Using Reverse Interlocking
Application
Example Each of the overcurrent stages can be blocked via binary inputs of the relay. A setting
parameter determines whether the binary input operates in the “normally open” (i.e.
energize input to block) or the “normally closed” (i.e. energize input to release) mode.
Thus, the overcurrent time protection can be used as fast busbar protection in star
connected networks or in open ring networks (ring open at one location), using the
“reverse interlock” principle. This is used in high voltage systems, in power station
auxiliary supply networks, etc., in which cases a transformer feeds from the higher
voltage system onto a busbar with several outgoing feeders (refer to Figure 2-57).
Figure 2-57 Fast busbar protection using reverse interlock — principle
Fault location
¯
: Tripping time T I>>
Fault location
°
: Tripping time t1
Backup time T I>
I> I>>
T I> T I> >
I> I>
t1
T I> T I>>
t1
Trip Trip Trip Trip
¯
°
Infeed direction
“
!,!!EORFN
”
t1
7UT612
Idiff
Trip
2 Functions
82 7UT612 Manual
C53000–G1176–C148–1
The time overcurrent protection is applied to the lower voltage side. “Reverse inter-
locking” means, that the overcurrent time protection can trip within a short time T–I>>,
which is independent of the grading time, if it is not blocked by pickup of one of the
next downstream time overcurrent relays (Figure 2-57). Therefore, the protection
which is closest to the fault will always trip within a short time, as it cannot be blocked
by a relay behind the fault location. The time stages I> or Ip operate as delayed backup
stages.
2.4.2 Setting the Function Parameters
During configuration of the functional scope (Subsection 2.1.1, margin heading “Spe-
cial Cases”, page 16) in addresses to the sides of the protected object and
the type of characteristic were determined, separately for the phase current stages
and zero sequence current stage. Only the settings for the characteristic selected can
be performed here. The definite time stages I>>, 3I0>>, I> and 3I0> are always avail-
able.
2.4.2.1 Phase Current Stages
General In address 3+$6(2& time overcurrent protection for phase currents can be
switched 21 or 2)).
Address $ 0$18$/&/26( determines the phase current stage which is to be
activated instantaneously with a detected manual close. Settings ,!!LQVWDQW and
,!LQVWDQW can be set independent from the type of characteristic selected. ,S
LQVWDQW is only available if one of the inverse time stages is configured. This pa-
rameter can only be changed with DIGSI® 4 under “Additional Settings”.
If time overcurrent protection is applied on the supply side of a transformer, select the
higher stage I>> which does not pick up during inrush conditions or set the manual
close feature to ,QDFWLYH.
In address ,Q5XVK5HVW3K inrush restraint (restraint with 2nd harmonic) is
enabled or disabled for all phase current stages of time overcurrent protection (except-
ed the I>> stage). Set 21 if one time overcurrent protection stage is to operate at the
supply side of a transformer. Otherwise, use setting 2)). If you intend to set a very
small pickup value for any reason, consider that the inrush restraint function cannot
operate below 20 % nominal current (lower limit of harmonic filtering).
Definite Time
High-Current
Stages I>>
If I>>–stage ,!! (address ) is combined with I>–stage or Ip–stage, a two-stage
characteristic will be the result. If one stage is not required, the pickup value has to be
set to ∞. Stage ,!! always operates with a defined delay time.
If time overcurrent protection is used on the supply side of a transformer, a series re-
actor, a motor or starpoint of a generator, this stage can also be used for current grad-
2.4 Time Overcurrent Protection for Phase and Residual Currents
837UT612 Manu al
C53000–G1176–C148–1
ing. Setting instructs the device to pick up on faults only inside the protected object but
not for traversing fault currents.
Calculation example:
Power transformer feeding a busbar, with the following data:
Power transformer YNd5
35 MVA
110 kV/20 kV
usc = 15 %
Current transformers 200 A/5 A on the 110 kV side
The time overcurrent protection is assigned to the 110 kV side (= feeding side).
The maximum possible three-phase fault current on the 20 kV side, assuming a con-
stant voltage source on the 110 kV side, is:
Assumed a safety margin of 20 %, the primary setting value results:
Setting value I>> = 1.2 · 1224.7 A = 1470 A
For setting in primary values via PC and DIGSI®4 this value can be set directly. For
setting with secondary values the currents will be converted for the secondary side of
the current transformer.
Secondary setting value:
i.e. for fault currents higher than 1470 A (primary) or 36.7 A (secondary) the fault is in
all likelihood located in the transformer zone. This fault can immediately be cleared by
the time overcurrent protection.
Increased inrush currents, if their fundamental oscillation exceeds the setting value,
are rendered harmless by delay times (address 7,!!). The inrush restraint
does not apply to stages I>>.
Using reverse interlocking (Subsection 2.4.1.6, see also Figure 2-57) the multi-stage
function of the time overcurrent protection offers its advantages: Stage 7,!! e. g. is
used as accelerated busbar protection having a short safety delay ,!! (e. g. 5 0 ms).
For faults at the outgoing feeders the stage I>> is blocked. Stages ,S or ,! serve as
backup protection. The pickup values of both stages (,! or ,S and ,!!) are set equal.
Time delay 7,! or 7,S (IEC characteristic) or ',S (ANSI characteristic) is set such
that it overgrades the delay for the outgoing feeders.
If fault protection for motors is applied, you have to make sure that the setting value
,!! is smaller than the smallest (two-pole) fault current and higher than the highest
startup current. Since the maximum appearing startup current is usually below 1.6 x
the rated startup current (even with unfavourable conditions), the following setting is
adequate for fault current stage I>>:
1.6 · Istartup > ,!! < I
sc2-pole
The increased startup current possibly caused by overvoltage is already considered
with factor 1.6. Stage I>> can trip instantaneously (7,!! = V) since there is
no saturation of shunt reactance for motors, other than for transformers.
I
SROHPD[
1
u
VF WUDQVI
------------------ I
1WUDQVI
1
u
VF WUDQVI
------------------ S
1WUDQVI
3U
1
⋅
------------------- 1
0.15
----------- 35 MVA
3 110 kV⋅
------------------------------ 1224.7 A
=
⋅
=
⋅
=
⋅
=
Setting value I>> 1470 A
200 A
------------------- 5 A⋅36.7 A
==
2 Functions
84 7UT612 Manual
C53000–G1176–C148–1
The settable time 7,!! is an additional time delay and does not include the operating
time (measuring time, dropout time). The delay can be set to infinity ∞. If set to infinity,
the pickup of this function will be indicated but the stage will not trip after pickup. If the
pickup threshold is set to ∞, neither a pickup annunciation nor a trip is generated.
Definite Time
Overcurrent
Stages I>
For setting the time overcurrent stage ,! (address ) the maximum appearing op-
erational current is relevant. A pickup caused by an overload must be excluded, as the
device operates in this mode as fault protection with correspondingly short tripping
times and not as overload protection. For lines or busbars a rate of approx. 20 %
above the maximum expected (over)load is set, for transformers and motors a rate of
approx. 40 %.
The settable time delay (address 7,!) results from the grading coordination
chart defined for the network.
The settable time is an additional time delay and does not include the operating time
(measuring time, dropout time). The delay can be set to infinity ∞. If set to infinity, the
pickup of the corresponding function will be signalled but the stage will not issue a trip
command. If the pickup threshold is set to ∞, neither a pickup annunciation nor a trip
is generated.
Inverse Time
Overcurrent Stages
Ip with IEC curves
The inverse time stages, depending on the configuration (Subsection 2.1.1, address
), enable the user to select different characteristics. With the IEC characteristics
(address '07,'073+&+ = 72&,(&) the following is made available in ad-
dress ,(&&859(:
1RUPDO,QYHUVH (type A according to IEC 60255–3),
9HU\,QYHUVH (type B according to IEC 60255–3),
([WUHPHO\,QY (type C according to IEC 60255–3), and
/RQJ,QYHUVH (type B according to IEC 60255–3).
The characteristics and equations they are based on are listed in the Technical Data
(Section 4.4, Figure 4-7).
If the inverse time trip characteristic is selected, it must be noted that a safety factor
of about 1.1 has already been included between the pickup value and the setting
value. This means that a pickup will only occur if a current of about 1.1 times of the
setting value is present. The function will reset as soon as the value undershoots 95 %
of the pickup value.
The current value is set in address ,S. The maximum operating current is of pri-
mary importance for the setting. A pickup caused by an overload must be excluded,
as the device operates in this mode as fault protection with correspondingly short trip-
ping times and not as overload protection.
The corresponding time multiplier is accessible via address 7,S. The time mul-
tiplier must be coordinated with the grading coordination chart of the network.
The time multiplier can also be set to ∞. If set to infinity, the pickup of this function will
be indicated but the stage will not trip after pickup. If the Ip–stage is not required,
select address '07,'073+&+ = 'HILQLWH7LPH when configuring the
protection functions (Subsection 2.1.1).
Inverse Time
Overcurrent Stages
Ip with ANSI curves
The inverse time stages, depending on the configuration (Subsection 2.1.1, address
), enable the user to select different characteristics. With the ANSI characteristics
2.4 Time Overcurrent Protection for Phase and Residual Currents
857UT612 Manu al
C53000–G1176–C148–1
(address '07,'073+&+ = 72&$16,) the following is made a vailable in
address $16,&859(:
'HILQLWH,QY,
([WUHPHO\,QY,
,QYHUVH,
/RQJ,QYHUVH,
0RGHUDWHO\,QY,
6KRUW,QYHUVH, and
9HU\,QYHUVH.
The characteristics and the equations they are based on are listed in the Technical
Data (Section 4.4, Figures 4-8 and 4-9).
If the inverse time trip characteristic is selected, it must be noted that a safety factor
of about 1.1 has alrea dy been includ ed betwe en the pic kup val ue and the set tin g
value. This means that a pickup will only occur if a current of about 1.1 times of the
setting value is present.
The current valu e is s et in a ddres s ,S. The maximum operating current is of pri-
mary importance for the setting. A pickup caused by overload must be excluded,
since, in this mode, the device operates as fault protection with correspondingly short
tripping times and not as overload protection.
The corresponding time multiplier is set in address ',S. The time multiplier
must be coordinated with the grading coordination chart of the network.
The t ime mul tipli er can als o be set to ∞. If set to infinity, the pickup of this function will
be indicated but the stage will not trip after pickup. If the Ip–stage is not required,
select address '07,'073+&+ = 'HILQLWH7LPH when configuring the
protection functions (Subsection 2.1.1).
If 'LVN(PXODWLRQ is set in address 72&'523287, dropout is being pro-
duced according to the dropout characteristic. For more information see Subsection
2.4.1.2, margin heading “Dropout for ANSI Curves” (page 77).
Dynamic Cold Load
Pickup An alternative set of pickup values can be set for each stage. It is selected automati-
cally-dynamically during operation. For more information on this function see Section
2.6 (page 108).
For the stages the following alternative values are set:
−for definite time overcurrent protection (phases):
address pick up val ue ,!!,
addres s delay time 7,!!,
address pickup val ue ,!,
addres s delay time 7,!;
−for inverse ti me overcurrent protection (phases) acc. IEC curves:
address pick up val ue ,S,
addres s time multiplier 7,S;
−for inverse ti me overcurrent protection (phases) acc. ANSI curves:
address pick up val ue ,S,
addres s time dial ',S.
2 Functions
86 7UT612 Manual
C53000–G1176–C148–1
User Specified
Curves For inverse-time overcurrent protection the user may define his own tripping and drop-
out characteristic. For configuration in DIGSI®4 a dialog box is to appear. Enter up to
20 pairs of current value and tripping time value (Figure 2-58).
In DIGSI®4 the characteristic can also be viewed as an illustration, see the right part
of Figure 2-58.
Figure 2-58 Entering a user specified tripping curve using DIGSI®4 — example
To create a user-defined tripping characteristic, the following must be set for configu-
ration of the functional scope (Subsection 2.1.1): address '07,'073+&+,
option 8VHU'HILQHG38. If you also want to specify the dropout characteristic, set
8VHUGHI5HVHW.
Value pairs are referred to the setting values for current and time.
Since current values are rounded in a specific table before they are processed in the
device (see Table 2-3), we recommend to use exactly the same preferred current val-
ues you can find in this table.
.
Table 2-3 Preferred values of the standard currents for user specified trip characteristi cs
,,S WR ,,S WR ,,S WR ,,S WR
1.00 1.50 2.00 3.50 5.00 6.50 8.00 15.00
1.06 1.56 2.25 3.75 5.25 6.75 9.00 16.00
1.13 1.63 2.50 4.00 5.50 7.00 10.00 17.00
1.19 1.69 2.75 4.25 5.75 7.25 11.00 18.00
1.25 1.75 3.00 4.50 6.00 7.50 12.00 19.00
1.31 1.81 3.25 4.75 6.25 7.75 13.00 20.00
1.38 1.88 14.00
1.44 1.94
2.4 Time Overcurrent Protection for Phase and Residual Currents
877UT612 Manu al
C53000–G1176–C148–1
The def au l t se t ti ng o f cu rr en t valu e s i s ∞. Thus they are made invalid. No pickup and
no tripping by this protective function takes place.
For specification of a tripping characteristic please observe the following:
−The value pairs are to be indicated in a continuous order. You may also enter less
than 20 value pairs. In most cases, 10 value pairs would be sufficient to be able to
define an exact characteristic. A value pair which will not be used has to be made
invalid entering “∞” for the threshold! Please ensure that a clear and steady char-
acteristic is formed from the value pairs.
−For currents select the values from Table 2-3 and add the corresponding time val-
ues. Deviating values I/Ip are rounded. This, however, will not be indicated.
−Currents smaller than the current value of the
smallest
characteristic point do not
lead to a prolongation of the tripping time. The pickup characteristic (see Figure 2-
59, right side) goes parallel to the current axis, up to the
smallest
characteristic
point.
Figure 2-59 User specified characteristic — example
−Currents greater than the current value of the
greatest
characteristic point do not
lead to a reduction of the tripping time. The pickup characteristic (see Figure 2-59,
right side) goes parallel to the current axis, beginning with the
greatest
characteris-
tic point.
For specification of a dropout characteristic please observe the following:
−For currents select the values from Table 2-4 and add the corresponding time val-
ues. Deviating values I/Ip are rounded. This, however, will not be indicated.
−Currents greater than the current value of the
greatest
characteristic point do not
lead to a prolongation of the dropout time. The dropout characteristic (see Figure 2-
59, left side) goes parallel to the current axis, up to the
greatest
characteristic point.
−Currents smaller than the current value of the
smallest
characteristic point do not
lead to a reduction of the dropout time. The dropout characteristic (see Figure 2-59,
left side) goes parallel to the current axis, beginning with the
smallest
characteristic
point.
0.9 1.0 .1 20
T/Tp
Trip
Reset
I/Ip
Largest current point Smallest current point
Smallest current point Largest current point
2 Functions
88 7UT612 Manual
C53000–G1176–C148–1
−Currents smaller than 0.05 times the setting value of currents lead to an immediate
drop out .
.
Inrush Restraint In address ,Q5XVK5HVW3K of the general settings (page 82, margin heading
“General”) the inrush restraint can be enabled (21) or disabled (2))). Especially for
transformers and if overcurrent time protection is used on the supply side, this inrush
restraint is required. Function parameters of the inrush restraint are set in “Inrush”.
It is based on an evaluation of the 2nd harmonic present in the inrush current. The ratio
of 2nd harmonics to the fundamental +$503KDVH (address ) is set to I2fN/
IfN = % as default setting. It can be used without being changed. To provide more
restraint in exceptional cases, where energizing conditions are particularly unfavour-
able, a smaller value can be set in the address before-mentioned.
If the current exceeds the value indicated in address ,0D[,Q5U3K, no
restraint will be provoked by the 2nd harmonic.
The inrush restraint can be extended by the so-called “cross-block” function. This
means that if the harmonic component is only exceeded in
one
phase, all
three
phases
of the I>– or Ip–stages are blocked. In address &5266%/.3KDVH the cross-
block function is set to 21 or 2)).
The time period for which the crossblock function is active after detection of inrushes
is set at address 7&5266%/.3K.
2.4.2.2 Residual Current Stages
General In address ,2&, time overcurrent protection for residual current can be set
to 21 or 2)).
Address $ ,0$1&/26( determines which residual current stage is to be
activated instantaneously with a detected manual close. Settings ,!!LQVWDQW
and ,!LQVWDQW can be set independent from the type of characteristic selected.
,SLQVWDQW is only available if one of the inverse time stages is configured. This
Table 2-4 Preferred values of the standard currents for user specified reset characteristics
,,S WR ,,S WR ,,S WR ,,S WR
1.00 0.93 0.84 0.75 0.66 0.53 0.34 0.16
0.99 0.92 0.83 0.73 0.64 0.50 0.31 0.13
0.98 0.91 0.81 0.72 0.63 0.47 0.28 0.09
0.97 0.90 0.80 0.70 0.61 0.44 0.25 0.06
0.96 0.89 0.78 0.69 0.59 0.41 0.22 0.03
0.95 0.88 0.77 0.67 0.56 0.38 0.19 0.00
0.94 0.86
2.4 Time Overcurrent Protection for Phase and Residual Currents
897UT612 Manu al
C53000–G1176–C148–1
parameter can only be changed with DIGSI® 4 under “Additional Settings”. For this
setting, similar considerations apply as for the phase current stages.
In address ,Q5XVK5HVW, inrush rest raint (restrai nt with 2nd harmonic) is
enabled or disabled. Set 21 if the residual current stage of the time overcurrent pro-
tection is applied at the supply side of a transformer whose starpoint is earthed.
Otherwise, use setting 2)).
Definite Time
High-Current
Stage 3I0>>
If I0>>–stage ,!! (addr ess is combined with I>–stage or Ip–stage, a two-
stage characteristic will be the result. If one stage is not required, the pickup value has
to be set to ∞. Stage ,!! always operates with a defined delay time.
If the protected winding is not earthed, zero sequence current only emerges due to an
inner earth fault or double earth fault with one inner base point. Here, no I0>>-stage is
required usually.
Stage I0>> can be applied e.g. for current grading. Please note that the zero sequence
system of currents is of importance. For transformers with separate windings, zero se-
quence systems are usually kept separate (exception: bilateral starpoint earthing).
Inrush currents can only be created in zero sequence systems, if the starpoint of the
winding regarded is earthed. If its fundamental exceeds the setting value, the inrush
currents are rendered harmless by delay (address 7,!!).
“Reverse interlocking” (Subsection 2.4.1.6, see Figure 2-57) only makes sense if the
winding regarded is earthed. Then, we take advantage of the multi-stage function of
time overcurrent protection: Stage 7,!! e. g. is used as accelerated busbar pro-
tection having a short safety delay ,!! (e. g. 50 ms). For faults at the outgoing feed-
ers stage ,!! is blocked. Stages ,S or ,! serve as backup protection. The
pickup values of both stages (,! or ,S and ,!!) are set equal. Time delay 7
,! or 7,S (IEC characteristic) or ',S (ANSI characteristic) is set such that
it overgrades the delay for the outgoing feeders. Here, the grading coordination chart
for earth faults, which mostly allows shorter setting times, is of primary importance.
The s e t t i me 7,!! is an additional time delay and does not include the operating
time (measuring time, dropout time). The delay can be set to infinity ∞. If set to infinity,
the pickup of this function will be indicated but the stage will not trip after pickup. If the
pickup threshold is set to ∞, neither a pickup annunciation nor a trip is generated.
Definite Time
Overcurrent
Stage 3I0>
For setting the time overcurrent stage ,! (address ) the minimum appearing
earth fault current is relevant.
The settable time delay (param eter 7,!) derives from the grading coordi-
nation chart created for the network. For earth currents with earthed network, you can
mostly set up a separate grading coordination chart with shorter delay times. If you set
a very small pickup value, consider that the inrush restraint function cannot operate
below 20 % nominal current (lower limit of harmonic filtering). An adequate time delay
could be reasonable.
The set time is an additional time delay and does not include the operating time (meas-
uring time, dropout time). The delay can be set to infinity ∞. If set to infinity, the pickup
of this function will be indicated but the stage will not be able to trip after pickup. If the
pickup threshold is set to ∞, neither a pickup annunciation nor a trip is generated.
2 Functions
90 7UT612 Manual
C53000–G1176–C148–1
Inverse Time
Overcurrent Stage
3I0p with IEC
curves
The inverse time stage, depending on the configuration (Subsection 2.1.1, address
), enables the user to select different characteristics. With the IEC characteristics
(address '07,'07,&+ = 72&,(&) the following is made available in ad-
dress ,(&&859(:
1RUPDO,QYHUVH (type A according to IEC 60255–3),
9HU\,QYHUVH (type B according to IEC 60255–3),
([WUHPHO\,QY (type C according to IEC 60255–3), and
/RQJ,QYHUVH (type B according to IEC 60255–3).
The characteristics and equations they are based on are listed in the Technical Data
(Section 4.4, Figure 4-7).
If the inverse time trip characteristic is selected, it must be noted that a safety factor
of about 1.1 has already been included between the pickup value and the setting val-
ue. This means that a pickup will only occur if a current of about 1.1 times of the setting
value is present. The function will reset as soon as the value undershoots 95 % of the
pickup va lue.
The current value is set in address ,S. The most relevant for this setting is
the minimum appearing earth fault current.
The corresponding time multiplier is accessible via address 7,S. This has
to be coordinated with the grading coordination chart of the network. For earth cur-
rents with earthed network, you can mostly set up a separate grading coordination
chart with shorter delay times. If you set a very small pickup value, consider that the
inrush restraint function cannot operate below 20 % nominal current (lower limit of har-
monic filtering). An adequate time delay could be reasonable.
The time multiplier can also be set to ∞. If set to infinity, the pickup of this function will
be indicated but the stage will not be able to trip after pickup. If the Ip–stage is not re-
quired, select address '07,'07,&+ = 'HILQLWH7LPH when configuring
the protection functions (Subsection 2.1.1).
Inverse Time
Overcurrent Stage
3I0p with ANSI
curves
The inverse time stages, depending on the configuration (Subsection 2.1.1, address
), enable the user to select different characteristics. With the ANSI characteristics
(address '07,'07,&+ = 72&$16,) the following is made available in
address $16,&859(:
'HILQLWH,QY,
([WUHPHO\,QY,
,QYHUVH,
/RQJ,QYHUVH,
0RGHUDWHO\,QY,
6KRUW,QYHUVH, and
9HU\,QYHUVH.
The characteristics and the equations they are based on are listed in the Technical
Data (Section 4.4, Figures 4-8 and 4-9).
If the inverse time trip characteristic is selected, it must be noted that a safety factor
of about 1.1 has already been included between the pickup value and the setting val-
ue. This means that a pickup will only occur if a current of about 1.1 times of the setting
value is present.
The current value is set in address ,S. The most relevant for this setting is
the minimum appearing earth fault current.
2.4 Time Overcurrent Protection for Phase and Residual Currents
917UT612 Manu al
C53000–G1176–C148–1
The corresponding time multiplier is set in address ',S. This has to be co-
ordinated with the grading coordination chart of the network. For earth currents with
earthed network, you can mostly set up a separate grading coordination chart with
shorter delay times. If you set a very small pickup value, consider that the inrush re-
straint function cannot operate below 20 % nominal current (lower limit of harmonic fil-
tering). An adequate time delay could be reasonable.
The t ime mul tipli er can als o be set to ∞. If set to infinity, the pickup of this function will
be indicated but the stage will not be able to trip after pickup. If stage 3,0p is not re-
quired, select address '07,'07,&+ = 'HILQLWH7LPH when configuring
the protection functions (Subsection 2.1.1).
If 'LVN(PXODWLRQ is set in address 72&'523287, dropout is being pro-
duced according to the dropout characteristic. For more information see Subsection
2.4.1.2, margin heading “Dropout for ANSI Curves” (page 77).
Dynamic Cold Load
Pickup An alternative set of pickup values can be set for each stage. It is selected automati-
cally-dynamically during operation. For more information on this function see Section
2.6 (page 108).
For the stages the following alternative values are set:
−for definite time overcurrent protection 3I0:
address pickup val ue ,!!,
addres s delay time 7,!!,
address pickup val ue ,!,
addres s delay time 7,!;
−for inverse time overcurrent protection 3I0 acc. IEC curves:
address pickup val ue ,S,
addres s time multiplier 7,S;
−for inverse time overcurrent protection 3I0 acc. ANSI curves:
address pickup val ue ,S,
addres s time dial ',S.
User Specif ied
Curves For inverse time overcurrent protection the user may define his own tripping and drop-
out characteristic. For configuration in DIGSI®4 a dialog box is to appear. Enter up to
20 pairs of current and tripping time values (Figure 2-58, page 86).
The procedure is the same as for phase current stages. See Subsection 2.4.2.1, mar-
gin heading “User Specified Curves”, page 86.
To create a user defined tripping characteristic, the following must have been set for
configuration of the functional scope (Subsection 2.1.1): address '07,'07,
&+, option 8VHU'HILQHG38. If you also want to specify the dropout characteristic,
set option 8VHUGHI5HVHW.
Inrush Restraint In address ,Q5XVK5HVW, of the general settings (page 88, margin head-
ing “General”) the inrush restraint can be enabled (21) or di sabled (2))). Especially
for transformers and if overcurrent time protection is activated on the earthed supply
side, this inrush restraint is required. Function parameters of the inrush restraint are
set in “Inrush”.
It is based on an evaluation of the 2nd harmonic present in the inrush current. The ratio
of 2nd harmonics to the fundamental +$50, (address ) is preset to
2 Functions
92 7UT612 Manual
C53000–G1176–C148–1
I2fN/IfN = %. It can be used without being changed. To provide more restraint in ex-
ceptional cases, where energizing conditions are particularly unfavourable, a smaller
value can be set in the address before-mentioned.
If the current exceeds the value indicated in address ,0D[,Q5U,, no
restraint will be provoked by the 2nd harmonic.
2.4.3 Setting Overview
The following list indicates the setting ranges and the default settings of a rated sec-
ondary current IN = 1 A. For a rated secondary current of IN = 5 A these values have
to be multiplied by 5. For settings in primary values, a conversion rate from current
transformers has to be considered additionally.
Note:
Addresses which have an “A” attached to their end can only be changed in
DIGSI®4, Section „Additional Settings“.
Phase Currents
Addr. Setting Title Setting Options Default Setting Comments
2001 PHASE O/C ON
OFF OFF Phase Time Overcurrent
2002 InRushRest. Ph ON
OFF OFF InRush Restrained O/C Phase
2008A MANUAL CLOSE I>> instantaneously
I> instantaneously
Ip instantaneously
Inactive
I>> instantane-
ously O/C Manual Close Mode
2011 I>> 0.10..35.00 A; ∞ 2.00 A I>> Pickup
2012 T I>> 0.00..60.00 sec; ∞ 0.00 sec T I>> Time Delay
2013 I> 0.10..35.00 A; ∞ 1.00 A I> Pickup
2014 T I> 0.00..60.00 sec; ∞ 0.50 sec T I> Time Delay
2111 I>> 0.10..35.00 A; ∞ 10.00 A I>> Pickup
2112 T I>> 0.00..60.00 sec; ∞ 0.00 sec T I>> Time Delay
2113 I> 0.10..35.00 A; ∞ 2.00 A I> Pickup
2114 T I> 0.00..60.00 sec; ∞ 0.30 sec T I> Time Delay
2021 Ip 0.10..4.00 A 1.00 A Ip Pickup
2022 T Ip 0.05..3.20 sec; ∞ 0.50 sec T Ip Time Dial
2023 D Ip 0.50..15.00 ; ∞ 5.00 D Ip Time Dial
2024 TOC DROP-OUT Instantaneous
Disk Emulation Disk Em ulation TOC Drop-out characteristic
2.4 Time Overcurrent Protection for Phase and Residual Currents
937UT612 Manu al
C53000–G1176–C148–1
Residual Current
2025 IEC CURVE Normal Inverse
Very Inverse
Extremely Inverse
Long Inverse
Normal Inverse IEC Curve
2026 ANSI CURVE Very Inverse
Inverse
Short Inverse
Long Inverse
Moder atel y Inv ers e
Extremely Inverse
Definite Inverse
Very Inverse ANSI Curve
2121 Ip 0.10..4.00 A 1.50 A Ip Pickup
2122 T Ip 0.05..3.20 sec; ∞ 0.50 sec T Ip Time Dial
2123 D Ip 0.50..15.00; ∞ 5.00 D Ip Time Dial
2031 I/Ip PU T/Tp 1.00..20.00 I / Ip; ∞
0.01..999.00 Time Dial Pickup Curve I/Ip - TI/TIp
2032 MofPU Res T/Tp 0.05..0.95 I / Ip; ∞
0.01..999.00 Time Dial Multiple of Pickup <-> TI/TIp
2041 2.HARM. Phase 10..45 % 15 % 2nd harmonic O/C Ph. in % of
fundamental
2042 I Max InRr. Ph. 0.30..25.00 A 7.50 A Maximum Current for Inr. Rest.
O/C Phase
2043 CROSS BLK.Phase NO
YES NO CROSS BLOCK O/C Phase
2044 T CROSS BLK.Ph 0.00..180.00 sec 0.00 sec CROSS BLOCK Time O/C
Phase
Addr. Setting Title Setting Options Default Setting Comments
Addr. Setting Title Setting Options Default Setting Comments
2201 3I0 O/C ON
OFF OFF 3I0 Time Overcurrent
2202 InRushRest. 3I0 ON
OFF OFF InRush Restrained O/C 3I0
2208A 3I0 MAN. CLOSE 3I0>> instantaneously
3I0> instantaneously
3I0p instantaneously
Inactive
3I0>> inst an tan e-
ousl y O/C 3I0 Manual Close Mode
2211 3I0>> 0.05..35.00 A; ∞ 0.50 A 3I0>> Pickup
2212 T 3I0>> 0.00..60.00 sec; ∞ 0.10 sec T 3I0>> Time Delay
2213 3I0> 0.05..35.00 A; ∞ 0.20 A 3I0> Pickup
2214 T 3I0> 0.00..60.00 sec; ∞ 0.50 sec T 3I0> Time Delay
2311 3I0>> 0.05..35.00 A; ∞ 7.00 A 3I0>> Pickup
2 Functions
94 7UT612 Manual
C53000–G1176–C148–1
2.4.4 Information Overview
General
2312 T 3I0>> 0.00..60.00 sec; ∞ 0.00 sec T 3I0>> Time Delay
2313 3I0> 0.05..35.00 A; ∞ 1.50 A 3I0> Pickup
2314 T 3I0> 0.00..60.00 sec; ∞ 0.30 sec T 3I0> Time Delay
2221 3I0p 0.05..4.00 A 0.20 A 3I0p Pickup
2222 T 3I0p 0.05..3.20 sec; ∞ 0.20 sec T 3I0p Time Dial
2223 D 3I0p 0.50..15.00; ∞ 5.00 D 3I0p Time Dial
2224 TOC DROP-OUT Instantaneous
Disk Emulation Disk Em ulation TOC Drop-out Chara c teristic
2225 IEC CURVE Normal Inverse
Very Inverse
Extremely Inverse
Long Invers e
Normal Inverse IEC Curve
2226 ANSI CURVE Very Inverse
Inverse
Short Inverse
Long Invers e
Moderately Inverse
Extremely Inverse
Definite Inverse
Very Inverse ANSI Curve
2321 3I0p 0.05..4.00 A 1.00 A 3I0p Pickup
2322 T 3I0p 0.05..3.20 sec; ∞ 0.50 sec T 3I0p Time Dial
2323 D 3I0p 0.50..15.00; ∞ 5.00 D 3I0p Time Dial
2231 I/I0p PU T/TI0p 1.00..20.00 I / Ip; ∞
0.01..999.00 Time Dial Pickup Curve 3I0/3I0p - T3I0/
T3I0p
2232 MofPU ResT/TI0p 0.05..0.95 I / Ip; ∞
0.01..999.00 Time Dial Multiple of Pickup <-> T3I0/
T3I0p
2241 2.HARM. 3I0 10..45 % 15 % 2nd harmonic O/C 3I0 in % of
fundamental
2242 I Max InRr. 3I0 0.30..25.00 A 7.50 A Maximum Current for Inr. Rest.
O/C 3I0
Addr. Setting Title Setting Options Default Setting Comments
F.No. Alarm Comments
01761 Overcurrent PU Time Overcurrent picked up
01791 OvercurrentTRIP Time Overcurrent TRIP
2.4 Time Overcurrent Protection for Phase and Residual Currents
957UT612 Manu al
C53000–G1176–C148–1
Phases Currents
F.No. Alarm Comments
01704 >BLK Phase O/C >BLOCK Phase time overcurrent
07571 >BLK Ph.O/C Inr >BLOCK time overcurrent Phase InRush
01751 O/C Phase OFF Time Overcurrent Phase is OFF
01752 O/C Phase BLK Time Overcurrent Phase is BLOCKED
01753 O/C Phase ACT Time Overcurrent Phase is ACTIVE
07581 L1 InRush det. Phase L1 InRush detected
07582 L2 InRush det. Phase L2 InRush detected
07583 L3 InRush det. Phase L3 InRush detected
01843 INRUSH X-BLK Cross blk: PhX blocked PhY
01762 O/C Ph L1 PU Time Overcurrent Phase L1 picked up
01763 O/C Ph L2 PU Time Overcurrent Phase L2 picked up
01764 O/C Ph L3 PU Time Overcurrent Phase L3 picked up
07565 L1 InRush PU Phase L1 InRush picked up
07566 L2 InRush PU Phase L2 InRush picked up
07567 L3 InRush PU Phase L3 InRush picked up
01721 >BLOCK I>> >BLOCK I>>
01852 I>> BLOCKED I>> BLOCKED
01800 I>> picked up I>> picked up
01804 I>> Time Out I>> Time Out
01805 I>> TRIP I>> TRIP
01722 >BLOCK I> >BLOCK I>
01851 I> BLOCKED I> BLOCKED
01810 I> picked up I> picked up
07551 I> InRush PU I> InRush picked up
01814 I> Time Out I> Time Out
01815 I> TRIP I> TRIP
01723 >BLOCK Ip >BLOCK Ip
01855 Ip BLOCKED Ip BLOCKED
01820 Ip picked up Ip picked up
07553 Ip InRush PU Ip InRush picked up
01824 Ip Time Out Ip Time Out
01825 Ip TRIP Ip TRIP
01860 O/C Ph. Not av. O/C Phase Not avali. for this objekt
2 Functions
96 7UT612 Manual
C53000–G1176–C148–1
Residual Current
F.No. Alarm Comments
01741 >BLK 3I0 O/C >BLOCK 3I0 time overcurrent
07572 >BLK 3I0O/C Inr >BLOCK time overcurrent 3I0 InRush
01748 O/C 3I0 OFF Time Overcurrent 3I0 is OFF
01749 O/C 3I0 BLK Time Overcurrent 3I0 is BLOCKED
01750 O/C 3I0 ACTIVE Time Overcurrent 3I0 is ACTIVE
01766 O/C 3I0 PU Time Overcurrent 3I0 picked up
07568 3I0 InRush PU 3I0 InRush picked up
01742 >BLOCK 3I0>> >BLOCK 3I0>> time overcurrent
01858 3I0>> BLOCKED 3I0>> BLOCKED
01901 3I0>> picked up 3I0>> picked up
01902 3I0>> Time Out 3I0>> Time Out
01903 3I0>> TRIP 3I0>> TRIP
01743 >BLOCK 3I0> >BLOCK 3I 0> time overcurrent
01857 3I0> BLOCKED 3I0> BLOCKED
01904 3I0> picked up 3I0> picked up
07569 3I0> InRush PU 3I0> InRush picked up
01905 3I0> Time Out 3I0> Time Out
01906 3I0> TRIP 3I0> TRIP
01744 >BLOCK 3I0p >BLOCK 3I0p time overcurrent
01859 3I0p BLOCKED 3I0p BLOCKED
01907 3I0p picked up 3I0p picked up
07570 3I0p InRush PU 3I0p InRush picked up
01908 3I0p TimeOut 3I0p Time Out
01909 3I0p TRIP 3I0p TRIP
01861 O/C 3I0 Not av. O/C 3I0 Not avali. for this objekt
2.5 Time Overcurrent Protection for Earth Current
977UT612 Manu al
C53000–G1176–C148–1
2.5 Time Overcurrent Protection for Earth Current
The time overcurrent protection for earth current is always assigned to the current in-
put I7 of the device. Principally, it can be used for any desired application of overcur-
rent detection. Its preferred application is the detection of an earth current between the
starpoint of a protected three-phase object and the earthing electrode.
This protection can be used in addition to the restricted earth fault protection (Section
2.3). Then it forms the backup protection for earth faults outside the protected zone
which are not cleared there. Figure 2-60 shows an example.
The time overcurrent protection for earth current provides two definite time stages and
one inverse time stage. The latter may operate according an IEC or an ANSI, or an
user defined characteristic.
Figure 2-60 Time overcurrent protection as backup protection for restricted earth fault
protection
2.5.1 Function Description
2.5.1.1 Definite Time Overcurrent Protection
The definite time stages for earth current are always available even if an inverse time
characteristic has been configured according to Subsection 2.1.1 (address ).
Pickup, Trip Two definite time stages are available for the earth current IE.
The current measured at the input I7 is compared with the setting value ,(!!. Current
above the pickup value is detected and annunciated. When the delay time 7,(!! is
expired, tripping command is issued. The reset value is approximately 5 % below the
pickup value for currents > 0.3 ·I
N
.
ISP
7UT612
IL1
IL2
IL3
L1
L2
L3
I7
L1
L2
L3
Restricted
earth fault protection
Time overcurrent prot.
for earth current
2 Functions
98 7UT612 Manual
C53000–G1176–C148–1
Figure 2-61 shows the logic diagram for the high-current stage IE>>.
Figure 2-61 Logic diagram of the high-current stage IE>> for earth current
The current detected at the current measuring input I7 is additionally compared with
setting value ,(!. An annunciation is generated if the value is exceeded. But if inrush
restraint is used (cf. Subsection 2.5.1.5), a frequency analysis is performed first (Sub-
section 2.5.1.5). If an inrush condition is detected, pickup annunciation is suppressed
and an inrush message is output instead. If there is no inrush or if inrush restraint is
disabled, a tripping command will be output after expiration of delay time 7,(!. If
inrush restraint is enabled and inrush current is detected, there will be no tripping. Nev-
ertheless, an annunciation is generated indicating that the time expired. The dropout
value is approx. a 95 % of the pickup value for currents greater than 0.3 ·I
N
.
Figure 2-62 shows the logic diagram of the earth overcurrent stage IE>.
The pickup values for each of the stages IE> and IE>> and the delay times can be set
individually.
&
T0
≥
1
O/C Earth BLK
O/C Earth OFF
&IE>> T R IP
IE>> picked up
„1“
Man. Close &
IE>> Time Out
21
2))
„1“
>BLOCK IE>>
>BLK Earth O/C
IE>> BLOCKED
FNo 1831
FNo 1833
FNo 1832
FNo 1854
FNo 1757
FNo 1756
FNo 1714
FNo 1724
Meas. release
I>>
,(!!
I
7
≥
1
O/C Earth ACT
FNo 1758
(s. Fig. 2-54)
,QDFWLYH
,(!!LQVWDQW
,(SLQVWDQW
,(!LQVWDQW
,(0$1&/26(
($57+2&
7,(!!
2.5 Time Overcurrent Protection for Earth Current
997UT612 Manu al
C53000–G1176–C148–1
Figure 2-62 Logic di agram of the overcurrent stage IE> for earth current
2.5.1.2 Inverse Time Overcurrent Protection
The inverse-time overcurrent stage operates with a characteristic either according to
the IEC- or the ANSI-standard or with a user-defined characteristic. The characteristic
curves and their equations are represented in Technical Data (Figures 4-7 to 4-9 in
Section 4.4). If one of the inverse time characteristics is configured, the definite time
stages IE>> and IE> are also enabled (see Subsection 2.5.1.1).
Pickup, Trip The current detected at the current measuring input I7 is compared with setting value
,(S. If the current exceeds 1.1 times the set value, the stage picks up and an annun-
ciation is made. But if inrush restraint is used (cf. Subsection 2.5.1.5), a frequency
analysis is performed first (Subsection 2.5.1.5). If an inrush condition is detected, pick-
up annunciation is suppressed and an inrush message is output instead. The RMS
value of the fundamental is used for the pickup. During the pickup of an ,Ep stage, trip-
ping time is calculated from the flowing fault current by means of an integrating meas-
uring procedure, depending on the selected tripping characteristic. After expiration of
this time period, a trip command is output as long as no inrush current is detected or
inrush restraint is disabled. If inrush restraint is enabled and inrush current is detected,
there will be no tripping. Nevertheless, an annunciation is generated indicating that the
tim e expired.
„1“
Man. Close &
IE> Time Out
21
2))
„1“
>BLOCK IE>
>BLK Earth O/C O/C Eart h BLK
≥1
O/C Earth OFF
IE> BLOCKED
FNo 1834
FNo 1835
FNo 1853
FNo 1757
FNo 1756
FNo 1714
Meas. relea se
FNo 1725
(s. Fig. 2-54)
I>
,(!
I
7
&
&
Rush Blk E
FNo 1765
&
&IE> TRIP
FNo 1836
≥
1
O/C Eart h ACT
FNo 1758
FNo 7564
Earth InRush PU
IE> picked up
O/C Earth PU
FNo 7552
IE> InRush PU
&
T0
,QDFWLYH
,(!!LQVWDQW
,(SLQVWDQW
,(!LQVWDQW
,(0$1&/26(
($57+2&
7,(!
2 Functions
100 7UT612 Manual
C53000–G1176–C148–1
Figure 2-63 shows the logic diagram of the inverse time overcurrent protection.
Figure 2- 63 Logic diagram of the inverse time overcurrent pr otection stage IEp — example for IEC–curves
Dropout for IEC
Curves Dropout of the stage using an IEC curves occurs when the respective current decreas-
es below about 95 % of the pickup value. A renewed pickup will cause a renewed start
of the delay timers.
Dropout for ANSI
Curves Using the ANSI-characteristics you can determine whether the dropout of the stage is
to follow right after the threshold undershot or whether it is evoked by disk emulation.
“Right after” means that the pickup drops out when the pickup value of approx. 95 %
is undershot. For a new pickup the time counter starts at zero.
The disk emulation evokes a dropout process (time counter is decrementing) which
begins after de-energization. This process corresponds to the back turn of a Ferraris-
disk (explaining its denomination “disk emulation”). In case several faults occur suc-
cessively, it is ensured that due to the inertia of the Ferraris-disk the “History” is taken
into consideration and the time behaviour is adapted. The reset begins as soon as
90 % of the setting value is undershot, in correspondence to the dropout curve of the
selected characteristic. Within the range of the dropout value (95 % of the pickup val-
ue) and 90 % of the setting value, the incrementing and the decrementing processes
are in idle state. If 5 % of the setting value is undershot, the dropout process is being
finished, i.e. when a new pickup is evoked, the timer starts again at zero.
„1“
Man. Close &
IEp TimeOut
21
2))
„1“
>BLOCK IEp
>BLK Earth O/C O/C Eart h BLK
≥1
O/C Earth OFF
IEp BLOCKED
FNo 1837
FNo 1838
FNo 1856
FNo 1757
FNo 1756
FNo 1714
Meas. release
FNo 1726
(s. Fig. 2-54)
1,1I>
,(S
3
I
0
&
&
Rush Blk E
FNo 1765
IEp TRIP
FNo 1839
≥
1
O/C Eart h ACT
FNo 1758
FNo 7564
Earth InRush PU
IEp picked up
O/C Earth PU
FNo 7554
IEp InRush PU
t
I
&
&&
,QDFWLYH
,(!!LQVWDQW
,(SLQVWDQW
,(!LQVWDQW
,(0$1&/26(
($57+2&
7,(S
,(&&859(
2.5 Time Overcurrent Protection for Earth Current
1017UT612 Manual
C53000–G1176–C148–1
The disk emulation offers its advantages when the grading coordination chart of the
time overcurrent protection is combined with other devices (on electro-mechanical or
induction base) connected to the system.
Use Specified
Curves The tripping characteristic of the user-configurable characteristic can be defined via
several points. Up to 20 pairs of current and time values can be entered. With these
values the device approximates a characteristic by linear interpolation.
If required, the dropout characteristic can also be defined. For the functional descrip-
tion see “Dropout for ANSI Curves”. If no user-configurable dropout characteristic is
desired and if approx. a 95 % of the pickup value is undershot, dropout is initiated.
When a new pickup is evoked, the timer starts again at zero.
2.5.1.3 Manual Close Command
When a circuit breaker is closed onto a faulted protected object, a high speed re-trip
by the breaker is often desired. The manual closing feature is designed to remove the
delay from one of the time overcurrent stages when the breaker is manually closed
onto a fault. The time delay is then bypassed via an impulse from the external control
switch. This impulse is prolonged by a period of at least 300 ms (Figure 2-54, page
79). Address $ ,(0$1&/26( determines for which stages the delay is de-
feated under manual close condition.
2.5.1.4 Dynamic Cold Load Pickup
Dynamic changeover of pickup values is available also for time overcurrent protection
for earth current as it is for the time overcurrent protection for phase currents and re-
sidual current (Section 2.4). Processing of the dynamic cold load pickup conditions is
common for all time overcurrent stages, and is explained in Section 2.6 (page 108).
The alternative values themselves are set for each of the stages.
2.5.1.5 Inrush Restraint
Earth current time overcurrent protection provides an integrated inrush restraint func-
tion which blocks the overcurrent stages IE> and IEp (not IE>>) i n case of det ection of
an inrush on a transformer.
If the second harmonic content of the earth current exceeds a selectable threshold,
trip is blocked.
2 Functions
102 7UT612 Manual
C53000–G1176–C148–1
The inrush restraint feature has an upper operation limit. Above this (adjustable) cur-
rent blocking is suppressed since a high-current fault is assumed in this case. The low-
er limit is the operating limit of the harmonic filter (0.2 IN).
Figure 2-64 shows a simplified logic diagram.
Figure 2-64 Logic diagram of the inrush restraint feature
2.5.2 Setting the Function Parameters
General When configuring the protection functions (see Subsection 2.1.1, margin heading
“Special Cases”, page 16) the type of characteristic was set (address ). Only set-
tings for the characteristic selected can be performed. Definite time stages IE>> and
IE> are always available.
In address ($57+2&, time overcurrent protection for earth current can be set
to 21 or 2)).
Address $ ,(0$1&/26( determines which earth current stage is to be acti-
vated instantaneously with a detected manual close. Settings ,(!!LQVWDQW and
,(!LQVWDQW can be set independent from the type of characteristic selected. ,(S
LQVWDQW is only available if one of the inverse time stages is configured. This pa-
rameter can only be changed with DIGSI® 4 under “Additional Settings”.
If time overcurrent protection is applied on the feeding side of a transformer, select the
higher stage IE>> which does not pick up by the inrush current, or select the Manual
Close ,QDFWLYH.
In address ,Q5XVK5HVW(DUWK inrush restraint (inrush restraint with 2nd har-
monic) is enabled or disabled. Set 21 if the protection is applied at the feeding side of
an earthed transformer. Otherwise, use setting 2)).
Definite Time
High-Current
Stage IE>>
If ,(!!–stage (address ) is combined with the IE>–stage or the IEp–stage, a two-
stage characteristic will be the result. If this stage is not required, the pickup value shall
be set to ∞. Stage ,(!! always operates with a defined delay time.
&
fN
2fN
21
2))
„1“
>BLK E O/C Inr
Meas. release
≥
1
FNo 07573
,Q5XVK5HVW(DUWK
+$50(DUWK
,0D[,Q5U(
IE
E
Rush blk E
2.5 Time Overcurrent Protection for Earth Current
1037UT612 Manual
C53000–G1176–C148–1
Current and time setting shall exclude pickup during switching operations. This stage
is applied if you want to create a multi-stage characteristic together with stage IE> or
IEp (below described). With a certain degree of exactness, current grading can also be
achieved, similar to the corresponding stages of the time overcurrent protection for
phase and residual currents (Subsection 2.4.2). However, zero sequence system
quantities must be taken into consideration.
In most cases, this stage operates instantaneously. A time delay, however, can be
achieved by setting address 7,(!!.
The set time is an additional time delay and does not include the operating time (meas-
uring time, dropout time). The delay can be set to infinity ∞. If set to infinity, the pickup
of this function will be indicated but the stage will not be able to trip after pickup. If the
pickup threshold is set to ∞, neither a pickup annunciation nor a trip is generated.
Definite Time
Overcurrent
Stage IE>
Using the time overcurrent stage ,(! (address ) earth faults can also be detect-
ed with weak fault currents. Since the starpoint current originates from one single cur-
rent transformer, it is not affected by summation effects evoked by different current
transformer errors like, for example, the zero sequence current derived from phase
currents. Therefore, this address can be set to very sensitive. Consider that the inrush
restraint function cannot operate below 20 % nominal current (lower limit of harmonic
filtering). An adequate time delay could be reasonable for very sensitive setting if in-
rush restraint is used.
Since this stage also picks up with earth faults in the network, the time delay (address
7,(!) has to be coordinated with the grading coordination chart of the network
for earth faults. Mostly, you may set shorter tripping times than for phase currents
since a galvanic separation of the zero sequence systems of the connected power
system sections is ensured by a transformer with separate windings.
The set time is an additional time delay and does not include the operating time (meas-
uring time, dropout time). The delay can be set to infinity ∞. If set to infinity, the pickup
of this function will be indicated but the stage will not trip after pickup. If the pickup
threshold is set to ∞, neither a pickup annunciation nor a trip is generated.
Inverse Time
Overcurrent Stages
IEp with IEC curves
The inverse time stage, depending on the configuration (Subsection 2.1.1, address
), enables the user to select different characteristics. With the IEC characteristics
(address '07,'07(&+5 = 72&,(&) the following is made available in ad-
dress ,(&&859(:
1RUPDO,QYHUVH (type A according to IEC 60255–3),
9HU\,QYHUVH (type B according to IEC 60255–3),
([WUHPHO\,QY (type C according to IEC 60255–3), and
/RQJ,QYHUVH (type B according to IEC 60255–3).
The characteristics and equations they are based on are listed in the Technical Data
(Section 4.4, Figure 4-7).
If the inverse time trip characteristic is selected, it must be noted that a safety factor
of about 1.1 has already been included between the pickup value and the setting val-
ue. This means that a pickup will only occur if a current of about 1.1 times of the setting
value is present. The function will reset as soon as the value undershoots 95 % of the
pickup value.
Using the time overcurrent stage ,(S (address ) earth faults can also be detect-
ed with weak fault currents. Since the starpoint current originates from one single cur-
2 Functions
104 7UT612 Manual
C53000–G1176–C148–1
rent transformer, it is not affected by summation effects evoked by different current
transformer errors like, for example, the zero sequence current derived from phase
currents. Therefore, this address can be set to very sensitive. Consider that the inrush
restraint function cannot operate below 20 % nominal current (lower limit of harmonic
filtering). An adequate time delay could be reasonable for very sensitive setting if in-
rush restraint is used.
Since this stage also picks up with earth faults in the network, the time multiplier (ad-
dress 7,(S) has to be coordinated with the grading coordination chart of the
network for earth faults. Mostly, you may set shorter tripping times than for phase cur-
rents since a galvanic separation of the zero sequence systems of the connected pow-
er system sections is ensured by a transformer with separate windings.
The time multiplier can also be set to ∞. If set to infinity, the pickup of this function will
be indicated but the stage will not trip after pickup. If the IEp–stage is not required, se-
lect addres s '07,'07(&+5 = 'HILQLWH7LPH when configuring the pro-
tection functions (Subsection 2.1.1).
Inverse Time
Overcurrent Stages
Ip with ANSI curves
The inverse time stages, depending on the configuration (Subsection 2.1.1, address
), enable the user to select different characteristics. With the ANSI characteristics
(address '07,'07(&+5 = 72&$16,) the following is made available in
address $16,&859(:
'HILQLWH,QY,
([WUHPHO\,QY,
,QYHUVH,
/RQJ,QYHUVH,
0RGHUDWHO\,QY,
6KRUW,QYHUVH, and
9HU\,QYHUVH.
The characteristics and the equations they are based on are listed in the Technical
Data (Section 4.4, Figures 4-8 and 4-9).
If the inverse time trip characteristic is selected, it must be noted that a safety factor
of about 1.1 has already been included between the pickup value and the setting val-
ue. This means that a pickup will only occur if a current of about 1.1 times of the setting
value is present.
Using the time overcurrent stage ,(S (address ) earth faults can also be detect-
ed with weak fault currents. Since the starpoint current originates from one single cur-
rent transformer, it is not affected by summation effects evoked by different current
transformer errors like, for example, the zero sequence current derived from phase
currents. Therefore, this address can be set to very sensitive. Consider that the inrush
restraint function cannot operate below 20 % nominal current (lower limit of harmonic
filtering). An adequate time delay could be reasonable for very sensitive setting if in-
rush restraint is used.
Since this stage also picks up with earth faults in the network, the time multiplier (ad-
dress ',(S) has to be coordinated with the grading coordination chart of the
network for earth faults. Mostly, you may set shorter tripping times than for phase cur-
rents since a galvanic separation of the zero sequence systems of the connected pow-
er system sections is ensured by a transformer with separate windings.
The time multiplier can also be set to ∞. If set to infinity, the pickup of this function will
be indicated but the stage will not trip after pickup. If the IEp–stage is not required, se-
2.5 Time Overcurrent Protection for Earth Current
1057UT612 Manual
C53000–G1176–C148–1
lect address '07,'07(&+5 = 'HILQLWH7LPH when configuring the pro-
tection functions (Subsection 2.1.1).
If 'LVN(PXODWLRQ is set in address 72&'523287, dropout is being pro-
duced according to the dropout characteristic. For more information see Subsection
2.5.1.2, margin heading “Dropout for ANSI Curves” (page 100).
Dynamic Cold Load
Pickup An alternative set of pickup values can be set for each stage. It is selected automati-
cally-dynamically during operation. For more information on this function see Section
2.6 (page 108).
For the stages the following alternative values are set:
−for definite time overcurrent protection:
address pickup valu e ,(!!,
addres s delay time 7,(!!,
address pickup valu e ,(!,
addres s delay time 7,(!;
−for inverse time overcurrent protection acc. IEC curves:
address pickup valu e ,(S,
addres s time multiplier 7,(S;
−for inverse time overcurrent protection acc. ANSI curves:
address pickup val ue ,(S,
addres s time dial ',(S.
User Specif ied
Curves For inverse time overcurrent protection the user may define his own tripping and drop-
out characteristic. For configuration in DIGSI®4 a dialog box is to appear. Enter up to
20 pairs of current and tripping time values (Figure 2-58, page 86).
The procedure is the same as for phase current stages. See Subsection 2.4.2.1, mar-
gin heading “User Specified Curves”, page 86.
To create a user-defined tripping characteristic for earth current, the following has to
be set for configuration of the functional scope: address (Subsection 2.1.1) '07
,'07(&+5, option 8VHU'HILQHG38. If you also want to specify the dropout
characteristic, set option 8VHUGHI5HVHW.
Inrush Restraint In address ,Q5XVK5HVW(DUWK of the general settings (page 102, margin head-
ing “General”) the inrush restraint can be enabled (21) or disabled (2))). This inru sh
restraint only makes sense for transformers and if overcurrent time protection is acti-
vated on the earthed feeding side. Function parameters of the inrush restraint are set
in “Inrush”.
It is based on an evaluation of the 2nd harmonic present in the inrush current. The ratio
of 2nd harmonics to the fundamental +$50(DUWK (address ) is set to I2fN/
IfN = % as default setting. It can be used without being changed. To provide more
restraint in exceptional cases, where energizing conditions are particularly unfavour-
able, a smaller value can be set in the address before-mentioned.
If the current exceeds the value indicated in address ,0D[,Q5U(, no re-
straint will be provoked by the 2nd harmonic.
2 Functions
106 7UT612 Manual
C53000–G1176–C148–1
2.5.3 Setting Overview
The following list indicates the setting ranges and the default settings of a rated sec-
ondary current IN = 1 A. For a rated secondary current of IN = 5 A these values have
to be multiplied by 5. For settings in primary values, a conversion rate of the current
transformers has to be considered additionally.
Note:
Addresses which have an “A” attached to their end can only be changed in
DIGSI®4, Section „Additional Settings“.
Addr. Setting Title Setting Options Default Setting Comments
2401 EARTH O/C ON
OFF OFF Earth Time Overcurrent
2402 InRushRestEarth ON
OFF OFF InRush Restrained O/C Earth
2408A IE MAN. CLOSE IE>> instantaneously
IE> instantaneously
IEp instantaneously
Inactive
IE>> instanta-
neously O/C IE Manual Close Mode
2411 IE>> 0.05..35.00 A; ∞ 0.50 A IE>> Pickup
2412 T IE>> 0.00..60.00 sec; ∞ 0.10 sec T IE>> Time Delay
2413 IE> 0.05..35.00 A; ∞ 0.20 A IE> Pickup
2414 T IE> 0.00..60.00 sec; ∞ 0.50 sec T IE> Time Delay
2511 IE>> 0.05..35.00 A; ∞ 7.00 A IE>> Pickup
2512 T IE>> 0.00..60.00 sec; ∞ 0.00 sec T IE>> Time Delay
2513 IE> 0.05..35.00 A; ∞ 1.50 A IE> Pickup
2514 T IE> 0.00..60.00 sec; ∞ 0.30 sec T IE> Time Delay
2421 IEp 0.05..4.00 A 0.20 A IEp Pickup
2422 T IEp 0.05..3.20 sec; ∞ 0.20 sec T IEp Time Dial
2423 D IEp 0.50..15.00; ∞ 5.00 D IEp Time Dial
2424 TOC DROP-OUT Instantaneous
Disk Emulation Disk Emulat ion TOC Drop-out Charac teristic
2425 IEC CURVE Normal Inverse
Very Inverse
Extremely Inverse
Long Invers e
Normal Inverse IEC Curve
2426 ANSI CURVE Very Inverse
Inverse
Short Inverse
Long Invers e
Moderate ly Invers e
Extremely Inverse
Definite Inverse
Very Inverse ANSI Curve
2521 IEp 0.05..4.00 A 1.00 A IEp Pickup
2522 T IEp 0.05..3.20 sec; ∞ 0.50 sec T IEp Time Dial
2.5 Time Overcurrent Protection for Earth Current
1077UT612 Manual
C53000–G1176–C148–1
2.5.4 Information Overview
2523 D IEp 0.50..15.00; ∞ 5.00 D IEp Time Dial
2431 I/IEp PU T/TEp 1.00..20.00 I / Ip; ∞
0.01..999.00 Time Dial Pickup Curve IE/IEp - TIE/TIEp
2432 MofPU Res T/TEp 0.05..0.95 I / Ip; ∞
0.01..999.00 Time Dial Multiple of Pickup <-> TI/TIEp
2441 2.HARM. Earth 10..45 % 15 % 2nd harmonic O/C E in % of fundamental
2442 I Max InRr. E 0.30..25.00 A 7.50 A Maximum Current for Inr. Rest. O/C Earth
Addr. Setting Title Setting Options Default Setting Comments
F.No. Alarm Comments
01714 >BLK Earth O/C >BLOCK Earth time overcurrent
07573 >BLK E O/C Inr >BLOCK time overcurrent Earth InRush
01756 O/C Earth OFF Time Overcurrent Earth is OFF
01757 O/C Earth BLK Time Overcurrent Earth is BLOCKED
01758 O/C Earth ACT Time Overcurrent Earth is ACTIVE
01765 O/C Earth PU Time Overcurrent Earth picked up
07564 Earth InRush PU Earth InRush picked up
01724 >BLOCK IE>> >BLOCK IE>>
01854 IE>> BLOCKED IE>> BLOCKED
01831 IE>> picked up IE>> picked up
01832 IE>> Time Out IE>> Time Out
01833 IE>> TRIP IE>> TRIP
01725 >BLOCK IE> >BLOCK IE>
01853 IE> BLOCKED IE> BLOCKED
01834 I E> picked up IE> picked up
07552 IE> InRush PU IE> InRush picked up
01835 IE> Time Out IE> Time Out
01836 IE> TRIP IE> TRIP
01726 >BLOCK IEp >BLOCK IEp
01856 IEp BLOCKED IEp BLOCKED
01837 IEp picked up IEp picked up
07554 IEp InRush PU IEp InRush picked up
01838 IEp TimeOut IEp Time Out
01839 IEp TRIP IEp TRIP
2 Functions
108 7UT612 Manual
C53000–G1176–C148–1
2.6 Dynamic Cold Load Pickup for Time Overcurrent Protection
With the dynamic cold load pickup feature, it is possible to dynamically increase the
pickup values of the time overcurrent protection stages when dynamic cold load over-
current conditions are anticipated, i.e. when consumers have increased power con-
sumption after a longer period of dead condition, e.g. in air conditioning systems, heat-
ing systems, motors, etc. By allowing pickup values and the associated time delays to
increase dynamically, it is not necessary to incorporate cold load capability in the nor-
mal settings.
The dynamic cold load pickup feature operates with the time overcurrent protection
functions described in the sections 2.4 and 2.5. A set of alternative values can be set
for each stage.
2.6.1 Function Description
There are two primary methods used by the device to determine if the protected equip-
ment is de-energized:
•Via a binary input, an auxiliary contact in the circuit breaker can be used to deter-
mine if the circuit breaker is open or closed.
•The current flow monitoring threshold may be used to determine if the equipment is
de-energized.
You may select one of these criteria for the time overcurrent protection for phase cur-
rents (Section 2.4) and for that for residual current (Section 2.4). The device assigns
automatically the correct side for current detection or the breaker auxiliary contact.
The time overcurrent protection for earth current (Section 2.5) allows the breaker cri-
terion only if it is assigned to a certain side of the protected object (address , see
also Section 2.1.1 under margin header “Special Cases”, page 16); otherwise exclu-
sively the current criterion can be used.
If the device recognizes the protected equipment be de-energized via one of the crite-
ria above, then the alternative pickup values will become effective for the overcurrent
stages once a specified time delay has elapsed. Figure 2-66 shows the logic diagram
for dynamic cold load pickup function. The time &%2SHQ7LPH controls how long the
equipment can be de-energized before the dynamic cold load pickup function is acti-
vated. When the protected equipment is re-energized (i.e. the device receives input
via a binary input that the assigned circuit breaker is closed or the assigned current
flowing through the breaker increases above the current flow monitoring threshold),
the active time $FWLYH7LPH is initiated. Once the active time has elapsed, the pick-
up values of the overcurrent stages return to their normal settings. The active time
controls how long dynamic cold load pickup settings remain in place once the protect-
Note:
Dynamic cold load pickup is in addition to the four setting groups (A to D) which are
configured separately.
2.6 Dynamic Cold Load Pickup for Time Overcurrent Protection
1097UT612 Manual
C53000–G1176–C148–1
ed object is re-energized. Upon re-energizing of the equipment, if the measured cur-
rent values are below the normal pickup settings, an alternative time delay referred to
as the 6WRS7LPH is also initiated. As in the case with the active time, once this time
has elapsed, the pickup values of overcurrent stages change from the dynamic cold
load pickup values to their normal settings. The 6WRS7LPH controls how long dynam-
ic cold load pickup settings remain in place given that measured currents are below
the normal pickup settings. To defeat this time from switching the overcurrent stages
pickup settings back to normal, it may be set to ∞ or blocked via the binary input “!%/.
&/3VWS7LP”.
Figure 2-65 Cold load pickup timing sequence
Circu it break er
closed
open
“CB open time”
“Active time” Possible shorter
CLP due to
“Stop Time”
Operating state
“Normal”
pickup levels
“DCP” settings active
“normal” settings active
“Stop time”
Pickup
Dropout
Trip, if increased power demand
is present after “active time”
Increased power consumption
after long outage
“CB open time”
&%2SHQ7LPH
address
$FWLYH7LPH
address
6WRS7LPH
address
2 Functions
110 7UT612 Manual
C53000–G1176–C148–1
If an overcurrent stage picks up while the dynamic settings are enabled, elapse of the
active time $FWLYH7LPH will not restore the normal pickup settings until drop out of
the overcurrent stage occurs based on the dynamic settings.
If the dynamic cold load pickup function is blocked via the binary input “!%/2&.&/3”,
all triggered timers will be immediately reset and all “normal” settings will be restored.
If blocking occurs during an on-going fault with dynamic cold load pickup functions en-
abled, the timers of all overcurrent stages will be stopped, and then restarted based
on their “normal” duration.
During power up of the protective relay with an open circuit breaker, the time delay &%
2SHQ7LPHis started, and is processed using the normal settings. Therefore, when
the circuit breaker is closed, the normal settings are effective.
Figure 2-65 shows a timing diagram, Figure 2-66 describes the logic for cold load pick-
up function.
Figure 2-66 Logic diagram for dynamic cold load pickup feature — illustrated for phase
overcurrent protection stage on side 1
Circuit breaker
open
283
IL1, IL2, IL3
„1“
&
S Q
R
>BLK CLP stpTim
≥1
>CB1 3p Closed
>CB1 3p Open
≥
1
&≥1
2))
21
„1“
>BLOCK CLP
CLP running
Meas. release
CLP BLOCKED
CLP OFF
&
≥1
Ι<
Max. of
T0
&
dynamic pickup T0
T0
IE Dyn.set. ACT
Processing of the
cold load pickup values
in the overcurrent stages
Exceeding one of the the dynamic cold load
pick-up thresholds of the overcurrent stages
>CB1 configured.NO
>CB1 configured NC ≥1&
normal pickup
Exceeding one of the “normal” pick-up
thresholds of the overcurrent stages
FNo 173 1
FNo 410
FNo 411
FNo 1730 FNo 1995
FNo 199 6
FNo 1994
FNo 2000
3I0 Dyn.set.ACT
FNo 1999
I Dyn.set. ACT
FNo 1998
&2/'/2$'3,&.83
&%2SHQ7LPH
6WDUW&/33KDVH
6WRS7LPH
$FWLYH7LPH
%UHDNHU6,!
1R&XUUHQW
%UHDNHU&RQWDFW
2.6 Dynamic Cold Load Pickup for Time Overcurrent Protection
1117UT612 Manual
C53000–G1176–C148–1
2.6.2 Setting th e Function Parameters
General Dynamic cold load pickup can only be enabled if address &ROGORDG3LFNXS
was set to (QDEOHG. If this feature is not required, address is set to 'LVDEOHG.
Under address &2/'/2$'3,&.83 the function can be switched 21 or 2)).
Cold Load Criteria You can determine the criteria for dynamic switchover to the cold load pickup values
for all protective functions which allow this switchover. Select the current criterion 1R
&XUUHQW or the breaker position criterion %UHDNHU&RQWDFW:
address 6WDUW&/33KDVH for the phase current stages,
address 6WDUW&/3, for the residual current stages.
The current criterion takes the currents of that side where the corresponding protective
function is assigned to. When using the breaker position criterion, the auxiliary contact
of the assigned side must inform the device via a binary input about the breaker posi-
tion.
The time overcurrent protection for earth current allows only the current criterion be-
cause it cannot assigned to any circuit breaker. (address 6WDUW&/3(DUWK
is always 1R&XUUHQW).
Timers There are no specific procedures on how to set the time delays at addresses &%
2SHQ7LPH, $FWLYH7LPH and 6WRS7LPH. These time delays must be
based on the specific loading characteristics of the equipment being protected, and
should be selected to allow the brief overloads associated with dynamic cold load con-
ditions.
Cold Load Pickup
Values The dynamic pickup values and time delays associated with the time overcurrent stag-
es are set in the related addresses of these stages themselves.
2.6.3 Setting Overview
Addr. Setting Title Setting Options Default Setting Comments
1701 COLDLOAD PICKUP OFF
ON OFF Cold-Load-Pickup Function
1702 Start CLP Phase No Current
Breaker Contact No Current Start Condition CLP for O/C
Phase
1703 Start CLP 3I0 No Current
Breaker Contact No Current Start Condition CLP for O/C 3I0
1704 Start CLP Earth No Current
Breaker Contact No Current Start Condition CLP for O/C
Earth
1711 CB Open Time 0..21600 sec 3600 sec Circuit Breaker OPEN Time
1712 Active Time 1..21600 sec 3600 sec Active Time
2 Functions
112 7UT612 Manual
C53000–G1176–C148–1
2.6.4 Information Overview
1713 Stop Time 1..600 sec; ∞ 600 sec Stop Time
Addr. Setting Title Setting Options Default Setting Comments
F.No. Alarm Comments
01730 >BLOCK CLP >BLOCK Cold-Load-Pickup
01731 >BLK CLP stpTim >BLOCK Cold-Load-Pickup stop timer
01994 CLP OFF Cold-Load-Pickup switched OFF
01995 CLP BLOCKED Cold-Load-Pickup is BLOCKED
01996 CL P running Cold-Load-Pickup is RUNNING
01998 I Dyn.se t. ACT Dynami c settings O/C Phase are ACTIVE
01999 3I0 Dyn.set.ACT Dynamic settings O/C 3I0 are ACTIVE
02000 IE Dyn.set. ACT Dynamic settings O/C Earth are ACTIVE
2.7 Single-Phase Time Overcurrent Protection
1137UT612 Manual
C53000–G1176–C148–1
2.7 Single-Phase Time Overcurrent Protection
The single-phase time overcurrent protection can be assigned either to the measured
current input I7 or I8. It can be used for any desired single-phase application. If as-
signed to I8 a very sensitive pickup threshold is possible (smallest setting 3 mA at the
current input).
Examples for application are high-impedance unit protection or highly sensitive tank
leakage protection. These applications are covered in the following subsections: Sub-
section 2.7.2 for high-impedance protection, and Subsection 2.7.3 for high-sensitivity
tank leakage protection.
The single-phase time overcurrent protection comprises two definite time delayed
stages which can be combined as desired. If you need only one stage, the other can
be set to infinity.
2.7.1 Function Description
The measured current is filtered by numerical algorithms. Because of the high sensi-
tivity a particular narrow band filter is used.
For the single-phase I>> stage, the current measured at the configured current input
(I7 or I8) is compared with the setting value 3KDVH,!!. Current above the pickup
value is detected and annunciated. When the delay time 73KDVH,!! has expire d,
tripping command is issued. The reset value is approximately 5 % below the pickup
value for currents > 0.3 ·I
N
.
For the single-phase I> stage, the current measured at the configured current input is
compared with the setting value 3KDVH,!. Current above the pickup value is de-
tected and annunciated. When the delay time 73KDVH,! has expired, tripping
command is issued. The reset value is approximately 5 % below the pickup value for
currents > 0.3 ·I
N
.
Both stages form a two-stage definite time overcurrent protection whose tripping char-
acteristic is illustrated in Figure 2-67.
When high fault current occurs, the current filter can be bypassed in order to achieve
a very short tripping time. This is automatically done when the instantaneous value of
the current exceeds the set value I>> by the factor 2·√2.
The logic diagram of the single-phase time overcurrent protection is shown in Figure
2-68.
2 Functions
114 7UT612 Manual
C53000–G1176–C148–1
Figure 2-67 Two-stage tripping characteristic of the single-phase time overcurrent protection
Figure 2-68 Logic diagram of the singl e-phase time overcurrent protection — example for detection of the current
at input I8
t
I
,!!,!
7,!!
7,!
Tripping
'LVDEOHG
21
2))
„1“
>BLK 1Ph. I>
>BLK 1Ph. O/C O/C 1Ph. BLK
O/C 1Ph. OFF
O/C 1Ph I> BLK
O/C 1Ph I> TRIP
O/C 1Ph I> PU
FNo 597 4
FNo 597 5
FNo 596 6
FNo 5962
FNo 596 1
FNo 5952
FNo 5951
Meas. release
I>
3KDVH,!
&
I
7
I
8
'073+$6(
T0
FNo 5977
FNo 5979
Meas. release
I>>
3KDVH,!!
&
T0
2·√2·I>>
≥1
>BLK 1Ph. I>> O/C 1Ph I>> BLK
FNo 596 7
FNo 5953
O/C 1Ph I>> PU
O/C1Ph I>> TRIP
≥
1
≥
1
O/C 1Ph TRIP
FNo 597 2
O/C 1Ph PU
FNo 5971
≥
1
O/C 1Ph. ACT
FNo 5963
3KDVH2&
73KDVH,!!
73KDVH,!
XQVHQV&7
VHQV&7
2.7 Single-Phase Time Overcurrent Protection
1157UT612 Manual
C53000–G1176–C148–1
2.7.2 High-Impedance Differential Protection
Application
Example With the high-impedance scheme all current transformers at the limits of the protection
zone operate parallel to a common relatively high-ohmic resistance R whose voltage
is measured. With 7UT612 the voltage is registered by measuring the current through
the external resistor R at the sensitive current measuring input I8.
The current transformers have to be of equal design and provide at least a separate
core for high-impedance protection. They also must have the same transformation
ratio and approximately the same knee-point voltage.
With 7UT612 the high-impedance principle is very suited for detection of earth faults
in transformers, generators, motors and shunt reactors in earthed systems. High-im-
pedance protection can be used instead of or in addition to the restricted earth fault
protection (see Section 2.3). Of course, the sensitive current measuring input I8 can
only be used for high-impedance protection
or
tank leakage protection (Subsection
2.7.3).
Figure 2-69 (left side) illustrates an application example for an earthed transformer
winding or an earthed motor/generator. The example on the right side shows a non-
earthed transformer winding or an non-earthed motor/generator where the earthing of
the system is assumed somewhere else.
Figure 2-69 Earth fault protection according to the high-impedance sche me
High-Impedance
Principle The high-impedance principle is explained on the basis of an earthed transformer
winding (Fi gure 2-7 0).
No zero sequence current will flow during normal operation, i.e. the starpoint current
is ISP = 0 and the line currents are 3I0 = IL1 + IL2 + IL3 = 0.
With an external earth fault (Figure 2-70, left side), whose fault current is supplied via
the earthed starpoint, the same current flows through the transformer starpoint and the
phases. The corresponding secondary currents (all current transformers having the
same transformation ratio) compensate each other, they are connected in series.
Across resistance R only a small voltage is generated. It originates from the inner re-
sistance of the transformers and the connecting cables of the transformers. Even if
any current transformer experiences a partial saturation, it will become low-ohmic for
the period of saturation and creates a low-ohmic shunt to the high-ohmic resistor R.
ISP
IL1
IL2
IL3
L1
L2
L3
R
IL1
IL2
IL3
L1
L2
L3
R
2 Functions
116 7UT612 Manual
C53000–G1176–C148–1
Thus, the high resistance of the resistor also has an stabilizing effect (the so-called
resistance stabilization).
Figure 2-70 Earth fault protection using the high-impedance principle
In case there is an earth fault in the protection zone (Figure 2-70, right side), a star-
point current ISP will be present for sure. The earthing conditions in the rest of the net-
work determine how strong a zero sequence current from the system is. A secondary
current which is equal to the total fault current tries to pass through the resistor R.
Since the latter is high-ohmic, a high voltage emerges immediately. Therefore, the cur-
rent transformers get saturated. The RMS voltage across the resistor approximately
corresponds to the knee-point voltage of the current transformers.
Resistance R is dimensioned such that, even with the very lowest earth fault current
to be detected, it generates a secondary voltage which is equal to the half knee-point
voltage of current transformers (see also notes on dimensioning in Subsection 2.7.4).
High-Impedance
Protection with
7UT612
With 7UT612 the sensitive measuring input I8 is used for high-impedance protection.
As this is a current input, the protection detects current through the resistor instead of
the voltage across the r esistor R.
Figure 2-71 shows the connection example. The 7UT612 is connected in series to re-
sistor R and measures its current.
Varistor V limits the voltage when inner faults occur. High voltage peaks emerging with
transformer saturation are cut by the varistor. At the same time, voltage is smoothed
without reduction of the mean value.
For protection against overvoltages it is also important that the device is directly con-
nected to the earthed side of the current transformers so that the high voltage at the
resistor can be kept away from the device.
For generators, motors and shunt reactors high-impedance protection can be used
analogously. All current transformers at the overvoltage side, the undervoltage side
and the current transformer at the starpoint have to be connected in parallel when us-
ing auto-transformers.
In principle, this scheme can be applied to every protected object. When applied as
busbar protection, for example, the device is connected to the parallel connection of
all feeder current transformers via the resistor.
ISP
IL1
IL2
IL3
L1
L2
L3
RISP
IL1
IL2
IL3
L1
L2
L3
R
2.7 Single-Phase Time Overcurrent Protection
1177UT612 Manual
C53000–G1176–C148–1
Figure 2-71 Connection scheme for earth fault protection according to the high-impedance
principle
2.7.3 Tank Leakage Protection
Application
Example The tank leakage protection has the task to detect earth leakage — even high-ohmic
— between a phase and the frame of a power transformer. The tank must be isolated
from earth (refer to Figure 2-72). A conductor links the tank to earth, and the current
through this conductor is fed to a current input of the relay. When a tank leakage oc-
curs, a fault current (tank leakage current) will flow through the earthing conductor to
earth. This tank leakage current is detected by the single-phase overcurrent protection
as an overcurrent; an instantaneous or delayed trip command is issued in order to dis-
connect all sides of the transformer.
The high-sensitivity current input I8 is used for tank leakage protection. Of course, this
current input can only be used once: either for tank leakage protection or for high-im-
pedance differential protection according to Subsection 2.7.2.
Figure 2-72 Principle of tank leakage protection
ISP 7UT612
IL1
IL2
IL3
I8
L1
L2
L3
R
V
isolated
7UT612
I8
2 Functions
118 7UT612 Manual
C53000–G1176–C148–1
2.7.4 Setting the Function Parameters
General In address 3KDVH2&, the single-phase time overcurrent protection can
switched 21 or 2)).
The settings depend on the application. The setting ranges depend on whether the
cur rent at i nput I7 or at I8 is us ed. This was dete rmined du ring con figurat ion of t he pro-
tective functions (Subsection 2.1.1 under “Special Cases”, page 16) in address :
'073+$6( = XQVHQV&7
In this case you set the pickup value 3KDVH,!! in address , t he pick up valu e
3KDVH,! in address . If you need only one stage, set the other to ∞.
'073+$6( = VHQV&7
In this case you set the pickup value 3KDVH,!! in address , t he pick up valu e
3KDVH,! in address . If you need only one stage, set the other to ∞.
If you need a trip time delay, set it in address 73KDVH,!! for the I>> stage,
and/or in address 73KDVH,! for the I> stage. With setting s no delay takes
place.
The set times are pure delay times which do not include the inherent operating times
of the protection stages. If you set a time to ∞ the associated stage does not trip but
pickup annunciation will occur.
Special notes are given in the following for the use as high-impedance unit protection
and tank leakage protect ion.
Use as High-
Impedance
Protection
When used as high-impedance protection, only the pickup value of the single-phase
overcurrent protection is set on the 7UT612 to detect overcurrent at the current input
I8. Consequently, during configuration of the protective functions (Subsection 2.1.1
under “Special Cases”, page 16), address is set '073+$6( = VHQV&7.
But, the entire function of the high-impedance unit protection is dependent on the co-
ordination of the current transformer characteristics, the external resistor R and the
voltage across R. The following three header margins give information about these
considerations.
Current
Transformer Data
for High-Impedance
Protection
All current transformers must have identical transformation ratio and nearly equal
knee-point voltage. This is usually the case if they are of equal design and identical
rated data. If the knee-point voltage is not stated, it can be approximately calculated
from the rated data of a CT as follows:
where UKPV = knee-point voltage of the CT
Ri = Internal burden of the CT
PN = rated power of the CT
IN = rated secondary current of the CT
ALF = rated accuracy limit factor of the CT
The rated current, rated power and accuracy limit factor are normally stated on the rat-
ing plate of the current transformer, e.g.
UKPV RiPN
IN2
--------+
ALF IN
⋅⋅
=
2.7 Single-Phase Time Overcurrent Protection
1197UT612 Manual
C53000–G1176–C148–1
Current transformer 800/5; 5P10; 30 VA
That means
IN = 5 A (from 800/5)
ALF = 10 (from 5P10)
PN = 30 VA
The internal burden is often stated in the test report of the current transformer. If not it
can be derived from a DC measurement on the secondary winding.
Calculation example:
Current transformer 800/5; 5P10; 30 VA with Ri = 0.3 Ω
or
Current transformer 800/1; 5P10; 30 VA with Ri = 5 Ω
Besides the CT data, the resistance of the longest connection lead between the CTs
and the 7UT612 device must be known.
Stability with High-
Impedance
Protection
The stability condition is based on the following simplified assumption: If there is an
external fault,
one
of the current transformers gets totally saturated. The other ones
will continue transmitting their (partial) currents. In theory, this is the most unfavour-
able case. Since, in practice, it is also the saturated transformer which supplies cur-
rent, an automatic safety margin is guaranteed.
Figure 2-73 shows a simplified equivalent circuit. CT1 and CT2 are assumed as ideal
transformers with their inner resistances Ri1 and Ri2. Ra are the resistances of the con-
necting cables between current transformers and resistor R. They are multiplied by 2
as they have a go- and a return line. Ra2 is the resistance of the longest connecting
cable.
CT1 tran smits curre nt I1. CT2 shall be saturated. Because of saturation the transform-
er represents a low-resistance shunt which is illustrated by a dashed short-circuit line.
R >> (2Ra2 + Ri2) is a further prerequisite.
Figure 2- 73 Simplified equivalent circuit of a circulating current system for high-impedance
differential protection
UKPV RiPN
IN2
--------+
ALF IN0.3 Ω30 VA
5 A()
2
----------------+
10 5 A 75 V
=
⋅⋅
=
⋅⋅
=
U
KPV RiPN
IN2
--------+
ALF IN5 Ω30 VA
1 A()
2
----------------+
10 1 A 350 V
=
⋅⋅
=
⋅⋅
=
R
R
i1 2Ra1 2Ra2 Ri2
CT1 CT2I1
2 Functions
120 7UT612 Manual
C53000–G1176–C148–1
The voltage across R is then
UR ≈ I1 · (2Ra2 + Ri2)
It is assumed that the pickup value of the 7UT612 corresponds to half the knee-point
voltage of the current transformers. In the balanced case results
UR = UKPV/2
This r es ul ts in a s tab il it y l imit ISL, i.e. the maximum through-fault current below which
the scheme remains stable:
Calculation example:
For the 5 A CT like above with UKPV = 75 V and Ri = 0.3 Ω
longest CT connection lead 22 m with 4 mm2 cross-section, results in Ra ≈ 0,1 Ω
that is 15 × rated current or 12 kA primary.
For the 1 A CT like above with UKPV = 350 V and Ri = 5 Ω
longest CT connection lead 107 m with 2.5 mm2 cross-s ection, re sults in Ra ≈ 0.75 Ω
that is 27 × rated current or 21,6 kA primary.
Sensitivity with
High Impedance
Protection
As before mentioned, high-impedance protection is to pick up with approximately half
the knee-point voltage of the current transformers. Resistance R can be calculated
from it.
Since the device measures the current flowing through the resistor, resistor and meas-
uring input of the device are to be connected in series (see also Figure 2-71). Since,
furthermore, the resistance shall be high-ohmic (condition: R >> 2Ra2 + Ri2, as above
mentioned), the inherent resistance of the measuring input can be neglected. The re-
sistance is then calculated from the pickup current Ipu and the half knee-point voltage:
Calculation example:
For the 5 A CT like above with
required pickup value Ipu = 0.1 A (corresponding to 16 A primary)
For the 1 A CT like above
required pickup value Ipu = 0.05 A (corresponding to 40 A primary)
ISL UKPV 2⁄
2R
a2
⋅Ri2
+
--------------------------------=
ISL UKPV 2⁄
2R
a2
⋅Ri2
+
-------------------------------- 37.5 V
20.1 Ω⋅ 0.3 Ω
+
-------------------------------------------- 75 A
===
ISL UKPV 2⁄
2R
a2
⋅Ri2
+
-------------------------------- 175 V
20.75 Ω⋅ 5
+Ω
------------------------------------------ 27 A
===
RUKPV 2⁄
Ipu
---------------------=
RUKPV 2⁄
Ipu
--------------------- 75 V 2⁄
0.1 A
------------------- 375 Ω===
RUKPV 2⁄
Ipu
--------------------- 350 V 2⁄
0.05 A
----------------------- 3500 Ω===
2.7 Single-Phase Time Overcurrent Protection
1217UT612 Manual
C53000–G1176–C148–1
The required short-term power of the resistor is derived from the knee-point voltage
and the resistance:
As this power only appears during earth faults for a short period of time, the rated pow-
er can be smaller by approx. factor 5.
The varistor (see also Figure 2-71) must be dimensioned such that it remains high-
ohmic up to the knee-point voltage, e.g.
approx. 100 V for the 5 A CT example,
approx. 500 V for the 1 A CT example.
For 7UT612, the pickup value (0.1 A or 0.05 A in the example) is set in address
3KDVH,!. Stage I>> is not required (Address 3KDVH,!! = ∞).
The trip command of the protection can be delayed in address 73KDVH,!.
This time delay is usually set to 0.
If a higher number of current transformers is connected in parallel, e.g. when using as
busbar protection with several feeders, the magnetizing currents of the transformers
connected in parallel cannot be neglected anymore. In this case, the magnetizing cur-
rents at the half knee-point voltage (corresponds to the setting value) have to be
summed. These magnetizing currents reduce the current through the resistor R.
Therefore the actual pickup value will be correspondingly higher.
Use as Tank
Leakage Protection If the single-phase time overcurrent protection is used as tank leakage protection,
merely the pickup value for the current at the input I8 is set on 7UT612. Consequently,
during configuration of the protective functions (Subsection 2.1.1 under “Special Cas-
es”, page 16) had been set under address : '073+$6( = VHQV&7.
The tank leakage protection is a highly sensitive overcurrent protection which detects
the leakage current between the isolated transformer tank and earth. Its sensitivity is
set in address 3KDVH,!. The I>> stage is not used (address 3KDVH
,!! = ∞).
The trip command can be delayed under address 73KDVH,!. Normally, this
delay time is set to .
2.7.5 Setting Overview
The following list indicates the setting ranges and the default settings of a rated sec-
ondary current IN = 1 A. For a rated secondary current of IN = 5 A these values have
to be multiplied by 5. For settings in primary values, a conversion rate of the current
transformers has to be considered additionally.
PRUKPV2
R
----------------- 75 V()
2
375 Ω
-------------------- 15 W
===
PRUKPV2
R
----------------- 350 V()
2
3500 Ω
----------------------- 35 W
===
for the 5 A CT example
for the 1 A CT example
2 Functions
122 7UT612 Manual
C53000–G1176–C148–1
2.7.6 Information Overview
Addr. Setting Title Setting Options Default Setting Comments
2701 1Phase O/C OFF
ON OFF 1P hase Time Overcurrent
2702 1Phase I>> 0.05..35.00 A; ∞ 0.50 A 1Phase O/C I>> Pickup
2703 1Phase I>> 0.003..1.500 A; ∞ 0.300 A 1Phase O/C I>> Pickup
2704 T 1Phase I>> 0.00..60.00 sec; ∞ 0.10 sec T 1Phase O/C I>> Time Delay
2705 1Phase I> 0.05..35.00 A; ∞ 0.20 A 1Phase O/C I> Pickup
2706 1Phase I> 0.003..1.500 A; ∞ 0.100 A 1Phase O/C I> Pickup
2707 T 1Phase I> 0.00..60.00 sec; ∞ 0.50 sec T 1Phase O/C I> Time Delay
F.No. Alarm Comments
05951 >BLK 1Ph. O/C >BLOCK Time Overcurrent 1Phase
05952 >BLK 1Ph. I> >BLOCK Time Overcurrent 1Ph. I>
05953 >BLK 1 Ph. I>> >BLOCK Time Overcurrent 1Ph. I>>
05961 O/C 1Ph. OFF Time Overcurrent 1Phase is OFF
05962 O/C 1Ph. BLK Time Overcurrent 1Phase is BLOCKED
05963 O/C 1Ph. ACT Time Overcurrent 1Phase is ACTIVE
05966 O/C 1Ph I> BLK Time Overcurrent 1Phase I> BLOCKED
05967 O/C 1Ph I>> BLK Time Overcurrent 1Phase I>> BLOCKED
05971 O/C 1Ph PU Time Overcurrent 1Phase picked up
05972 O/C 1Ph TRIP Time Overcurrent 1Phase TRIP
05974 O/C 1Ph I> PU Time Overcurrent 1Phase I> picked up
05975 O/C 1Ph I> TRIP Time Overcurrent 1Phase I> TRIP
05977 O/C 1Ph I>> PU Time Overcurrent 1Phase I>> picked up
05979 O/C1Ph I>> TRIP Time Overcurrent 1Phase I>> TRIP
05980 O/C 1Ph I: Time Overcurrent 1Phase: I at pick up
2.8 Unbalanced Load Protection
1237UT612 Manual
C53000–G1176–C148–1
2.8 Unbalanced Load Protection
General Negative sequence protection detects unbalanced loads on the system. In addition, it
may be used to detect interruptions, faults, and polarity problems with current trans-
formers. Furthermore, it is useful in detecting phase-to-ground, phase-to-phase, and
double phase-to-ground faults with magnitudes lower than the maximum load current.
Negative sequence protection is reasonable only for three-phase equipment. It is,
therefore, not available in case of 35272%-(&7 = SK%XVEDU or SKDVH
WUDQVI (address , see Subsection 2.1.1).
The application of unbalanced load protection to generators and motors has a special
significance. The negative sequence currents associated with unbalanced loads cre-
ate counter-rotating fields in three-phase induction machines, which act on the rotor
at double frequency. Eddy currents are induced at the rotor surface, and local over-
heating at the transition between the slot wedges and the winding bundles takes
place.
In addition, the threat of thermal overload exists when motors are supplied by unbal-
anced system voltages. Because the motor represents a small impedance to negative
sequence voltages, small voltage imbalances can lead to large negative sequence
currents.
The unbalanced load protection operates always on the side of the protected object to
which it is assigned during configuration of the protective functions. (see Subsection
2.1.1 under “Special Cases”, page 17, address ).
The unbalanced load protection consists of two definite time stages and one inverse
time stage which latter may operate according to an IEC or ANSI characteristic.
2.8.1 Function Description
Determination of
Unbalanced Load The unbalanced load protection of 7UT612 uses numerical filters to dissect the phase
currents into their symmetrical components. If the negative sequence component of
the phase currents is at least 10 % of the nominal device current, and all phase cur-
rents are less than four times the nominal device current, then the negative sequence
current is fed into the current detector elements.
2.8.1.1 Definite Time Stages
The definite time characteristic is of two-stage design. When the negative sequence
current exceeds the set threshold ,! the timer 7,! is started and a corresponding
pickup message is output. When the negative sequence current exceeds the set
threshold ,!! of the high-set stage the timer 7,!! is started and a corresponding
pickup message is output.
When a delay time is expired trip command is issued (see Figure 2-74).
2 Functions
124 7UT612 Manual
C53000–G1176–C148–1
Figure 2-74 Trip characteristic of the definite time unbalanced load protection
2.8.1.2 Inverse Time Stage
The inverse time overcurrent stage operates with a tripping characteristic either ac-
cording to the IEC- or the ANSI-standard. The characteristic curves and the corre-
sponding equations are represented in the Technical Data (Figures 4-7 and 4-8 in
Section 4.4). The inverse time characteristic superposes the definite time stages I2>>
and I2> (see Subsection 2.8.1.1).
Pickup, Trip The negative sequence current I2 is compared with setting value ,S. When negative
sequence current exceeds 1.1 times the setting value, a pickup annunciation is gen-
erated. The tripping time is calculated from the negative sequence current according
to the characteristic selected. After expiration of the time period a tripping command
is output. Figure 2-75 shows the qualitative course of the characteristic. In this figure
the overlapping stage I2>> is represented as a dashed line.
Dropout for IEC
Curves Dropout of the stage using an IEC curves occurs when the current decreases below
about 95 % of the pickup value. A renewed pickup will cause a renewed start of the
delay timers.
Dropout for ANSI
Curves Using the ANSI-characteristics you can determine whether the dropout of the stage is
to follow right after the threshold undershot or whether it is evoked by disk emulation.
“Right after” means that the pickup drops out when the pickup value of approx. 95 %
is undershot. For a new pickup the time counter starts at zero.
The disk emulation evokes a dropout process (time counter is decrementing) which
begins after de-energization. This process corresponds to the back turn of a Ferraris-
disk (explaining its denomination “disk emulation”). In case several faults occur suc-
cessively, it is ensured that due to the inertia of the Ferraris-disk the “History” is taken
into consideration and the time behaviour is adapted. This ensures a proper simulation
Tripping
I2/IN
I2>I2>>
t
T I2>
T I2>>
2.8 Unbalanced Load Protection
1257UT612 Manual
C53000–G1176–C148–1
of the temperature rise of the protected object even for extremely fluctuating unbal-
anced load values. The reset begins as soon as 90 % of the setting value is undershot,
in correspondence to the dropout curve of the selected characteristic. Within the range
of the dropout value (95 % of the pickup value) and 90 % of the setting value, the in-
crementing and the decrementing processes are in idle state. If 5 % of the setting val-
ue is undershot, the dropout process is finished, i.e. when a new pickup is evoked, the
timer starts again at zero.
Figure 2-75 Trip characteristic of the inverse time unbalanced load protection (with
su perimposed definite time st age)
Logic Figure 2-76 shows the logic diagram of the unbalanced load protection. The protection
may be blocked via a binary input. That way, pickups and time stages are reset.
When the tripping criterion leaves the operating range of the overload protection (all
phase currents below 0.1 ·I
N
or at least one phase current is greater than 4 · IN), the
pickups of all unbalanced load stages drop off.
I2/IN
I2p I2>>
t
T I2>>
superimposed
I2>> stage
Tripping
2 Functions
126 7UT612 Manual
C53000–G1176–C148–1
Figure 2-76 Logic diagram of the unbalanced load protection — illustrated for IEC–
characteristic
2.8.2 Setting the Function Parameters
General During configuration of the functional scope (Subsection 2.1.1, margin heading “Spe-
cial Cases”, page 17) the sides of the protected object were determined in address
. The corresponding characteristic type was selected in address . In the fol-
lowing only settings for the characteristic selected can be performed. The definite time
stages I2>> and I2> are always available.
Unbalanced load protection only makes sense with three-phase protected objects. For
35272%-(&7 = SK%XVEDU or SKDVHWUDQVI (address , see Subsection
2.1.1) the following settings are not available.
In address 81%$/$1&(/2$' the function can be set to 21 or 2)).
Definite Time
Stages I2>>, I2> A two-stage characteristic enables the user to set a short time delay (address 7
,!!) for the upper stage (address ,!!) and longer time delay (address
7,!) for the lo wer stage (a ddress ,!). Stage I2>, for example, can be used
as alarm stage, stage I2>> as tripping stage. Setting ,!! to a percentage higher than
60 % makes sure that no tripping is performed with stage I2>> in case of phase failure.
I2
>BLOCK I2
2))
21
„1“
I2 OFF
I2 BLOCKED
I2
t
I2 ACTIVE
T0
≥1I2 TR IP
I2>> picked up
I2p picked up
I2> picked up
FNo 5166
FNo 5165
FNo 5170
FNo 5159
FNo 5152
FNo 5153
FNo 5151
FNo 5143
T0
Meas. release
I2>
I2>>
1.1 I2p
≥
1
'HILQLWH7LPH
81%$/$1&(/2$'
,S
,!
,!!
7,!
7,S
7,!!
,(&&859(
,(&&859(
81%$//2$'&+5
72&,(&
72&$16,
2.8 Unbalanced Load Protection
1277UT612 Manual
C53000–G1176–C148–1
The magnitude of the negative sequence current when one phase is lost, is
On the other hand, with more than 60 % negative sequence current, a two-phase fault
in the system may be assumed. Therefore, the delay time 7,!! must be coordinat-
ed with the time grading of the system.
On line feeders, negative sequence protection may serve to identify low-current un-
symmetrical faults below the pickup values of the time overcurrent protection. In this
case:
−a two-phase fault with fault current I produces a negative sequence current
−a single-phase fault with fault current I produces a negative sequence current
With more than 60 % negative sequence current, a two-phase fault can be assumed.
The delay time 7,!! must be coordinated with the time grading of the system.
For a power transformer, negative sequence protection may be used as sensitive pro-
tection for low magnitude phase-to-ground and phase-to-phase faults. In particular,
this application is well suited for delta-wye transformers where low side phase-to-
ground faults do not generate a high side zero sequence current.
The relationship between negative sequence currents and total fault current for phase-
to-phase faults and phase-to-ground faults are valid for the transformer as long as the
turns ratio is taken into consideration.
Considering a power transformer with the following data:
the following faults may be detected at the lower-voltage side:
If the pickup setting (PU) of the device on the high side is set to ,! = 0.1 A, then a
phase-to-ground fault current of I = 3 · (110 kV/20 kV) · ,! = 3 · 0.1 · 100 A = 165 A
and a phase-to-phase fault of √3 · (110/20) · 0.1 · 100 A = 95 A can be detected on
the low side. This corresponds to 36 % and 20 % of the power transformer rating.
To prevent false operation for faults in other zones of protection, the delay time 7,!
must be coordinated with the time grading of other relays in the system.
For generators and motors, the setting depends on the permissible unbalanced load
of the protected object. It is reasonable to set the I2> stage to the continuously permis-
sible negative sequence current and a long time delay in order to obtain an alarm
stage. The I2>> stage is then set to a short-term negative sequence current with the
delay time permitted here.
Rated apparent power SNT = 16 MVA
Nominal high side voltage UHS = 110 kV
Nominal low side voltage ULS = 20 kV
Transformer connection Dyn5
I213
------- I
⋅0.58 I⋅
==
I
2
1
3
------- I
⋅0.58 I⋅
==
I
2
1
3
---I
⋅0.33 I⋅
==
2 Functions
128 7UT612 Manual
C53000–G1176–C148–1
Example:
To achieve a better adaptation to the protected object, use the additional inverse-time
stage.
Inverse Time
Stage I2p with
IEC curves
Having selected an inverse time tripping characteristic the thermal load of a machine
caused by unbalanced load can be simulated easily. Use the characteristic which is
most similar to the thermal unbalanced load curve of the machine manufacturer.
With the IEC-characteristics (address 81%$//2$'&+5 = 72&,(&, see also
Subsection 2.1.1) the following characteristics are made available in address
,(&&859(:
1RUPDO,QYHUVH (type A according to IEC 60255–3),
9HU\,QYHUVH (type B according to IEC 60255–3),
([WUHPHO\,QY (type C according to IEC 60255–3).
The characteristics and equations they are based on are listed in the Technical Data
(Section 4.4, Figure 4-7).
If an inverse-time characteristic is selected, it must be noted that a safety factor of
about 1.1 has already been included between the pickup value and the setting value.
This means that a pickup will only occur if an unbalanced load of about 1.1 times the
setting value of ,S (Ad dress ) is present. The function will reset as soon as the
value undershoots 95 % of the pickup value.
The corresponding time multiplier is accessible via address 7,S.
The time multiplier can also be set to ∞. If set to infinity, the pickup of this function will
be indicated but the stage will not be able to trip after pickup. If the inverse time stage
is not required, select address 81%$//2$'&+5 = 'HILQLWH7LPH when
configuring the protection functions (Subsection 2.1.1).
The above mentioned definite time stages can be used in addition to the inverse-time
stage as alarm and tripping stages (see margin heading “Definite Time Stages I2>>,
I2>”).
Inverse Time
Stage I2p with
ANSI curves
Having selected an inverse-time tripping characteristic the thermal load of a machine
caused by unbalanced load can be simulated easily. Use the characteristic which is
most similar to the thermal unbalanced load curve of the machine manufacturer.
With the ANSI characteristics (address 81%$//2$'&+5 = 72&$16,) the
following is made available in address $16,&859(:
Motor INmotor = 545A
I2prim
/ INmotor = 0,11 continuous
I2prim /INmotor = 0,55 for Tmax = 1s
Current transf. INprim / INsec = 600 A/1 A
Setting I2> = 0.11 · 545 A = 60 A primary or
0.11 · 545 A · (1/600) = 0.10 A secondary
Setting I2>> = 0.55 · 545 A = 300 A primary or
0,55 · 545 A · (1/600) = 0.50 A secondary
Delay TI2>> = 1 s
2.8 Unbalanced Load Protection
1297UT612 Manual
C53000–G1176–C148–1
([WUHPHO\,QY,
,QYHUVH,
0RGHUDWHO\,QY, and
9HU\,QYHUVH.
The characteristics and equations they are based on are listed in the Technical Data
(Section 4.4, Figure 4-8).
If an inverse-time characteristic is selected, it must be noted that a safety factor of
about 1.1 has already been included between the pickup value and the setting value.
This means that a pickup will only occur if an unbalanced load of about 1.1 times the
setting value of ,S (Address ) is present.
The corresponding time multiplier is accessible via address ',S.
The t ime mul tipli er can als o be set to ∞. If set to infinity, the pickup of this function will
be indicated but the stage will not be able to trip after pickup. If the inverse-time stage
is not required, select address 81%$//2$'&+5 = 'HILQLWH7LPH when
configuring the protection functions (Subsection 2.1.1).
The above mentioned definite time stages can be used in addition to the inverse-time
stage as alarm and tripping stages (see margin heading “Definite Time Stages I2>>,
I2>”).
If 'LVN(PXODWLRQ is set in address ,S'523287, dropout is being pro-
duced according to the dropout characteristic. For more information see Subsection
2.8.1.2, margin heading “Dropout for ANSI Curves” (page 124).
2.8.3 Setting Overview
Note:
The following list indicates the setting ranges and default settings for a rated
secondary current of IN = 1 A. For a rated secondary current of IN = 5 A, these values
must be multiplied by 5. When performing settings in primary values, the current trans-
former ratios have to be taken into consideration.
Addr. Setting Title Setting Options Default Setting Comments
4001 UNBALANCE LOAD OFF
ON OFF Unbalance Load (Negative
Sequence)
4002 I2> 0.10..3.00 A 0.10 A I2> Pickup
4003 T I2> 0.00..60.00 sec; ∞ 1.50 sec T I2> Time Delay
4004 I2>> 0.10..3.00 A 0.50 A I2>> Pickup
4005 T I2>> 0.00..60.00 sec; ∞ 1.50 sec T I2>> Time Delay
4006 IEC CURVE Normal Inverse
Very Inverse
Extremely Inverse
Extremely Inverse IEC Curve
4007 ANSI CURVE Extremely Inverse
Inverse
Moder atel y Inv ers e
Very Inverse
Extremely Inverse ANSI Curve
2 Functions
130 7UT612 Manual
C53000–G1176–C148–1
2.8.4 Information Overview
4008 I2p 0.10..2.00 A 0.90 A I2p Pickup
4009 D I2p 0.50..15.00; ∞ 5.00 D I2p Time Dial
4010 T I2p 0.05..3.20 sec; ∞ 0.50 sec T I2p Time Dial
4011 I2p DROP-OUT Instantaneous
Disk Emulation I nstan taneous I2p Drop-out Characteristic
Addr. Setting Title Setting Options Default Setting Comments
F.No. Alarm Comments
05143 >BLOCK I2 >BLOCK I2 (Unbalance Load)
05151 I2 OFF I2 switched OFF
05152 I2 BLOCKED I2 is BLOCKED
05153 I2 ACTIVE I2 is ACTIVE
05159 I2>> picked up I2>> picked up
05165 I2> picked up I2> picked up
05166 I2p picked up I2p picked up
05170 I2 TRIP I2 TRIP
05172 I2 Not avalia. I2 Not avaliable for this objekt
2.9 Thermal Overload Protection
1317UT612 Manual
C53000–G1176–C148–1
2.9 Thermal Overload Protection
The thermal overload protection prevents damage to the protected object caused by
thermal overloading, particularly in case of power transformers, rotating machines,
power reactors and cables. Two methods of overload detection are available in
7UT612:
•Overload calculation using a thermal replica according to IEC 60255-8,
•Calculation of the hot-spot temperature and determination of the ageing rate ac-
cording to IEC 60354.
You may select one of these two methods. The first one is characterized by easy han-
dling and setting, the second needs some knowledge about the protected object and
its thermal characteristics and the input of the cooling medium temperature.
2.9.1 Overload Protection Using a Thermal Replica
Principle The thermal overload protection of 7UT612 can be assigned to one of the sides of the
protected object (selectable), i.e. it evaluates the currents flowing at this side. Since
the cause of overload is normally outside the protected object, the overload current is
a through-flowing current.
The unit computes the temperature rise according to a thermal single-body model as
per the following thermal differential equation
with Θ– currently valid temperature rise referred to the final temperature rise
for the maximum permissible phase current k · INobj,
τth – thermal time constant for heating up,
k – k–factor which states the maximum permissible continuous current,
referred to the rated current of the protected object,
I– currently valid RMS current,
INobj – rated current of protected object.
The solution of this equation under steady-state conditions is an e–function whose
asymptote shows the final temperature rise Θend. When the temperature rise reaches
the first settable temperature threshold Θalarm, which is below the final temperature
rise, a warning alarm is given in order to allow an early load reduction. When the sec-
ond temperature threshold, i.e. the final temperature rise or tripping temperature, is
reached, the protected object is disconnected from the network. The overload protec-
tion can, however, also be set on $ODUP2QO\. In this case only an alarm is output
when the final temperature rise is reached.
The temperature rises are calculated separately for each phase in a thermal replica
from the square of the associated phase current. This guarantees a true RMS value
measurement and also includes the effect of harmonic content. The maximum calcu-
lated temperature rise of the three phases is decisive for evaluation of the thresholds.
The maximum permissible continuous thermal overload current Imax is described as a
multiple of the rated current INobj:
dΘ
dt
-------- 1
τth
------- Θ⋅
+1
τth
------- I
kI⋅Nobj
--------------------
2
⋅
=
2 Functions
132 7UT612 Manual
C53000–G1176–C148–1
Imax = k · INobj
INobj is the rated current of the protected object:
•For power transformers, the rated power of the assigned
winding
is decisive. The
device calculates this rated current from the rated apparent power of the transform-
er and the rated voltage of the assigned winding. For transformers with tap changer,
the non-regulated side must be used.
•For generators, motors, or reactors, the rated object current is calculated by the de-
vice from the set rated apparent power and the rated voltage.
•For short lines or busbars, the rated current was directly set.
In addition to the k–factor, the thermal time constant τth as well as the alarm temper-
ature rise Θalarm must be entered into the protection.
Apart from the thermal alarm stage, the overload protection also includes a current
overload alarm stage Ialarm, which can output an early warning that an overload cur-
rent is imminent, even when the temperature rise has not yet reached the alarm or trip
temperature rise values.
The overload protection can be blocked via a binary input. In doing so, the thermal rep-
lica are also reset to zero.
Extension of the
Time Constant
for Machines
The differential equation mentioned above assumes a constant cooling represented
by the thermal time constant τth = Rth · Cth (thermal resistance times thermal capaci-
tance). But, the thermal time constant of a self-ventilated machine during stand-still
differs substantially from that during operation because of the missing ventilation.
Thus, in this case, two time constants exist. This must be considered in the thermal
replica.
Stand-still of the machine is assumed when the current drops below the threshold
%UHDNHU6,! or %UHDNHU6,! (depending on the assigned side for overload
protection, refer also to “Circuit Breaker Status” in Subsection 2.1.2).
Motor Startup
Recognition On startup of electrical machines the temperature rise calculated by the thermal rep-
lica may exceed the alarm temperature rise or even the trip temperature rise. To avoid
an alarm or trip, the starting current is acquired and the increase of temperature rise
deriving from it is suppressed. This means that the calculated temperature rise is kept
constant as long as the starting current is detected.
Emergency
Starting of
Machines
When machines must be started for emergency reasons, operating temperatures
above the maximum permissible operating temperatures are allowed (emergency
start). Then exclusively the tripping signal can be blocked via a binary input
(”!(PHU6WDUW2/”). After startup and dropout of the binary input, the thermal
replica may still be greater than the trip temperature rise. Therefore the thermal replica
features a settable run-on time (7(0(5*(1&<) which is started when the binary input
drops out. It also suppresses the trip command. Tripping by the overload protection
will be defeated until this time interval elapses. This binary input only affects the trip
command. There is no effect on fault recording, nor does the thermal replica reset.
2.9 Thermal Overload Protection
1337UT612 Manual
C53000–G1176–C148–1
Figure 2-77 Logic diagr am of the thermal overload protection
2.9.2 Hot-Spot Calculation and Determination of the Ageing Rate
The overload calculation according to IEC 60354 calculates two quantities relevant for
the protection function: the relative ageing and the hot-spot temperature in the protect-
ed object. The user can install up to 12 temperature measuring points in the protected
object. Via one or two thermoboxes and a serial data connection the measuring points
inform the overload protection of the 7UT612 about the local coolant temperature.
One
of these points is selected to form the relevant point for hot-spot calculation. This point
shall be situated at the insulation of the upper inner turn of the winding since this is the
location of the hottest temperature.
The relative ageing is acquired cyclically and summed up to a total ageing sum.
dΘ
dt
-------- 1
τ
--- Θ⋅
+1
τ
---I
2
⋅
=
“1”
Θ
max
L1
Θ = 0
Θ
$/$50
100 % (fix)
≥
1&
≥
1
≥
1
&
>BLK ThOverload
FNo 01503
FNo 015 15
O/L I Alarm
FNo 015 16
O/L Θ Alarm
FNo 01521
ThOverload TRIP
FNo 015 12
Th.Overload BLK
FNo 01513
Th.Overload
FNo 01511
Th.Overload OFF
FNo 015 17
O/L Th. pick.up
&
>Emer.Start O/L
FNo 015 07
L3
L2
IL3
IL2
IL1
0T
Θ = const
Kτ · τ
CB closed
2))
21
$ODUP2QO\
O/L I AlarmO/L I Alarm
7,0(&2167$17
,$/$50 .)$&725
,0272567$57
.
τ
)$&725
7(0(5*(1&<
7KHU29(5/2$'
2 Functions
134 7UT612 Manual
C53000–G1176–C148–1
Cooling Methods The hot-spot calculation is dependent on the cooling method. Air cooling is always
available. Two different methods are distinguished:
•AN (Air Natural): natural air circulation and
•AF (Air Forced): forced air circulation (ventilation).
If liquid coolants are used in combination with the two cooling methods above-de-
scribed, the following types of coolants are available:
•ON (Oil Natural = naturally circulating oil): Because of emerging differences in tem-
perature the coolant (oil) moves within the tank. The cooling effect is not very in-
tense due to its natural convection. This cooling variant, however, is almost noise-
less.
•OF (Oil Forced = forced oil circulation): An oil pump makes the coolant (oil) move
within the tank. The cooling effect of this method is therefore more intense than with
the ON method.
•OD (Oil Directed = forced-directed oil circulation): The coolant (oil) is directed
through the tank. Therefore the oil flow is intensified for sections which are extreme-
ly temperature-sensitive. Therefore, the cooling effect is very good. This method
has the lowest temperature rise.
Figures 2-78 to 2-80 show examples of the cooling methods.
Figure 2-7 8 ON cooling (Oil Natural)
ONAN cooling
∞∞
ONAF cooling
2.9 Thermal Overload Protection
1357UT612 Manual
C53000–G1176–C148–1
Figure 2- 79 OF cooling (Oil Forced)
Figure 2-80 OD cooling (Oil Directed)
Hot-Spot
Calculation The hot-spot temperature of the protected object is an important value of status. The
hottest spot relevant for the life-time of the transformer is usually situated at the insu-
lation of the upper inner turn. Generally the temperature of the coolant increases from
the bottom up. The cooling method, however, affects the rate of the temperature drop.
The hot-spot temperature is composed of two parts:
the temperature at the hottest spot of the coolant (included via thermobox),
the temperature rise of the winding turn caused by the transformer load.
Thermobox 7XV566 can be used to acquire the temperature of the hottest spot. It con-
verts the temperature value into numerical signals and sends them to the correspond-
ing interface of device 7UT612. The thermobox is able to acquire the temperature at
up to 6 points of the transformer tank. Up to two thermoboxes of this types can be con-
nected to a 7UT612.
OFAN cooling
OD cooling
2 Functions
136 7UT612 Manual
C53000–G1176–C148–1
The device calculates the hot-spot temperature from these data and the settings of the
characteristical properties. When a settable threshold (temperature alarm) is exceed-
ed, an annunciation and/or a trip is generated.
Hot-spot calculation is done with different equations depending on the cooling method.
For ON–cooling and OF–cooling:
with
Θhhot-s pot temp eratu re
Θotop oil temperature
Hgr hot-spot to top-oil gradient
k load factor I/IN (measured)
Y winding exponent
For OD–cooling:
Ageing Rate
Calculation The life-time of a cellulose insulation refers to a temperature of 98 °C or 208.4 °F in
the direct environment of the insulation. Experience shows that an increase of 6 K
means half of the life-time. For a temperature which defers from the basic value of
98 °C (208.4 °F), the relative ageing rate V is given by
The mean value of the relative ageing rate L is given by the calculation of the mean
value of a certain period of time, i.e. from T1 to T2:
With constant rated load, the relative ageing rate L is equal to 1. For values greater
than 1, accelerated ageing applies, e.g. if L = 2 only half of the life-time is expected
compared to the life-time under nominal load conditions.
According to IEC, the ageing range is defined from 80 °C to 140 °C (176 °F to 284 °F).
This is the operating range of the ageing calculation in 7UT612: Temperatures below
80 °C (176 °F) do not extent the calculated ageing rate; values greater than 140 °C
(284 °F) do not reduce the calculated ageing rate.
The above-described relative ageing calculation only applies to the insulation of the
winding and cannot be used for other failure causes.
Output of Results The hot-spot temperature is calculated for the winding which corresponds to the side
of the protected object configured for overload protection (Subsection 2.1.1, address
). The calculation includes the current of that side and the cooling temperature
measured at a certain measuring point. There are two thresholds which can be set.
They output a warning (Stage 1) and an alarm (Stage 2) signal. When the alarm signal
is assigned to a trip output, it can also be used for tripping the circuit breaker(s).
ΘhΘoHgr kY
⋅
+=
ΘhΘoHgr kY
⋅
+=
ΘhΘoHgr kY
⋅0,15 ΘoHgr kY
⋅
+
()98 °C
–
[]⋅
++=
for k ≤ 1
for k > 1
VAgeing at Θh
Ageing at 98° C
------------------------------------------ 2Θh98
–
()6⁄
==
L
1
T
2
T
1
–
------------------- V td
T1
T2
∫
⋅
=
2.9 Thermal Overload Protection
1377UT612 Manual
C53000–G1176–C148–1
For the middle ageing rate, there is also a threshold for each of the warning and the
alarm signal.
The status can be read out from the operational measured values at any time. The in-
formation includes:
−hot-spot temperature for each winding in °C or °F (as configured),
−relative ageing rate expressed in per unit,
−load backup up to warning signal (Stage 1) expressed in per cent,
−load backup up to alarm signal (Stage 2) expressed in per cent.
2.9.3 Setting th e Function Parameters
General The overload protection can be assigned to any desired side of the protected object.
Since the cause of the overload current is outside the protected object, the overload
current is a through-flowing current, the overload protection may be assigned to a
feeding or a non-feeding side.
•For transformers with voltage regulation, i.e. with tap changer, the overload protec-
tion must be assigned to the non-regulated side as only this winding allows a de-
fined relationship between the rated current and the rated power.
•For generators, the overload protection is, normally, assigned to the starpoint side.
•For motors and shunt reactors, the overload protection is assigned to the feeding
side.
•For series reactors or short cables, nor preferable side exists.
•For busbar sections or overhead lines, the overload protection is, generally, not
used since calculation of a temperature rise is not reasonable because of the widely
varying ambient conditions (air temperature, wind). But, in these applications, the
current warning stage may be useful to announce overload currents.
The side of the protected object which is to be assigned to the overload protection,
was selected under address 7KHUP2YHUORDG during configuration of the pro-
tection functions (Subsection 2.1.1).
There are two method for evaluation of overload conditions in 7UT612, as explained
above. During configuration of the protection function (Subsection 2.1.1), you had al-
ready decided under address 7KHUP2/&+5, whether the protection shall op-
erate according to the “classical” method of a thermal replica (7KHUP2/&+5 =
FODVVLFDO) or whether the calculation of the hot-spot temperature according to IEC
60354 (7KHUP2/&+5 = ,(&) shall be carried out. In the latter case, at least
one thermobox 7XV566 must be connected to the device in order to inform the device
about the cooling medium temperature. The data concerning the thermobox were en-
tered to the device unde r addres s 57'&211(&7,21 (Subsecti on 2.1. 1) .
The thermal overload protection can be switched 21 or 2)) under address
7KHUP2YHUORDG. Furthermore $ODUP2QO\ can be set. With that latter setting the
protection function is active but only outputs an alarm when the tripping temperature
rise is reached, i.e. the output function “7K2YHUORDG75,3” is not active.
2 Functions
138 7UT612 Manual
C53000–G1176–C148–1
k–Factor The rated current of the protected object is taken as the base current for detecting an
overload. The setting factor k is set under address .)$&725. It is determined
by the relation between the permissible thermal continuous current and this rated cur-
rent:
When using the method with a thermal replica, it is not necessary to evaluate any ab-
solute temperature nor the trip temperature since the trip temperature rise is equal to
the final temperature rise at k · INobj. Manufacturers of electrical machines usually
state the permissible continuous current. If no data are available, k is set to 1.1 times
the rated current of the protected object. For cables, the permissible continuous cur-
rent depends on the cross-section, the insulation material, the design and the method
of installation, and can be derived from the relevant tables.
When using the method with hot-spot evaluation according to IEC 60354, set k = 1
since all remaining parameters are referred to the rated current of the protected object.
Time Constant τ for
Thermal Replica The thermal time constant τth is set under the address 7,0(&2167$17. This
is also to be stated by the manufacturer. Please note that the time constant is set in
minutes. Quite often other values for determining the time constant are stated which
can be converted into the time constant as follows:
•1–s current
•permissible current for application time other than 1 s, e.g. for 0.5 s
•t6–time; this is the time in seconds for which a current of 6 times the rated current
of the protected object may flow
Calculation examples:
Cable with
permissible continuous current 322 A
permissible 1–s current 13.5 kA
Setting value 7,0(&2167$17 = min.
Motor with t6–time 12 s
Setting value 7,0(&2167$17 = min.
For rotating machines, the time constant as set under address 7,0(&2167$17
is valid as long as the machine is running. The machine will cool down extensively
kImax
INobj
------------=
τth
min
--------- 1
60
------ permissible 1–s current
permissible continuous current
---------------------------------------------------------------------------------
2
⋅
=
τ
th
min
--------- 0.5
60
-------- p er mis sib le 0.5– s cur r ent
permissible continuous current
---------------------------------------------------------------------------------
2
⋅
=
τ
th
min
--------- 0.6 t6
⋅
=
τth
min
--------- 1
60
------ 13500 A
322 A
----------------------
2
1
60
------ 42229.4
=
⋅
=
⋅
=
τth
min
--------- 0.6 12 s⋅7.2==
2.9 Thermal Overload Protection
1397UT612 Manual
C53000–G1176–C148–1
slower during stand-still or running down if it is self-ventilated. This phenomenon is
consid er ed by a higher stand- s til l tim e constan t .τ)$&725 (address $) which
is set as a factor of the normal time constant. Stand-still of the machine is assumed
when the currents fall below the threshold %UHDNHU6,! or %UHDNHU6,!,
depending on the side to which the overload protection is assigned, (see margin
“Circuit Breaker Status” in Subsection 2.1.2). This parameter can only be changed
with DIGSI® 4 under “Additional Settings”.
If it not necessary to distinguish between different time constants, leave the factor .τ
)$&725 at (default setting).
Alarm Stages with
Thermal Replica By setting a thermal alarm stage Θ$/$50 (address ) an alarm can be output
before the tripping temperature is reached, so that a trip can be avoided by early load
reduction or by switching over. The percentage is referred to the tripping temperature
rise. Note that the final temperature rise is proportional to the square of the current.
Example:
k–factor = 1.1
Alarm shall be given when the temperature rise reaches the final (steady-state) tem-
perature rise at nominal current.
Setting value Θ$/$50 = %.
The current overload alarm setpoint ,$/$50 (address ) is stated in amps (pri-
mary or secondary) and should be set equal to or slightly below the permissible con-
tinuous current k · INobj. It can also be used
instead
of the thermal alarm stage. In this
case the thermal alarm stage is set to 100 % and thus practically ineffective.
Emer gency Star t
for Motors The run-on time value to be entered at address $7(0(5*(1&< must ensure
that after an emergency start and dropout of the binary input “!(PHU6WDUW2/” the
trip command is blocked until the thermal replica has fallen below the dropout thresh-
old. This parameter can only be changed with DIGSI® 4 under “Additional Settings”.
The startup itself is only recognized if the startup current ,0272567$57 set in ad-
dress $ is exceeded. Under each load and voltage condition during motor start,
the value must be overshot by the actual startup current. With short-time permissible
overload the value must not be reached. For other protected objects the setting ∞ will
not be changed. Thus the emergency start is disabled.
Temperature
Detectors For the hot-spot calculation according to IEC 60354 the device must be informed on
the type of resistance temperature detectors that will be used for measuring the oil
temperature, the one relevant for the hot-spot calculation and ageing determination.
Up to 6 sensors can be used with one thermobox 7XV566, with 2 boxes up to 12 sen-
sors. In address 2,/'(757' the identification number of the resistance
temperature detector decisive for hot-spot calculation is set.
The characteristic values of the temperature detectors are set separately, see Section
2.10.
Θalarn 1
1.12
----------- 0.826
==
2 Functions
140 7UT612 Manual
C53000–G1176–C148–1
Hot-Spot Stages There are two annunciation stages for the hot-spot temperature. To set a specific hot-
spot temperature value (expressed in °C) which is meant to generate the warning sig-
nal (Stage 1), use address +27632767. Use address +276327
67 to indicate the corresponding alarm temperature (Stage 2). Optionally, it can
be used for tripping of circuit breakers if the outgoing message “2/KVSRW75,3”
(FNo ) is allocated to a trip relay.
If address 7(0381,7 = )DKUHQKHLW is set (Subsection 2.1.2, margin heading
“Temperature Unit”), thresholds for warning and alarm temperatures have to be ex-
pressed in Fahrenheit (addresses and ).
If the temperature unit is changed in address after having set the thresholds for
temperature, these thresholds for the temperature unit changed must be set again in
the corresponding addresses.
Ageing Rate For ageing rate L thresholds can also be set, i.e. for the warning signal (Stage 1) in
address $*5$7(67 and for alarm signal (Stage 2) in address $*
5$7(67. This information is referred to the relative ageing, i.e. L = 1 is reached
at 98 °C or 208 °F at the hot spot. L > 1 means an accelerated ageing, L < 1 a delayed
ageing.
Cooling Method
and Insulation Data Set in address 0(7+&22/,1* which cooling method is used: 21 = Oil Natural
for natural cooling, 2) = Oil Forced for oil forced cooling or 2' = Oil Directed for oil
directed cooling. For definitions see also Subsection 2.9.2, margin heading “Cooling
Methods”.
For hot-spot calculation the device requires the winding exponent Y and the hot-spot
to top-oil gradient Hgr which is set in addre sses <:,1'(;321(17 and
+276327*5. If the corresponding information is not available, it can be taken from
the IEC 60354. An extract from the corresponding table of the standard with the tech-
nical data relevant for this project can be found hereinafter (Table 2-5).
Table 2-5 Thermal characteristics of power transformers
Cooling method:
Distribution
transformers Medium and large
power transfo rmer s
ONAN ON.. OF.. OD..
Winding exponent Y 1.6 1.8 1.8 2.0
Hot-spot to top-oil gradient Hgr 23 26 22 29
2.9 Thermal Overload Protection
1417UT612 Manual
C53000–G1176–C148–1
2.9.4 Setting Overview
Note:
The following list indicates the setting ranges and default settings for a rated
secondary current of IN = 1 A. For a rated secondary current of IN = 5 A, these values
must be multiplied by 5. When setting the device using primary values, the current
transformer ratios have to be taken into consideration.
Note:
Addresses which have an “A” attached to its end can only be changed in
DIGSI®4, under “Additional Settings”.
Addr. Setting Title Setting Options Default Setting Comments
4201 Ther. OVE R LOAD OFF
ON
Alarm Only
OFF Thermal Overload Protection
4202 K-FACTOR 0.10..4.00 1.10 K-Factor
4203 TIME CONSTANT 1.0..999.9 min 100.0 min Time Constant
4204 Θ ALARM 50..100 % 90 % Thermal Alarm Stage
4205 I ALARM 0.10..4.00 A 1.00 A Current Overload Alarm Setpoint
4207A Kτ-FACTOR 1.0..10.0 1.0 Kt-FACTOR when motor stops
4208A T EMERGENCY 10..15000 sec 100 sec Emergency Time
4209A I MOTOR START 0.60..10.00 A; ∞ ∞ A Current Pickup Value of Motor
Starting
4221 OIL-DET. RTD 1..6 1 Oil-Detector conected at RTD
4222 HOT SPOT ST. 1 98..140 °C 98 °C Hot Spot Temperature Stage 1
Pickup
4223 HOT SPOT ST. 1 208..284 °F 208 °F Hot Spot Temperature Stage 1
Pickup
4224 HOT SPOT ST. 2 98..140 °C 108 °C Hot Spot Temperature Stage 2
Pickup
4225 HOT SPOT ST. 2 208..284 °F 226 °F Hot Spot Temperature Stage 2
Pickup
4226 AG. RATE ST. 1 0.125..128.000 1.000 Aging Rate STAGE 1 Pickup
4227 AG. RATE ST. 2 0.125..128.000 2.000 Aging Rate STAGE 2 Pickup
4231 METH. COOLING ON (Oil-Natural)
OF (Oil-Forced)
OD (Oil-Directed)
ON (Oil-Natural) Method of Cooling
4232 Y-WIND.EXPONENT 1.6..2.0 1.6 Y-Winding Exponent
4233 HOT-SPOT GR 22..29 22 Hot-spot to top-oil gradie nt
2 Functions
142 7UT612 Manual
C53000–G1176–C148–1
2.9.5 Information Overview
F.No. Alarm Comments
01503 >BLK ThOverload >BLOCK Thermal Overload Protection
01507 >Emer.Start O/L >Emergency start Th. Overload Protection
01511 Th.Overl oad OFF Thermal Overload Protection OFF
01512 Th.Overl oad BLK Thermal Overload Protection BLOCKED
01513 Th.Overl oad ACT Thermal Overload Protection ACTIVE
01515 O/L I Alarm Th. Overload Current Alarm (I alarm)
01516 O/L Θ Alarm Thermal Overload Alarm
01517 O/L Th. pick.up Thermal Overload picked up
01521 ThOverload TRIP Thermal Overload TRIP
01541 O/L ht.spot Al. Thermal Overload hot spot Th. Alarm
01542 O/L h.spot TRIP Thermal Overload hot spot Th. TRIP
01543 O/L ag.rate Al. Thermal Overload aging rate Alarm
01544 O/L ag.rt. TRIP Thermal Overload aging rate TRIP
01545 O/L No Th.meas. Th. Overload No temperature mesured
01549 O/L Not avalia. Th. Overload Not avaliable for this obj.
2.10 Thermoboxes for Overload Protection
1437UT612 Manual
C53000–G1176–C148–1
2.10 Thermoboxes for Overload Protection
For overload protection with hot-spot calculation and relative ageing rate determina-
tion, the temperature of the hottest spot of the coolant is required. At least one resist-
ance temperature detector (RTD) must be installed at the hot-spot location which in-
forms the device about this temperature via a thermoboxes 7XV566. One thermobox
is able to process up to 6 RTDs. One or two thermoboxes can be connected to the
7UT612.
2.10.1 Function Description
A thermobox 7XV566 is suited for up to 6 measuring points (RTDs) in the protected
object, e.g. in the transformer tank. The thermobox takes the coolant temperature of
each measuring point from the resistance value of the temperature detectors connect-
ed with a two- or three-wire line (Pt100, Ni100 or Ni120) and converts it to a digital
value. The digital values are output at the serial interface RS485.
One or two thermoboxes can be connected to the service interface of the 7UT612.
Thus, up to 6 or 12 measuring points (RTDs) can be processed. For each temperature
detector, characteristic data as well as alarm (stage 1) and trip (stage 2) temperature
can be set.
The thermobox also acquires thresholds of each single measuring point. The informa-
tion is then passed on via an output relay. For further information refer to the instruc-
tion manual of the thermobox.
2.10.2 Setting the Function Parameters
For RTD1 (temperature detector for measuring point 1) the type of temperature detec-
tor is set in add ress $ 57'7<3(. 3WΩ, 1LΩ and 1LΩ are
available. If there is no measuring point for RTD1, set 57'7<3( = 1RWFRQQHFW
HG. This parameter can only be changed with DIGSI® 4 under “Additional Settings”.
Address $ 57'/2&$7,21 informs the device on the mounting location of
RTD1. 2LO, $PELHQW, :LQGLQJ, %HDULQJ and 2WKHU are available. This parameter
can only be changed with DIGSI® 4 under “Additional Settings”.
Furthermore, alarm and trip temperature can be set. Depending on the temperature
unit selected in the Power System Data (Subsection 2.1.2 in address 7(03
81,7, page 20), the alarm temperature can be expressed in Celsius (°C) (address
57'67$*() or Fahrenheit (°F) (address 57'67$*(). The trip
temperature expressed in Celsius (°C) is set in address 57'67$*(. To
express it in Fahrenh eit (°F) use addres s 57'67$*(.
For other temperature detectors connected to the first thermobox make settings cor-
respondingly:
2 Functions
144 7UT612 Manual
C53000–G1176–C148–1
for RTD2 address $ 57'7<3(,
address $ 57'/2&$7,21,
address 57'67$*( (in °C) or 57'67$*( (°F),
address 57'67$*( (in °C) or 57'67$*( (°F);
for RTD3 address $ 57'7<3(,
address $ 57'/2&$7,21,
address 57'67$*( (in °C) or 57'67$*( (°F),
address 57'67$*( (in °C) or 57'67$*( (°F);
for RTD4 address $ 57'7<3(,
address $ 57'/2&$7,21,
address 57'67$*( (in °C) or 57'67$*( (°F),
address 57'67$*( (in °C) or 57'67$*( (°F);
for RTD5 address $ 57'7<3(,
address $ 57'/2&$7,21,
address 57'67$*( (in °C) or 57'67$*( (°F),
address 57'67$*( (in °C) or 57'67$*( (°F);
for RTD6 address $ 57'7<3(,
address $ 57'/2&$7,21,
address 57'67$*( (in °C) or 57'67$*( (°F),
address 57'67$*( (in °C) or 57'67$*( (°F);
If two thermoboxes are connected, information for further temperature detectors can
be set:
for RTD7 address $ 57'7<3(,
address $ 57'/2&$7,21,
address 57'67$*( (in °C) or 57'67$*( (°F),
address 57'67$*( (in °C) or 57'67$*( (°F);
for RTD8 address $ 57'7<3(,
address $ 57'/2&$7,21,
address 57'67$*( (in °C) or 57'67$*( (°F),
address 57'67$*( (in °C) or 57'67$*( (°F);
for RTD9 address $ 57'7<3(,
address $ 57'/2&$7,21,
address 57'67$*( (in °C) or 57'67$*( (°F),
address 57'67$*( (in °C) or 57'67$*( (°F);
for RTD address $ 57'7<3(,
address $ 57'/2&$7,21,
address 57'67$*( (in °C) or 57'67$*( (°F),
address 57'67$*( (in °C) or 57'67$*( (°F);
for RTD address $ 57'7<3(,
address $ 57'/2&$7,21,
address 57'67$*( (in °C) or 57'67$*( (°F),
address 57'67$*( (in °C) or 57'67$*( (°F);
for RTD address $ 57'7<3(,
address $ 57'/2&$7,21,
address 57'67$*( (in °C) or 57'67$*( (°F),
address 57'67$*( (in °C) or 57'67$*( (°F).
2.10 Thermoboxes for Overload Protection
1457UT612 Manual
C53000–G1176–C148–1
2.10.3 Setting Overview
Note:
Addresses which have an “A” attached to its end can only be changed in
DIGSI®4, Section „Additional Settings“.
Addr. Setting Title Setting Options Default Setting Comments
9011A RTD 1 TYPE not connected
Pt 100 Ohm
Ni 120 Ohm
Ni 100 Ohm
Pt 100 Ohm RTD 1: Type
9012A RTD 1 LOCATION Oil
Ambient
Winding
Bearing
Other
Oil RTD 1: Location
9013 RTD 1 STAGE 1 -50..250 °C; ∞ 100 °C RTD 1: Temperature Stage 1 Pickup
9014 RTD 1 STAGE 1 -58..482 °F; ∞ 212 °F RTD 1: Temperature Stage 1 Pickup
9015 RTD 1 STAGE 2 -50..250 °C; ∞ 120 °C RTD 1: Temperature Stage 2 Pickup
9016 RTD 1 STAGE 2 -58..482 °F; ∞ 248 °F RTD 1: Temperature Stage 2 Pickup
9021A RTD 2 TYPE not connected
Pt 100 Ohm
Ni 120 Ohm
Ni 100 Ohm
not connected RTD 2: Type
9022A RTD 2 LOCATION Oil
Ambient
Winding
Bearing
Other
Other RTD 2: Location
9023 RTD 2 STAGE 1 -50..250 °C; ∞ 100 °C RTD 2: Temperature Stage 1 Pickup
9024 RTD 2 STAGE 1 -58..482 °F; ∞ 212 °F RTD 2: Temperature Stage 1 Pickup
9025 RTD 2 STAGE 2 -50..250 °C; ∞ 120 °C RTD 2: Temperature Stage 2 Pickup
9026 RTD 2 STAGE 2 -58..482 °F; ∞ 248 °F RTD 2: Temperature Stage 2 Pickup
9031A RTD 3 TYPE not connected
Pt 100 Ohm
Ni 120 Ohm
Ni 100 Ohm
not connected RTD 3: Type
9032A RTD 3 LOCATION Oil
Ambient
Winding
Bearing
Other
Other RTD 3: Location
9033 RTD 3 STAGE 1 -50..250 °C; ∞ 100 °C RTD 3: Temperature Stage 1 Pickup
9034 RTD 3 STAGE 1 -58..482 °F; ∞ 212 °F RTD 3: Temperature Stage 1 Pickup
9035 RTD 3 STAGE 2 -50..250 °C; ∞ 120 °C RTD 3: Temperature Stage 2 Pickup
9036 RTD 3 STAGE 2 -58..482 °F; ∞ 248 °F RTD 3: Temperature Stage 2 Pickup
2 Functions
146 7UT612 Manual
C53000–G1176–C148–1
9041A RTD 4 TYPE not connected
Pt 100 Ohm
Ni 120 Ohm
Ni 100 Ohm
not connected RTD 4: Type
9042A RTD 4 LOCATION Oil
Ambient
Winding
Bearing
Other
Other RTD 4: Location
9043 RTD 4 STAGE 1 -50..250 °C; ∞ 100 °C RTD 4: Temperature Stage 1 Pickup
9044 RTD 4 STAGE 1 -58..482 °F; ∞ 212 °F RTD 4: Temperature Stage 1 Pickup
9045 RTD 4 STAGE 2 -50..250 °C; ∞ 120 °C RTD 4: Temperature Stage 2 Pickup
9046 RTD 4 STAGE 2 -58..482 °F; ∞ 248 °F RTD 4: Temperature Stage 2 Pickup
9051A RTD 5 TYPE not connected
Pt 100 Ohm
Ni 120 Ohm
Ni 100 Ohm
not connected RTD 5: Type
9052A RTD 5 LOCATION Oil
Ambient
Winding
Bearing
Other
Other RTD 5: Location
9053 RTD 5 STAGE 1 -50..250 °C; ∞ 100 °C RTD 5: Temperature Stage 1 Pickup
9054 RTD 5 STAGE 1 -58..482 °F; ∞ 212 °F RTD 5: Temperature Stage 1 Pickup
9055 RTD 5 STAGE 2 -50..250 °C; ∞ 120 °C RTD 5: Temperature Stage 2 Pickup
9056 RTD 5 STAGE 2 -58..482 °F; ∞ 248 °F RTD 5: Temperature Stage 2 Pickup
9061A RTD 6 TYPE not connected
Pt 100 Ohm
Ni 120 Ohm
Ni 100 Ohm
not connected RTD 6: Type
9062A RTD 6 LOCATION Oil
Ambient
Winding
Bearing
Other
Other RTD 6: Location
9063 RTD 6 STAGE 1 -50..250 °C; ∞ 100 °C RTD 6: Temperature Stage 1 Pickup
9064 RTD 6 STAGE 1 -58..482 °F; ∞ 212 °F RTD 6: Temperature Stage 1 Pickup
9065 RTD 6 STAGE 2 -50..250 °C; ∞ 120 °C RTD 6: Temperature Stage 2 Pickup
9066 RTD 6 STAGE 2 -58..482 °F; ∞ 248 °F RTD 6: Temperature Stage 2 Pickup
9071A RTD 7 TYPE not connected
Pt 100 Ohm
Ni 120 Ohm
Ni 100 Ohm
not connected RTD 7: Type
Addr. Setting Title Setting Options Default Setting Comments
2.10 Thermoboxes for Overload Protection
1477UT612 Manual
C53000–G1176–C148–1
9041A RTD 4 TYPE not connected
Pt 100 Ohm
Ni 120 Ohm
Ni 100 Ohm
not connected RTD 4: Type
9042A RTD 4 LOCATION Oil
Ambient
Winding
Bearing
Other
Other RTD 4: Location
9043 RTD 4 STAGE 1 -50..250 °C; ∞ 100 °C RTD 4: Temperature Stage 1 Pickup
9044 RTD 4 STAGE 1 -58..482 °F; ∞ 212 °F RTD 4: Temperature Stage 1 Pickup
9045 RTD 4 STAGE 2 -50..250 °C; ∞ 120 °C RTD 4: Temperature Stage 2 Pickup
9046 RTD 4 STAGE 2 -58..482 °F; ∞ 248 °F RTD 4: Temperature Stage 2 Pickup
9051A RTD 5 TYPE not connected
Pt 100 Ohm
Ni 120 Ohm
Ni 100 Ohm
not connected RTD 5: Type
9052A RTD 5 LOCATION Oil
Ambient
Winding
Bearing
Other
Other RTD 5: Location
9053 RTD 5 STAGE 1 -50..250 °C; ∞ 100 °C RTD 5: Temperature Stage 1 Pickup
9054 RTD 5 STAGE 1 -58..482 °F; ∞ 212 °F RTD 5: Temperature Stage 1 Pickup
9055 RTD 5 STAGE 2 -50..250 °C; ∞ 120 °C RTD 5: Temperature Stage 2 Pickup
9056 RTD 5 STAGE 2 -58..482 °F; ∞ 248 °F RTD 5: Temperature Stage 2 Pickup
9061A RTD 6 TYPE not connected
Pt 100 Ohm
Ni 120 Ohm
Ni 100 Ohm
not connected RTD 6: Type
9062A RTD 6 LOCATION Oil
Ambient
Winding
Bearing
Other
Other RTD 6: Location
9063 RTD 6 STAGE 1 -50..250 °C; ∞ 100 °C RTD 6: Temperature Stage 1 Pickup
9064 RTD 6 STAGE 1 -58..482 °F; ∞ 212 °F RTD 6: Temperature Stage 1 Pickup
9065 RTD 6 STAGE 2 -50..250 °C; ∞ 120 °C RTD 6: Temperature Stage 2 Pickup
9066 RTD 6 STAGE 2 -58..482 °F; ∞ 248 °F RTD 6: Temperature Stage 2 Pickup
9071A RTD 7 TYPE not connected
Pt 100 Ohm
Ni 120 Ohm
Ni 100 Ohm
not connected RTD 7: Type
Addr. Setting Title Setting Options Default Setting Comments
2 Functions
148 7UT612 Manual
C53000–G1176–C148–1
9072A RTD 7 LOCATION Oil
Ambient
Winding
Bearing
Other
Other RTD 7: Location
9073 RTD 7 STAGE 1 -50..250 °C; ∞ 100 °C RTD 7: Temperature Stage 1 Pickup
9074 RTD 7 STAGE 1 -58..482 °F; ∞ 212 °F RTD 7: Temperature Stage 1 Pickup
9075 RTD 7 STAGE 2 -50..250 °C; ∞ 120 °C RTD 7: Temperature Stage 2 Pickup
9076 RTD 7 STAGE 2 -58..482 °F; ∞ 248 °F RTD 7: Temperature Stage 2 Pickup
9081A RTD 8 TYPE not connected
Pt 100 Ohm
Ni 120 Ohm
Ni 100 Ohm
not connected RTD 8: Type
9082A RTD 8 LOCATION Oil
Ambient
Winding
Bearing
Other
Other RTD 8: Location
9083 RTD 8 STAGE 1 -50..250 °C; ∞ 100 °C RTD 8: Temperature Stage 1 Pickup
9084 RTD 8 STAGE 1 -58..482 °F; ∞ 212 °F RTD 8: Temperature Stage 1 Pickup
9085 RTD 8 STAGE 2 -50..250 °C; ∞ 120 °C RTD 8: Temperature Stage 2 Pickup
9086 RTD 8 STAGE 2 -58..482 °F; ∞ 248 °F RTD 8: Temperature Stage 2 Pickup
9091A RTD 9 TYPE not connected
Pt 100 Ohm
Ni 120 Ohm
Ni 100 Ohm
not connected RTD 9: Type
9092A RTD 9 LOCATION Oil
Ambient
Winding
Bearing
Other
Other RTD 9: Location
9093 RTD 9 STAGE 1 -50..250 °C; ∞ 100 °C RTD 9: Temperature Stage 1 Pickup
9094 RTD 9 STAGE 1 -58..482 °F; ∞ 212 °F RTD 9: Temperature Stage 1 Pickup
9095 RTD 9 STAGE 2 -50..250 °C; ∞ 120 °C RTD 9: Temperature Stage 2 Pickup
9096 RTD 9 STAGE 2 -58..482 °F; ∞ 248 °F RTD 9: Temperature Stage 2 Pickup
9101A RTD10 TYPE not connected
Pt 100 Ohm
Ni 120 Ohm
Ni 100 Ohm
not connected RTD10: Type
9102A RTD10 LOCATION Oil
Ambient
Winding
Bearing
Other
Other RTD10: Location
Addr. Setting Title Setting Options Default Setting Comments
2.10 Thermoboxes for Overload Protection
1497UT612 Manual
C53000–G1176–C148–1
9103 RTD10 STAGE 1 -50..250 °C; ∞ 100 °C RTD10: Temperature Stage 1 Pickup
9104 RTD10 STAGE 1 -58..482 °F; ∞ 212 °F RTD10: Temperature Stage 1 Pickup
9105 RTD10 STAGE 2 -50..250 °C; ∞ 120 °C RTD10: Temperature Stage 2 Pickup
9106 RTD10 STAGE 2 -58..482 °F; ∞ 248 °F RTD10: Temperature Stage 2 Pickup
9111A RTD11 TYPE not connected
Pt 100 Ohm
Ni 120 Ohm
Ni 100 Ohm
not connected RTD11: Type
9112A RTD11 LOCATION Oil
Ambient
Winding
Bearing
Other
Other RTD11: Location
9113 RTD11 STAGE 1 -50..250 °C; ∞ 100 °C RTD11: Temperature Stage 1 Pickup
9114 RTD11 STAGE 1 -58..482 °F; ∞ 212 °F RTD11: Temperature Stage 1 Pickup
9115 RTD11 STAGE 2 -50..250 °C; ∞ 120 °C RTD11: Temperature Stage 2 Pickup
9116 RTD11 STAGE 2 -58..482 °F; ∞ 248 °F RTD11: Temperature Stage 2 Pickup
9121A RTD12 TYPE not connected
Pt 100 Ohm
Ni 120 Ohm
Ni 100 Ohm
not connected RTD12: Type
9122A RTD12 LOCATION Oil
Ambient
Winding
Bearing
Other
Other RTD12: Location
9123 RTD12 STAGE 1 -50..250 °C; ∞ 100 °C RTD12: Temperature Stage 1 Pickup
9124 RTD12 STAGE 1 -58..482 °F; ∞ 212 °F RTD12: Temperature Stage 1 Pickup
9125 RTD12 STAGE 2 -50..250 °C; ∞ 120 °C RTD12: Temperature Stage 2 Pickup
9126 RTD12 STAGE 2 -58..482 °F; ∞ 248 °F RTD12: Temperature Stage 2 Pickup
Addr. Setting Title Setting Options Default Setting Comments
2 Functions
150 7UT612 Manual
C53000–G1176–C148–1
2.10.4 Information Overview
Note:
Further annunciations on thresholds of each measuring point are available at
the thermobox itself for output at the relay contacts.
F.No. Alarm Comments
14101 Fail: RTD Fail: RTD (broken wire/shorted)
14111 Fail: RTD 1 Fail: RTD 1 (broken wire/shorted)
14112 RTD 1 St.1 p.up RTD 1 Temperature stage 1 picked up
14113 RTD 1 St.2 p.up RTD 1 Temperature stage 2 picked up
14121 Fail: RTD 2 Fail: RTD 2 (broken wire/shorted)
14122 RTD 2 St.1 p.up RTD 2 Temperature stage 1 picked up
14123 RTD 2 St.2 p.up RTD 2 Temperature stage 2 picked up
14131 Fail: RTD 3 Fail: RTD 3 (broken wire/shorted)
14132 RTD 3 St.1 p.up RTD 3 Temperature stage 1 picked up
14133 RTD 3 St.2 p.up RTD 3 Temperature stage 2 picked up
14141 Fail: RTD 4 Fail: RTD 4 (broken wire/shorted)
14142 RTD 4 St.1 p.up RTD 4 Temperature stage 1 picked up
14143 RTD 4 St.2 p.up RTD 4 Temperature stage 2 picked up
14151 Fail: RTD 5 Fail: RTD 5 (broken wire/shorted)
14152 RTD 5 St.1 p.up RTD 5 Temperature stage 1 picked up
14153 RTD 5 St.2 p.up RTD 5 Temperature stage 2 picked up
14161 Fail: RTD 6 Fail: RTD 6 (broken wire/shorted)
14162 RTD 6 St.1 p.up RTD 6 Temperature stage 1 picked up
14163 RTD 6 St.2 p.up RTD 6 Temperature stage 2 picked up
14171 Fail: RTD 7 Fail: RTD 7 (broken wire/shorted)
14172 RTD 7 St.1 p.up RTD 7 Temperature stage 1 picked up
14173 RTD 7 St.2 p.up RTD 7 Temperature stage 2 picked up
14181 Fail: RTD 8 Fail: RTD 8 (broken wire/shorted)
14182 RTD 8 St.1 p.up RTD 8 Temperature stage 1 picked up
14183 RTD 8 St.2 p.up RTD 8 Temperature stage 2 picked up
14191 Fail: RTD 9 Fail: RTD 9 (broken wire/shorted)
14192 RTD 9 St.1 p.up RTD 9 Temperature stage 1 picked up
14193 RTD 9 St.2 p.up RTD 9 Temperature stage 2 picked up
14201 Fail: RTD10 Fail: RTD10 (broken wire/shorted)
14202 RTD10 St.1 p.up RTD10 Temperature stage 1 picked up
14203 RTD10 St.2 p.up RTD10 Temperature stage 2 picked up
2.10 Thermoboxes for Overload Protection
1517UT612 Manual
C53000–G1176–C148–1
14211 Fail: RTD11 Fail: RTD11 (broken wire/shorted)
14212 RTD11 St.1 p.up RTD11 Temperature stage 1 picked up
14213 RTD11 St.2 p.up RTD11 Temperature stage 2 picked up
14221 Fail: RTD12 Fail: RTD12 (broken wire/shorted)
14222 RTD12 St.1 p.up RTD12 Temperature stage 1 picked up
14223 RTD12 St.2 p.up RTD12 Temperature stage 2 picked up
F.No. Alarm Comments
2 Functions
152 7UT612 Manual
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2.11 Circuit Breaker Failure Protection
2.11.1 Function Description
General The circuit breaker failure protection provides rapid backup fault clearance, in the
event that the circuit breaker fails to respond to a trip command from a feeder protec-
tion.
Whenever e.g. the differential protection or any short-circuit protection relay of a feed-
er issues a trip command to the circuit breaker, this is repeated to the breaker failure
protection (Figure 2-81). A timer T–BF in the breaker failure protection is started. The
timer runs as long as a trip command is present and current continues to flow through
the breaker poles.
Figure 2-81 Simplified function diagram of circuit breaker failure protection with current flow
monitoring
Normally, the breaker will open and interrupt the fault current. The current monitoring
stage CB– I> resets and stops the timer T–BF .
If the trip command is not carried out (breaker failure case), current continues to flow
and the timer runs to its set limit. The breaker failure protection then issues a com-
mand to trip the backup breakers and interrupt the fault current.
The reset time of the feeder protection is not relevant because the breaker failure pro-
tection itself recognizes the interruption of the current.
CB–I>
Feeder protec. &T–BF 0
Circuit breaker failure protection
BF
Trip
(external)
'LIISURW
≥1
7UT612
Diff
Trip
2.11 Circuit Breaker Failure Protection
1537UT612 Manual
C53000–G1176–C148–1
Please make sure that the measuring point of the current and the supervised circuit
breaker belong together! Both must be located at the supply side of the protected ob-
ject. In Figure 2-81 the current is measured at the busbar side of the transformer (=
supply side), therefore the circuit breaker at the busbar side is supervised. The adja-
cent circuit breakers are those of the busbar illustrated.
With generators the breaker failure protection usually affects the network breaker. In
cases other than that, the supply side must be the relevant one.
Initiation Figure 2-82 shows a logic diagram of the circuit breaker failure protection.
The breaker failure protection can be initiated by two different sources:
•Internal protective function of the 7UT612, e.g. trip commands of protective func-
tions or via CFC (internal logic functions),
•External trip signals via binary input.
In both cases, the breaker failure protection checks the continuation of current flow.
Additionally, the breaker position (read from the auxiliary contact) can be checked.
The current criterion is fulfilled if at least one of the three phase currents exceeds a set
thresh old valu e: %UHDNHU6,! or %UHDNHU6,!, depending on the side to
which the breaker failure protection is assigned, see also Subsection 2.1.2 under mar-
gin “Circuit Breaker Status” (page 27).
Processing of the auxiliary contact criterion depends on which auxiliary contacts are
available and how they are arranged to the binary inputs of the device. If both the nor-
mally closed (NC) as well as the normally open (NO) auxiliary contacts are available,
an intermediate position of the breaker can be detected. In this case, disappearance
of the current flow is always the only criterion for the breaker response.
Initiation can be blocked via the binary input “!%/2&.%NU)DLO” (e.g. during testing
of the feeder protection relay).
Delay Time and
Breaker Failure Trip For each of the two sources, a unique pickup message is generated, a unique time
delay is initiated, and a unique tripping signal is generated. The setting value for the
delay applies to both sources.
When the associated time has elapsed, trip command is issued. The two commands
are combined with an OR–gate and form the output information “%UN)DLOXUH75,3”
which is used to trip the adjacent breakers so that the fault current will be interrupted.
The adjacent breakers are those which can feed the same busbar or busbar section
to which the breaker is connected.
2 Functions
154 7UT612 Manual
C53000–G1176–C148–1
Figure 2-82 Logic diagram of the breaker failure protection, illustrated for side 1
75,37LPHU
75,37LPHU
BkrFail int PU
&
&%6LGH,!
283
IL1, IL2, IL3
>BrkFail extSRC
≥1
>CB1 3p Open
>CB1 3p Closed =
&
2))
21
„1“
%5($.(5)$,/85(
>BLOCK BkrFail BLOCK
BkrFail OFF
≥1
Ι>
Max. of
T0
CB op en configured
21
2))
„1“
&KN%5.&217$&7
&
CB closed config ure d
&
&
Error
&
&
&
&≥1
Device Trip BkrFail intTRIP
IL1, IL2, IL3 Ι>
Max. of
T0 BkrFail extTRIP
BkrFail ext PU
&
BkrFail ACTIVE
FNo 1452
FNo 1453
FNo 1451
FNo 1403
FNo 148 1
FNo 1457
FNo 1431
FNo 1480
FNo 145 6
FNo 411
FNo 410
Internal initiation source
External initiation source
≥1
≥1 BrkFailure TRIP
FNo 1471
&%6LGH,!
283
&
&
Meas. release
>BLOCK BkrFail
2.11 Circuit Breaker Failure Protection
1557UT612 Manual
C53000–G1176–C148–1
2.11.2 Setting the Function Parameters
General With the determination of the functional scope (Subsection 2.1.1) in address
%5($.(5)$,/85(, it was defined to which side of the protected object the circuit
breaker failure protection shall operate. Please make sure that the measuring point of
the current and the supervised circuit breaker are assigned to the same side! Both
must be located at the supply side of the protected object.
The breaker failure protection is switched 2)) or 21 under address %5($.(5
)$,/85(.
Initiation Current flow monitoring uses the values set in the Power System Data 1 (Subsection
2.1.2 under margin “Circuit Breaker Status”, page 27). Depending on the side of the
protected object to which the breaker failure protection is assigned, address
%UHDNHU6,! or address %UHDNHU6,! is decisive.
Normally, the breaker failure protection evaluates the current flow criterion as well as
the position of the breaker auxiliary contact(s). If the auxiliary contact(s) status is not
available in the device, this criterion cannot be processed. In this case, set address
&KN%5.&217$&7 to 12.
Time delay The delay times are determined from the maximum operating time of the feeder circuit
breaker, the reset time of the current detectors of the breaker failure protection, plus
a safety margin which allows for any tolerance of the delay timers. The time sequence
is illustrated in Figure 2-83. For the reset time, 11/2 cycle can be assumed.
The time delay is set under address 75,37LPHU.
Figure 2-83 Time sequence example for normal clearance of a fault, and with circuit breaker
failure
Fault inception
Normal fault clearance time
Prot.
trip CB operating time Reset
CB I> Safety
margin
CB operating time
(adjacent CBs)
Initiation breaker
failure protection
Time delay T–BF of breaker
failure protection
Total fault clearance time with breaker failure
2 Functions
156 7UT612 Manual
C53000–G1176–C148–1
2.11.3 Setting Overview
The following list indicates the setting ranges and the default settings of a rated sec-
ondary current IN = 1 A. For a rated secondary current of IN = 5 A, these values must
be multiplied by 5. When setting the device using primary values, the current trans-
former ratios have to be taken into consideration.
2.11.4 Information Overview
Addr. Setting Title Setting Options Default Setting Comments
7001 BREAKER
FAILURE OFF
ON OFF Breaker Failure Protection
7004 Chk BRK CON-
TACT OFF
ON OFF C heck Breaker contacts
7005 TRIP-Timer 0.06..60.00 sec; ∞ 0.25 sec TRIP-Timer
F.No. Alarm Comments
01403 >BLOCK BkrFail >BLOCK Breaker failure
01431 >BrkFail extSRC >Breaker failure initiated externally
01451 BkrFail OFF Breaker failure is switched OFF
01452 BkrFail BLOCK Breaker failure is BLOCKED
01453 BkrFail ACTIVE Breaker failure is ACTIVE
01456 BkrFa il int PU Breaker f ailure (internal) PICKUP
01457 BkrFail ext PU Breaker failure (external) PICKUP
01471 BrkFailure TRIP Breaker failure TRIP
01480 BkrFa il intTRIP Breaker failure (internal) TRIP
01481 BkrFail extTRIP Breaker failure (external) TRIP
01488 BkrFail Not av. Breaker failure Not aval. for this obj.
2.12 Processing of External Signals
1577UT612 Manual
C53000–G1176–C148–1
2.12 Processing of External Signals
2.12.1 Function Description
External Trip
Commands Two desired trip signals from external protection or supervision units can be incorpo-
rated into the processing of the differential protection 7UT612. The signals are cou-
pled into the device via binary inputs. Like the internal protection and supervision sig-
nals, the can be annunciated, delayed, transmitted to the output trip relays, and
blocked. This allows to include mechanical protective devices (e.g. pressure switch,
Buchholz protection) in the processing of 7UT612.
The minimum trip command duration set for all protective functions are also valid for
these external trip commands. (Subsection 2.1.2 under “Trip Command Duration”,
page 27, address $).
Figure 2-84 shows the logic diagram of one of these external trip commands. Two of
these functions are available. The function numbers FNo are illustrated for the exter-
nal trip command 1.
Figure 2-84 Logic diagram of external trip feature — illustrated for External Trip 1
Transformer
Messages In addition to the external trip commands as described above, some typical messages
from power transformers can be incorporated into the processing of the 7UT612 via
binary inputs. This prevents the user from creating user specified annunciations.
These messages are the Buchholz alarm, Buchholz trip and Buchholz tank alarm as
well as gassing alarm of the oil.
Blocking Signal for
External Faults Sometimes for transformers so-called sudden pressure relays (SPR) are installed in
the tank which are meant to switch off the transformer in case of a sudden pressure
increase. Not only transformer failures but also high traversing fault currents originat-
ing from external faults can lead to a pressure increase.
External faults are quickly recognized by 7UT612 (refer also to Subsection 2.2.1, mar-
gin heading “Add-on Stabilization during External Fault”, page 36). A blocking signal
can be created by means of a CFC logic in order to prevent from erroneous trip of the
SPR. Such a logic can be created according to Figure 2-85, for example.
FNo 04526
FNo 04532
Ext 1 BLOCKED
FNo 045 36
Ext 1 picked up
7'(/$<
&
>BLOCK Ext 1
FNo 04523
FNo 045 37
Ext 1 Gen. TRIP
T
>Ext trip 1
2 Functions
158 7UT612 Manual
C53000–G1176–C148–1
Figure 2-85 CFC chart for blocking of a pressure sensor during external fault
2.12.2 S etting the Function Parameters
General The direct external trip functions are only enabled if addresses (;775,3
and/or (;775,3 are set to (QDEOHG in the relay configuration (Subsection
2.1.1).
In ad dresses (;7(5175,3 and (;7(5175,3 functions can be
set to 21 or 2)) apart from each other. And, if required, only the trip command can be
blocked (%ORFNUHOD\).
Signals included from outside can be stabilized by means of a delay time and thus in-
crease the dynamic margin against interference signals. For external trip function 1
settings are done in address 7'(/$<, for external trip function 2 in address
7'(/$<.
2.12.3 Setting Overview
"IN:
%ORFN6DW/63
"
25
25²*DWH
25
3/&B%($
²
%2; <%2
%2;
%2;
"IN:
%ORFN6DW/63
"
"IN:
%ORFN6DW/63
"
"OUT:
%ORFN635,QW63
"
Addr. Setting Title Setting Options Default Setting Comments
8601 EXTERN TRIP 1 ON
OFF OFF External Trip Function 1
8602 T DELAY 0.00..60.00 sec; ∞ 1.00 sec Ext. Trip 1 Time Delay
8701 EXTERN TRIP 2 ON
OFF OFF External Trip Function 2
8702 T DELAY 0.00..60.00 sec; ∞ 1.00 sec Ext. Trip 2 Time Delay
2.12 Processing of External Signals
1597UT612 Manual
C53000–G1176–C148–1
2.12.4 Information Overview
F.No. Alarm Comments
04523 >BLOCK Ext 1 >Block external trip 1
04526 >Ext trip 1 >Trigger external trip 1
04531 Ext 1 OFF External trip 1 is switched OFF
04532 Ext 1 BLOCKED External trip 1 is BLOCKED
04533 Ext 1 ACTIVE External trip 1 is ACTIVE
04536 Ext 1 picked up External trip 1: General picked up
04537 Ext 1 Gen. TRIP External trip 1: General TRIP
04543 >BLOCK Ext 2 >BLOCK external trip 2
04546 >Ext trip 2 >Trigger external trip 2
04551 Ext 2 OFF External trip 2 is switched OFF
04552 Ext 2 BLOCKED External trip 2 is BLOCKED
04553 Ext 2 ACTIVE External trip 2 is ACTIVE
04556 Ext 2 picked up External trip 2: General picked up
04557 Ext 2 Gen. TRIP External trip 2: General TRIP
F.No. Alarm Comments
00390 >Gas in oil >Warning stage from gas in oil detector
00391 >Buchh. Warn >Warning stage from Buchholz protection
00392 >Buchh. Trip >Tripp. stage from Buchholz protection
00393 >Buchh. Tank >Tank supervision from Buchh. protect.
2 Functions
160 7UT612 Manual
C53000–G1176–C148–1
2.13 Monitoring Functions
The device incorporates comprehensive monitoring functions which cover both hard-
ware and software; the measured values are continuously checked for plausibility, so
that the CT circuits are also included in the monitoring system to a large extent. Fur-
thermore, binary inputs are available for supervision of the trip circuit.
2.13.1 Function Description
2.13.1.1 Hardware Monitoring
The complete hardware including the measurement inputs and the output relays is
monitored for faults and inadmissible states by monitoring circuits and by the proces-
sor.
Auxiliary and
Reference Voltages The processor voltage is monitored by the hardware as the processor cannot operate
if the voltage drops below the minimum value. In that case, the device is not opera-
tional. When the correct voltage has re-established the processor system is restarted.
Failure or switch-off of the supply voltage sets the system out of operation; this status
is signalled by a fail-safe contact. Transient dips in supply voltage will not disturb the
function of the relay (see also Subsection 4.1.2 in the Technical Data).
The processor monitors the offset and the reference voltage of the ADC (analog-to-
digital converter). In case of inadmissible deviations the protection is blocked; persist-
ent faults are signalled.
Back-up Battery The back-up battery guarantees that the internal clock continues to work and that me-
tered values and alarms are stored if the auxiliary voltage fails. The charge level of the
battery is checked regularly. If the voltage drops below the permissible minimum the
alarm “)DLO%DWWHU\” is output.
Memory Modules All working memories (RAMs) are checked during start-up. If a fault occurs, the start
is aborted and an LED starts flashing. During operation the memories are checked
with the help of their checksum.
For the program memory (EPROM), the cross-check sum is cyclically generated and
compared to a stored reference program cross-check sum.
For the parameter memory (EEPROM), the cross-check sum is cyclically generated
and compared to the cross-check sum that is refreshed after each parameterization
change.
If a fault occurs the processor system is restarted.
2.13 Monitoring Functi ons
1617UT612 Manual
C53000–G1176–C148–1
Sampling
Frequency The sampling frequency is continuously monitored. If deviations cannot be corrected
by another synchronization, the device sets itself out of operation and the red LED
“Blocked” lights up; the “Device OK” relay drops off and signals the malfunction by its
healthy status contact.
2.13.1.2 Software Monitoring
Watchdog For continuous monitoring of the program sequences, a watchdog timer is provided in
the hardware (hardware watchdog) which will reset and completely restart the proces-
sor system in the event of processor failure or if a program falls out of step.
A further software watchdog ensures that any error in the processing of the programs
will be recognized. Such errors also lead to a reset of the processor.
If such an error is not eliminated by restarting, another restart attempt is initiated. If the
fault is still present after three restart attempts within 30 s, the protection system will
take itself out of service, and the red LED “Blocked” lights up. The “Device OK” relay
drops off and signals the malfunction by its healthy status contact.
2.13.1.3 Monitoring of Measured Quantities
The device detects and signals most of the interruptions, short-circuits, or wrong con-
nections in the secondary circuits of current transformers (an important commission-
ing aid). For this the measured values are checked in background routines at cyclic
intervals, as long as no pickup condition exists.
Current Balance In healthy network operation it can be expected that the currents will be approximately
balanced. The monitoring of the measured values in the device checks this balance
for each side of a three-phase object. For this the lowest phase current is set in relation
to the highest. An unbalance is detected, e.g. for side 1, when
|Imin| / |Imax|<%$/)$&7,6 provided that
Imax / IN>%$/,/,0,76 / IN
Imax is the highest, Imin the lowest of the three phase currents. The balance factor
%$/)$&7,6 represets the degree of unbalance of the phase currents, the lim-
iting value %$/,/,0,76 is the lower threshold of the operating range of this
monitoring function (see Figure 2-86). Both parameters can be set. The resetting ratio
is approx. 97 %.
2 Functions
162 7UT612 Manual
C53000–G1176–C148–1
Figure 2-86 Current balance monitoring
Current balance monitoring is available separate for each side of the protected object.
It has no meaning with single-phase busbar protection and does not operate in this
case. Unsymmetrical condition is indicated for the corresponding side with the alarm
“)DLO,V\P” (FNo ) or “)DLO,V\P” (FNo ). The common mes-
sage “)DLO,EDODQFH” (FNo ) appears in both cases.
Phase Sequence To detect swapped connections in the current input circuits, the direction of rotation of
the phase currents for three-phase application is checked. Therefore the sequence of
the zero crossings of the currents (having the same sign) is checked for each side of
the protected object. For single-phase differential busbar protection and single-phase
transformers this function would not be of any use and is thus disabled.
Especially the unbalanced load protection requires clockwise rotation. If rotation in the
protected object is reverse, this must be considered for the configuration of the Power
System Data 1 (Subsection 2.1.2, margin heading “Phase sequence”).
Phase rotation is checked by supervising the phase sequence of the currents.
IL1 before IL2 before IL3
Supervision of current rotation requires a maximum current of
|IL1|, |IL2|, |IL3| > 0.5 IN.
If the rotation measured differs from the rotation set, the annunciation “)DLO3K6HT
,6” (FNo ) or “)DLO3K6HT,6” (FNo ) is output. At the same time,
the following annunciation appears: “)DLO3K6HT,” (FNo ).
2.13.1.4 Trip Circuit Supervision
The differential protection relay 7UT612 is equipped with an integrated trip circuit su-
pervision. Depending on the number of available binary inputs that are not connected
to a common potential, supervision modes with one or two binary inputs can be select-
ed. If the allocation of the necessary binary inputs does not comply with the selected
monitoring mode, an alarm is given.
Imin
IN
%$/,/,0,7
Slope:
%$/)$&725,
Imax
IN
“
)DLO,EDODQFH
”
2.13 Monitoring Functi ons
1637UT612 Manual
C53000–G1176–C148–1
Supervision Using
Two Binary Inputs If two binary inputs are used, they are connected according to Figure 2-87, one in par-
allel to the assigned command relay contact of the protection and the other parallel to
the circuit breaker auxiliary contact.
A precondition for the use of the trip circuit supervision is that the control voltage for
the circuit breaker is higher than the total of the minimum voltages drops at the two
binary inputs (UCtrl > 2·UBImin). As at least 19 V are needed at each binary input, su-
pervision can be used with a control voltage higher than 38 V.
Figure 2-87 Principle of the trip circuit supervision with two binary inputs
Depending on the state of the trip relay and the circuit breaker’s auxiliary contact, the
binary inputs are triggered (logic state “H” in Table 2-6) or short-circuited (logic state
“L”).
A state in which both binary inputs are not activated (“L”) is only possible in intact trip
circuits for a short transition period (trip relay contact closed but circuit breaker not yet
open).
This state is only permanent in the event of interruptions or short-circuits in the trip cir-
cuit or a battery voltage failure. Therefore, this state is the supervision criterion.
The states of the two binary inputs are interrogated periodically, approximately every
500 ms. Only after n = 3 of these consecutive state queries have detected a fault an
Table 2-6 Status table of the binary inputs depending on TR and CB
No Trip relay Circuit breaker Aux.1 Aux.2 BI 1 BI 2
1 open CLOSED closed open H L
2 open OPEN open closed H H
3 closed CLOSED closed open L L
4 closed OPEN open closed L H
L–
L+
TR
Aux.2
UBI1
UBI2
>TripC trip rel
>TripC brk rel.
UCtrl 7UT612
7UT612
TC
CB
Legend:
TR — Trip relay contact
CB — Circuit breaker
TC — Circuit breaker trip coil
Aux.1 — Circuit breaker auxiliary contact (make)
Aux.2 — Circuit breaker auxiliary contact (break)
UCtrl — Control voltage (trip voltage)
UBI1 — Input voltage of 1st binary input
UBI2 — Input voltage of 2nd binary input
Note:
The diagram shows the circuit breaker in closed
state.
Aux.1
)1R
)1R
2 Functions
164 7UT612 Manual
C53000–G1176–C148–1
alarm is given (see Figure 2-88). These repeated measurements result in a delay of
this alarm and thus avoid that an alarm is given during short-time transient periods.
After the fault is removed in the trip circuit, the fault message is reset automatically af-
ter the same time delay.
Figure 2-88 Logic diagram of the trip circuit supervision with two binary inputs
Supervision Using
One Binary Input The binary input is connected in parallel to the respective command relay contact of
the protection device according to Figure 2-89. The circuit breaker auxiliary contact is
bridged with the help of a high-ohmic substitute resistor R.
The control voltage for the circuit breaker should be at least twice as high as the min-
imum voltage drop at the binary input (UCtrl > 2·UBImin). Since at least 19 V are nec-
essary for the binary input, this supervision can be used with a control voltage higher
than 38 V.
An calculation example for the substitute resistance of R is shown in Subsection 3.1.2,
margin “Trip Circuit Supervision”.
Figure 2-89 Principle of the trip circuit supervision with one binary input
In normal operation the binary input is energized when the trip relay contact is open
and the trip circuit is healthy (logic state “H”), as the monitoring circuit is closed via the
auxiliary contact (if the circuit breaker is closed) or via the substitute resistor R. The
binary input is short-circuited and thus deactivated only as long as the tripping relay is
closed (logic state “L”).
If the binary input is permanently deactivated during operation, an interruption in the
trip circuit or a failure of the (trip) control voltage can be assumed.
&
>TripC trip rel
>TripC brk rel.
TT
T approx. 1 to 2 s
)1R
)1R
)1R
FAIL: Trip cir.
L–
L+
TR
Aux.2Aux.1
UBI >TripC trip rel
UCtrl 7UT612
7UT612
TC
CB
Legend:
TR — Trip relay contact
CB — Circuit breaker
TC — Circu it breaker trip coil
Aux.1 — Circuit breaker auxiliary contact (make)
Aux.2 — Circuit breaker auxiliary contact (break)
R — Substitute resistor
UCrtl — Control voltage (trip voltage)
UBI — Input voltage of binary input
UR— Voltage across the substitute resistor
Note:
The diagram shows the circuit breaker in closed state.
R
)1R
UR
2.13 Monitoring Functi ons
1657UT612 Manual
C53000–G1176–C148–1
As the trip circuit supervision is not operative during a system fault condition (picked-
up status of the device), the closed trip contact does not lead to an alarm. If, however,
the trip contacts of other devices are connected in parallel, the alarm must be delayed
(see also Figure 2-90). After the fault in the trip circuit is removed, the alarm is reset
automatically after the same time.
Figure 2-90 Logic diagram of the trip circuit supervision with one bina ry input
2.13.1.5 Fault Reactions
Depending on the kind of fault detected, an alarm is given, the processor is restarted
or the device is taken out of operation. If the fault is still present after three restart at-
tempts the protection system will take itself out of service and indicate this condition
by drop-off of the “Device OK” relay, thus indicating the device failure. The red LED
“Blocked” on the device front lights up, provided that there is an internal auxiliary volt-
age, and the green LED “RUN” goes off. If the internal auxiliary voltage supply fails,
all LEDs are dark. Table 2-7 shows a summary of the monitoring functions and the
fault reactions of the device.
&
>TripC trip rel
Gen Fault Detection TT
)1R )1R
T approx. 300 s
FA IL: Tr i p c i r.
Table 2-7 Summary of the fault reactions of the device
Supervision Possible causes Fault reaction Alarm Output
Auxilia ry voltag e
failure External (aux. voltage)
Internal (converter) Device out of operation
alarm, if possible All LEDs dark DOK2) drops off
Measured value
acquisition Internal (converter or
sampling) Protection out of
oper ati on, ala rm LED “ERROR”
“(UURU$'FRQY“DOK2) drops off
internal (offset) Protection out of
oper ati on, ala rm LED “ERROR”
“(UURU2IIVHW“DOK2) drops off
Hardware watchdog Internal (processor
failure) Device out of operation LED “ERROR“ DOK2) drops off
Software watchdog Internal (program flow) Restart attempt 1) LED “ERROR“ DOK2) drops off
Working memory Internal (RAM) Restart attempt 1),
Restart ab ort
device out of operation
LED flashe s DOK 2) drops off
Program memory Internal (EPROM) Restart attempt 1) LED “ERROR“ DOK2) drops off
Parameter
memory Internal (EEPROM or
RAM) Restart attempt 1) LED “ERROR“ DOK2) drops off
1) After three unsuccessful attempts the device is put out of operation
2) DOK = “Device OK” relay
2 Functions
166 7UT612 Manual
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2.13.1.6 Group Alarms
Certain messages of the monitoring functions are already combined to group alarms.
Table 2-8 shows an overview of these group alarms an their composition.
1A/5A/0.1A–
setting 1/5/0.1 A jumper wrong Alarms
Protection out of
operation
“(UURU$$ZURQJ“
LED “ERROR“ DOK2) drops off
Calibration data Internal (device not
calibrated) Alarm
Using default values “$ODUP12FDOLEU” as allocated
Backup battery Internal (backup battery) Alarm “)DLO%DWWHU\´ as allocated
Time clock Time synchronization Alarm “&ORFN6\QF(UURU” as allocated
Modules Module does not
comply with ordering
number
Alarms
Protection out of
operation
“(UURU%RDUG...”
and if applicable
“(UURU$'FRQY”
DOK2) drops off
Thermobox
connection Thermo box not
connected or number
does not match
Alarm
No overload protection
with RTD
“)DLO57'%R[” or
“)DLO57'%R[”as allocated
Current symmetry External (system or
current transformers) Alarm with i dentificatio n
of the side “)DLO,V\P” or
“)DLO,V\P”,
“)DLO,EDODQFH”
as allocated
Phase sequence External (system or
connections) Alarm with i dentificatio n
of the side “)DLO3K6HT,6” or
“)DLO3K6HT,6”,
“)DLO3K6HT,”
as allocated
Trip circuit
supervision External (trip circuit or
control voltage) Alarm “)$,/7ULSFLU” as allocated
Table 2-7 Summary of the fault reactions of the device
Supervision Possible causes Fault reaction Alarm Output
1) After three unsuccessful attempts the device is put out of operation
2) DOK = “Device OK” relay
Table 2-8 Group alarms
Group alarm Composed of
FNo Designation FNo Designation
00161 Failure I Supervision
(Measured value supervision without
consequences on protection functions)
00571
00572
00265
00266
Fail. Isym 1
Fail. Isym 2
FailPh.Seq I S1
FailPh.Seq I S2
00160 Alarm Sum Event
(Failures or configuration errors without
consequences on protection functions)
00161
00068
00177
00193
00198
00199
Fail I Superv.
Clock SyncError
Fail Battery
Alarm NO calibr
Err. Module B
Err. Module C
2.13 Monitoring Functi ons
1677UT612 Manual
C53000–G1176–C148–1
2.13.1.7 Setting Errors
If setting of the configuration and function parameters is carried out according to the
order they appear in this chapter, conflicting settings may be avoided. Nevertheless,
changes made in settings, during allocation of binary inputs and outputs or during as-
signment of measuring inputs may lead to inconsistencies endangering proper oper-
ation of protective and supplementary functions.
The device 7UT612 checks settings for inconsistencies and reports them. For in-
stance, the restricted earth fault protection cannot be applied if there is no measuring
input for the starpoint current between the starpoint of the protected object and the
earth electrode.
These inconsistencies are output with the operational and spontaneous annuncia-
tions. Table 3-10 (Subsection 3.3.4, page 227) gives an overview.
2.13.2 Setting the Function Parameters
The sensitivity of the measurement supervision can be altered. Experiential values set
ex works are sufficient in most cases. If an extremely high operational unbalance of
the currents is to be expected in the specific application, or if during operation moni-
toring functions are operated sporadically, the relevant parameters should be set less
sensitive.
Measured Value
Supervision The symmetry supervision can be switched 21 or 2)) in address %$/$1&(,.
In address 3+$6(527$7,21 phase rotation supervision can be set to 21 or
2)).
Address %$/,/,0,76 determines the threshold current for side 1 above
which the current balance supervision is effective (also see Figure 2-86). Address
%$/)$&7,6 is the associated balance factor, i.e. the gradient of the
balance characteristic (Figure 2-86).
Failure measured values
(Fatal configuration or measured value
errors with blocking of all protection
functions)
00181
00190
00183
00192
Error A/D-conv.
Error Board 0
Error Board 1
Error1A/5Awrong
00140 Error Sum Alarm
(Problems which can lead to part
blocking of protection functions)
00161
00191
00264
00267
Fail I Superv.
Error Offset
Fail: RTD-Box 1
Fail: RTD-Box 2
Table 2-8 Group alarms
Group alarm Composed of
FNo Designation FNo Designation
2 Functions
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Address %$/,/,0,76 determines the threshold current for side 1 above
which the current balance supervision is effective (also see Figure 2-86). Address
%$/)$&7,6 is the associated balance factor, i.e. the gradient of the
balance characteristic (Figure 2-86).
Trip Circuit
Supervision When address 7ULS&LU6XS was configured (Subsection 2.1.1), the number
of binary inputs per trip circuit was set. If the trip circuit supervision function is not used
at all, 'LVDEOHG is set there. If the routing of the binary inputs required for this does
not comply with the selected supervision mode, an alarm is output (“7ULS&3URJ
)DLO”).
The trip circuit supervision can be switched 21 or 2)) in address 75,3&LU
683.
2.13.3 Setting Overview
The following list indicates the setting ranges and the default settings of a rated sec-
ondary current IN = 1 A. For a rated secondary current of IN = 5 A, these values must
be multiplied by 5. When setting the device using primary values, the current trans-
former ratios have to be taken into consideration.
Addr. Setting Title Setting Options Default Setting Comments
8101 BALANCE I ON
OFF OFF Current Balance Supervision
8102 PHASE ROTATION ON
OFF OFF Phase Rotation Supervision
8111 BAL. I LIMIT S1 0.10..1 .00 A 0.50 A Current Balance Monitor Side 1
8112 BAL. FACT. I S1 0.10..0.90 0.50 Balance Factor for Current Moni-
tor S1
8121 BAL. I LIMIT S2 0.10..1 .00 A 0.50 A Current Balance Monitor Side 2
8122 BAL. FACT. I S2 0.10..0.90 0.50 Balance Factor for Current Moni-
tor S2
Addr. Setting Title Setting Options Default Setting Comments
8201 TRIP Cir. SUP. ON
OFF OFF TRIP Circuit Supervision
2.13 Monitoring Functi ons
1697UT612 Manual
C53000–G1176–C148–1
2.13.4 Information Overview
F.No. Alarm Comments
00161 Fail I Superv. Failure: General Current Supervision
00163 Fail I balance Failure: Current Balance
00571 Fail. Isym 1 Fail.: Current symm. supervision side 1
00572 Fail. Isym 2 Fail.: Current symm. supervision side 2
00175 Fail Ph. Seq. I Failure: Phase Sequence Current
00265 FailPh.Seq I S1 Failure: Phase Sequence I side 1
00266 FailPh.Seq I S2 Failure: Phase Sequence I side 2
F.No. Alarm Comments
SysIntErr. Error Systeminterface
Error FMS1 Error FMS FO 1
Error FMS2 Error FMS FO 2
00110 Event Lost Event lost
00113 Flag Lost Flag Lost
00140 Error Sum Alarm Error with a summary alarm
00181 Error A/D-conv. Error: A/D converte r
00190 Error Board 0 Error Board 0
00183 Error Board 1 Error Board 1
00192 Error1A/5Awrong Error:1A/5Ajumper different from setting
00191 Error Offset Error: Offse t
00264 Fail: RTD-Box 1 Failure: RTD-Box 1
00267 Fail: RTD-Box 2 Failure: RTD-Box 2
00160 Alarm Sum Event Alarm Summary Event
00193 Alarm NO calibr Alarm: NO calibration data available
00177 Fail Battery Failure: Battery empty
00068 Clock SyncError Clock Synchronization Error
00198 Err. Module B Error: Communication Module B
00199 Err. Module C Error: Communication Module C
2 Functions
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F.No. Alarm Comments
06851 >BLOCK TripC >BLOCK Trip circuit supervision
06852 >TripC trip rel >Trip circuit supervision: trip relay
06853 >TripC brk rel. >Trip circuit supervision: breaker relay
06861 TripC OFF Trip circuit supervision OFF
06862 TripC BLOCKED Trip circuit supervision is BLOCKED
06863 TripC ACTIVE Trip circuit supervision is ACTIVE
06864 TripC ProgFail Trip Circuit blk. Bin. input is not set
06865 FAIL: Trip cir. Failure Trip Circuit
2.14 Protection Function Control
1717UT612 Manual
C53000–G1176–C148–1
2.14 Protection Function Control
The function control is the control centre of the device. It coordinates the sequence of
the protection and ancillary functions, processes their decisions and the information
coming from the power system. Among these are
•processing of the circuit breaker position,
•fault detection/pickup logic,
•tripping logic.
2.14.1 Fault Detection Logic of the Entire Device
General Pickup The fault detection logic combines the pickup signals of all protection functions. The
pickup signals are combined with
OR
and lead to a general pickup of the device. It is
signalled with the alarm “5HOD\3,&.83”. If no protection function of the device has
picked up any longer, “5HOD\3,&.83” disappears (message: “*RLQJ”).
The general pickup is the precondition for a number of internal and external conse-
quential functions. Among these functions, which are controlled by the general pickup,
are:
•Start of a fault log: All fault messages are entered into the trip log from the beginning
of the general pickup to the dropout.
•Initialization of the fault recording: The recording and storage of fault wave forms
can additionally be made subject to the presence of a trip command.
•Creation of spontaneous displays: Certain fault messages can be displayed as so
called spontaneous displays (see “Spontaneous Displays” below). This display can
additionally be made subject to the presence of a trip command.
External functions can be controlled via an output contact. Examples are:
•Further additional devices or similar.
Spontaneous
Displays Spontaneous displays are alarms that are displayed automatically after a general pick-
up of the device or after the trip command of the device. In the case of 7UT612 they
are the following:
•“5HOD\3,&.83”: pickup of any protection function with phase indication;
•“5HOD\75,3”: trip of any protection function;
•“387LPH”: the operating time from the general pickup to the dropout of the
device, the time is given in ms;
•“75,37LPH”: the operating time from the general pickup to the first trip
command of the device, the time is given in ms.
Note, that the overload protection does not have a pickup comparable to the other pro-
tective functions. The general device pickup time is started with the trip signal, which
starts the trip log.
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2.14.2 Tripping Logic of the Entire Device
General Tripping All tripping signals of the protection functions are combined with logical
OR
and lead
to the alarm “5HOD\75,3“. This can be allocated to an LED or output relay as can
be each of the individual trip commands. It is suitable as general trip information as
well as used for the output of trip commands to the circuit breaker.
Terminating the
Trip Command Once a trip command is activated, it is stored separately for each side of the protected
object (Figure 2-91). At the same time a minimum trip command duration 70LQ75,3
&0' is started to ensure that the command is sent to the circuit breaker long enough
if the tripping protection function should drop off too quickly or if the breaker of the
feeding end operates faster. The trip commands cannot be terminated until the last
protection function has dropped off (no function activated)
AND
the minimum trip com-
mand duration is over.
A further condition for terminating the trip command is that the circuit breaker is rec-
ognized to be open. The current through the tripped breaker must have fallen below
the value that corresponds to the setting value %UHDNHU6,! (address for side
1), or %UHDNHU6,! (address for side 2), refer to “Circuit Breaker Status” in
Subsection 2.1.2, page 27) plus 10 % of the fault current.
Figure 2-91 Storage and termination of the trip command
Reclosure
Interlocking When tripping the circuit breaker by a protection function the manual reclosure must
often be blocked until the cause for the protection function operation is found.
Using the user-configurable logic functions (CFC) an automatic reclosure interlocking
function can be created. The default setting of 7UT612 offers a pre-defined CFC logic
which stores the trip command of the device until the command is acknowledged man-
ually. The CFC-block is illustrated in Appendix A.5, margin heading “Preset CFC–
Charts” (page 306). The internal output “*7534XLW” must be additionally assigned
to the tripping output relays which are to be sealed.
Acknowledgement is done via binary input “!4XLW*753”. With default configuration,
press function key F4 at the device front to acknowledge the stored trip command.
If the reclosure interlocking function is not required, delete the allocation between the
internal single-point indication “*7534XLW” and the source “CFC” in the configura-
tion matrix.
CB open
T
S
R
Q
&
Trip commands
(from protection &
functions)
Relay TRIP
70LQ75,3&0'
FNo 005 11
2.14 Protection Function Control
1737UT612 Manual
C53000–G1176–C148–1
“No Trip no Flag” The storage of fault messages allocated to local LEDs and the availability of sponta-
neous displays can be made dependent on the device sending a trip command. Fault
event information is then
not
output when one or more protection functions have
picked up due to a fault but no tripping occurred because the fault was removed by
another device (e.g. on a different feeder). The information is thus limited to faults on
the protected line (so-called “no trip – no flag” feature).
Figure 2-92 shows the logic diagram of this function.
Figure 2-92 Logic diagram of the “no–trip–no–flag” feature (command-dependent alarms)
CB Operation
Statistics The number of trips caused by the device 7UT612 is counted.
Furthermore, the current interrupted for each pole is acquired, provided as an informa-
tion and accumulated in a memory.
The levels of these counted values are buffered against auxiliary voltage failure. They
can be set to zero or to any other initial value. For further information refer to the
SIPROTEC® 4 System Manual, order no. E50417–H1176–C151.
2.14.3 Setting the Function Parameters
The parameters for the tripping logic of the entire device and the circuit breaker test
have already been set in Subsection 2.1.2.
Address )OW'LVS/('/&' still decides whether the alarms that are allocated
to local LEDs and the spontaneous displays that appear on the local display after a
fault should be displayed on every pickup of a protection function (7DUJHWRQ38) or
whether they should be stored only when a tripping command is given (7DUJHWRQ
75,3).
&
Device TRIP
“1“
Device dropoff
Reset LED and spontaneous displays
)OW'LVS/('/&'
7DUJHWRQ38
7DUJHWRQ75,3
2 Functions
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2.14.4 Setting Overview
2.14.5 Information Overview
Addr. Setting Title Setting Options Default Setting Comments
7110 FltDisp.LED/LCD Display Targets on every
Pickup
Display Targets on TRIP only
Display Targets on
every Pickup Fault Displ ay on LED / LCD
F.No. Alarm Comments
00003 >Time Synch >Synchronize Internal Real Time Clock
00005 >Reset LED >Reset LED
00060 Reset LED Reset LED
00015 >Test mode >Test mode
Test mode Test mode
00016 >DataStop >Stop data transmission
DataStop Stop data transmission
U nlockDT Unlock data transmission via BI
>Light on >Back Light on
00051 Device OK Device is Operational and Protecting
00052 ProtActive At Least 1 Protection Funct. is Active
00055 Reset Device Reset Device
00056 Initial Start Initial Start of Device
00067 Resume Resume
00069 DayLightSavTime Daylight Saving Time
SynchC lock Clock Synchronization
00070 Settings Calc. Setting calculation is running
00071 Settings Chec k Setting s Chec k
00072 Level-2 change Level-2 change
00109 Frequ. o.o.r. Frequency out of range
00125 Chatter ON Chatter ON
HWTestMod Hardware Test Mode
2.15 Ancillary Functions
1757UT612 Manual
C53000–G1176–C148–1
2.15 Ancillary Functions
The auxiliary functions of the 7UT612 relay include:
•processing of messages,
•processing of operational measured values,
•storage of fault record data.
2.15.1 Processing of Messages
2.15.1.1 General
For the detailed fault analysis, the information regarding the reaction of the protection
device and the measured values following a system fault are of interest. For this pur-
pose, the device provides information processing which operates in a threefold man-
ner:
Indicators (LEDs)
and Binary Outputs
(Output Relays)
Important events and states are indicated with optical indicators (LED) on the front
plate. The device furthermore has output relays for remote indication. Most of the sig-
nals and indications can be marshalled, i.e. routing can be changed from the preset-
ting with delivery. The procedure is described in detail in the SIPROTEC® 4 system
manual, order no. E50417–H1176–C151. The state of the delivered relay (presetting)
is listed in Section A.5 of the Appendix
The output relays and the LEDs may be operated in a latched or unlatched mode
(each may be individually set).
The latched state is saved against loss of auxiliary supply. It is reset:
−locally by operation of the key LED reset on the front of the device,
−from remote via a binary input,
−via one of the serial interfaces,
−automatically on detection of a new fault.
Condition messages should not be latched. Also, they cannot be reset until the condi-
tion to be reported has reset. This applies to e.g. messages from monitoring functions,
or similar.
A green LED indicates that the device is in service (“RUN”); it can not be reset. It ex-
tinguishes if the self-monitoring of the microprocessor recognizes a fault or if the aux-
iliary supply fails.
In the event that the auxiliary supply is available while there is an internal device fail-
ure, the red LED (“ERROR”) is illuminated and the device is blocked.
The binary inputs, outputs, and LEDs of a SIPROTEC®4 device can be individually
and precisely checked using DIGSI®4. This feature is used to verify wiring from the
device to plant equipment during commissioning (refer also to Subsection 3.3.3).
2 Functions
176 7UT612 Manual
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Information on the
Integrated Display
(LCD) or to a
Personal Computer
Events and states can be obtained from the LCD on the front plate of the device. A
personal computer can be connected to the front interface or the service interface for
retrieval of information.
In the quiescent state, i.e. as long as no system fault is present, the LCD can display
selectable operational information (overview of the operational measured values). In
the event of a system fault, information regarding the fault, the so-called spontaneous
displays, are displayed instead. The quiescent state information is displayed again
once the fault messages have been acknowledged. The acknowledgement is identical
to the resetting of the LEDs (see above).
The device in addition has several event buffers for operational messages, switching
statistics, etc., which are saved against loss of auxiliary supply by means of a battery
buffer. These messages can be displayed on the LCD at any time by selection via the
keypad or transferred to a personal computer via the serial service or PC interface.
The retrieval of events/alarms during operation is extensively described in the
SIPROTEC® 4 System Manual, order no. E50417–H1176–C151.
With a PC and the protection data processing program DIGSI®4 it is al so po ssib le to
retrieve and display the events with the convenience of visualisation on a monitor and
a menu-guided dialogue. The data may be printed or stored for later evaluation.
Information to a
Control Centre If the device has a serial system interface, the information may additionally be trans-
ferred via this interface to a centralized control and monitoring system. Several com-
munication protocols are available for the transfer of this information.
You may test whether the information is transmitted correctly with DIGSI®4.
Also the information transmitted to the control centre can be influenced during opera-
tion or tests. For on-site monitoring, the IEC protocol 60870–5–103 offers the option
to add a comment saying “test mode” to all annunciations and measured values trans-
mitted to the control centre. It is then understood as the cause of annunciation and
there is no doubt on the fact that messages do not derive from real disturbances. Al-
ternatively, you may disable the transmission of annunciations to the system interface
during test s (“t rans mi ssi on blo ck ”).
To influence information at the system interface during test mode (“test mode” and
“transmission block”) a CFC logic is required. Default settings already include this log-
ic (see Appendix A.5, margin heading “Preset CFC–Charts”, page 306).
For information on how to enable and disable the test mode and the transmission
block see for the SIPROTEC® 4 System Manual E50417–H1176–C151.
Structure of
Messages The messages are categorized as follows:
•Event Log: these are operating messages that can occur during the operation of the
device. They include information about the status of device functions, measurement
data, system data, and similar information.
•Trip Log: these are fault messages from the last eight network faults that were proc-
essed by the device.
•Switching statistics; these messages count the trip commands initiated by the de-
vice, values of accumulated circuit currents and interrupted currents.
A complete list of all message and output functions that can be generated by the de-
vice, with the associated information number (FNo), can be found in the Appendix.
The lists also indicate where each message can be sent. The lists are based on a
2.15 Ancillary Functions
1777UT612 Manual
C53000–G1176–C148–1
SIPROTEC® 4 device with the maximum complement of functions. If functions are not
present in the specific version of the device, or if they are set as “'LVDEOHG” in device
configuration, then the associated messages cannot appear.
2.15.1.2 Event Log (Operating Messages)
Operating messages contain information that the device generates during operation
and about the operation. Up to 200 operating messages are stored in chronological
order in the device. New messages are added at the end of the list. If the memory has
been exceeded, then the oldest message is overwritten for each new message.
Operational annunciations come in automatically and can be read out from the device
display or a personal computer. Faults in the power system are indicated with “1HW
ZRUN)DXOW” and the present fault number. The fault messages (Trip Log) contain
details about the history of faults. This topic is discussed in Subsection 2.15.1.3.
2.15.1.3 Trip Log (Fault Messages)
Following a system fault, it is possible to for example retrieve important information re-
garding its progress, such as pickup and trip. The start of the fault is time stamped with
the absolute time of the internal system clock. The progress of the disturbance is out-
put with a relative time referred to the instant of fault detection (first pickup of a protec-
tion function), so that the duration of the fault until tripping and up to reset of the trip
command can be ascertained. The resolution of the time information is 1 ms.
A system fault starts with the recognition of the fault by the fault detection, i.e. first pick-
up of any protection function, and ends with the reset of the fault detection, i.e. dropout
of the last protection function, or after the expiry of the auto-reclose reclaim time, so
that several unsuccessful auto-reclose cycles are also stored cohesively. Accordingly
a system fault may contain several individual fault events (from fault detection up to
reset of fault detection).
Spontaneous
Displays The spontaneous messages appear automatically in the display, after a general pick-
up of the device. The most important data about a fault can be viewed on the device
front in the sequence shown in Figure 2-93.
Figure 2-93 Display of spontaneous messages in the display
Protection function that had picked up, e.g.
differential protection, with phase information;
Protection function that had tripped, e.g.
differential protection;
Elapsed time from pickup until dropoff;
Elapsed time from pickup until the first trip com-
mand of a protection function.
'LII3LFNXS/(
'LII7ULS
387LPHPV
75,37LPHPV
2 Functions
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Retrieved
messages The messages for the last eight network faults can be retrieved. Altogether up to 600
indications can be stored. Oldest data are erased for newest data when the buffer is
full.
2.15.1.4 Spontaneous Annunciations
Spontaneous annunciations contain information on new incoming annunciations.
Each new incoming annunciation appears immediately, i.e. the user does no have to
wait for an update or initiate one. This can be a useful help during operation, testing
and commissioning.
Spontaneous annunciations can be read out via DIGSI®4. For further information see
the SIPROTEC® 4 System Manual (order-no. E50417–H1176–C151).
2.15.1.5 General Interrogat ion
The present condition of a SIPROTEC® device can be examined by using DIGSI®4
to view the contents of the “General Interrogation” annunciation. All of the messages
that are needed for a general interrogation are shown along with the actual values or
states.
2.15.1.6 Switching Statistics
The messages in switching statistics are counters for the accumulation of interrupted
cur rent s by ea ch of the brea ker p oles , th e numb er of trip s issu ed by the devic e to the
breakers. The interrupted currents are in primary terms.
Switching statistics can be viewed on the LCD of the device, or on a PC running
DIGSI®4 and connected to the operating or service interface.
The counters and memories of the statistics are saved by the device. Therefore the
information will not get lost in case the auxiliary voltage supply fails. The counters,
however, can be reset back to zero or to any value within the setting range.
A password is not required to read switching statistics; however, a password is re-
quired to change or delete the statistics. For further information see the SIPROTEC®
4 System Manual (order-no. E50417–H1176–C151).
2.15 Ancillary Functions
1797UT612 Manual
C53000–G1176–C148–1
2.15.2 Measurement during Operation
Display and
Transmission of
Measured Values
Operating measured values are determined in the background by the processor sys-
tem. They can be called up at the front of the device, read out via the operating inter-
face using a PC with DIGSI®4, or transferred to a central master station via the sys-
tem interface (if available).
Precondition for a correct display of primary and percentage values is the complete
and correct entry of the nominal values of the instrument transformers and the power
system according to Subsection 2.1.2. Table 2-9 shows a survey of the operational
measured values. The scope of measured values depends on the ordered version, the
configured functions and the connection of the device.
To be able to output a measured voltage “8PHDV”, a measured voltage has to be con-
nected to one of the current inputs I7 or I8 via an external series resistor. Via a user-
configurable CFC logic (CFC block “Life_Zero”) the current proportional to the voltage
can be measured and indicated as voltage “8PHDV”. For more information see the
manual CFC.
The apparent power “6” is not a measured value, but a value calculated from the rated
voltage of the protected object which is set and the actually flowing currents of side 1:
for three-phase applications or S =
for single-phase transformers. If, however, the voltage measurement described in the
previous paragraph is applied, this voltage measurement is used to calculate the ap-
parent power.
The phase angles are listed in Table 2-10, the measured thermal values in Table 2-
11. The latter can only appear if the overload protection is set to (QDEOHG. Which
measured values are available to the user also depends on the method of overload
detection selected and maybe on the number of temperature detectors interconnected
between device and thermobox.
The operational measured values are also calculated during a running fault in intervals
of approx. 0.6 s.
The referred values are always based on the nominal values of the protected object
(cf. also the footnotes of the tables), the temperature rise is based on the trip temper-
ature rise. The phase angles and the temperature degrees have actually no base
values. But, processing of these values in the CFC-logic or transmission via the serial
interfaces requires values without dimension, therefore, base values are defined arbi-
trarily. These are stated in the Tables 2-10 and 2-11 in the column titled “%–Conver-
sion”.
SUN
3
------I
L1S1 IL2S1 IL3S1
++
()⋅
=U
N
2
----- I L1S1 IL3S1
+
()⋅
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Table 2-9 Operational measured values (magnitudes primary, secondary, percent)
Measured values primary secondary % referred to
IL1S1, IL2S1, IL3S1 3) Phase currents of side 1 A; kA A Operating nominal current 1)
3I0S1 3) Residual current of side 1 A; kA A Operating nominal current 1)
I1S1, I2S1 3) Positive and negative sequence
component currents of side 1 A; kA A Operating nominal current 1)
IL1S2, IL2S2, IL3S2 3) Phase currents of side 2 A; kA A Operating nominal current 1)
3I0S2 3) Residual current of side 2 A; kA A Operating nominal current 1)
I1S2, I2S2 3) Positive and negative sequence
component currents of side 2 A; kA A Operating nominal current 1)
I7 3) Current at current input I7 A; kA A Operating nominal current 1)
I1 ... I7 4) Currents at the current inputs A; kA A Operating nominal current 1)
I8 Current at current input I8A mA Operating nominal current 1) 2)
Umeas 5) Voltage from current at I7 or I8 V; kV; MV ——
S 6) Apparent power kVA; MVA;
GVA ——
f Frequency Hz Hz Rated frequency
1) for transformers acc. to addresses
,
, and
(see Subsection 2.1.2) IN = S N/(√3·UN) or IN = SN/UN (1-phase)
for generators/motors/reactors acc. to addresses
and
(see Subsection 2.1.2) IN = SN/(√3·UN);
for busbars and lines acc. to address
(see Subsection 2.1.2)
2) with consideration of the factor address
)DFWRU,
(see Subsection 2.1.2)
3) only for three-phase objects
4) only for single-phase busbar protection
5) if configured and prepared in CFC
6) calculated from phase currents and nominal voltage or measured voltage Umeas
Table 2-10 Operational measured values ( phase relationship)
Measured values Dimensi on %–Conversion 5)
ϕIL1S1 , ϕIL2S1 , ϕIL3S 1 3) Phase angl e of the currents of side 1,
towards IL1S1 ° 0° = 0 %
360° = 100 %
ϕIL1S2 , ϕIL2S2, ϕIL3S2 3) Phase angle of the currents of side 2,
towards IL1S1 ° 0° = 0 %
360° = 100 %
ϕI1 ... ϕI7 4) Phase angle of the currents at the current inputs,
towards I1 ° 0° = 0 %
360° = 100 %
ϕI7 3) Phase angle of the current at the current input I7,
towards I1 ° 0° = 0 %
360° = 100 %
3) only for three-phase object s
4) only for single-phase busbar protection
5) only for CFC and
serial interfaces
2.15 Ancillary Functions
1817UT612 Manual
C53000–G1176–C148–1
Differential
Protection Values The differential and restraining values of the differential protection and the restricted
earth fault protection are listed in Table 2-12.
The IBS-Tool The commissioning help “IBS-tool” offers a wide range of commissioning and monitor-
ing functions that allows a detailed illustration of the most important measured values
via a personal computer equipped with a web-browser. For more details refer to the
“Online Help” for the IBS-tool. The “Online Help” can be downloaded from the INTER-
NET.
Table 2-11 Thermal values
Measured values Dimension %–Conversion 5)
ΘL1/Θtrip, ΘL2/Θtrip, ΘL3/Θtrip 1)Thermal value of each phase,
referred to the tripping value %
Θ/Θtrip 1)Thermal resultant value,
referred to the tripping value %
Ag.Rate 2) 3) Relative ageing rate p.u.
ResWARN 2) 3) Load reserve to hot-spot warning (stage 1) %
ResALARM 2) 3) Load reserve to hot-spot alarm (stage 2) %
Θleg1,Θleg2, Θleg3 2) 3) Hot-spot temperature for each phase °C or °F 0 °C = 0 %
500 °C = 100 %
0°F = 0%
1000 °F = 100 %
ΘRTD1 ... ΘRTD12 3) Temperature of the temperature detectors 1 to 12 °C or °F
1) only for overload protection with thermal replica (IEC 60255–8): address
7KHUP2/&+5
=
FODVVLFDO
(Subsection 2.1.1)
2) only for overload protection with hot-spot c alculation (IEC 60354): address
7KHUP2/&+5
=
,(&
(Subsection 2.1.1)
3) only if thermobox(es) available (Section 2.10)
5) only for CFC and
serial interfaces
Table 2-12 Values of the differential protection
Measured values % referred to
IDiffL1, IDiffL2, IDiffL3 Calculated differential currents of the three phases Operating nominal current 1)
IRestL1, IRestL2, IRestL3 Calculated restraining currents of the three phases Operating nominal current 1)
IDiffEDS Calculated differe ntial current of the restricted earth fault
protection Operating nominal current 1)
IRestEDS Calculated restraining current of the restricted earth fault
protection Operating nominal current 1)
1) for transformers acc. to addresses
,
, and
(see Subsection 2.1.2) IN = SN/(√3·UN) or IN = SN/UN (1-phase);
for generators/motors/reactors acc. to addresses
and
(see Subsection 2.1.2) IN = SN/(√3·UN);
for busbars and lines acc. to address
(see Subsection 2.1.2)
2 Functions
182 7UT612 Manual
C53000–G1176–C148–1
This tool allows to illustrate the measured values of all ends of the protected object
during commissioning and during operation. The currents appear as vector diagrams
and are indicated as numerical values. Figure 2-94 shows an example.
Additionally the position of the differential and restraint values can be viewed in the
pickup ch ar acter is ti c.
Figure 2-94 Measured values of the sides of the protected ob ject — example for through-flowing currents
User Defined
Set-Points In SIPRO TEC® 7UT612, set-points can be configured for measured and metered val-
ues. If, during operation, a value reaches one of these set-points, the device gener-
ates an alarm which is indicated as an operational message. As for all operational
messages, it is possible to output the information to LED and/or output relay and via
the serial interfaces. The set-points are supervised by the processor system in the
background, so they are not suitable for protection purposes.
Set-points can only be set if their measured and metered values have been configured
correspondingly in CFC (see SIPROTEC®4 System Manual, ordering number
E50417–H1176–C151).
Secondary Values
Currents: Si de 1 Currents: Side 2
–90°
0° 0°±180° ±180°
+90° +90°
–90°
IL1 L S1 =
IL2 L S1 =
IL3 L S1 =
1.01 A,
0.98 A,
0.99 A,
0.0 °
240.2 °
119.1 °
IL1LS2 =
IL2LS2 =
IL3LS2 =
0.99 A,
0.97 A,
0.98 A,
177.9 °
58.3 °
298.2 °
2.15 Ancillary Functions
1837UT612 Manual
C53000–G1176–C148–1
2.15.3 Fault Recording
The differential protection 7UT612 is equipped with a fault recording function. The in-
stantaneous values of the measured quantities
iL1S1, iL2S1, iL3S1, iL1S2, iL2S2, iL3S2, 3i0S1, 3i0S2, i7, i8, and
IDiffL1, IDiffL2, IDiffL3, IRestL1, IRestL2, IRestL3
are sampled at 12/3ms intervals (for a frequency of 50 Hz) and stored in a cyclic buffer
(12 samples per period). When used as single-phase busbar protection, the first six
feeder currents are stored instead of the phase currents, the zero sequence currents
are nor applicable.
During a system fault these data are stored over a time span that can be set (5 s at
the longest for each fault record). Up to 8 faults can be stored. The total capacity of
the fault record memory is approx. 5 s. The fault recording buffer is updated when a
new fault occurs, so that acknowledging is not necessary. Fault recording can be ini-
tiated, additionally to the protection pickup, via the integrated operator panel, the serial
operator interface and the serial service interface.
The data can be retrieved via the serial interfaces by means of a personal computer
and evaluated with the protection data processing program DIGSI®4 and the graphic
analysis software SIGRA 4. The latter graphically represents the data recorded during
the system fault and calculates additional information from the measured values. A se-
lection may be made as to whether the measured quantities are represented as pri-
mary or secondary values. Binary signal traces (marks) of particular events e.g. “fault
detection”, “tripping” are also represented.
If the device has a serial system interface, the fault recording data can be passed on
to a central device via this interface. The evaluation of the data is done by the respec-
tive programs in the central device. The measured quantities are referred to their max-
imum values, scaled to their rated values and prepared for graphic representation. In
addition, internal events are recorded as binary traces (marks), e.g. “fault detection”,
“tripping”.
Where transfer to a central device is possible, the request for data transfer can be ex-
ecuted automatically. It can be selected to take place after each fault detection by the
protection, or only after a trip.
2.15.4 Setting the Function Parameters
Measured Values In addition to the values measured directly and the measured values calculated from
currents and maybe from temperatures the 7UT612 can also output the voltage and
the apparent power.
To get the voltage values, a voltage must be connected to the current measuring input
I7 or I8 via an external series resistor. Additionally, a user-defined logic must be cre-
ated in CFC (see Subsection 2.15.2, margin heading “Display and Transmission of
Measured Values”).
The apparent power is either calculated from this voltage or from the rated voltage of
side 1 of the protected object and the currents of the same side. For the first case, set
2 Functions
184 7UT612 Manual
C53000–G1176–C148–1
address 32:(5&$/&8/ to = ZLWK9PHDVXU, for the latter case ZLWK9
VHWWLQJ.
Waveform Capture The settings pertaining to waveform capture are found under the 26&)$8/75(&
sub-menu of the 6(77,1*6 menu.
Distinction is made between the starting instant (i.e. the instant where time tagging is
T = 0) and the criterion to save the record (address :$9()25075,**(5). With
the setting 6DYHZ3LFNXS, the starting instant and the criterion for saving are the
same: the pickup of any protective element. The option 6DYHZ75,3 means that
also the pickup of a protective function starts fault recording but the record is saved
only if the device issues a trip command. The final option for address is 6WDUW
Z75,3: A trip command issued by the device is both the starting instant and the
criterion to save the record.
An oscillographic record includes data recorded prior to the time of trigger, and data
after the dropout of the recording criterion. You determine the length of pre-trigger time
and post-dropout time to be included in the fault record with the settings in Address
35(75,*7,0( and addre ss 32675(&7,0(
The maximum length of time of a record is entered in address 0$;/(1*7+.
The largest value here is 5 seconds. A total of 8 records can be saved. However the
total length of time of all fault records in the buffer may not exceed 5 seconds. Once
the capacity of the buffer is exceeded the oldest fault is deleted, whereas the new fault
is saved in the buffer.
An oscillographic record can be triggered and saved via a binary input or via the op-
erating interface connected to a PC. The trigger is dynamic. The length of a record for
these special triggers is set in address %LQ,Q&$377,0( (upper bound is ad-
dress ). Pre-t rigge r and post-dr opo ut sett ing s in Addre sses and are in-
cluded. If address is set for “∞”, then the length of the record equals the time that
the binary input is activated (static), or the 0$;/(1*7+ setting in address ,
whichever is shorter.
2.15.5 Setting Overview
Measured Values
Fault Recording
Addr. Setting Title Setting Options Default Setting Comments
7601 POWER CALCUL. with V setting
with V measuring with V setting Calculation of Power
Addr. Setting Title Setting Options Default Setting Comments
401 WAVEFORMTRIG-
GER Save with Pickup
Save with TRIP
Start with TRIP
Save with Pickup Waveform Capture
403 MAX. LENGTH 0.30..5.00 sec 1.00 sec Max. length of a Wave form Capture Record
2.15 Ancillary Functions
1857UT612 Manual
C53000–G1176–C148–1
2.15.6 Information Overview
Statistics
Measured Values
404 PRE. TRIG. TIME 0.05..0.50 sec 0.10 sec Captured Waveform Prior to Trigger
405 POST REC. TIME 0.05..0.50 sec 0.10 sec Captured Waveform after Event
406 BinIn CAPT.TIME 0.10..5.00 sec; ∞ 0.50 sec Capt ure Time via Binary Input
Addr. Setting Title Setting Options Default Setting Comments
F.No. Alarm Comments
00409 >BLOCK Op Count >BLOCK Op Counter
01020 Op.Hours= Counter of operating hours
01000 # TRIPs= Number of breaker TRIP commands
30607 ΣIL1S1: Accumulation of interrupted curr. L1 S1
30608 ΣIL2S1: Accumulation of interrupted curr. L2 S1
30609 ΣIL3S1: Accumulation of interrupted curr. L3 S1
30610 ΣIL1S2: Accumulation of interrupted curr. L1 S2
30611 ΣIL2S2: Accumulation of interrupted curr. L2 S2
30612 ΣIL3S2: Accumulation of interrupted curr. L3 S2
30620 ΣI1 : Accumulation of interrupted curr. I1
30621 ΣI2: Accumulation of interrupted curr. I2
30622 ΣI3: Accumulation of interrupted curr. I3
30623 ΣI4: Accumulation of interrupted curr. I4
30624 ΣI5: Accumulation of interrupted curr. I5
30625 ΣI6: Accumulation of interrupted curr. I6
30626 ΣI7: Accumulation of interrupted curr. I7
F.No. Alarm Comments
00721 IL1S1= Operat. meas. current IL1 side 1
00722 IL2S1= Operat. meas. current IL2 side 1
00723 IL3S1= Operat. meas. current IL3 side 1
30640 3I0S1= 3I0 (zero sequence) of side 1
30641 I1S1= I1 (positive sequence) of side 1
2 Functions
186 7UT612 Manual
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30642 I2S1= I2 (negative sequence) of side 1
00724 IL1S2= Operat. meas. current IL1 side 2
00725 IL2S2= Operat. meas. current IL2 side 2
00726 IL3S2= Operat. meas. current IL3 side 2
30643 3I0S2= 3I0 (zero sequence) of side 2
30644 I1S2= I1 (positive sequence) of side 2
30645 I2S2= I2 (negative sequence) of side 2
30646 I1= Operat. meas. current I1
30647 I2= Operat. meas. current I2
30648 I3= Operat. meas. current I3
30649 I4= Operat. meas. current I4
30650 I5= Operat. meas. current I5
30651 I6= Operat. meas. current I6
30652 I7= Operat. meas. current I7
30653 I8= Operat. meas. current I8
07740 ϕIL1S1= Phase angle in phase IL1 side 1
07741 ϕIL2S1= Phase angle in phase IL2 side 1
07749 ϕIL3S1= Phase angle in phase IL3 side 1
07750 ϕIL1S2= Phase angle in phase IL1 side 2
07759 ϕIL2S2= Phase angle in phase IL2 side 2
07760 ϕIL3S2= Phase angle in phase IL3 side 2
30633 ϕI1= Phase angle of current I1
30634 ϕI2= Phase angle of current I2
30635 ϕI3= Phase angle of current I3
30636 ϕI4= Phase angle of current I4
30637 ϕI5= Phase angle of current I5
30638 ϕI6= Phase angle of current I6
30639 ϕI7= Phase angle of current I7
30656 Umeas.= Operat. meas. voltage Umeas.
00645 S = S (apparent power)
00644 Freq= Frequency
F.No. Alarm Comments
2.15 Ancillary Functions
1877UT612 Manual
C53000–G1176–C148–1
Thermal Values
Diff-Values
F.No. Alarm Comments
00801 Θ /Θtrip = Temp erat. rise for warning and trip
00802 Θ /Θtr ipL1= Temperature rise for ph ase L1
00803 Θ /ΘtripL2= Temperature rise for ph ase L2
00804 Θ /ΘtripL3= Temperature rise for ph ase L3
01060 Θ leg 1= Hot spot temperature of leg 1
01061 Θ leg 2= Hot spot temperature of leg 2
01062 Θ leg 3= Hot spot temperature of leg 3
01063 Ag.Rate= Aging Rate
01066 ResWARN= Load Reserve to warning level
01067 ResALARM= Load Reserve to alarm level
01068 Θ RTD 1 = Temperature of RTD 1
01069 Θ RTD 2 = Temperature of RTD 2
01070 Θ RTD 3 = Temperature of RTD 3
01071 Θ RTD 4 = Temperature of RTD 4
01072 Θ RTD 5 = Temperature of RTD 5
01073 Θ RTD 6 = Temperature of RTD 6
01074 Θ RTD 7 = Temperature of RTD 7
01075 Θ RTD 8 = Temperature of RTD 8
01076 Θ RTD 9 = Temperature of RTD 9
01077 Θ RTD10 = Temperature of RT D10
01078 Θ RTD11 = Temperature of RTD11
01079 Θ RTD12 = Temperature of RTD12
F.No. Alarm Comments
07742 IDiffL1= IDiffL1(I/Inominal object [%])
07743 IDiffL2= IDiffL2(I/Inominal object [%])
07744 IDiffL3= IDiffL3(I/Inominal object [%])
07745 IRestL1= IRestL1(I/Inominal object [%])
07746 IRestL2= IRestL2(I/Inominal object [%])
07747 IRestL3= IRestL3(I/Inominal object [%])
30654 IdiffREF= Idiff REF (I/Inominal object [%])
30655 IrestREF= Irest REF (I/Inominal object [%])
2 Functions
188 7UT612 Manual
C53000–G1176–C148–1
Set-Points
Fault Recording
Puls metering if co nfig ur ed (CFC )
F.No. Alarm Comments
00272 SP. Op Hours> Set Point Operating Hours
F.No. Alarm Comments
00004 >Trig.Wave.Cap. >Trigger Waveform Capture
00203 Wave. deleted Waveform data deleted
FltRecSta Fault Recording Start
F.No. Alarm Comments
00888 Wp(puls) Pulsed Energy Wp (active)
00889 Wq(puls) Pulsed Energy Wq (reactive)
2.16 Processing of Commands
1897UT612 Manual
C53000–G1176–C148–1
2.16 Processing of Commands
General In addition to the protective functions described so far, control command processing
is integrated in the SIPROTEC® 7UT612 to coordinate the operation of circuit break-
ers and other equipment in the power system. Control commands can originate from
four command sources:
−Local operation using the keypad on the local user interface of the device,
−Local or remote operation using DIGSI®4,
−Remote operation via system (SCADA) interface (e.g. SICAM),
−Automatic functions (e.g. using a binary inputs, CFC).
The number of switchgear devices that can be controlled is basically limited by the
number of available and required binary inputs and outputs. For the output of control
commands it has be ensured that all the required binary inputs and outputs are con-
figured and provided with the correct properties.
If specific interlocking conditions are needed for the execution of commands, the user
can program the device with bay interlocking by means of the user-defined logic func-
tions (CFC).
The configuration of the binary inputs and outputs, the preparation of user defined log-
ic functions, and the procedure during switching operations are described in the
SIPROTEC® 4 System Manual, order no. E50417–H1176–C151.
2.16.1 Types of Commands
The following types of commands are distinguished.
Control Commands These commands operate binary outputs and change the power system status:
•Commands for the operation of circuit breakers (without synchro-check) as well as
commands for the control of isolators and earth switches,
•Step commands, e.g. for raising and lowering transformer taps,
•Commands with configurable time settings (e.g. Petersen coils).
Internal / Pseudo
Commands These commands do not directly operate binary outputs. They serve to initiate internal
functions, simulate or acknowledge changes of state.
•Manual entries to change the feedback indication of plant such as the status condi-
tion, for example in the case when the physical connection to the auxiliary contacts
is not available or is defective. The process of manual entries is recorded and can
be displayed accordingly.
•Additionally, tagging commands can be issued to establish internal settings, such
as switching authority (remote / local), parameter set changeover, data transmis-
sion inhibit and metering counter reset or initialization.
2 Functions
190 7UT612 Manual
C53000–G1176–C148–1
•Acknowledgment and resetting commands for setting and resetting internal buffers.
•Status information commands for setting / deactivating the “information status” for
the information value of an object:
−Controlling activation of binary input status,
−Blocking binary outputs.
2.16.2 Steps in the Command Sequence
Safety mechanisms in the command sequence ensure that a command can only be
released after a thorough check of preset criteria has been successfully concluded.
Additionally, user-defined interlocking conditions can be configured separately for
each device. The actual execution of the command is also monitored after its release.
The entire sequence of a command is described briefly in the following:
Check Sequence •Command entry (e.g. using the keypad on the local user interface of the device)
−Check password → access rights;
−Check switching mode (interlocking activated/deactivated) → selection of
deactivated interlocking status.
•User configurable interlocking checks that can be selected for each command
−Switching authority (local, remote),
−Switching direction control (target state = present state),
−Zone controlled/bay interlocking (logic using CFC),
−System interlocking (centrally via SICAM),
−Double operation (interlocking against parallel switching operation),
−Protection blocking (blocking of switching operations by protective functions).
•Fixed command checks
−Timeout monitoring (time between command initiation and execution can be
monitored),
−Configuration in process (if setting modification is in process, commands are
rejected or delayed ),
−Equipment not present at output (if controllable equipment is not assigned to a
binary output, then the command is denied),
−Output block (if an output block has been programmed for the circuit breaker, and
is active at the moment the command is processed, then the command is
denied),
−Component hardware malfunction,
−Command in progress (only one command can be processed at a time for each
circuit breaker or switc h),
2.16 Processing of Commands
1917UT612 Manual
C53000–G1176–C148–1
−1-out-of-n check (for schemes with multiple assignments and common potential
contact, it is checked whether a command has already been initiated for the
common output contact).
Monitoring the
Command
Execution
−Interruption of a command because of a cancel command,
−Running time monito r (feedb ac k mes sage mon itoring time).
2.16.3 Interlocking
Interlocking is executed by the user-defined logic (CFC). The interlocking checks of a
SICAM/SIPROTEC®-system are classified into:
•System interlocking checked by a central control system (for interbay interlocking)
•Zone controlled/bay interlocking checked in the bay device (for the feeder-related
intelocking)
System interlocking relies on the system data base in the central control system. Zone
controlled/bay interlocking relies on the status of the circuit breaker and other switches
that are connected to the relay.
The extent of the interlocking checks is determined by the configuration and interlock-
ing logic of the relay.
Switchgear which is subject to system interlocking in the ce ntral contro l system is
identified with a specific setting in the command properties (in the routing matrix).
For all commands the user can select the operation mode with interlocking (normal
mode) or without interlocking (test mode):
−for local commands by reprogramming the settings with password check,
−for automatic commands via command processing with CFC,
−for local / remote commands by an additional interlocking command via Profibus.
2.16.3.1 Interlocked/Non-Interlocked Switching
The command checks that can be selected for the SIPROTEC®-relays are also re-
ferred to as “standard interlocking”. These checks can be activated (interlocked) or de-
activated (non interlocked) via DIGSI®4.
Deactivated interlock switchi ng means the configured interlocking conditions are by-
passed in the relay.
Interlocked switching means that all configured interlocking conditions are checked in
the command check routines. If a condition could not be fulfilled, the command will be
rejected by a message with a minus added to it (e.g. “CO-”), followed by an operation
response information. T able 2-13 shows some types of commands and messages. For
2 Functions
192 7UT612 Manual
C53000–G1176–C148–1
the device the messages designated with *) are displayed in the event logs, for
DIGSI®4 they appear in spontaneous messages.
The “plus” sign indicated in the message is a confirmation of the command execution:
the command execution was as expected, in other words positive. The “minus” is a
negative confirmation, the command was rejected. Figure 2-95 shows the messages
relating to command execution and operation response information for a successful
operation o f the circuit breaker.
The check of interlocking can be programmed separately for all switching devices and
tags that were set with a tagging command. Other internal commands such as manual
entry or abort are not checked, i.e. carried out independent of the interlocking.
Figure 2-95 Example of a message when cl osing the circuit breaker Q0
Standard
Interlocking The standard interlocking includes the checks for each device which were set during
the configuration of inputs and outputs.
An overview for processing the interlocking conditions in the relay is shown by Figure
2-96.
Table 2-13 Types of command and messages
Type of command Abbrev. Message
Control issued CO CO+/–
Manual tagging (positive / negative) MT MT+/–
Input blocking IB IB+/– *)
Output blocking OB OB+/– *)
Control abortion CA CA+/–
(9(17/2*
4&2FORVH
4)%FORVH
2.16 Processing of Commands
1937UT612 Manual
C53000–G1176–C148–1
.
Figure 2-96 Standard Interlocking Arrangements
The display shows the configured interlocking reasons. The are marked by letters ex-
plained in the following Table 2-14.
Table 2-14 Interlocking commands
&
or
or
&
Remote
&
DIGSI
&
&
&
&
or
Device with Source
Switching Authority
Protec tion Blo cking
Non-Interlocked
Interlocked
Comm an d
SCHEDULED=ACT.y/n
System Interlock. y/n
Field Interlocking y/n
Protection Blockingy/n
Double Oper. Blocky/n
SW. Auth. LOCA> y/n
Sw. Auth. REMOTEy/n
LOCAL
DIGSI
AUTO
Switching Authority
Switching Mode
Switching Mode
52 Close
52 Open
feedback Indication
On/Off
Switching Authority Switching Mode
Event
Condition
of Command =
SCHEDULED=ACT .y/n
&
1) Source REMOTE also includes SAS.
LOCAL Command via substation controller.
REMOTE Command via telecontrol system to substation controller and from substation controller to device.
(Local/Remote) DIGSI
Local
or
SAS REMOTE1),
DIGSI
Local
Remote
Output
to Relay
Local
Remote
On/Off
Interlocking commands Abbrev. Message
Control authorization L L
System in terlock S S
Zone controlled Z Z
Target state = present state
(check switch position) PP
Block by protection B B
2 Functions
194 7UT612 Manual
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Figure 2-97 shows all interlocking conditions (which usually appear in the display of
the device) for three switchgear items with the relevant abbreviations explained in
Table 2-14. All parameterized interlocking conditions are indicated (see Figure 2-97).
Figure 2-97 Example of configured interlocking conditions
Control Logic using
CFC For zone controlled/field interlocking, control logic can be programmed, using the
CFC. Via specific release conditions the information “released” or “bay interlocked”
are available.
2.16.4 Recording and Acknowledgement of Commands
During the processing of the commands, independent of the further processing of in-
formation, command and process feedback information are sent to the message
processing centre. These messages contain information on the cause. The messages
are entered in the event list.
Acknowledgement
of Commands to
the Device Front
All information which relates to commands that were issued from the device front
“Command Issued = Local” is transformed into a corresponding message and shown
in the display of the device.
Acknowledgement
of Commands to
Local/Remote/Digsi
The acknowledgement of messages which relate to commands with the origin “Com-
mand Issued = Local/Remote/DIGSI” are sent back to the initiating point independent
of the routing (configuration on the serial digital interface).
The acknowledgement of commands is therefore not provided with a response indica-
tion as it is done with the local command but with ordinary recorded command and
feedback information.
Mon i t o r i ng of
Feedback
Information
The processing of commands monitors the command execution and timing of feed-
back information for all commands. At the same time the command is sent, the moni-
toring time is started (monitoring of the command execution). This time controls
whether the device operation is executed with the required final result within the mon-
itoring time. The monitoring time is stopped as soon as the feedback information is de-
tected. If no feedback information arrives, a response “Timeout command monitoring
time” is indicated and the command sequence is terminated.
4&ORVH2SHQ6²=3%
,QWHUORFNLQJ
4&ORVH2SHQ6²=3%
4&ORVH2SHQ6²=3%
2.16 Processing of Commands
1957UT612 Manual
C53000–G1176–C148–1
Commands and information feedback are also recorded in the event list. Normally the
execution of a command is terminated as soon as the feedback information (FB+) of
the relevant switchgear arrives or, in case of commands without process feedback in-
formation, the command output resets.
The “plus” appearing in a feedback information confirms that the command was suc-
cessful, the command was as expected, in other words positive. The “minus” is a neg-
ative confirmation and means that the command was not executed as expected.
Command Output
and Switching
Relays
The command types needed for tripping and closing of the switchgear or for raising
and lowering of transformer taps are described in the SIPROTEC® 4 System Manual,
order no. E50417–H1176–C151.
2.16.5 Information Overview
n
F.No. Alarm Comments
Cntrl Auth Control Authority
ModeREMOTE Controlmode REMOTE
ModeLOCAL Controlmode LOCAL
2 Functions
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1977UT612 Manual
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Installation and Commissioning 3
This chapter is primarily for personnel who are experienced in installing, testing, and
commissioning protective and control systems, and are familiar with applicable safety
rules, safety regulations, and the operation of the power system.
Installation of the 7UT612 is described in this chapter. Hardware modifications that
might be needed in certain cases are explained. Connection verifications required be-
fore the device is put in service are also given. Commissioning tests are provided.
Some of the tests require the protected object (line, transformer, etc.) to carry load.
3.1 Mounting and Connections 198
3.2 Checking the Connections 218
3.3 Commissioning 222
3.4 Final Preparation of the Device 245
3 Installation and Commissioning
198 7UT612 Manual
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3.1 Mounting and Connections
Preconditions Verification of the ratings of the 7UT612 as well as matching to ratings of the power
equipment must have been completed.
3.1.1 Installation
Panel Flush
Mounting
q
Remove the 4 covering caps located on the corners of the front cover, reveal the
4 slots in the mounting flange.
q
Insert the device into the panel cut-out and fasten with four screws. Refer to Figure
4-13 in Section 4.15 for dimensions.
q
Replace the four covers.
q
Connect the ground on the rear plate of the device to the protective ground of the
panel. Use at least one M4 screw for the device ground. The cross-sectional area
of the ground wire must be greater than or equal to the cross-sectional area of any
other control conductor connected to the device. Furthermore, the cross-section of
the ground wire must be at least 2.5 mm2.
q
Connect the plug terminals and/or the screwed terminals on the rear side of the de-
vice according to the wiring diagram for the panel.
When using forked lugs or directly connecting wires to screwed terminals, the
screws must be tightened so that the heads are even with the terminal block before
the lugs or wires are inserted.
A ring lug must be centred in the connection chamber so that the screw thread fits
in the hole of the lug.
The System Manual (order–no. E50417–H1176–C151) has pertinent information
regarding wire size, lugs, bending radii, etc. Installation notes are also given in the
brief reference booklet attached to the device.
Warning!
The successful and safe operation of the device is dependent on proper handling, in-
stallation, and application by qualified personnel under observance of all warnings and
hints contained in this manual.
In particular the general erection and safety regulations (e.g. IEC, ANSI, DIN, VDE,
EN or other national and international standards) regarding the correct use of hoisting
gear must be observed. Non-observance can result in death, personal injury, or sub-
stantial property damage.
3.1 Mounting and Connections
1997UT612 Manual
C53000–G1176–C148–1
Figure 3-1 Panel mounting of a 7UT612
Rack Mounting and
Cubicle Mounting To install the device in a frame or cubicle, two mounting brackets are required. The
ordering codes are stated in the Appendix A in Subsection A.1.1.
q
Loosely screw the two mounting brackets in the rack with four screws.
q
Remove the 4 covers at the corners of the front cover. The 4 slots in the mounting
flange are revealed and can be accessed.
q
Fasten the device to the mounting brackets with four screws.
q
Replace the four covers.
q
Tighten the mounting brackets to the rack using eight screws.
q
Connect the ground on the rear plate of the device to the protective ground of the
rack. Use at least one M4 screw for the device ground. The cross-sectional area of
the ground wire must be greater than or equal to the cross-sectional area of any oth-
er control conductor connected to the device. Furthermore, the cross-section of the
ground wire must be at least 2.5 mm2.
q
Connect the plug terminals and/or the screwed terminals on the rear side of the de-
vice according to the wiring diagram for the rack.
When using forked lugs or directly connecting wires to screwed terminals, the
screws must be tightened so that the heads are even with the terminal block before
the lugs or wires are inserted.
A ring lug must be centred in the connection chamber so that the screw thread fits
in the hole of the lug.
The System Manual (order–no. E50417–H1176–C151) has pertinent information
regarding wire size, lugs, bending radii, etc. Installation notes are also given in the
brief reference booklet attached to the device.
Elongated
holes SIEMENS SIPROTEC
1 2
6
3
+/-0
54
7 8 9
7UT612
RUN ERROR
MENU
ESC
LED ENTER
F4
F1
F2
F3
Annunciation
Meas. Val.
0$,10(18
$QQXQFLDWLRQ
0HDVXUHPHQW
Trip log
3 Installation and Commissioning
200 7UT612 Manual
C53000–G1176–C148–1
Figure 3-2 Installing a 7UT612 in a rack or cubicle
Panel Surface
Mounting
q
Secure the device to the panel with four screws. Refer to Figure 4-14 in Section
4.15 for dimensions.
q
Connect the ground of the device to the protective ground of the panel. The cross-
sectional area of the ground wire must be greater than or equal to the cross-sec-
tional area of any other control conductor connected to the device. Furthermore, the
cross-section of the ground wire must be at least 2.5 mm2.
q
Solid, low-impedance operational grounding (cross-sectional area ≥ 2.5 mm2) must
be connected to the grounding surface on the side. Use at least one M4 screw for
the device ground.
q
Connect the screwed terminals on the top and bottom of the device according to the
wiring diagram for the panel. Optical connections are made on the inclined housings
on the top and/or bottom of the case. The System Manual (order–no. E50417–
H1176–C151) has pertinent information regarding wire size, lugs, bending radii,
etc. Installation notes are also given in the brief reference booklet attached to the
device.
SIEMENS SIPROTEC
1 2
6
3
+/-0
54
7 8 9
7UT612
RUN ERROR
MENU
ESC
LED ENTER
F4
F1
F2
F3
Annunciation
Meas. Val.
0$,10(18(
$QQXQFLDWLRQ
0HDVXUHPHQW
Mounting bracket
Mounting bracket
Tr ip log
3.1 Mounting and Connections
2017UT612 Manual
C53000–G1176–C148–1
3.1.2 Termination Variants
General diagrams are shown in Appendix A.2. Connection examples for current trans-
former circuits are provided in Appendix A.3. It must be checked that the settings for
configuration (Subsection 2.1.1) and the power system data (Subsection 2.1.2) match
the connections to the device.
Protecte d Object The setting 35272%-(&7 (address ) must correspond to the object to be pro-
tected. Wrong setting may cause unexpected reaction of the device.
Please note that auto-transformers are identified as 35272%-(&7 =
$XWRWUDQVI, not SKDVHWUDQVI. For SKDVHWUDQVI, the centre phase
L2 remains unconnected.
Currents Connection of the CT currents depends on the mode of application.
With three-phase connection the three phase currents are allocated to each side of
the protected object. For connection examples see Appendix A.3, Figures A-3 to A-6
and A-9 to A-13 referring to the protected object types.
With two-phase connection of a single-phase transformer the centre phase will not be
used (IL2). Figure A-7 in Appendix A.3 shows a connection diagram. Even if there is
only one current transformer, both phases will be used (IL1 and IL3), see the right part
of Figure A-8.
For single-phase busbar protection every measuring input (except I8) is allocated to a
busbar feeder. Figure A-14 in Appendix A.3 illustrates an example for one phase. The
other phases are to be connected correspondingly. If the device is connected via sum-
mation transformers, see Figure A-15. With the latter case you have to take into con-
sideration that the rated output current of the summation transformers is usually
100 mA. The measuring inputs of the device have to be matched accordingly (refer
also to Subsection 3.1.3).
The allo cat ion of t he curr ent inp uts I7 and I8 is to be checked. Connections also differ
according to the application the device is used for. The Appendix offers some connec-
tion examples (e.g. Figures A-4 to A-7 and A-11 to A-15) which refer to different appli-
cations.
Also check the rated data and the matching factors for the current transformers.
The allocation of the protection functions to the sides must be consistent. This partic-
ularly goes for the circuit breaker failure protection whose measuring point (side) must
correspond with the side of the circuit breaker to be monitored.
Binary Inputs and
Outputs The connections to the power plant depend on the possible allocation of the binary
inputs and outputs, i.e. how they are assigned to the power equipment. The preset
allocation can be found in Tables A-2 and A-3 in Section A.5 of Appendix A. Also
check that the labels on the front panel correspond to the configured message func-
tions.
It is also very important that the feedback components (auxiliary contacts) of the circuit
breaker monitored are connected to the correct binary inputs which correspond to the
assigned side of the circuit breaker failure protection.
3 Installation and Commissioning
202 7UT612 Manual
C53000–G1176–C148–1
Changing Setting
Groups with Binary
Inputs
If binary inputs are used to switch setting groups, note:
•Two binary inputs must be dedicated to the purpose of changing setting groups
when four groups are to be switched. One binary input must be set for “!6HW
*URXS%LW”, the other input for “!6HW*URXS%LW”. If either of these input
functions is not assigned, then it is considered as not controlled.
•To control two setting groups, one binary input set for “!6HW*URXS%LW” is
sufficient since the binary input “!6HW*URXS%LW”, which is not assigned, is
considered to be not controlled.
•The status of the signals controlling the binary inputs to activate a particular setting
group must remain constant as long as that particular group is to remain active.
Table 3-1 shows the relationship between “!6HW*URXS%LW”, “!6HW*URXS%LW
”, and the setting groups A to D. Principal connection diagrams for the two binary in-
puts are illustrated in Figure 3-3. The figure illustrates an example in which both Set
Group Bits 0 and 1 are configured to be controlled (actuated) when the associated bi-
nary input is energized (high).
no= not energized
yes= energized
Figure 3-3 Connection diagram (example) for setting group switching with binary inputs
Table 3-1 Setting group selection with binary inputs — example
Binary Input Events Active Group
!6HW*URXS%LW !6HW*URXS%LW
no no Group A
yes no Group B
no yes Group C
yes yes Group D
A
B
C
D
L–
L+
Selector switch for
setting group
Binary input set for:
“
!6HW*URXS%LW
”, High
A
B
C
DL–
L+
Binary input set for:
”
!6HW*URXS%LW
”, High
7UT612
3.1 Mounting and Connections
2037UT612 Manual
C53000–G1176–C148–1
Trip Circuit
Supervision It must be noted that two binary inputs or one binary input and one bypass resistor R
must be connected in series. The pick-up threshold of the binary inputs must therefore
be substantially below half the rated control DC voltage.
If
two
binary inputs are used for the trip circuit supervision, these binary inputs must
be volt-free i.o.w. not be commoned with each other or with another binary input.
If
one
binary input is used, a bypass resistor R must be employed (refer to Figure 3-
4). This resistor R is connected in series with the second circuit breaker auxiliary con-
tact (Aux2). The value of this resistor must be such that in the circuit breaker open con-
dition (therefore Aux1 is open and Aux2 is closed) the circuit breaker trip coil (TC) is
no longer picked up and binary input (BI1) is still picked up if the command relay con-
tact is open.
Figure 3-4 Trip circuit supervision with one binary input
This results in an upper limit for the resistance dimension, Rmax, and a lower limit Rmin,
from which the optimal value of the arithmetic mean should be selected.
In order that the minimum voltage for controlling the binary input is ensured, Rmax is
derived as:
So the circuit breaker trip coil does not remain energized in the above case, Rmin is
derived as:
L–
L+
RTC
Aux2Aux1
UBI >TripC trip rel
UCTR 7UT612
7UT612
TC
CB
Legend:
RTC — Relay Tripping Contact
CB — Circuit Breaker
TC — Circuit breaker Trip Coil
Aux1 — Circuit breaker Auxiliary contact
(closed when CB is closed)
Aux2 — Circuit breaker Auxiliary contact
(closed when CB is open)
R — Bypass Resistor
UCTR — Control voltage (trip voltage)
UBI — Input voltage for Binary Input
R
RRmax Rmin
+
2
---------------------------------=
Rmax UCRT UBI min
–
IBI (High)
--------------------------------------
R
CBTC
–
=
Rmin RTC UCTR UTC (LOW)
–
UTC (LOW)
-----------------------------------------------
⋅=
3 Installation and Commissioning
204 7UT612 Manual
C53000–G1176–C148–1
•If the calculation results that Rmax < Rmin, then the calculation must be repeated,
with the next lowest switching threshold UBI min, and this threshold must be imple-
mented in the relay using plug-in bridges (see Subsection 3.1.3).
For the power consumption of the resistor:
Example:
Rmax = 53 kΩ
Rmin = 27 kΩ
The closed standard value of 39 kΩ is selected; the power is:
Thermoboxes If the overload protection operates with processing of the coolant temperature (over-
load protection with hot-spot calculation), one or two thermoboxes 7XV5662 can be
connected to the serial service interface at port C.
IB I (HIGH) Constant current with BI on (=1.7 mA)
UBI min Minimum contr ol voltage for BI
=19 V for delivery setting for nominal voltage of 24/48/60 V
= 73 V for delivery setting for nominal voltage of 110/125/220/250 V
UCTR Control voltage for trip circuit
RCBTC DC resistance of circuit breaker trip coil
UCBTC (LOW) Maximum voltage on the circuit breaker trip coil that does not lead to tripping
IBI (HIGH) 1. 7 mA (f rom SIPRO T EC ® 7UT612)
UBI min 19 V for delivery setting for nominal voltage 24/48/60 V
73 V for delivery setting for nominal voltage 110/125/220/250 V
UCTR 110 V from trip circuit (control voltage)
RCBTC 500 Ω from trip circuit (resistance of CB trip coil)
UCBTC (LOW) 2 V from trip circuit (max. voltage not to trip breaker)
PRI2R⋅UCTR
RR
CBTC
+
----------------------------
2
R⋅
==
R
max
110 V 19 V
–
1.7 mA
----------------------------------
500 Ω
–=
Rmin 500 Ω 110 V 2 V
–
2 V
------------------------------
500 Ω
–=
RRmax Rmin
+
2
-------------------------------- 40 kΩ
==
P
R
110 V
39 kΩ0.5 kΩ
+
----------------------------------------
2
39 kΩ⋅
=
PR0.3 W≥
3.1 Mounting and Connections
2057UT612 Manual
C53000–G1176–C148–1
3.1.3 Hardware Modifications
3.1.3.1 General
Hardware modifications might be necessary or desired. For example, a change of the
pickup threshold for some of the binary inputs might be advantageous in certain appli-
cations. Terminating resistors might be required for the communication bus. In either
case, hardware modifications are needed. If modifications are done or interface mod-
ules are replaced, please observe the details in Subsections 3.1.3.2 to 3.1.3.5.
Power Supply
Voltage There are dif ferent input ranges for the power supply voltage. Refer to the data for the
7UT612 ordering numbers in Section A.1 of Appendix A. The power supplies with the
ratings 60/110/125 VDC and 110/125/220/250 VDC / 115/230 VAC are interconver-
tible. Jumper settings determine the rating. The assignment of these jumpers to the
supply voltages are illustrated below in Section 3.1.3.3 under margin “Processor
Board A–CPU”. When the relay is delivered, these jumpers are set according to the
name-plate sticker. Generally, they need not be altered.
Nominal Currents Jumper settings determine the rating of the current input transducers of the device.
When the relay is delivered, these jumpers are set according to the name-plate sticker
to 1 A or 5 A, for the current inputs I1 to I7; the input I8 is independent of the rated cur-
rent.
If the current transformer sets have different rated secondary currents at the sides of
the protected object and/or of current input I7, the device must be adapted to it. The
same applies for the current transformers of the busbar feeders when single-phase
busbar protection is applied. Using single-phase busbar protection with summation
transformers interconnected, rated currents for current inputs I1 to I7 are usually
100 mA.
The physical arrangements of these jumpers that correspond to the different current
ratings are described below in Subsection 3.1.3.3 under margin “Input/Output Board
A–I/O–3”.
When performing changes, please make sure that the device is always informed about
them:
−Using three-phase applications and single-phase transformers, changes for side 1
are to be set in addre ss ,16(&&76 and changes for side 2 in address
,16(&&76 in the Power System Data (refer to Subsection 2.1.2, margin
heading “Current Transformer Data for 2 Sides”, page 23).
−Using three-phase applications and single-phase transformers, changes for current
input I7 are to be performed in address ,16(&&7, (refer to Subsection
2.1.2, margin heading “Current Transformer Data for Current Input I7”, page 26).
−Using single-phase busbar protection, changes are made in addresses ,1
6(&&7, to ,16(&&7, (refer to Subsection 2.1.2, margin heading
“Current Transformer Data for Single-phase Busbar Protection”, page 25).
The current measuring input I8 — disregarding the rated current of the device — is
suited for highly sensitive current measurement (approx. 3 mA to 1.6 A).
3 Installation and Commissioning
206 7UT612 Manual
C53000–G1176–C148–1
Control Voltages
for Binary Inputs When the device is delivered from the factory, the binary inputs are set to operate with
a voltage that corresponds to the rated voltage of the power supply. In general, to op-
timize the operation of the inputs, the pickup voltage of the inputs should be set to
most closely match the actual control voltage being used. Each binary input has a
pickup voltage that can be independently adjusted; therefore, each input can be set
according to the function performed.
A jumper position is changed to adjust the pickup voltage of a binary input. The phys-
ical arrangement of the binary input jumpers in relation to the pickup voltages is
explained below in Section 3.1.3.3, margin heading “Processor Board A–CPU”.
Type of Contact for
Binary Outputs The processor module A–CPU contains 2 output relays the contact of which can be
set as normally closed or normally open contact. Therefore it might be necessary to
rearrange a jumper. Subsection 3.1.3.3, margin heading margin “Processor Board A–
CPU” describes to which type of relays in which boards this applies.
Interface Modules The serial interface modules can be replaced. Which kind of interfaces and how the
interfaces can be replaced is described in „Replacing Interface Modules”, Section
3.1.3.4.
Termination of
Serial Interfaces If the device is equipped with a serial RS485 port, the RS485 bus must be terminated
with resistors at the last device on the bus to ensure reliable data transmission. For
this purpose, terminating resistors are provided on the interface modules. The physi-
cal arrangement and jumper positions on the interface modules see Subsection
3.1.3.4, margin heading “RS485 Interface”.
Spare Parts Spare parts may be the backup battery that maintains the data in the battery-buffered
RAM when the voltage supply fails, and the miniature fuse of the internal power
supply. Their physical location is shown in Figure 3-6. The ratings of the fuse are
printed on the module next to the fuse itself. When exchanging the fuse, please
observe the hints given in the System Manual (order no. E50417–H1176–C151) in
Chapter „Maintenance“.
Note:
If the 7UT612 performs trip circuit monitoring, two binary inputs, or one binary input
and a resistor, are connected in series. The pickup voltage of these inputs must be
less than half of the nominal DC voltage of the trip circuit.
3.1 Mounting and Connections
2077UT612 Manual
C53000–G1176–C148–1
3.1.3.2 Disassembling the Device
If changes to jumper settings are required to modify the rating of the power supply , the
nominal rating of the current inputs, the pickup voltage of binary inputs, or the state of
the terminating resistors, proceed as follows:
oPrepare area of work. Provide a grounded mat for protecting components subject to
damage from electrostatic discharges (ESD). The following equipment is needed:
−screwdriver with a 5 to 6 mm wide tip,
−1 Philips screwdriver size Pz1,
−4.5 mm socket or nut driver.
oUnfasten the screw-posts of the D-subminiature connector on the back panel at loca-
tion “A”.
This activity does not apply if the device is for surface mounting.
oIf the device has more communication interfaces on the rear, the screws located diag-
onally to the interfaces must be removed.
This activity is not necessary if the device is for surface mountin g.
oRemove the four caps on the front cover and loosen the screws that become acces-
sible.
oCarefully pull off the front cover. The front cover is connected to the CPU board with
a short ribbon-cable. Refer to Figure 3-5 for the physical arrangement of the printed
boards.
WARNING!
For the following steps it is assumed that the device is not in operating state. Since
dangerous voltages and laser radiation may develop, do not connect the device to
auxiliary voltage, measured values or optical fibres!
Caution!
Jumper-setting changes that affect nominal values of the device render the ordering
number and the corresponding nominal values on the name-plate sticker invalid. If
such changes are necessary , the changes should be clearly and fully noted on the de-
vice. Self adhesive stickers are available that can be used as replacement name-
plates.
Caution!
Electrostatic discharges through the connections of the components, wiring, plugs,
and jumpers must be avoided. Wearing a grounded wrist strap is preferred. Otherwise,
first touch a grounded metal part.
3 Installation and Commissioning
208 7UT612 Manual
C53000–G1176–C148–1
The order of the boards is shown in Figure 3-5.
oDisconnect the ribbon-cable between the front cover and the A–CPU board (å) at the
cover end. To disconnect the cable, push up the top latch of the plug connector and
push down the bottom latch of the plug connector. Carefully set aside the front cover.
oDisconnect the ribbon-cables between the A–CPU board (å) and the A–I/O–3 board
().
oRemove the boards and set them on the grounded mat to protect them from electro-
static damage. A greater effort is required to withdraw the A–CPU board, especially in
versions of the device for surface mounting, because of the plug connectors.
oCheck the jumpers according to Figures 3-6 and 3-7 and the following notes. Change
or remove the jumpers as necessary.
Figure 3-5 Front view of the device after removal of the front cover
(simplified and scaled down)
1
2
Slot 5 Slot 19
Binary Inputs (BI)
Input/output printed circuit board A–I/O–3
Prozessorbaugruppe
Processor printed circuit board A–CPU
1 2
BI1 to
BI3
3.1 Mounting and Connections
2097UT612 Manual
C53000–G1176–C148–1
3.1.3.3 Jumper Settings on Printed Circuit Boards
Processor Board
A–CPU The design of a jumper setting for the processor board A–CPU is shown in Figure
3-6.
The preset rated voltage of the integrated power supply is checked according to Table
3-2, the pickup voltages of the binary inputs BI1 through BI3 are checked according
to Table 3-3, and the quiescent state of the binary outputs (BO1 and BO2) is checked
according to Table 3-4.
Figure 3-6 Processor board A–CPU (without interface modules) with representation of the
jumper settings required for the mo dule configuration
F1
Time Syn-
chronization
(Por t A)
Front Se ri al
G1
+
–
Battery Grip
Battery
Mini-fuse
X23
LH
X21
LH LH
X22
31
X51
2
X53
3
1
2
X52
1234
T 2,0H250V
X41
1
23
X42
1
23
Operating
Interface
3 Installation and Commissioning
210 7UT612 Manual
C53000–G1176–C148–1
1)Factory settings for devices with power supply voltages of 24 VDC to 125 VDC
2)Factory settings for devices with power supply voltages of 110 V to 250 VDC and 115 to 230 VAC
Table 3-2 Jumper settings for the nominal voltage of the integrated power supply on the
processor board A–CPU
Jumper N ominal voltage
24 to 48 VDC 60 to 125 VDC 110 to 250 VDC; 115 to 230 VDC
X51 not fitted 1–2 2–3
X52 not fitted 1–2 and 3–4 2–3
X53 not fitted 1–2 2–3
Table 3-3 Jumper settings for the pickup v olt ag es of the b inary input s BI1 throu gh BI3 on
the processor board A –CPU
Binary Input Jumper 17 VDC pickup 1) 73 VDC pickup 2)
BI1 X21 1–2 2–3
BI2 X22 1–2 2–3
BI3 X23 1–2 2–3
Table 3-4 Jumper setting for the quiescent state of the Binary Outputs on the processor-
board A–CPU
For Jumper Open i n th e q uie sc en t state
(NO contac t) C l os ed i n the quiescent sta te
(NC contact) Presetting
BO1 X41 1–2 2–3 1–2
BO2 X42 1–2 2–3 1–2
3.1 Mounting and Connections
2117UT612 Manual
C53000–G1176–C148–1
Input/Output Board
A–I/O–3 The design of a jumper setting for the processor board A–I/O–3 is shown in Figure 3-7.
Figure 3-7 Input/output board A–I/O–3 with representation of the jumper settings
required for the module configuration
The rated current settings of the input current transformers are checked on the
A–I/O–3 board.
With default settings all jumpers (X61 to X70) are set to the same rated current
(according to the order number of the device). However, rated currents can be
changed for each individual input transformer.
To do so you have to change the location of the jumpers next to the transformers. Ad-
ditionally, settings of the common jumpers X68 to X70 must be changed correspond-
ingly. Table 3-5 shows the assignment of the jumpers to the current measuring inputs.
5A 1A
0.1A
X61
X68
5A
5A
X70
1A
X64
5A
1A 0.1A
X63
5A
1A 0.1A
X69
5A
5A 1A
0.1A
X62X67
5A
1A 0.1A
5A 1A
0.1A
X65
5A 1A
0.1A
X66
0.1A rated
current
I7
1A
0.1A rated
current
1A
0.1A rated
current
undef undef
side 2
side 1
I8
IL2S2
IL3S2
IL1S2
I7
IL2S1
IL3S1
IL1S1
I4
I5
I6
I2I1
I3
3 Installation and Commissioning
212 7UT612 Manual
C53000–G1176–C148–1
•For three-phase applications and single-phase transformers:
There are 3 measuring inputs for each side. The jumpers belonging to one side
must be plugged to the same rated current. Furthermore, the corresponding com-
mon jumper (X68 for side 1 and X69 for side 2) has to be plugged to the same rated
current.
For measuring input I7 the individual and the common jumper are plugged to the
same rated current.
•For single -phase busbar protection:
Each input can be set individually.
Only if measuring inputs I1 to I3 have the same rated current, X68 is plugged to the
same rated current.
Only if measuring inputs I4 to I6 have the same rated current, X69 is plugged to the
same rated current.
If different rated currents are reigning within the input groups, the corresponding
common jumper is plugged to “undef”.
For interposed summation transformers with 100 mA output, jumpers of all meas-
uring inputs, including the common jumpers, are plugged to “0.1A”.
Table 3-5 Assignment of the jumpers to the measuring inputs
Application Jumper
3-phase 1-phase Individual Common
IL1S1 I1X61 X68IL2S1 I2X62
IL3S1 I3X63
IL1S2 I4X65 X69IL2S2 I5X66
IL3S2 I6X67
I7I7X64 X70
I8I8——
3.1 Mounting and Connections
2137UT612 Manual
C53000–G1176–C148–1
3.1.3.4 Interface Modules
Replacing Interface
Modules The interface modules are located on the processor board A–CPU. Figure 3-8 shows
the CPU board and the location of the interface modules.
Figure 3-8 Processor board A–CPU with interface modules
Please note the following:
•Interface modules can only be exchanged for devices with flush mounting housing.
Interface modules for devices with surface mounting housing must be exchanged
in our manufacturing centre.
•Use only interface modules that can be ordered as an option of the device (see also
Appendix A.1).
B
C
System Interface
Service Interface/
Port on the rear side
of the housing
Thermobox
3 Installation and Commissioning
214 7UT612 Manual
C53000–G1176–C148–1
•Termination of the serial interfaces in case of RS485 must be ensured according to
header margin “RS485 Interface”.
The ordering numbers of the exchange modules are listed in Appendix A.1.1, (Acces-
sories).
RS232 Interface The RS232 interface can be transformed into a RS485 interface according to Figure
3-10.
Figure 3-8 shows the PCB of the A–CPU with the location of the modules. Figure 3-9
shows how jumpers of interface RS232 are located on the interface module.
Here, terminating resistors are not required. They are always disabled.
Figure 3-9 Location of the jumpers on interface module for RS232
Table 3-6 Exchange interface modules for devices with flush mounting housing
Interface Mounting Port Replacing Module
System Interface B
RS232
RS485
Optical 820 nm
Profibus FMS RS485
Profibus FMS single ring
Profibus FMS double ring
Profibus DP RS485
Profibus DP double ring
Modbus RS485
Modbus 820 nm
DNP 3.0 RS485
DNP 3.0 820 nm
Service Interface/
Thermobox C
RS232
RS485
Optical 820 nm
X3132
X10
132
8X
1
3
2
X12
132
C53207-
A324-B180
1
3
2
X11
X6
X7
X4
X5 132
1
3
2
X13
Jumpers illustrated in
factory position
3.1 Mounting and Connections
2157UT612 Manual
C53000–G1176–C148–1
With jumper X11 the flow control which is important for modem communication is en-
abled. Jumper settings are explained in the following:
Jumper setting 2–3: The modem control signals CTS (Clear-To-Send) according to
RS232 are not available. This is a standard connection via star coupler or optical fibre
converter. They are not required since the connection to the SIPROTEC® devices is
always operated in the half-duplex mode. Please use connection cable with order
number 7XV 51 00–4 .
Jumper setting 1–2: Modem signals are made available. For a direct RS232 connec-
tion between the device and the modem this setting can be selected optionally. We
recommend to use a standard RS232 modem connection cable (converter 9-pole on
25-pole).
RS485 Interface The interface RS485 can be transformed into interface RS232 according to Figure 3-
9.
Using interfaces with bus capability requires a termination for the last device at the
bus, i.e. terminating resistors must be switched to the line.
The terminating resistors are connected to the corresponding interface module that is
mounted to the processor input/output board A–CPU. Figure 3-8 shows the printed cir-
cuit board of the A–CPU and the allocation of the modules.
The module for the RS485 interface is illustrated in Figure 3-10, for the profibus inter-
face in Figure 3-11. The two jumpers of a module must always be plugged in the same
position.
When the module is delivered, the jumpers are plugged so that th resistors are discon-
nected.
Exception:
Connecting one or two temperature measuring devices 7XV566 to the
service interface, the terminating resistors are switched onto the line since this is the
standard for this application. This only goes for Port C for devices with order number
7UT612*–****2–4*** (position 12 = 2; position 13 = 4).
Table 3-7 Jumper setting for CTS (Clear-To-Send) on the interface module
Jumper /CTS from RS232 interface /CTS controlled by /RTS
X11 1–2 2–3
3 Installation and Commissioning
216 7UT612 Manual
C53000–G1176–C148–1
Figure 3-10 Location of the jumpers of the RS485 interface module
Figure 3-11 Location of the jumpers of the Profibus interface module
Terminating resistors can also be implemented outside the device (e.g. in the plug
connectors). In that case the terminating resistors provided on the RS485 or Profibus
interface module must be switched out.
Figure 3-1 2 External ter minat ing resistors
X3132
X10
132
8X
1
3
2
X12
132
C53207-
A324-B180
1
3
2
X11
X6
X7
X4
X5 132
1
3
2
X13
Jumper Terminating Resistor s
Connected Disconnected
X3 2–3 1–2 *)
X4 2–3 1–2 *)
*) Factory setting (exception see text)
X3312
X4312
Jumper Terminating Resistors
Connected Disconnected
X3 1–2 2–3 *)
X4 1–2 2–3 *)
C53207-A322-
234
B100
B101
*) Factory Setting
390 Ω
220 Ω
390 Ω
+5 V
A/A´
B/B´
3.1 Mounting and Connections
2177UT612 Manual
C53000–G1176–C148–1
3.1.3.5 To Reassem ble the Device
To reassemble the device, proceed as follows:
oCarefully insert the boards into the housing. The installation locations of the boards
are shown in Figure 3-5.
For the model of the device designed for surface mounting, use the metal lever to in-
sert the A–CPU board. The installation is easier with the lever.
oFirst insert the plug connectors on the ribbon cable in the input/output board A–I/O–3
and then on the processor board A–CPU. Be careful not to bend any of the connecting
pins! Do not use force!
oInsert the plug connector of the ribbon cable between the processor board A–CPU and
the front cover in the socket on the front cover.
oPress the latches of the plug connectors together.
oReplace the front cover and secure to the housing with the screws.
oReplace the covers.
oRe-fasten the interfaces on the rear of the device housing.
This activity is not necessary if the device is for surface mountin g.
3 Installation and Commissioning
218 7UT612 Manual
C53000–G1176–C148–1
3.2 Checking the Connections
3.2.1 Data Connections of the Serial Interfaces
The tables of the following margin headers list the pin-assignments for the different se-
rial interfaces of the device and the time synchronization interface. The physical ar-
rangement of the connectors is illustrated in Figure 3-13.
Figure 3-13 9-pin D-subminiature sockets
Operating Interface
at Front When the recommended communication cable is used, correct connection between
the SIPROTEC® device and the PC is automatically ensured. See the Appendix A,
Subsection A.1.1 for an ordering description of the cable.
System (SCADA)
Interface When a serial interface of the device is connected to a central substation control sys-
tem, the data connection must be checked. A visual check of the transmit channel and
the receive channel is important. Each connection is dedicated to one transmission di-
rection. The data output of one device must be connected to the data input of the other
device, and vice versa.
The data cable connections are designated in sympathy with DIN 66020 and ISO
2110 (see also Table 3-8):
−TxD Data Transmit
−RxD Data Receive
−RTS Request to Send
−CTS Clear to Send
−DGND Signal/Chassis Ground
The cable shield is to be grounded at only both ends . For extremely EMC-loaded en-
vironments the GND may be integrated into a separate individually shielded wire pair
to improve the immunity to interference.
P-Slave
AME RS232
RS232-LWL
RS485
1
6
5
9
at the Rear Side
5
9
1
6
Operating Interface
at the Front Side
1
6
5
9
Serial Interface
Time Synchronization
Interface at the
Rear Side
(Panel Flush Mounting)
3.2 Checking the Connections
2197UT612 Manual
C53000–G1176–C148–1
Termination The RS485 interface is capable of half-duplex service with the signals A/A’ and B/B’
with a common reference potential C/C’ (DGND). Verify that only the last device on the
bus has the terminating resistors connected, and that the other devices on the bus do
not. Jumpers for the terminating resistors are on the interface module RS485 (Figure
3-10) or on the Profibus module (Figure 3-11). It is also possible that the terminating
resistors are arranged externally (Figure 3-12).
If the bus is extended, make sure again that only the last device on the bus has the
terminating resistors switched in, and that all other devices on the bus do not.
Time
Synchronization Either 5 VDC, 12 VDC or 24 VDC time synchronization signals can be processed if the
connections are made as indicated in Table 3-9.
.
Table 3-8 Pin-assignments of the D-subminiature ports
Pin-No. Operating
Interface RS232 RS485 Profibus FMS Slave, RS485
Profibus DP Slave, RS485 Modbus RS485
DNP3.0 RS485
1 Screen (with screen ends electrically connected)
2RxD RxD —— —
3
TxD TxD A/A' (RxD/TxD–N) B/B' (RxD/TxD–P) A
4 — — — CNTR–A (TTL) RTS (TTL level)
5 GND GND C/C' (GND) C/C' (GND) GND1
6 — — — +5 V (max. load 100 mA) VCC1
7RTS RTS —*) — —
8CTS CTS B/B' (RxD/TxD–P) A/A' (RxD/TxD–N) B
9— — — — —
*) Pin 7 also may carry the RS232 RTS signal on an RS485 interface. Pin 7 must therefore not be connected!
Table 3-9 Pin-assignments of the D-subminiature port of the time synchronization interface
Pin-No. Designation Signal Meaning
1 P24_TSIG Input 24 V
2 P5_TSIG Input 5 V
3 M_TSIG Return Line
4 M_TSYNC*) Return Line *)
5 Screen Screen potential
6– –
7 P12_TSIG Input 12 V
8 P_TSYNC*) Input 24 V *)
9 Screen Screen potential
*) assigned, but not available
3 Installation and Commissioning
220 7UT612 Manual
C53000–G1176–C148–1
Optical Fibres Signals transmitted over optical fibres are unaffected by interference. The fibres guar-
antee electrical isolation between the connections. Transmit and receive connections
are identified with the symbols for transmit and for receive.
The character idle state for the optical fibre interface is “Light off”. If this setting is to
be changed, use the operating program DIGSI®4, as described in the SIPROTEC®
System Manual, order-no. E50417–H1176–C151.
Thermoboxes If one or two thermoboxes 7XV566 are connected for considering the coolant temper-
ature when using overload protection with hot-spot calculation, check this connection
at the service interface (Port C).
Check also for the termination: The terminating resistors must be connected to the
device 7UT612 (see Subsection 3.1.3.4, margin heading “RS485 Interface”).
For notes concerning the 7XV566 see for the instruction manual attached to the de-
vice. Check the transmission parameters at the temperature measuring device. Be-
sides Baud-rate and parity also the bus number is of primary importance.
•For the connection of 1 thermobox 7XV566:
bus number =
0
with Simplex-transmission (to be set at 7XV566),
bus number =
1
with Duplex-transmission (to be set at 7XV566),
•For the connection of 2 thermoboxes 7XV566:
bus number =
1
for the 1st thermobox (to be set at 7XV566 for RTD1 to 6),
bus number =
2
for the 2nd thermobox (to be set at 7XV566 for RTD7 to 12).
3.2.2 Checking Power Plant Connections
Before the device is energized for the first time, the device should be in the final oper-
ating environment for at least 2 hours to equalize the temperature and to minimize hu-
Warning!
Laser injection! Do not look directly into the fibre-optic elements!
Warning!
Some of the following test steps will be carried out in presence of hazardous voltages.
They shall be performed only by qualified personnel which is thoroughly familiar with
all safety regulations and precautionary measures and pay due attention to them.
Caution!
Operating the device on a battery charger without a connected battery can lead to im-
permissibly high voltages and consequently , the destruction of the device. For limit val-
ues see Subsection 4.1.2 in the Technical Data.
3.2 Checking the Connections
2217UT612 Manual
C53000–G1176–C148–1
midity and avoid condensation. Connection are checked with the device at its final lo-
cation. The plant must first be switched off and grounded.
Connection examples for the current transformer circuits are given in the Appendix
Section A.3. Please observe the plant diagrams, too.
oProtective switches (e.g. test switches, fuses, or miniature circuit breakers) for the
power supply must be opened.
oCheck the continuity of all current transformer connections against the switch-gear
and connection diagrams:
q
Are the current transformers grounded properly?
q
Are the polarities of the current transformers the same for each CT set?
q
Is the phase relationship of the current transformers correct?
q
Is the polarity for current input I7 correct (if used)?
q
Is the polarity for current input I8 correct (if used)?
oCheck the functions of all test switches that may be installed for the purposes of sec-
ondary testing and isolation of the device. Of particular importance are test switches
in current transformer circuits. Be sure these switches short-circuit the current trans-
formers when they are in the test mode (open).
oThe short-circuit feature of the current circuits of the device are to be checked. An
ohmmeter or other test equipment for checking continuity is needed.
q
Remove the front panel of the device (see Figure 3-5).
q
Remove the ribbon cable connected to the A–I/O–3 board and pull the board out
until there is no contact between the board and the rear connections of the device.
q
At the terminals of the device, check continuity for each pair of terminals that re-
ceives current from the CTs.
q
Firmly re-insert the board. Carefully connect the ribbon cable. Do not bend any con-
nector pins! Do not use force!
q
Check continuity for each of the current terminal-pairs again.
q
Attach the front panel and tighten the screws.
oConnect an ammeter in the supply circuit of the power supply. A range of about 2.5 A
to 5 A for the meter is appropriate.
oClose the protective switches to apply voltage to the power supply of the device.
Check the polarity and magnitude of the voltage at the device terminals.
oThe measured steady-state current should correspond to the quiescent power con-
sumption of the device. Transient movement of the ammeter merely indicates the
charging current of capacitors.
oRemove the voltage from the power supply by opening the protective switches.
oDisconnect the measuring equipment; restore the normal power supply connections.
oCheck the trip circuits to the power system circuit breakers.
oVerify that the control wiring to and from other devices is correct.
oCheck the signalling connections.
oClose the protective switches to apply voltage to the power supply.
3 Installation and Commissioning
222 7UT612 Manual
C53000–G1176–C148–1
3.3 C ommissioning
When testing the device with secondary test equipment, make sure that no other
measurement quantities are connected. Take also into consideration that the trip and
close commands to the circuit breakers and other primary switches are disconnected
from the device unless expressly stated.
For the commissioning switching operations have to be carried out. A prerequisite for
the prescribed tests is that these switching operations can be executed without dan-
ger. They are accordingly not meant for operational checks.
Warning!
Hazardous voltages are present in this electrical equipment during operation. Non–
observance of the safety rules can result in severe personal injury or property dam-
age.
Only qualified personnel shall work on and around this equipment after becoming thor-
oughly familiar with all warnings and safety notices of this manual as well as with the
applicable safety regulations.
Particular attention must be drawn to the following:
•The earthing screw of the device must be connected solidly to the protective earth
conductor before any other electrical connection is made.
•Hazardous voltages can be present on all circuits and components connected to the
supply voltage or to the measu ring and tes t quanti ti es.
•Hazardous voltages can be present in the device even after disconnection of the
supply voltage (storage capacitors!).
•Wait for at least 10 s after having disconnected the supply voltage before you re-
apply the voltage in order to achieve defined initial conditions.
•The limit values stated in the Technical Data must not be exceeded at all, not even
during testing and commissioning.
DANGER!
Current transformer secondary circuits must have been short-circuited before
the current leads to the device are disconnected!
If test switches are installed that automatically short-circuit the current transformer
secondary circuits, it is sufficient to place them into the “Test” position provided the
short-circuit functions has been previously tested.
Warning!
Primary tests must only be carried out by qualified personnel, who are familiar with the
commissioning of protection systems, the operation of the plant and the safety rules
and regulations (switching, earthing, etc.).
3.3 Commissioning
2237UT612 Manual
C53000–G1176–C148–1
3.3.1 Testing Mode and Transmission Blocking
If the device is connected to a substation control system or a server, the user is able
to modify, in some protocols, information that is transmitted to the substation (see Sec-
tion A.6 “Protocol Dependent Functions” in Appendix A).
In the WHVWLQJPRGH all messages sent from a SIPROTEC®4–device to the substa-
tion are marked with an extra test bit so that the substation is able to identify them as
messages announcing no real faults. Furthermore the WUDQVPLVVLRQEORFNLQJ
function leads to a total blocking of the message transmission process via the system
interfac e in the tes tin g mode.
Refer to System Manual (Order-no. E50417–H1176–C151) to know how the testing
mode and the transmission blocking can be enabled and disabled. Please note that it
is necessary to be 2QOLQH to be able to use the testing mode.
3.3.2 Checking the System (SCADA) Interface
Preliminary
Notes Provided that the device is equipped with a system (SCADA) interface that is used for
the communication with a central computer station, it is possible to test via the
DIGSI®4 operational function if messages are transmitted correctly. Do not apply this
test feature while the device is in service on a live system!
The system interface test is carried out 2QOLQH using DIGSI®4:
q
Double-click on the 2QOLQH directory to open the required dialogue box.
q
Click on 7HVW and the functional options appear on the right side of the window.
Double-click on 7HVWLQJ0HVVDJHVIRU6\VWHP,QWHUIDFH shown in the list
view. The dialogue box *HQHUDWH,QGLFDWLRQV opens (refer to Figure 3-14).
Structure of the
Dialogue Box In the column ,QGLFDWLRQ, all message texts that were configured for the system in-
terface in the matrix will then appear. In the column 6(732,17VWDWXV you to define
the value for the messages to be tested. Depending on the type of message different
DANGER!
The transmission and reception of messages via the system (SCADA) interface
by means of the testing mode is the real exchange of information between the
SIPROTEC®4 device and the substation. Connected equipment such as circuit
breakers or disconnectors can be operated as a result of these actions!
Note:
After termination of this test, the device will reboot. All annunciation buffers are
erased. If required, these buffers should be extracted with DIGSI®4 prior to the test.
3 Installation and Commissioning
224 7UT612 Manual
C53000–G1176–C148–1
entering fields are available (e.g. message 21 / message 2))). By clicking onto one
of the fields the required value can be selected from the list.
Figure 3-14 Dialogue box: Generate indications — example
Changing the
Operat ing State Clicking for the first time onto one of the field in column $FWLRQ yo u w il l be a sked for
password no. 6 (for hardware test menus). Having entered the correct password mes-
sages can be issued. To do so, click on 6HQG. The corresponding message is issued
and can be read out either from the event log of the SIPROTEC®4 device as well as
from the central master computer.
As long as the windows is open, further tests can be performed.
Test in Message
Direction For all information that is transmitted to the central station the following is to be
checked under 6(732,17VWDWXV:
q
Make sure that each checking process is carried out carefull y without causing any
danger (see above and refer to DANGER!).
q
Click on 6HQG and check whether the transmitted information reaches the central
station and shows the desired reaction.
Exiting the Test
Mode To end the system interface test, click on &ORVH. The device is briefly out of service
while the processor system starting up. The dialogue box closes.
Test in Command
Direction Information in command direction must be sent by the central station. Check whether
the reaction is correct.
3.3 Commissioning
2257UT612 Manual
C53000–G1176–C148–1
3.3.3 Checking the Binary Inputs and Outputs
Preliminary Notes The binary inputs, outputs, and LEDs of a SIPROTEC®4 device can be individually
and precisely controlled using DIGSI®4. This feature is used to verify control wiring
from the device to plant equipment during commissioning. This test feature shall not
be used while the device is in service on a live system.
Note:
After termination of the hardware test, the device will reboot. Thereby, all annun-
ciation buffers are erased. If required, these buffers should be extracted with DIGSI®4
prior to the test.
The hardware test can be done using DIGSI®4 in the online operating mode:
q
Open the 2QOLQH directory by double-clicking; the operating functions for the de-
vice appear.
q
Click on 7HVW; the function selection appears in the right half of the screen.
q
Double-click in the list view on +DUGZDUH7HVW. The dialogue box of the same
name opens (see Figure 3-15).
Figure 3-15 Dialogue box for hardware test — example
DANGER!
Changing the status of a binary input or output using the test feature of DIGSI®4
results in an actual and immediate corresponding change in the SIPROTEC® de-
vice. Connected equipment such as circuit breakers or disconnectors will be
operated as a result of these actions!
3 Installation and Commissioning
226 7UT612 Manual
C53000–G1176–C148–1
Structure of the
Test Dialogue Box The dialogue box is divided into three groups: %, for binary inputs, 5(/ for output
relays, and /(' for light-emitting diodes. Each of these groups is associated with an
appropriately marked switching area. By double-clicking in an area, components with-
in the associated group can be turned on or off.
In the 6WDWXV column, the present (physical) state of the hardware component is
displayed. The binary inputs and outputs are indicated by an open or closed switch
symbol, the LEDs by a dark or illuminated LED symbol.
The possible intended condition of a hardware component is indicated with clear text
under the 6FKHGXOHG column, which is next to the 6WDWXV column. The intended
condition offered for a component is always the opposite of the present state.
The right-most column indicates the commands or messages that are configured
(maske d) to the hardwa re comp onen ts .
Changing the
Hardware
Conditions
To change the condition of a hardware component, click on the associated switching
fi eld in the 6FKHGXOHG column.
Password No. 6 (if activated during configuration) will be requested before the first
hardware modification is allowed. After entry of the correct password a condition
change will be executed.
Further condition changes remain possible while the dialog box is open.
Test of the Binary
Outputs Each individual output relay can be energized allowing a check of the wiring between
the output relay of the 7UT612 and the plant, without having to generate the message
that is assigned to the relay. As soon as the first change of state for any one of the
output relays is initiated,
all
output relays are separated from the internal device func-
tions, and can only be operated by the hardware test function. This implies that a
switching signal to an output relay from e.g. a protection function or control command
cannot be executed.
q
Ensured that the switching of the output relay can be executed without danger (see
above under DANGER!).
q
Each output relay must be tested via the corresponding 6FKHGXOHG–cell in the di-
alog box.
q
The test sequence must be terminated (refer to margin heading “Exiting the Proce-
dure”), to avoid the initiation of inadvertent switching operations by further tests.
Test of the Binary
Inputs To test the wiring between the plant and the binary inputs of the 7UT612 the condition
in the plant which initiates the binary input must be generated and the response of the
device ch ec ke d.
To do this, the dialogue box +DUGZDUH7HVW must again be opened to view the phys-
ical state of the binary inputs. The password is not yet required.
q
Each state in the plant which causes a binary input to pick up must be generated.
q
The response of the device must be checked in the 6WDWXV–column of the dialogue
box. To do this, the dialogue box must be updated. The options may be found below
under the margin heading “Updating the Display”.
If however the effect of a binary input must be checked without carrying out any switch-
ing in the plant, it is possible to trigger individual binary inputs with the hardware test
function. As soon as the first state change of any binary input is triggered and the
3.3 Commissioning
2277UT612 Manual
C53000–G1176–C148–1
password nr. 6 has been entered,
all
binary inputs are separated from the plant and
can only be activated via the hardware test function.
q
Terminate the test sequence (see above under the margin heading „Exiting the Pro-
cedure“).
Test of the LED’s The LED’s may be tested in a similar manner to the other input/output components.
As soon as the first state change of any LED has been triggered,
all
LEDs are sepa-
rated from the internal device functionality and can only be controlled via the hardware
test frunction. This implies that no LED can be switched on anymore by e.g. a protec-
tion function or operation of the LED reset key.
Updating the
Display When the dialog box +DUGZDUH7HVW is opened, the present conditions of the hard-
ware components at that moment are read in and displayed. An update occurs:
−for each harware component, if a command to change the condition is successfully
performed,
−for all hardware components if the 8SGDWH button is clicked,
−for all hardware components with cyclical updating if the $XWRPDWLF8SGDWH
VHF field is marked.
Exiting the
Procedure To end the hardware test, click on &ORVH. The dialog box closes. The device becomes
unavailable for a brief start-up period immediately after this. Then all hardware com-
ponents are returned to the operating conditions determined by the plant settings.
3.3.4 Checking the Setting Consistency
The device 7UT612 checks settings of the protection functions against the corre-
sponding configuration parameters. Any inconsistencies will be reported. For in-
stance, earth fault differential protection cannot be applied if there is no measuring
input for the starpoint current between starpoint of the protected object and the
earthing electrode.
In the operational or spontaneous annunciations check if there is any information on
inconsistencies. Table 3-10 shows such inconsistency annunciations.
Table 3-10 Annunciations on Inconsistencies
Message FNo Description See Section
Error1A/
5Awrong 00192 Setting of the rated secondary currents on Input/Output Board A–I/O–3
inconsistent 2.1.2
3.1.3.3
Diff Adap.fact. 05620 The matching factor of the current transformers for differential protection is
too great or too small. 2.1.2
2.2
REF Adap.fact. 05836 The matching factor of the current transformers for restricted earth fault
protection is too great or too small. 2.1.2
REF Err CTstar 05830* There is no measuring input assigned for restricted earth fault protection 2.1.1
3 Installation and Commissioning
228 7UT612 Manual
C53000–G1176–C148–1
In the operational or spontaneous annunciations also check if there are any fault an-
nunciations from the device.
3.3.5 Checking for Breaker Failure Protection
If the device is equipped with the breaker failure protection and this function is used,
the interaction with the breakers of the power plant must be tested.
Because of the manifold application facilities and various configuration possibilities of
the power plant it is not possible to give detailed description of the test steps neces-
sary to verify the correct interaction between the breaker failure protection and the
breakers. It is important to consider the local conditions and the protection and plant
drawings.
It is advised to isolate the circuit breaker of the tested feeder at both sides, i.e. to keep
the busbar disconnector and the line disconnector open, in order to ensure operation
of the breaker without risk.
The following lists do not claim to cover all possibilities. On the other hand, they may
contain items that can be bypassed in the actual application.
REF Not avalia. 05835* Restricted earth faul t protection is not available for the configured protected
object 2.1.1
O/C Ph. Not av. 01860* Time overcurrent protection for phase currents is not available for the
configured protected object 2.1.1
O/C 3I0 Not av. 01861* Time overcurrent protection for residual current is not available for the
configured protected object 2.1.1
I2 Not avalia. 05172* Unbalanced load protection is not available for the configured protected
object 2.1.1
O/L No Th.meas. 01545* Temperature reception for overload protection is missing (from thermobox) 2.1.1
2.9.3
O/L Not avalia. 01549* Overload protection is not available for the configured protected object 2.1.1
BkrFail Not av . 01488* Breaker failure protection is not available for the configured protected object 2.1.1
TripC ProgFail 06864 For trip circuit supervision the number of binary inputs was set incorrectly 2.13.1.4
3.1.2
Fault Configur.. 00311 Group indication of fault annunciations marked with “*”.
Table 3-10 Annunciations on Inconsis tencies
Message FNo Description See Section
Caution!
Tripping of the complete busbar or busbar section may occur even during tests at the
local feeder breaker. Therefore, it is recommended to interrupt the tripping commands
to the adjacent (busbar) breakers e.g. by switch-off of the associated control voltage.
Nevertheless ensure that trip remains possible in case of a real primary fault if parts
of the power plant are in service.
3.3 Commissioning
2297UT612 Manual
C53000–G1176–C148–1
Circuit Breaker
Auxiliary Contacts The circuit breaker auxiliary contact(s) form an essential part of the breaker failure pro-
tection system in case they have been connected to the device. Make sure that the
correct assignment has been checked (Subsection 3.3.3). Make sure that the meas-
ured currents for breaker failure protection (CTs), the tested circuit breaker, and its
auxiliary contact(s) relate to the same side of the protected object.
External Initiation
Conditions If the breaker failure protection is intended to be initiated by external protection devic-
es, each of the external initiation conditions must be checked.
At least the tested phase of the device must be subjected to a test current to enable
initiation of the breaker failure protection. This may be a secondary injected current.
q
Start by trip command of the external protec tion:
Binary input “!%UN)DLOH[W65&” (FNo ); look up in the trip log or sponta-
neous mes s ages .
q
Following initiation the message “%NU)DLOH[W38” (F No ) must appear in
the fault annunciations (trip log) or in the spontaneous messages.
q
Trip command of the circuit breaker failure protection after the delay time 75,3
7LPHU (address ).
Switch off test current.
The following applies if initiation without current flow is possible:
q
Close tested circuit breaker while the disconnectors at both sides open.
q
Start by trip command of the external protec tion:
Binary input “!%UN)DLOH[W65&” (FNo ); look up in the trip log or sponta-
neous mes s ages .
q
Following initiation the message “%NU)DLOH[W38” (F No ) must appear in
the fault annunciations (trip log) or in the spontaneous messages.
q
Trip command of the circuit breaker failure protection after the delay time 75,3
7LPHU (address ).
Reopen the local circuit breaker.
Busbar Trip The most important thing is the check of the correct distribution of the trip commands
to the adjacent circuit breakers in case the local breaker fails.
The adjacent circuit breakers are those of all feeders which must be tripped in order
to ensure interruption of the fault current should the local breaker fail. In other words,
the adjacent breaker are those of all feeders which may feed the same busbar or bus-
bar section as the faulty feeder. In case of a power transformer, the adjacent breakers
may include the breaker of the other side of the transformer.
The identification of the adjacent feeders depends widely on the topology of the bus-
bar and its possible arrangement or switching states. That is why a generally detailed
test description cannot be specified.
In particular if multiple busbars are concerned the trip distribution logic to the other
breakers must be checked. It must be verified for each busbar section that all breakers
connected to the same section are tripped in case the concerned feeder breaker fails,
and no other breakers.
3 Installation and Commissioning
230 7UT612 Manual
C53000–G1176–C148–1
Termination of the
Checks After completion of the tests, re-establish all provisory measures which might have
been taken for the above tests. Ensure that the states of all switching devices of the
plant are correct, that interrupted trip commands are reconnected and control voltages
are switched on, that setting values which might have been altered are reverted to cor-
rect values, and that protective function are switched to the intended state (on or off).
3.3.6 Symmetrical Current Tests on the Protected Object
Should secondary test equipment be connected to the device, it is to be removed or,
if applying, test switches should be in normal operation position.
The measured quantities of the following tests can be read out from the PC using
DIGSI®4 or a web browser via the “IBS-Tool”. This provides comfortable read-out
possibilities for all measured values with visualisation using phasor diagrams.
If you choose to work with the IBS-Tool, please note the Help files referring to the “IBS-
Tool”. The IP–address neede for the browser depends on the poert where the PC is
connected:
•Connection to the front operation interface: IP–address 141.141.255.160
•Connection to the rear service interface: IP–address 141.143.255.160
The following descriptions refer to read-out using DIGSI®4.
Preparation of
Symmetrical
Current Tests
At first commissioning, current checks must be performed before the protected object
is energized for the first time. This ensures that the differential protection is operative
as a short-circuit protection during the first excitation of the protected object with volt-
age. If current checks are only possible with the protected object under voltage (e.g.
power transformers in networks when no low-voltage test equipment is available), it is
imperative that a backup protection, e.g. time overcurrent protection, be commis-
sioned before, which operates at least at the feeding side. The trip circuit of other pro-
tection devices (e.g. Buchholz protection) must either remain operative.
The test arrangement varies dependent on the application.
Note:
It must be taken into consideration that tripping may occur if connections were made
wrong.
DANGER!
Operations in the primary area must be performed only with plant sections
voltage-free and earthed! Perilous voltages may occur even on voltage-free
plant sections due to capacitive influence caused by other live sections.
3.3 Commissioning
2317UT612 Manual
C53000–G1176–C148–1
On network power transformers and asynchronous machines, a low-voltage test
equipment is preferably used. A low-voltage source is used to energize the protected
object, which is completely disconnected from the network (see Figure 3-16). On
transformers, the test source is normally connect at the primary side. A short-circuit
bridge which is capable to carry the test current, is installed outside of the protected
zone and allows the symmetrical current to flow. On a motor, its star point enables cur-
rent flow.
Figure 3-16 Current test with low-voltage test source — examples for a transformer and a motor
On power station unit transformers and synchronous machines, the checks are per-
formed during the current tests. The generator itself forms the test current source (see
Figure 3-17). The current is produced by a three-pole short-circuit bridge which is in-
stalled outside of the protected zone and is capable to carry rated current for a short
time.
Figure 3-17 Current test in a power station with generator as test source — example
On busbars, bran ch poi nts, and short lines, a low-voltage test source can be used. Al-
ternatively, load current test is possible. In the latter case the above hint about backup
protection must be observed!
With the single-phase differential protection for busbars with more than 2 feeders,
symmetrical current test is not necessary (but permissible, of course). The test can be
carried out using a single-phase current source. But, current tests must be performed
for each possible current path, e.g. feeder 1 against feeder 2, feeder 1 against feeder
400 V
3~
400 V
M
400 V
3~
400 V
Test source Test source
7UT612 7UT612
7UT612
G
7UT612
7UT612
3 Installation and Commissioning
232 7UT612 Manual
C53000–G1176–C148–1
3, etc. Please read at first the notes about “Checking for Busbar Protection”, Subsec-
tion 3.3.8 (page 240).
Realization of
Symmetrical
Current Tests
For this commissioning tests, the test current must be at least 2 % of the rated relay
current for each phase.
This test cannot replace visual inspection of the correct current transformer connec-
tions. Therefore, the inspection according to Section 3.2.2 is a prerequisite.
Since 7UT612 offers comprehensive commissioning aids commissioning can be per-
formed quickly and without external instrumentation. The following indices are used
for the display of measured values:
The equation symbol for current (I, ϕ) is followed by the phase identifier L and by a
number that identifies the side (e.g. the transformer winding). Example:
IL1S1 current in phase L1 on Side 1.
The following procedure applies to three-phase protected objects. For transformers it
is assumed that side 1 is the overvoltage side of the transformer.
oSwitch on the test current, or start up the generator and bring it to nominal speed and
excite it to the required test current. None of the measurement monitoring functions in
the device must respond. If there was a fault message, however, the Event Log or
spontaneous messages could be checked to investigate the reason for it. Refer also
to the SIPROTEC® 4 System Manual, order-no. E50417–H1176–C151.
oRead out the current magnitudes:
Compare the measured values under 0HDVXUHPHQW → 6HFRQGDU\9DOXHV →
2SHUDWLRQDOYDOXHVVHFRQGDU\ with the real values:
IL1S1 =
IL2S1 =
IL3S1 =
3I0S1 =
IL1S2 =
IL2S2 =
IL3S2 =
3I0S2 =
Note:
The “IBS Tool” provides comfortable read-out possibilities for all measured val-
ues with visualisation using phasor diagrams (Figure 3-18).
If deviations occur which cannot be explained by measuring tolerances, an error can
be assumed in the device connections or in the test arrangement.
q
Switch off the test source and the protected object (shut down the generator) and
earth it.
q
Re-check the plant connections to the device and the test arrangement and correct
them.
If a substantial zero sequence current 3I0 occurs one two of the currents of the cor-
responding side must have a wrong polarity.
−3I0 ≈ phase current ⇒ one or two phase currents are missing,
−3I0 ≈ doubled phase current ⇒ one or two phase cu rren ts hav e a reversed
polarit y.
q
Repeat test and re-check the current magnitudes.
3.3 Commissioning
2337UT612 Manual
C53000–G1176–C148–1
Figure 3-18 Measured values on the sides of the protected object — example for through-flowing currents
oPhase angle measurement for side 1 with test current:
Read out the phase angles under 0HDVXUHPHQW → 6HFRQGDU\9DOXHV → $QJOHV
of side 1 of the protected object. All angles are referred to IL1S1. The following values
must result approximately for a clockwise phase rotation:
ϕL1S1 ≈ 0°
ϕL2S1 ≈ 240°
ϕL3S1 ≈ 120°
If the angles are wrong, reverse polarity or swapped phase connections on side 1 of
the protected object may be the cause.
q
Switch off the test source and the protected object (shut down the generator) and
earth it.
q
Re-check the plant connections to the device and the test arrangement and correct
them.
q
Repeat test and re-check the current angles.
oPhase angle measurement for side 2 with test current:
Read out the phase angles under 0HDVXUHPHQW → 6HFRQGDU\9DOXHV → $QJOHV
of side 2 of the protected object. All angles are referred to IL1S1.
Secondary Values
Currents: Si de 1 Currents: Side 2
–90°
0° 0°±180° ±180°
+90° +90°
–90°
IL1 L S1 =
IL2 L S1 =
IL3 L S1 =
1.01 A,
0.98 A,
0.99 A,
0.0 °
240.2 °
119.1 °
IL1LS2 =
IL2LS2 =
IL3LS2 =
0.99 A,
0.97 A,
0.98 A,
177.9 °
58.3 °
298.2 °
3 Installation and Commissioning
234 7UT612 Manual
C53000–G1176–C148–1
Consider that always the currents flowing into the protected object are defined as pos-
itive. That means that, with through-flowing in-phase currents, the currents leaving the
protected object at side 2, have reversed polarity (180° phase displacement) against
the corresponding in-flowi ng currents at side 1.
Exception:
With transverse differential
protection, the currents of the corresponding phase have equal phase!
For clockwise phase rotation, approximately the values according to Table 3-11 result.
If considerable deviations occur, reversed polarity or swapped phases are expected
on side 2.
q
Deviation in individual phases indicates reversed polarity in the related phase cur-
rent connection or acyclically swapped phases.
q
If all phase angles differ by the same value, phase current connections of side 2 are
cyclically swapped or the connection group of the transformer differs from the set
group. In the latter case, re-check the matching parameters (Subsection 2.1.2 un-
der margin “Object Data with Transformers”, page 20) under addresses , ,
and .
q
If all phase angles differ by 180°, the polarity of the complete CT set for side 2 is
wrong. Check and correct the applicable power system data (cf. Subsection 2.1.2
under “Current Transformer Data for 2 Sides”, page 23):
address 675317!2%-6 for side 1,
address 675317!2%-6 for side 2.
For single-phase busbar protection refer to Subsection 2.1.2 under header margin
“Current Transformer Data for Single-phase Busbar Protection”.
If connection errors are assumed:
q
Switch off the test source and the protected object (shut down the generator) and
earth it.
q
Re-check the plant connections to the device and the test arrangement and correct
them.
q
Repeat test and re-check the current angles.
Measuring Differen-
tial and Restraint
Currents
Before the tests with symmetrical currents are terminated, the differential and restraint
currents are examined. Even though the above tests with symmetrical current should
have widely detected connection errors, nevertheless, errors are possible concerning
current matching and the assignment of the connection group cannot be completely
excluded.
Table 3-11 Phase indication dependent on the protected object (three-phase)
Prot. object →Generator/Motor/
Busbar/Line
Transformer with connection group numeral 1)
↓ Phase angle 0 1 234567891011
ϕL1S2 180° 180° 150° 120° 90° 60° 30° 0° 330° 300° 270° 240° 210°
ϕL2S2 60° 60° 30° 0° 330° 300° 270° 240° 210° 180° 150° 120° 90°
ϕL3S2 300° 300° 270° 240° 210° 180° 150° 120° 90° 60° 30° 0° 330°
1) The stated angles are valid if the high-voltage winding is side 1. Otherwise read 360° minus the stated angle
3.3 Commissioning
2357UT612 Manual
C53000–G1176–C148–1
The differential and restraint currents are referred to the nominal currents of the pro-
tected object. This must be considered when they are compared with the test currents.
oRead out the differential and restraint currents under 0HDVXUHPHQW → 3HUFHQW
9DOXHV → 'LIIHUHQWLDODQG5HVWUDLQW&XUUHQWV.
In the “IBS-Tool”, the differential and restraint currents are displayed as a graph in a
characteristics diagram. An example is illustrated in Figure 3-19.
Figure 3-19 Differential and restraint currents — example for plausible currents
q
The differential currents must be low, at least one scale less than the currents flow-
ing through.
q
The restraint currents correspond to twice the through-flowing test currents.
Tripping Characteristics
IDiffL1 =
IDiffL2 =
IDiffL3 =
0.03 I/InO
0.02 I/InO
0.10 I/InO
1
2
3
123
Diff.-Current
I/InO
Rest.-Current
I/InO
IRestL1 =
IRestL2 =
IRestL3 =
0.80 I/InO
0.74 I/InO
0.78 I/InO
Diff.-Current Rest.-Current
Parameter I DIFF >: I/InO
Parameter I DIFF> >: 0.3
7.5 I/InO
3 Installation and Commissioning
236 7UT612 Manual
C53000–G1176–C148–1
q
If there are differential currents in the size of the restraint currents (approximately
twice the through-flowing test current), you may assume a polarity reversal of the
current transformer(s) at one side. Check the polarity again and set it right after
short-circuiting all the six current transformers. If you have modified these current
transformers, also perform an angle test.
q
If there are differential currents which are nearly equal in all three phases, matching
of the measured values may be erroneous. Wrong connection group of a power
transformer can be excluded because they should have been detected during the
phase angle test. Re-check the settings for current matching. These are mainly the
data of the protected object:
−For all kind of power transformers, addresses , and under “Object
Data with Transformers”, (page 20) and addresses , , and
under “Current Transformer Data for 2 Sides” (page 23).
−For generators, motors, reactors, addresses and under “Object Data
with Generators, Motors and Reactors” (page 22) and addresses ,
and under “Current Transformer Data for 2 Sides” (page 23).
−For mini-busbars, address under “Object Data with Mini-Busbars, Branch-
Points, Short Lines” (page 22) and addresses , , and under
“Current Transformer Data for 2 Sides” (page 23).
−For single-phase busbar protection, addresses and under “Object Data
with Busbars with up to 7 Feeders” (page 23) and addresses to under
“Current Transformer Data for Single-phase Busbar Protection” (page 25). If
interposed summation transformers are used, matching errors can be caused by
wrong connections at the summation CTs.
oFinally, switch off the test source and the protected object (shut down the generator).
oIf parameter settings have been changed for the tests, reset them to the values nec-
essary for operation.
3.3.7 Zero Sequence Current Tests on the Protected Object
The zero sequence current tests are only necessary if the starpoint of a three-phase
object or a single-phase transformer is earthed and if the current between starpoint
and earth is available and fed to the current input I7 of the device.
The polarity of this earth current (starpoint current) at I7 is essential for zero sequence
current correction of the differential protection (increased earth fault sensitivity) and
the restricted earth fault protection.
No pol arit y check is ne cessary for I7 (and/or I8) if only the magnitude of the respective
current is processed (e .g. for time overcurrent protection).
Note:
It must be taken into consideration that tripping may occur if connections were made
wrong.
3.3 Commissioning
2377UT612 Manual
C53000–G1176–C148–1
Preparation of Zero
Sequence Current
Tests
Zero sequence current measurements are always performed from that side of the pro-
tected object where the starpoint is earthed, on auto-transformers from the high-volt-
age side. Power transformers shall be equipped with a delta winding (d–winding or
compensating winding). The side which is not included in the tests remains open as
the delta winding ensures low-ohmic termination of the current path.
The test arrangement varies with the application. Figures 3-20 to 3-24 show schematic
example s of arran gem ents .
Figure 3-20 Zero sequence current measurement on a star-delta transformer
Figure 3-21 Zero sequence current measurement on a star-star transformer with
compensation winding
DANGER!
Operations in the primary area must be performed only with plant sections
voltage-free and earthed! Perilous voltages may occur even on voltage-free
plant sections due to capacitive influence caused by other live sections.
~Test source
7UT612
~Test source
7UT612
3 Installation and Commissioning
238 7UT612 Manual
C53000–G1176–C148–1
Figure 3-22 Zero sequence current measurement on a zig-zag-winding
Figure 3-23 Zero sequence current measurement on a delta winding with neutral earthing
reactor within the protected zone
Figure 3-24 Zero sequence current measurement on an earthed single-phase transformer
~Test source
7UT612
~Test source
7UT612
~Test source
7UT612
3.3 Commissioning
2397UT612 Manual
C53000–G1176–C148–1
Realization of
Zero Sequence
Current Tests
For this commissioning tests, the zero sequence current must be at least 2 % of the
rated relay current for each phase, i.e. the test current at least 6 %.
This test cannot replace visual inspection of the correct current transformer connec-
tions. Therefore, the inspection according to Section 3.2.2 is a prerequisite.
oSwitch on test current.
oRead out the current magnitudes under 0HDVXUHPHQW → 6HFRQGDU\9DOXHV →
2SHUDWLRQDOYDOXHVVHFRQGDU\ and compare them with the real values:
−All phase currents of the tested side correspond to approximately 1/3 of the test
current (1/2 with single-phase transformers).
−3I0 of the tested side corresponds to the test current.
−Phase currents and zero sequence current of the other side are, on transformers,
nearly 0.
−Current I7 correspond to the test current.
Deviation can practically occur only for the current I7 because the phase currents had
been tested already during the symmetrical tests. When deviations are in I7:
q
Switch off the test source and the protected object (shut down the generator) and
earth it.
q
Re-check the I7 connections and the test arrangement and correct them.
q
Repeat test and re-check the current magnitudes.
Measuring Differen-
tial and Restraint
Currents
The differential and restraint currents are referred to the nominal currents of the pro-
tected object. This must be considered when they are compared with the test currents.
oSwitch on test current.
oRead out the differential and restraint currents under 0HDVXUHPHQW → 3HUFHQW
9DOXHV → 'LIIHUHQWLDODQG5HVWUDLQW&XUUHQWV.
q
The differential current of the restricted earth fault protection IDiffREF must be low,
at least one scale less than the test current.
q
The restraint current IRestREF corresponds to twice the test current.
q
If the differential current is in the size of the restraint current (approximately twice
the test current), you may assume a polarity reversal of the current transformer for
I7. Check the polarity again and compare it with the setting in address ($57+
(/(&752' (cf. also Subsection 2.1.2 under margin “Current Transformer Data for
Current Input I7” (page 26).
q
If there is a differential current which does not correspond to twice the test current,
the matching factor for I7 may be incorrect. Check the setting relevant for current
matching. These are mainly the data of the protected object (Subsection 2.1.2):
−addresses and under “Object Data with Transformers”, (page 20) and
−addresses and under “Current Transformer Data for Current Input I7”
(page 26).
3 Installation and Commissioning
240 7UT612 Manual
C53000–G1176–C148–1
oCheck also the differential currents IDiffL1, IDiffL2, IDiffL3.
q
The differential currents of the differential protection must either be low, at least one
scale less than the test current. If considerable differential currents occur, re-check
the settings for the starpoints:
−Starpoint conditioning of a transformer: addresses 67$53176,'(,
67$53176,'(, Subsection 2.1.2 under margin “Object Data with
Transformers”, (page 20), as well as
−the assignment of the starpoint current transformer to the input I7: address
,&7&211(&7, Subsection 2.1.1 under “Special Cases” (page 16).
q
Countercheck: The restraint currents of the differential protection IRestL1, IRestL2,
IRestL3 are equally small. If all tests have been successful until now, this should be
ensured.
oFinally, switch off the test source and the protected object (shut down the generator).
oIf parameter settings have been changed for the tests, reset them to the values nec-
essary for operation.
3.3.8 Checking for Busbar Protection
General For single-phase busbar protection with one device per phase or with summation
transformers, the same checks have to be performed as described in Subsection 3.3.6
“Symmetrical Current Tests on the Protected Object”. Please observe the following 4
notes:
1. Checks are often done with operational currents or primary testing devices.
Please take note of all warnings you can find in the sections and be aware of the
fact that you will require a backup protection at the supplying point.
2. Checks have to be performed for every current path, beginning with the supplying
feeder.
3. When using one device per phase, checks are to be performed for each phase. In
the following you can find some more information on summation transformers.
4. However, each check is restricted on
one
current pair, i.e. on the
one
traversing
testing current. Information on vector group matching and vectors (except the
phase angle comparison of the traversing current = 180° at the sides tested) or
similar is not relevant.
Connection via
Summation CTs If summation transformers are used, different connection possibilities exist. The fol-
lowing clarification are based on the normal connection mode L1–L3–E according to
Figure 3-25. Figure 3-26 applies for connection L1–L2–L3.
Single-phase primary tests are to be preferred, since they evoke clearer differences in
the measured currents. They also detect connecting errors in the earth current path.
The measured current to be read out in the operational measured values only corre-
sponds to the testing current if three-phase symmetrical check is performed. In other
3.3 Commissioning
2417UT612 Manual
C53000–G1176–C148–1
cases there are deviations which are listed in the figures as factor of the testing cur-
rent.
Figure 3-25 CT connection L1–L3–E
Figure 3-26 CT connection L1–L2–L3
Deviations which cannot be explained by measuring tolerances may be caused by
connection errors or matching errors of the summation transformers:
q
Switch off the test source and the protected object and earth it.
q
Re-check the connections and the test arrangement and correct them.
q
Repeat test and re-check the current magnitudes.
The phase angles must be 180° in all cases.
Check the differential and restraint currents.
If single-phase primary checks cannot be carried out but only symmetrical operational
currents are available, polarity or connecting errors in the earth current path with sum-
mation transformer connection L1–L3–E according to Figure 3-25 will not be detected
with the before-mentioned checks. In this case, asymmetry is to be achieved by sec-
ondary manipulation.
Therefore the current transformer of phase L2 is short-circuited. See Figure 3-27.
IL3
L1
IL1 SCT IM
3I0
1
2
3
L2L3
Test Current Measured Current
L1–L2–L3 (sym.)
L1–L2
L2–L3
L3–L1
L1–E
L2–E
L3–E
1.00
1.15
0.58
0.58
2.89
1.73
2.31
Test Current Measured Current
L1–L2–L3 (sym.)
L1–L2
L2–L3
L3–L1
L1–E
L2–E
L3–E
1.00
0.58
1.15
0.58
1.15
0.58
1.73
IL2
L1
IL1 SCT IM
IL3
1
2
3
L2L3
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C53000–G1176–C148–1
Figure 3-27 Unsymmetrical test with summation CT conne ction L1–L3–E
The measured current is now 2.65 times the current of the symmetrical test.
This test must be carried out for each summation CT.
3.3.9 Checking for Current Input I8
Checks concerning the measured current input I8 extremely depend on how this
measuring input is applied.
By any means, the matching factor for the magnitude has to be checked (address ,
see also Subsection 2.1.2, margin heading “Current Transformer Data for Current In-
put I8”, page 27). Polarity check is not required since only the current magnitude is de-
tected.
With high-impedance protection the current at I8 corresponds to the fault current in the
protected object. Polarity of all current transformers supplying the resistor, whose cur-
rent is measured at I8, must be uniform. Here, tr aversing currents are used as for dif-
ferential protection checks. Each current transformer must be included into a meas-
urement. The current at I8 must not exceed, by no means, the half of the pickup value
of the single-phase time overcurrent protection.
DANGER!
All precautionary measures must be observed when working on the instrument
transformers! Secondary connections of the current transformers must have
been short-circuited before any current lead to the relay is interrupted!
IL3
L1
IL1 SCT IM
3I0
1
2
3
L2L3
3.3 Commissioning
2437UT612 Manual
C53000–G1176–C148–1
3.3.10 Testing User Specified Functions
7UT612 has a vast capability for allowing functions to be defined by the user, espe-
cially with the CFC logic. Any special function or logic added to the device must be
checked.
Naturally, general test procedures cannot be given. Rather, the configuration of these
user defined functions and the necessary associated conditions must be known and
verified. Of particular importance are possible interlocking conditions of the switch-
gear (circuit breakers, isolators, etc.). They must be considered and tested.
3.3.11 Stability Check and Triggering Oscillographic Recordings
At the end of commissioning, an investigation of switching operations of the circuit
breaker(s), under load conditions, should be done to assure the stability of the protec-
tion system during the dynamic processes. Oscillographic recordings obtain the max-
imum information about the behaviour of the 7UT612.
Requirements Along with the capability of recording waveform data during system faults, the 7UT612
also has the capability of capturing the same data when commands are given to the
device via the service program DIGSI®4, the serial interfaces, or a binary input. For
the latter, the binary input must be assigned to the function “!7ULJ:DYH&DS”
(FNo ). Triggering for the oscillographic recording then occurs when the input
is energized.
An oscillographic recording that is externally triggered (that is, without a protective el-
ement pickup or device trip) is processed by the device as a normal fault recording
with the exception that data are not given in the fault messages (trip log). The exter-
nally triggered record has a number for establishing a sequence.
Triggering with
DIGSI®4 To trigger oscillographic recording with DIGSI®4, click on 7HVW in the left part of the
window . Double click the entry 7HVW:DYH)RUP in the list in the right part of the win-
dow to trigger the recording. See Figure 3-28.
A report is given in the bottom left region of the screen. In addition, message segments
concerning the progress of the procedure are displayed.
The SIGRA program or the Comtrade Viewer program is required to view and analyse
the oscillographic data.
Such test records are especially informative on power transformers when they are trig-
gered by the switch-on command of the transformer. Since the inrush current may
have the same effect as a single-ended infeed but must not initiate tripping, the effec-
tiveness of the inrush restraint is checked by energizing the power transformer several
times.
The trip circuit should be interrupted or the differential protection should be switched
to ',))3527 = %ORFNUHOD\ (address ) during this tests in order to avoid
tripping.
3 Installation and Commissioning
244 7UT612 Manual
C53000–G1176–C148–1
Figure 3-28 Triggering oscillographic recording with DIGSI®4 — example
As the pickup signal of the protection is not stabilized, the inrush current will start fault
recording automatically provided the pickup threshold is reached.
Conclusions as to the effectiveness of the inrush restraint can be drawn from the re-
cording of the differential currents and the harmonic contents. If necessary the inrush
current restraint effect can be increased (smaller value of +$5021,&, address
) when trip occurs or when the recorded data show that the second harmonic
content does not safely exceed the restraining threshold (address ). A further
method to increase inrush stability is to set the crossblock function effective or to in-
crease the duration of the crossblock function (address $ &5266%+$50).
For further detail refer to Subsection 2.2.7 under “Harmonic Restraint”, page 60).
Note:
Do not forget to switch the differential protection 21 (address ) after completion
of the test.
3.4 Final Preparation of the Device
2457UT612 Manual
C53000–G1176–C148–1
3.4 Final Preparation of the Device
Tighten the used screws at the terminals; those ones not being used should be slightly
fastened. Ensure all pin connectors are properly inserted.
Verify that all service settings are correct. This is a crucial step because some setting
changes might have been made during commissioning. The protective settings under
device configuration, input/output configuration are especially important as well as the
power system data, and activated Groups A through D (if applicable). All desired ele-
ments and functions must be set 21. See (Chapter 2). Keep a copy of all of the in-serv-
ice settings on a PC.
Check the internal clock of the device. If necessary, set the clock or synchronize the
clock if it is not automatically synchronized. For assistance, refer to the system man-
ual.
The annunciation memory buffers should be cleared, particularly the operational mes-
sages (event log) and fault messages (trip log). Future information will then only apply
for actual system events and faults. To clear the buffers, press 0$,10(18 → $Q
QXQFLDWLRQ → 6HW5HVHW. Refer to the system manual if further assistance is
needed. The numbers in the switching statistics should be reset to the values that
were existing prior to the testing, or to values in accordance with the user’s practices.
Set the statistics by pressing 0$,10(18 → $QQXQFLDWLRQ → 6WDWLVWLF.
Press the key, several times if necessary, to return to the default display.
Clear the LEDs on the front panel by pressing the key. Any output relays that were
picked up prior to clearing the LEDs are reset when the clearing action is performed.
Future indications of the LEDs will then apply only for actual events or faults. Pressing
the key also serves as a test for the LEDs because they should all light when the
button is pushed. Any LEDs that are lit after the clearing attempt are displaying actual
conditions.
The green “581” LED must be on. The red “(5525” LED must not be lit.
Close the protective switches. If test switches are available, then these must be in the
operating position.
The device is now ready for operation.
n
Caution!
Do not use force! The permissible tightening torques must not be exceeded as the
threads and terminal chambers may otherwise be damaged!
ESC
LED
LED
3 Installation and Commissioning
246 7UT612 Manual
C53000–G1176–C148–1
2477UT612 Manual
C53000–G1176–C148–1
Technical Data 4
This chap ter prov ides th e tec hnic al dat a of th e SIP ROTEC®4 7UT612 device and its
individual functions, including the limiting values that must not be exceeded under any
circumstances. The electrical and functional data of fully equipped 7UT612 devices
are followed by the mechanical data, with dimensional drawings.
4.1 General Device Data 248
4.2 Differential Protection 258
4.3 Restricted Earth Fault Protection 263
4.4 Time Overcurrent Protection for Phase and Residual Currents 264
4.5 Time Overcurrent Protection for Earth Current 271
4.6 Dynamic Cold Load Pickup for Time Overcurrent Protection 272
4.7 Single-Phase T ime Overcurrent Pr otection 273
4.8 Unbalanced Load Protection 274
4.9 Thermal Overload Protection 275
4.10 Thermoboxes for Overload Protection 277
4.11 Circuit Br eaker Fa ilure Protection 278
4.12 External Trip Commands 278
4.13 Monitoring Functions 279
4.14 Ancill ary Functions 280
4.15 Dimensions 282
4 Technical Data
248 7UT612 Manual
C53000–G1176–C148–1
4.1 General Device Data
4.1.1 Analog Inputs
Nominal frequency fN50 Hz / 60 Hz / 162/3Hz (adjustable)
Current Inputs Nominal current IN1 A or 5 A or 0.1 A (changeable)
Power consumption per input I1 to I7
–at I
N
= 1 A approx. 0.02 VA
–at I
N
= 5 A approx. 0.2 VA
–at I
N
= 0.1 A approx. 1 mVA
– for hi gh-sensitivity input I8 at 1 A approx. 0.05 VA
Current over loa d capabi li ty per input I1 to I7
– thermal (rms) 100 · IN for 1 s
30 · IN for 10 s
4 · IN continuous
– dynamic (pulse) 1250 A (half cycle)
Current overload capability for high-sensitivity input I8
– thermal (rms) 300 A for 1 s
100 A for 10 s
15 A continuous
– dynamic (pulse) 750 A (half cycle)
Current
Transformer
Requirements
Underburden factor
max. ratio of nominal primary current
of the current transformers
to nominal object current
4.1.2 Power Supply
Direct Voltage Voltage supply via integrated DC/DC converter:
Permissible AC ripple voltage,
peak to peak ≤15 % of the nominal power supply voltage
n’ 4 Ikd max
IN prim
------------------
⋅≥ for τ ≤ 100 ms
n' n PNPi
+
P' Pi
+
-------------------
⋅
=
n’ 5 Ikd max
IN prim
------------------
⋅≥ for τ > 100 ms
INprim transf
INprim obj
---------------------------- 4 for phase currents
8 for earth current at I7
≤
Nominal power supply direct voltage UNDC 24/48 VDC 60/110/125 VDC
Permissible voltage ranges 19 to 58 VDC 48 to 150 VDC
Nomin al powe r suppl y dire ct vo ltag e UNDC 110/125/220/250 VDC
Permissible voltage ranges 88 to 300 VDC
4.1 General Device Data
2497UT612 Manual
C53000–G1176–C148–1
Power consumption
– quiescent approx. 5 W
– energized approx. 7 W
Bridging time for failure/short-circuit ≥50 ms at UH = 48 V and UNDC ≥ 110 V
of the power suppl y ≥20 ms at UH = 24 V and UNDC = 60 V
Alternating Voltage Voltage supply via integrated AC/DC converter
Power consumption
– quiescent approx. 6.5 VA
– energized approx. 8.5 VA
Bridging time for failure/short-circuit
of the power suppl y ≥ 50 ms
4.1.3 Binary Inputs and Outputs
Binary Inputs Number 3 (allocatable)
Nominal voltage 24 VDC to 250 VDC in 2 ranges, bipolar
Switching thresholds adjustable with jumpers
– for nominal voltages 24/48 VDC Upickup ≥ 19 VDC
60/110/125 VDC Udropoff
≤ 14 VDC
– for nominal voltages 110/125/ Upickup ≥ 88 VDC
220/250 VDC Udropoff ≤ 66 VDC
Current consumption, energized approx. 1.8 mA
independent of the control voltage
Maximum permissible voltage 300 VDC
Input interference suppression 220 nF coupling capacitance at 220 V
with recovery time >60 ms
Binary Outputs Signalling/command relays (see also General Diagrams in Section A.2 of Appendix A)
Number: 4, each with 1 NO contact (volt-free)
(allocatable)
Switchi ng capability MA KE 1 000 W/VA
BREA K 30 V A
40 W ohmic
25 W for L/R ≤ 50 ms
Alarm relay 1, with 1 NO or NC contact (reconnectable)
Switchi ng ca pabi li ty MA KE 1000 W /VA
BREAK 30 VA
40 W ohmic
25 W for L/R ≤ 50 ms
Switchi ng vo ltag e 250 V
Nominal po wer supply al ternating voltage UNAC 115/230 VAC
Permissible voltage ranges 92 to 265 VAC
4 Technical Data
250 7UT612 Manual
C53000–G1176–C148–1
Permissible current per contact 5 A continuous
30 A for 0.5 s
Permissible total current on 5 A continuous
common paths 30 A for 0.5 s
4.1.4 C ommunications Interfaces
Operation Interface – Connection front panel, non-isolated, RS 232
9-pin DSUB socket
for connecting a personal computer
– O pe ratio n with DIGSI®4
– Transmission speed min. 4800 Baud; max. 115200 Baud
factory setting: 38400 Baud; parity: 8E1
– Maximum transmission distance 15 m (50 ft)
Service/Modem
Interface
(optional)
RS232/RS485/Optical isolated interface for data transfer
acc. ordered version for operation with DIGSI®4
or connection of a thermobox
RS232
– Connection for flush mounted case rear panel, mounting location “C”
9-pin DSUB socket
for surface mounted case at the inclined housing on the case bottom
shiel ded data cabl e
– Test voltage 500 V; 50 Hz
– Transmission speed min. 4800 Baud; max. 115200 Baud
factory setting: 38400 Baud
– Maximum transmission distance 15 m (50 ft)
RS485
– Connection for flush mounted case rear panel, mounting location “C”
9-pin DSUB socket
for surface mounted case at the inclined housing on the case bottom
shiel ded data cabl e
– Test voltage 500 V; 50 Hz
– Transmission speed min. 4800 Baud; max. 115200 Baud
factory setting: 38400 Baud
– Maximum transmission distance 1000 m (3300 ft)
Optical fibre
– C o nne cto r Type ST–conn ec tor
for flush mounted case rear panel, mounting location “C”
for surface mounted case at the inclined housing on the case bottom
4.1 General Device Data
2517UT612 Manual
C53000–G1176–C148–1
– Optical wavelength λ = 820 nm
– Laser class 1 acc. EN 60825–1/ –2 using glass fibre 50/125 µm or
using glass fibre 62.5/125 µm
– Permissible optical signal attenuation max. 8 dB using glass fibre 62.5/125 µm
– Maximum transmission distance 1.5 km (1 mile)
– Character idle state selectable; factory setting: “Light off”
System (SCADA)
Interface (optional) RS232/RS485/Optical isolated interface for data transfer
Profibus RS485/Profibus Optical to a master terminal
acc. to ordered version
RS232
– Connection for flush mounted case rear panel, mounting location “B”
9-pin DSUB socket
for surface mounted case at the inclined housing on the case bottom
– Test voltage 500 V; 50 Hz
– Transmission speed min. 4800 Bd, max. 38400 Bd
factory setting: 19200 Bd
– Maximum transmission distance 15 m (50 ft)
RS485
– Connection for flush mounted case rear panel, mounting location “B”
9-pin DSUB socket
for surface mounted case at the inclined housing on the case bottom
– Test voltage 500 V, 50 Hz
– Transmission speed min. 4800 Bd, max. 38400 Bd
factory setting: 19200 Bd
– Maximum transmission distance 1000 m (3300 ft)
Optical fibre
– Connector Type ST–connector
for flush mounted case rear panel, mounting location “B”
for surface mounted case at the inclined housing on the case bottom
– Optical wavelength λ = 820 nm
– Laser class 1 acc. EN 60825–1/ –2 using glass fibre 50/125 µm or
using glass fibre 62.5/125 µm
– Permissible optical signal attenuation max. 8 dB using glass fibre 62.5/125 µm
– Maximum transmission distance 1.5 km (1 mile)
– Character idle state selectable; factory setting: “Light off”
Profibus RS485 (FMS and DP)
– Connectionfor flush mounted case rear panel, mounting location “B”
9-pin DSUB socket
for surface mounted case at the inclined housing on the case bottom
– Test voltage 500 V; 50 Hz
4 Technical Data
252 7UT612 Manual
C53000–G1176–C148–1
– Transmission speed up to 1.5 MBd
– Maximum transmission distance 1000 m (3300 ft) at ≤ 93.75 kBd
500 m (1640 ft) at ≤ 187.5 kBd
200 m (660 ft) at ≤ 1.5 MBd
Profibus Optical (FMS and DP)
– C o nne cto r Type ST–plug
FMS: single ring or twin ring depending on
ordered version
DP: twin ring only
– Connection for flush mounted case rear panel, mounting location “B”
for surface mounted case at the inclined housing on the case bottom
– Transmission speed to 1.5 MBd
recommended: > 500 kBd
– Optical wavel engt h λ = 820 nm
– Laser class 1 acc. EN 60825–1/ –2 using glass fibre 50/125 µm or
usin g glass fibre 62.5/125 µm
– Permissible optical signal attenuation max. 8 dB using glass fibre 62.5/125 µm
– Maximum transmission distance 1.5 km (1 mile)
DNP3.0 RS485
– Connectionfor flush mounted case rear panel, mounting location “B”
9-pin DSUB socket
for surface mounted case at the inclined housing on the case bottom
– Test voltage 500 V; 50 Hz
– Transmission speed up to 19200 Bd
– Maximum transmission distance 1000 m (3300 ft)
DNP3.0 Optic al
– C o nne cto r Type ST–plug trans mi tter /rec ei ver
– Connection for flush mounted case rear panel, mounting location “B”
for surface mounted case at the inclined housing on the case bottom
– Transmission speed up to 19200 Bd
– Optical wavel engt h λ = 820 nm
– Laser class 1 acc. EN 60825–1/ –2 using glass fibre 50/125 µm or
using glass fibre 62.5/125 µm
– Permissible optical signal attenuation max. 8 dB using glass fibre 62.5/125 µm
– Maximum transmission distance 1.5 km (1 mile)
MODBUS RS485
– Connection for flush mounted case rear panel, mounting location “B”
9-pin DSUB socket
for surface mounted case at the inclined housing on the case bottom
– Test voltage 500 V; 50 Hz
4.1 General Device Data
2537UT612 Manual
C53000–G1176–C148–1
– Transmission speed up to 19200 Bd
– Maximum transmission distance 1000 m (3300 ft)
MODBUS LWL
– Connector Type ST–plug transmitter/receiver
– Connection for flush mounted case rear panel, mounting location “B”
for surface mounted case at the inclined housing on the case bottom
– Transmission speed up to 19200 Bd
– Optical wavelength λ = 820 nm
– Laser class 1 acc. EN 60825–1/ –2 using glass fibre 50/125 µm or
using glass fibre 62.5/125 µm
– Permissible optical signal attenuation max. 8 dB using glass fibre 62,5/125 µm
– Maximum transmission distance 1.5 km (1 mile)
Time
Synchronization – Signal type DCF77/IRIG B-Signal
– Connection for flush mounted case rear panel, mounting location “A”
9-pin DSUB socket
for surface mounted case at the terminal on the case bottom
– Nominal signal voltages optional 5 V, 12 V or 24 V
– S i gnal level and bur de n:
4.1.5 El ectrical Tests
Specifications Standards: IEC 60255 (Product standards)
ANSI/IEEE C37.90.0; C37.90.0.1;
C37.90.0.2
DIN 57435 Part 303
See also standards for individual tests
Insulation Tests Standards: IEC 60255–5 and 60870–2–1
– High voltage test (routine test) 2.5 kV (rms); 50 Hz
all circuits except power supply,
binary inputs, and
communication/time sync. interfaces
Nominal signal input voltage
5V 12V 24V
U
IHigh 6.0 V 15.8 V 31 V
UILow 1.0 V at IILow = 0.25 mA 1.4 V at IILow = 0.25 mA 1.9 V at IILow = 0.25 mA
IIHigh 4.5 mA to 9.4 mA 4.5 mA to 9.3 mA 4.5 mA to 8.7 mA
RI890 Ω at UI = 4 V
640 Ω at UI = 6 V 1930 Ω at UI = 8.7 V
1700 Ω at UI = 15.8 V 3780 Ω at UI = 17 V
3560 Ω at UI = 31 V
4 Technical Data
254 7UT612 Manual
C53000–G1176–C148–1
– High voltage test (routine test) 3.5 kVDC
only power supply and binary inputs
– High Voltage Test (routine test) 500 V (rms); 50 Hz
only isolated communication
/time sync. interfaces
– Impulse voltage test (type test) 5 kV (peak); 1.2/50 µs; 0.5 Ws; 3 positive
all circuits except communication and 3 negative impulses in intervals of 5 s
/time sync. interfaces, class III
EMC Tests;
Interference
Immunity (Type
Tests)
Standards: IEC 60255–6 and –22 (Product standards)
EN 50082–2 (Generic standard)
DIN 57435 Part 303
– H i gh frequenc y tes t 2 .5 kV (Peak ); 1 MHz; τ = 15 µs;
IEC 60255–22 –1, cl as s III 400 surges per s; test duration 2 s
and VDE 0435 part 303, class III Ri = 200 Ω
– Electrostatic discharge 8 kV contact discharge;
IEC 60255–22–2 class IV 15 kV air discharge, both polarities;
and IEC 61000–4–2, class IV 150 pF; Ri = 330 Ω
– Irradiation with HF field, non-modulated10 V/m; 27 MHz to 500 MHz
IEC 60255–22–3 (report) class III
– Irradiation with HF field, amplitude 10 V/m; 80 MHz to 1000 MHz; 80 % AM;
modulated; IEC 61000–4–3, class III 1kHz
– Irradiation with HF field, 10 V/m; 900 MHz; repetition frequency
pulse modulated 200 Hz; duty cycle of 50 %
IEC 61000–4–3/ENV 50204, class III
– Fast transient disturbance/burst 4 kV; 5/50 ns; 5 kHz; burst length = 15 ms;
IEC 60255–22–4 and repetition rate 300 ms; both polarities;
IEC 61000–4–4, class IV Ri = 50 Ω; test duration 1 min
– High energy surge voltages impulse: 1.2/50 µs
(SURGE), IEC 61000–4–5
insta llation class 3
power supply common mode: 2 kV; 12 Ω; 9 µF
diff. mode: 1 kV; 2 Ω; 18 µF
analogue inputs, binary inputs common mode: 2 kV; 42 Ω; 0.5 µF
and outputs diff. mode: 1 kV; 42 Ω; 0.5 µF
– Line conducted HF, amplitude 10 V; 150 kHz to 80 MHz; 80 % AM; 1 kHz
modulated; IEC 61000–4–6, class III
– Power system frequency magnetic 30 A/m continuous; 300 A/m for 3 s; 50 Hz
field; IEC 61000–4–8, class IV; 0.5 mT; 50 Hz
IEC 60255–6
– Oscillatory surge withstand capability 2.5 to 3 kV (peak value); 1 to 1.5 MHz
ANSI/IEEE C37.90.1 decaying wave; 50 surges per s;
duration 2 s; Ri = 150 Ω to 200 Ω
– Fast transient surge withstand cap- 4 kV to 5 kV; 10/150 ns; 50 surges per s;
ability, ANSI/IEEE C37.90.1 both polarities; duration 2 s; Ri = 80 Ω
– Radiated electromagnetic interference 35 V/m; 25 MHz to 1000 MHz
ANSI/IEEE Std C37.90.2 amplitude and pulse modulated
4.1 General Device Data
2557UT612 Manual
C53000–G1176–C148–1
– Damped oscillations 2.5 kV (peak value), polarity alternating;
IEC 60694, IEC 61000–4–12 100 kHz, 1 MHz, 10 MHz and 50 MHz;
Ri = 200 Ω
EMC Tests;
Interference
Emission (Type
Tests)
Standard: EN 50081–* (Generic standard)
– Conducted interference, 150 kHz to 30 MHz
only power supply voltage limit class B
IEC–CISPR 22
– Radio interference field strength 30 MHz to 1000 MHz
IEC–CISP R 22 lim it class B
4.1.6 Mechanical Stress Tests
Vibration and
Shock During
Operation
Standards: IEC 60255–21 and IEC 60068
– Vibration sinusoidal
IEC 60255–21–1, class 2 10 Hz to 60 Hz: ±0.075 mm amplitude
IEC 60068–2–6 60 Hz to 150 Hz: 1 g acceleration
frequency sweep rate 1 octave/min
20 cycles in 3 orthogonal axes.
– Shock half-sine shaped
IEC 60255–21–2, class 1 acceleration 5 g, duration 11 ms,
IEC 60068–2–27 3 shocks in each direction of
3 orthogonal axes
– Seismic vibration sinusoidal
IEC 60255–21–3, class 1 1 Hz to 8 Hz: ±3.5 mm amplitude
IEC 60068–3–3 (horizontal axis)
1 Hz to 8 Hz: ±1.5 mm amplitude
(vertical axis)
8 Hz to 35 Hz: 1 g acceleration
(horizontal axis)
8 Hz to 35 Hz: 0.5 g acceleration
(vertical axis)
Frequency sweep rate1 octave/min
1 cycle in 3 orthogonal axes
Vibration and
Shock During
Transport
Standards: IEC 60255–21 and IEC 60068
– Vibration sinusoidal
IEC 60255–21–1, class 2 5 Hz to 8 Hz: ±7.5 mm amplitude
IEC 60068–2–6 8 Hz to 150 Hz: 2 g acceleration
Frequency sweep rate1 octave/min
20 cycles in 3 orthogonal axes
– Shock half-sine shaped
IEC 60255–21–2, class 1 acceleration 15 g; duration 11 ms;
IEC 60068–2–27 3 shocks in each direction of
3 orthogonal axes
4 Technical Data
256 7UT612 Manual
C53000–G1176–C148–1
– Continuous shock half-sine shaped
IEC 60255–21–2, class 1 acceleration 10 g; duration 16 ms;
IEC 60068–2–29 1000 shocks in each direction of
3 orthogonal axes
4.1.7 Climat ic Stre ss Test s
Ambient
Temperatures Standards: IEC 60255–6
– recommended operating temperature –5 °C to +55 °C (+23 °F to +131 °F)
– limiting temporary (transient) –20 °C to +70 °C
operating temperature (–4 °F to 158 °F)
in quiescent state, i.e. no pickup and no indications
– limiting temperature during storage –25 °C to +55 °C (–13 °F to 131 °F)
– limiting temperature during transport –25 °C to +70 °C (–13 °F to 158 °F)
Storage and transport of the device with factory packaging!
Humidity Permissible humidity mean value p. year ≤75 % relative humidity
on 56 days per year up to 93 % relative
humidity; condensation not permissible!
All devices shall be installed such that they are not exposed to direct sunlight, nor
subject to large fluctuations in temperature that may cause condensation to occur.
4.1.8 Service Conditions
The device is designed for use in an industrial environment or an electrical utility
environment, for installation in standard relay rooms and compartments so that proper
installation and electromagnetic compatibility (EMC) is ensured. In addition, the
following are recommended:
•All contactors and relays that operate in the same cubicle, cabinet, or relay panel
as the numerical protective device should, as a rule, be equipped with suitable
surge suppression components.
•For substations with operating voltages of 100 kV and above, all external cables
should be shielded with a conductive shield grounded at both ends. The shield must
be capable of carrying the fault currents that could occur. For substations with lower
operating voltages, no special measures are normally required.
•Do not withdraw or insert individual modules or boards while the protective device
is energized. When handling the modules or the boards outside of the case,
standards for components sensitive to electrostatic discharge (ESD) must be
observed. The modules, boards, and device are not endangered when the device
is compl etel y asse mbl ed.
Visibility of display
may be impaired
above +55 °C/130 °F
4.1 General Device Data
2577UT612 Manual
C53000–G1176–C148–1
4.1.9 Construction
Housing 7XP20
Dimensions see drawings, Section 4.15
Weight (mass), approx.
– in flush mounted case, size 1/25.1 kg (111/4 lb)
– in surface mounted case, size 1/29.6 kg (211/4 lb)
Degree of protection acc. IEC 60529
– for the device
in surface mounted case IP 51
in flush mounted case
front IP 51
rear IP 50
– for human safety IP 2x with closed protection cover
4 Technical Data
258 7UT612 Manual
C53000–G1176–C148–1
4.2 Differential Prote c tion
4.2.1 General
Pick up Values Differential current IDIFF>/INobj 0.05 to 2.00 (steps 0.01)
High-current stage IDIFF>>/INobj 0.5 to 35.0 (steps 0.1)
or ∞ (stage ineffective)
Pickup on switch-on
(factor of IDIFF>) 1.0 to 2.0 (steps 0.1)
Add-on stabilization on external fault
(IRest > set value) Iadd-on/INobj 2.00 to 15.00 (steps 0.01)
action time 2 to 250 cycles (steps 1 cycle)
or ∞ (effective until dropoff)
Trip characteristic see Figur e 4-1
Tolerances (at preset parameters)
–IDIFF> stage and characteristic 5 % of set value
–IDIFF>> stage 5 % of set value
Time Delays Delay of IDIFF> stage TI-DIFF> 0.00 s to 60.00 s (steps 0.01 s)
or ∞ (no trip)
Delay of IDIFF>> s tage TI-DIFF>> 0.00 s to 60.00 s (steps 0.01 s)
or ∞ (no trip)
Time tolerance 1 % of set value or 10 ms
The set times are pure delay times
Figure 4-1 Tripping characteristic of the differential protection
1234 67891011121314151617
1
2
3
4
5
6
7
8
9
10
,²',))!!
,²',))!
%$6(32,17
%$6(32,17
Tripping
Istab
INobj
---------------
Idiff
INobj
--------------- Fault Characteristic
Blocking
,²$''2167$%
Add-on Stabilization
5
Legend:
Idiff Differential current = |I1 + I2|
Istab Stabilizing current = |I1| + |I2|
INobj Nominal current of prot. object
4.2 Differential Protection
2597UT612 Manual
C53000–G1176–C148–1
4.2.2 Transformers
Harmonic Restraint Inrush restaint ratio 10 % to 80 % (steps 1 %)
(2nd harmonic) I2fN/IfN see also Figure 4-2
Stabilization ratio further (n-th) harmonic 10 % to 80 % (steps 1 %)
(optional 3. or 5.) InfN/IfN see also Figure 4-3
Crossblock function can be activated / deactivated
max. action time for Crossblock 2 to 1000 AC cycles (steps 1 cycles)
or 0 (crossblock deactivated)
or ∞ (active until dropout)
Operating Times Pickup time/dropout time with single-side infeed
Dropout ratio, approx. 0.7
Current Matching
for Transforme rs Matching of vector group 0 to 11 (× 30°) (steps 1)
Star point conditioning earthed or non-earthed (for each winding)
Frequency Frequency correction in the range 0.9 ≤ f/fN ≤ 1.1
Frequenc y inf lue nce see Figure 4-4
Figure 4-2 Stabilizing influence of 2nd harmonic (transformer protection)
50 Hz 60 Hz 162/3Hz
38 ms
25 ms
19 ms
35 ms
22 ms
17 ms
85 ms
55 ms
25 ms
35 ms 30 ms 80 ms
Pickup time at frequency
at 1.5 · setting value IDIFF>
at 1.5 · setting value IDIFF>>
at 5 · setting value IDIFF>>
Dropout time, approx.
0 0.1 0.2 0.4 0.5
0.2
0.5
0.1
1.0
10.0
5.0
2.0 settable
e.g. 2nd Harmonic = 15 %
settable
e.g. IDIFF>/INobj = 0.15
settable
e.g. IDIFF>>/INobj = 10
I2f
IfN
IfN
INobj
Blocking
Legend:
Idiff Differential current =
|I1 + I2|
INobj Nominal current of
protected object
IfN Current with nominal
frequency
I2f Current with twice
nominal frequency
Blocking
0.3
Tripping
4 Technical Data
260 7UT612 Manual
C53000–G1176–C148–1
Figure 4-3 Stabilizing influence of n-th harmonic (transformer protection)
Figure 4-4 Frequency influence (transformer protection)
0 0.1 0.2 0.3 0.4 0.5
0.2
0.5
0.1
1.0
10.0
5.0
2.0
settable
e.g. n-th Harmonic = 40 %
settable
e.g. IDIFF>/INobj = 0.15
settable
e.g. I
',))PD[Q+0
/I
1REM
= 5
Inf
IfN
IfN
INobj
Blocking
Tripping
Legend:
Idiff Differential current =
|I1 + I2|
INobj Nominal current of
protected object
IfN Current with nominal
frequency
Inf Current with n-fold
nominal frequency
(n = 3 or 4)
0 0.2 0.4 0.6 0.8
0.2
0.5
0.1
1.0
20
5
2
settable
e.g. IDIFF>/INobj = 0.15
settable e.g.
1.0 1.2 1.4
0.3
3
10
f/fN
IDIFF>>/INobj = 5.0
Legend:
Idiff Diff erent ial current = |I1 + I2|
INobj Nominal current of the protected
object
IXf Current with any frequency
in operating range
Tripping
Blocking
Blocking
IXf
INobj
4.2 Differential Protection
2617UT612 Manual
C53000–G1176–C148–1
4.2.3 Generators, Moto rs, Reacto rs
Operating Times Pickup time/dropout time with single-side infeed
Dropout ratio, approx. 0.7
Frequency Frequency correction in the range 0.9 ≤ f/fN ≤ 1.1
Frequency influence see Figure 4-5
Figure 4-5 Frequency influence (generator / motor protection)
50 Hz 60 Hz 162/3Hz
38 ms
25 ms
19 ms
35 ms
22 ms
17 ms
85 ms
55 ms
25 ms
35 ms 30 ms 80 ms
Pickup time at frequency
at 1.5 · setting value IDIFF>
at 1.5 · setting value IDIFF>>
at 5 · setting value IDIFF>>
Dropout time, approx.
0 0.2 0.4 0.6 0.8
0.2
0.1
0.3
2
0.6
0.4
IDIFF>>/INobj (settable)
1.0 1.2 1.4
1
f/fN
Setting value e.g. 0.1
Legend:
Idiff Differential current = |I1 + I2|
INobj Nominal current of the protected object
IXf Current with any frequency
in operating range
Tripping
Blocking
IXf
INobj
4 Technical Data
262 7UT612 Manual
C53000–G1176–C148–1
4.2.4 Busbars, Branch-Points, Short Lines
Differencial Current
Monitor Steady-state differential current monitoring
Idiff mon/INobj 0.15 to 0.80 (steps 0.01)
Delay of blocking by differential current
monitoring Tdiff mon 1 s to 10 s (steps 1 s)
Feeder Current
Guard Trip release Iguard/INObj 0.20 to 2.00 (steps 0.01)
by feeder current guard or 0 (always released)
Operating Times Pickup time/dropout time with single-side infeed
Dropout ratio, approx. 0.7
Frequency Frequency correction in the range 0.9 ≤ f/fN ≤ 1.1
Frequency influence see Figure 4-5
50 Hz 60 Hz 162/3Hz
25 ms
20 ms
19 ms
25 ms
19 ms
17 ms
50 ms
45 ms
35 ms
30 ms 30 ms 70 ms
Pickup time at frequency
at 1.5 · setting value IDIFF>
at 1.5 · setting value IDIFF>>
at 5 · setting value IDIFF>>
Dropout time, approx.
4.3 Restricted Earth Fault Protection
2637UT612 Manual
C53000–G1176–C148–1
4.3 Restricted Earth Fault Protection
Settings Differential current IREF>/INobj 0.05 to 2.00 (steps 0.01)
Limit angle ϕREF 110° (fix)
Trip characteristic see Figure 4-6
Pickup tolerance 5 % at I < 5 · IN
Time delay TREF 0.00 s to 60.00 s (steps 0.01 s)
or ∞ (no trip)
Time tolerance 1 % of set value or 10 ms
The set times are pure delay times
Operating Times
Dropout ratio, approx. 0.7
Frequency Frequency influence 1 % in the range 0.9 ≤ f/fN ≤ 1.1
Figure 4-6 Tripping characteristic of the restricted earth fault protection dependent on zero
se quence current ratio 3I0"/3I0’ (both current in phase or counter-phase)
50 Hz 60 Hz 162/3Hz
40 ms
37 ms 38 ms
32 ms 100 ms
80 ms
40 ms 40 ms 80 ms
Pickup time at frequency
at 1.5 · setting value IEDS>, approx.
at 2.5 · setting value IEDS>, approx.
Dropout time, approx.
-0.3 -0.2 -0.1 0.0 0.1 0.2 0.3
4
3
2
1
IREF
IREF>
3Io"
3Io’
Tripping
Blocking
4 Technical Data
264 7UT612 Manual
C53000–G1176–C148–1
4.4 Time Overcurrent Protection for Phase and Residual Currents
Characteristics Definite time stages (DT) IPh>>, 3I0>>, IPh>, 3I0>
Inverse time stages (IT) IP, 3I0P
(acc. IEC or ANSI) one of the curves according to Figures
4-7 to 4-9 can be selected
alternatively user specified trip and
reset ch ar acter ist ic
Reset characteristics (IT) see Figures 4-10 and 4-11
(acc. ANSI with disk emulation)
Current Stages High-current stages IPh>> 0.10 A to 35.00 A 1) (steps 0.01 A)
or ∞ (stage ineffective)
TIPh>> 0.00 s to 60.00 s (steps 0.01 s)
or ∞ (no trip)
3I0>> 0.05 A to 35.00 A 1) (steps 0.01 A)
or ∞ (stage ineffective)
T
3I0>> 0.00 s to 60.00 s (steps 0.01 s)
or ∞ (no trip)
Definite time stages IPh> 0.10 A to 35.00 A 1) (steps 0.01 A)
or ∞ (stage ineffective)
T
IPh> 0.00 s to 60.00 s (steps 0.01 s)
or ∞ (no trip)
3I0> 0.05 A to 35.00 A 1) (steps 0.01 A)
or ∞ (stage ineffective)
T
3I0> 0.00 s to 60.00 s (steps 0.01 s)
or ∞ (no trip)
Inverse time stages IP 0.10 A to 4.00 A 1) (steps 0.01 A)
(acc. IEC) TIP 0.05 s to 3.20 s (steps 0.01 s)
or ∞ (no trip)
3I0P 0.05 A to 4.00 A 1) (steps 0.01 A)
T3I0P 0.05 s to 3.20 s (steps 0.01 s)
or ∞ (no trip)
Inverse time stages IP 0.10 A to 4.00 A 1) (steps 0.01 A)
(acc. ANSI) DIP 0.50 s to 15.00 s (steps 0.01 s)
or ∞ (no trip)
3I0P 0.05 A to 4.00 A 1) (steps 0.01 A)
D3I0P 0.50 s to 15.00 s (steps 0.01 s)
or ∞ (no trip)
Tolerances currents 3 % of set value or 1 % of nominal current
with definite time times 1 % of set value or 10 ms
4.4 Time Overcurrent Protection for Phase and Residual Currents
2657UT612 Manual
C53000–G1176–C148–1
Tolerances currents Pickup at 1.05 ≤ I/IP ≤ 1.15;
with inverse time or 1.05 ≤ I/3I0P ≤ 1.15
(acc. IEC ti mes 5 % ± 15 ms at fN = 50/60 Hz
5 % ± 45 ms at fN = 162/3Hz
for 2 ≤ I/IP ≤ 20
and TIP/s ≥ 1;
or 2 ≤ I/3I0P ≤ 20
and T3I0P/s ≥ 1
(acc. ANSI) times 5 % ± 15 ms at fN = 50/60 Hz
5 % ± 45 ms at fN = 162/3Hz
for 2 ≤ I/IP ≤ 20
and DIP/s ≥ 1;
or 2 ≤ I/3I0P ≤ 20
and D3I0P/s ≥ 1
The set definite times are pure delay times.
1) Secondary values based on IN = 1 A; for IN = 5 A they must be multiplied by 5.
Operating Times of
the Definite Time
Stages
Pickup time/dropout time phase current stages
Pickup time/dropout time residual current stages
Drop-out Ratios Current stages approx. 0.95 for I/IN ≥ 0.5
Inrush Blocking Inrush blocking ratio 10 % to 45 % (steps 1 %)
(2nd harmonic) I2fN/IfN
Lower operation limit I > 0.2 A 1)
Max. current for blocking 0.03 A to 25.00 A 1) (steps 0.10 A)
Crossblock function between phases can be activated/deactivated
max. action time for crossblock 0.00 s to 180 s (steps 0.01 s)
1) Secondary values based on IN = 1 A; for IN = 5 A they must be multiplied by 5.
Frequency Frequency influence 1 % in the range 0.9 ≤ f/fN ≤ 1.1
50 Hz 60 Hz 162/3Hz
20 ms
25 ms 18 ms
23 ms 30 ms
45 ms
40 ms
45 ms 35 ms
40 ms 85 ms
100 ms
30 ms 30 ms 80 ms
Pickup time at frequency
without inrush restraint, min.
without inrush restraint, typical
with inrush restraint, min.
with inrush restraint, typical
Dropout time, typical
50 Hz 60 Hz 162/3Hz
40 ms
45 ms 35 ms
40 ms 100 ms
105 ms
40 ms
45 ms 35 ms
40 ms 100 ms
105 ms
30 ms 30 ms 80 ms
Pickup time at frequency
without inrush restraint, min.
without inrush restraint, typical
with inrush restraint, min.
with inrush restraint, typical
Dropout time, typical
4 Technical Data
266 7UT612 Manual
C53000–G1176–C148–1
Figure 4-7 Trip time characteristics of inverse time overcurrent protection and unbalanced load protection, according
IEC
0.1
0.2
0.4
1.6
3.2
0.05
Extremely inverse:
(
type
C)
I
/
I
p
1
0.3
0.1
1 2 3 5 10 20
100
20
10
5
2
0.5
0.2
0.05
Inverse:
Very inverse:
(
type
B)
T
p
t [s] t [s]
I
/
I
p
I
/
I
p
1
0.3
0.1
1 2 3 5 10 20
100
20
10
5
2
0.5
0.2
0.05
[s] [s]
1 2 5 10 20
0.3
0.1
100
20
10
2
0.05
5
[s]
0.2
0.5
1
t [s]
3
3
30 30
3
t014,
II
p
⁄()
0.02 1
–
----------------------------------- Tp
⋅
=
(type A)
t13 5,
II
p
⁄()
1
1
–
---------------------------- Tp
⋅
=
t80
II
p
⁄()
2
1
–
---------------------------- Tp
⋅
=
0.8
0.1
0.2
0.4
1.6
3.2
0.05
0.8
7
T
p
0.1 0.2 0.4
1.6
3.2
0.8
T
p
0.05
t tripping time
Tpset time multiplier
Ifault current
Ipset pickup value
Notes:
Shortest trip time for 162/3Hz is 100 ms.
For residual current read 3I0p instead of Ip and T3I0p instead of Tp
for earth current read IEp instead of Ip and TIEp instead of Tp
for unbalanced load read I2p instead of Ip and TI2p instead of Tp
0.1
0.2
0.4
3.2
0.05
10
3
1
1 2 3 5 10 20
1000
200
100
50
20
2
0.5
Longtime inverse:
T
p
t [s]
I
/
I
p
[s]
300
0.8
t120
II
p
⁄()
1
1
–
---------------------------- Tp
⋅
=
1.6
not for unbalanced load protection
30
5
7
10
3
1
1000
200
100
50
20
2
0.5
300
30
5
0.5
3
4.4 Time Overcurrent Protection for Phase and Residual Currents
2677UT612 Manual
C53000–G1176–C148–1
Figure 4-8 Trip time characteristics of inverse time overcurrent protection and unbalanced load protection, according
ANSI/IEEE
Moderately inverse
I
/
I
p
D [s]
1
2
5
10
15
0.5
1
0.3
0.1
1 2 3 5 10 20
100
20
10
0.5
0.2
0.05
t0.0103
II
p
⁄()
0.02 1
–
----------------------------------- 0.0228
+
D⋅
=
[s]
3
5
t [s]
2
50
Extremely inverse
I
/
I
p
t5.64
II
p
⁄()
2
1
–
---------------------------- 0.02434
+
D⋅
=[s] t8.9341
II
p
⁄()
2.0938 1
–
----------------------------------------- 0.17966
+
D⋅
=
1
0.3
0.1
1 2 3 5 10 20
100
20
10
5
2
0.5
0.2
0.05
Inverse
D [s]
t [s]
I
/
I
p
1
2
5
10
15
0.5
[s]
3
30
1
0.3
0.1
1 2 3 5 10 20
100
20
10
5
2
0.5
0.2
0.05
Very invers e
D [s]
t [s]
I
/
I
p
1
2
5
10
15
0.5
[s]
t3.992
II
p
⁄()
2
1
–
---------------------------- 0.0982
+
D⋅
=
30
3
t tripping time
D set time dial
Ifault current
Ipset pickup value
Notes:
Shortest trip time for 162/3Hz is 100 ms.
For residual current read 3I0p instead of Ip
for earth current read IEp instead of Ip
for unbalanced load read I2p instead of Ip
D [s]
12
5
10
15
0,5
2 3 5 10 20
0,3
0,1
500
20
10
2
0,05
5
0,2
0,5
1
t [s]
30
100
200
3
50
1
4 Technical Data
268 7UT612 Manual
C53000–G1176–C148–1
Figure 4-9 Trip time characteristics of inverse time overcurrent protection, according ANSI/IEEE
t0.2663
II
p
⁄()
1.2969 1
–
----------------------------------------- 0.03393
+
D⋅
=
Short inverse
t [s]
I
/
I
p
D [s]
12
5
10
15
0.5
1
0.3
0.1
1 2 3 5 10 20
100
20
10
5
2
0.5
0.2
0.05
[s]
30
3
Definite inverse
D [s]
I
/
I
p
1
2
5
10
15
0.5
1 2 3 5 10 20
0.3
0.1
100
20
10
2
0.05
5
[s]
0.2
0.5
1
t [s]
3
t0.4797
II
p
⁄()
1.5625 1
–
----------------------------------------- 2.1359
+
D⋅
=
30
t tripping time
D set time dial
Ifault current
Ipset pickup value
Long inverse
D [s]
I
/
I
p
1
2
5
10
15
0.5
1 2 3 5 10 20
0.3
0.1
100
20
10
2
0.05
5
[s]
t5.6143
II
p
⁄()1
–
------------------------- 2.18592
+
D⋅
=
0.2
0.5
1
t [s]
3
50
Notes:
Shortest trip time for 162/3Hz is 100 ms.
For residual current read 3I0p instead of Ip
for earth current read IEp instead of Ip a
3
50
4.4 Time Overcurrent Protection for Phase and Residual Currents
2697UT612 Manual
C53000–G1176–C148–1
Figure 4-10 Reset time characteristics of inverse time overcurrent protection and unbalanced load protection with disk
emulation, according ANSI/IEEE
Extremely inverse
[s]
t5.82
II
p
⁄()
2
1
–
----------------------------
D⋅
=
Inverse
t8.8
II
p
⁄()
2.0938 1
–
-----------------------------------------
D⋅
=
I
/
I
p
0.05 0.1 0.2 0.5 1.0
0.3
0.1
500
20
10
2
0.05
5
0.2
0.5
1
t [s]
30
100
0.3
200
3
50 5
2
1
0.5
10
D [s ]
15
[s]
I
/
I
p
0.05 0.1 0.2 0.5 1.0
0.3
0.1
500
20
10
2
0.05
5
0.2
0.5
1
t [s]
30
100 10
5
2
1
0.5
0.3
200
3
50
D [s]
15
Mo derately in v erse
[s]
t0.97
II
p
⁄()
2
1
–
----------------------------
D⋅
=
I
/
I
p
0.05 0.1 0.2 0.5 1.0
0.3
0.1
500
20
10
2
0.05
5
0.2
0.5
1
t [s]
30
100
10
5
2
1
0.5
0.3
200
3
50 D [s]
15
[s]
t4.32
II
p
⁄()
2
1
–
----------------------------
D⋅
=
I
/
I
p
0.05 0.1 0.2 0.5 1.0
0.3
0.1
500
20
10
2
0.05
5
0.2
0.5
1
t [s]
30
100
10
5
2
1
0.5
0.3
200
3
50
15
D [s]
treset time
D set time dial
Iinterr upt ed cur ren t
Ipset pickup value
Notes:
For residual current read 3I0p instead of Ip
for earth current read IEp instead of Ip
for unbalanced load read I2p instead of Ip
Very inverse
4 Technical Data
270 7UT612 Manual
C53000–G1176–C148–1
Figure 4-11 Reset time characteri stics of inverse time overcurrent protection with disk emulation, according ANSI/IEEE
I
/
I
p
0.05 0.1 0.2 0.5 1.0
0.3
0.1
500
20
10
2
0.05
5
0.2
0.5
1
t [s]
30
100
15
10
5
2
1
0,5
0.3
200
3
50
D [s]
Short inverse
[s]
t0.831
II
p
⁄()
1.2969 1
–
-----------------------------------------
D⋅
=
De f inite inve rse
[s]
t1.0394
II
p
⁄()
1.5625 1
–
-----------------------------------------
D⋅
=
I
/
I
p
0.05 0.1 0.2 0.5 1.0
0.3
0.1
500
20
10
2
0.05
5
0.2
0.5
1
t [s]
30
100
15
10
5
2
1
0.5
0.3
200
3
50 D [s]
Long inverse
t12.9
II
p
⁄()
1
1
–
----------------------------
D⋅
=[s]
I
/
I
p
0.05 0.1 0.2 0.5 1.0
0.3
0.1
500
20
10
2
0.05
5
0.2
0.5
1
t [s]
30
100
0.3
200
3
50
5
2
1
0.5
10
D [s ]
15
I
/
I
p
t [s]
15
10
5
2
1
0.5
D [s]
treset time
D set time dial
Iinterr upt ed curr en t
Ipset pickup value
Notes:
For residual current read 3I0p instead of Ip
for earth current read IEp instead of Ip
4.5 Time Overcurrent Protection for Earth Current
2717UT612 Manual
C53000–G1176–C148–1
4.5 Time Overcurrent Protection for Earth Current
Characteristics Definite time stages (DT) IE>>, IE>
Inverse time stages (IT) IEP
(acc. IEC or ANSI) one of the curves according to Figures
4-7 to 4-9 can be selected
alternatively user specified trip and
reset characteristic
Reset characteristics (IT) see Figures 4-10 and 4-11
(acc. ANSI with disk emulation)
Current Stages High-current stage IE>> 0.05 A to 35.00 A 1) (steps 0.01 A)
or ∞ (stage ineffective)
TIE>> 0.00 s to 60.00 s (steps 0.01 s)
or ∞ (no trip)
Definite time stage IE> 0.05 A to 35.00 A 1) (steps 0.01 A)
or ∞ (stage ineffective)
T
IE> 0.00 s to 60.00 s (steps 0.01 s)
or ∞ (no trip)
Inverse time stages IEP 0.05 A to 4.00 A 1) (steps 0.01 A)
(acc. IEC) TIEP 0.05 s to 3.20 s (steps 0.01 s)
or ∞ (no trip)
Inverse time stages IEP 0.05 A to 4.00 A 1) (steps 0.01 A)
(acc. ANSI) DIEP 0.50 s to 15.00 s (steps 0.01 s)
or ∞ (no trip)
Tolerances definite time currents 3 % of set value or 1 % of nominal current
times 1 % of set value or 10 ms
Tolerances inverse time currents Pickup at 1.05 ≤ I/IEP ≤ 1.15
(acc. IEC ti mes 5 % ± 15 ms at fN = 50/60 Hz
5 % ± 45 ms at fN = 162/3Hz
for 2 ≤ I/IEP ≤ 20
and TIEP/s ≥ 1
(acc. ANSI) times 5 % ± 15 ms at fN = 50/60 Hz
5 % ± 45 ms at fN = 162/3Hz
for 2 ≤ I/IEP ≤ 20
and DIEP/s ≥ 1
The set definite times are pure delay times.
1) Secondary values based on IN = 1 A; for IN = 5 A they must be multiplied by 5.
4 Technical Data
272 7UT612 Manual
C53000–G1176–C148–1
Operating Times of
the Definite Time
Stages
Pickup time/dropout time
Drop-out ratios Current stages a ppr ox. 0.95 for I/IN ≥ 0.5
Inrush Blocking Inrush blocking ratio 10 % to 45 % (steps 1 %)
(2nd harmonic ) I2fN/IfN
Lower operation limit I > 0.2 A 1)
Max. current for blocking 0.30 A to 25.00 A 1) (steps 0.01 A)
1) Secondary values based on IN = 1 A; for IN = 5 A they must be multiplied by 5.
Frequency Frequency influence 1 % in the range 0.9 ≤ f/fN ≤ 1.1
4.6 Dynamic Cold Load Pickup for Time Overcurrent Protection
Time Control Start criterion Binary input from circuit breaker
auxiliary contact or current criterion
(of the assigned side)
CB open time TCB open 0 s to 21600 s (= 6 h) (steps 1 s)
Active time TActive time 1 s to 21600 s (= 6 h) (steps 1 s)
Accelerated dropout time TStop Time 1 s to 600 s (= 10 min) (steps 1 s)
or ∞ (no accelerated dropout)
Setting Ranges and
Changeover Values Dynamic parameters of current Setting ranges and steps are the same
pickups and delay times as for the functions to be influenced
or time multipliers
50 Hz 60 Hz 162/3Hz
20 ms
25 ms 18 ms
23 ms 30 ms
45 ms
40 ms
45 ms 35 ms
40 ms 85 ms
100 ms
30 ms 30 ms 80 ms
Pickup time at frequency
without inrush restraint, min.
without inrush restraint, typical
with inrush restraint, min.
with inrush restraint, typical
Dropout time, typical
4.7 Single-Phase Time Overcurrent Protection
2737UT612 Manual
C53000–G1176–C148–1
4.7 Single-Phase Time Overcurrent Protection
Current Stages High-current stage I>> 0.05 A to 35.00 A 1) (steps 0.01 A)
0.003 A to 1.500 A 2) (steps 0.001A)
or ∞ (stage ineffective)
TI>> 0.00 s to 60.00 s (steps 0.01 s)
or ∞ (no trip)
Definite time stage I> 0.05 A to 35.00 A 1) (steps 0.01 A)
0.003 A to 1.500 A 2) (steps 0.001A)
or ∞ (stage ineffective)
T
I> 0.00 s to 60.00 s (steps 0.01 s)
or ∞ (no trip)
Tolerances currents 3 % of set value or 1 % of nominal current
at IN = 1 A or 5 A;
5 % of set value or 3 % of nominal current
at IN = 0.1 A
times 1 % of set value or 10 ms
The set definite times are pure delay times.
1) Secondary values based on IN = 1 A; for IN = 5 A they must be multiplied by 5.
2) Secondary values for high-sensitivity current input I7, independent of nominal current.
Operating Times Pickup time/dropout time
Drop-out Ratios Current stages approx. 0.95 for I/IN ≥ 0.5
Frequency Frequency influence 1 % in the range 0.9 ≤ f/fN ≤ 1.1
Pickup time at frequency
minimum
typical
Dropout time, typical
Pickup time at frequency
minimum
typical
Dropout time, typical
50 Hz 60 Hz 162/3Hz
20 ms
30 ms 18 ms
25 ms 35 ms
80 ms
30 ms 27 ms 80 ms
4 Technical Data
274 7UT612 Manual
C53000–G1176–C148–1
4.8 U nbalanced Load Protection
Characteristics Definite time stages (DT) I2>>, I2>
Inverse time stages (IT) I2P
(acc. IEC or ANSI) one of the curves according to Figures
4-7 or 4-8 can be selected
Reset characteristics (IT) see Figure 4-10
(acc. ANSI with disk emulation)
Operating range 0.1 A to 4 A 1)
1) Secondary values based on IN = 1 A; for IN = 5 A they must be multiplied by 5.
Current Stages High-current stage I2>> 0.10 A to 3.00 A 1) (steps 0.01 A)
TI2>> 0.00 s to 60.00 s (steps 0.01 s)
or ∞ (no trip)
Definite time stage I2> 0.10 A to 3.00 A 1) (steps 0.01 A)
T
I2> 0.00 s to 60.00 s (steps 0.01 s)
or ∞ (no trip)
Inverse time stages I2P 0.10 A to 2.00 A 1) (steps 0.01 A)
(acc. IEC) TI2P 0.05 s to 3.20 s (steps 0.01 s)
or ∞ (no trip)
Inverse time stages I2P 0.10 A to 2.00 A 1) (steps 0.01 A)
(acc. ANSI) DI2P 0.50 s to 15.00 s (steps 0.01 s)
or ∞ (no trip)
Tolerances definite time currents 3 % of set value or 1 % of nominal current
times 1 % of set value or 10 ms
Tolerances inverse time currents Pickup at 1.05 ≤ I2/I2P ≤ 1.15;
(acc. IEC times 5 % ± 15 ms at fN = 50/60 Hz
5 % ± 45 ms at fN = 162/3Hz
for 2 ≤ I2/2IP ≤ 20
and TI2P/s ≥ 1
(acc. ANSI) times 5 % ± 15 ms at fN = 50/60 Hz
5 % ± 45 ms at fN = 162/3Hz
for 2 ≤ I2/2IP ≤ 20
and DI2P/s ≥ 1
The set definite times are pure delay times.
1) Secondary values based on IN = 1 A; for IN = 5 A they must be multiplied by 5.
Operating Times of
the Definite Time
Stages
Pickup time/dropout time
Drop-out Ratios Current stages approx. 0.95 for I2/IN ≥ 0.5
Frequency Frequency influence 1 % in the range 0.9 ≤ f/fN ≤ 1.1
Pickup time at frequency
minimum
typical
Dropout time, typical
50 Hz 60 Hz 162/3Hz
50 ms
55 ms 45 ms
50 ms 100 ms
130 ms
30 ms 30 ms 70 ms
4.9 Thermal Overload Protection
2757UT612 Manual
C53000–G1176–C148–1
4.9 Thermal Overload Protection
4.9.1 Overload Protection Using a Thermal Replica
Setting Ranges Factor k acc. IEC 60255–8 0.10 to 4.00 (steps 0.01)
Time constant τ1.0 min to 999.9 min (steps 0.1 min)
Cooling down factor at motor stand-still
(for motors) Kτ–factor 1.0 to 10.0 (steps 0.1)
Thermal alarm stage Θalarm/Θtrip 50 % to 100 % referred to trip
temperature rise (steps 1 %)
Current alarm stage Ialarm 0.10 A to 4.00 A 1) (steps 0.01 A)
Start-up recognition Istart-up 0.60 A to 10.00 A 1) (steps 0.01 A)
(for motors) or ∞ (no start-up recognition)
Emergency start run-on time
(for motors) Trun-on 10 s to 15000 s (steps 1 s)
1) Secondary values based on IN = 1 A; for IN = 5 A they must be multiplied by 5.
Tripping
Characteristics see Figure 4-12
Dropout Ratios Θ/Θtrip dropout at Θalarm
Θ/Θalarm approx. 0.99
I/Ialarm approx. 0.97
Tolerances Referring to k · IN 2 % or 10 mA 1); class 2 % acc.
IEC 60255–8
Referring to tripping time 3 % or 1 s at fN = 50/60Hz
5% or 1s at f
N
= 162/3Hz
for I/(k·IN) > 1.25
1) Secondary values based on IN = 1 A; for IN = 5 A they must be multiplied by 5.
Freq. Influence
Referring to k · IN In the range 0.9 ≤ f/fN ≤ 1.1 1 % at fN = 50/60 Hz
3% at f
N
= 162/3Hz
tτ
I
kIN
⋅
-------------
2I
pre
kIN
⋅
-------------
2
–
I
k
I
N
⋅
-------------
2
1
–
-------------------------------------------------
ln
⋅
=
Tripping characteristic
t tripping tim e
τheating-up time constant
Iactual load current
Ipre preload current
ksetting factor IEC 60255–8
INnominal current of the protected object
Meaning of abbreviations:
for I/(k·IN) ≤ 8
4 Technical Data
276 7UT612 Manual
C53000–G1176–C148–1
Figure 4-12 Trip time characteristics of the overload protection with thermal replica
1
0.3
0.1
1 2 3 5 10 12
100
20
10
5
2
0.5
0.2
0.05
t [min ] t [min ]
I
/ (k
·IN
)
1000
1
0.3
0.1
100
20
10
5
2
0.5
0.2
0.05
3
30
30
3
Parameter:
Setting Value
Time Constant
20
200
500
100
50
10
5
2
1
4 6 7 8
50
tτ
I
kIN
⋅
--------------
2
I
kI
N
⋅
--------------
2
1–
--------------------------------
ln
⋅=
without preload:
I
/ (k
·IN
)
1 2 3 5 10 12 4 6 7 8
with 90
%
preload:
tτ
I
kIN
⋅
--------------
2
I
pre
kIN
⋅
--------------
2
–
I
kI
N
⋅
--------------
2
1–
---------------------------------------------------
ln
⋅=
50
Parameter:
Setting Value
Time C onstant
1000
500
200
100
50
20
10
5
2
1
τ
[min ]
τ
[min]
[min]
[min]
4.10 Thermoboxes for Overload Protection
2777UT612 Manual
C53000–G1176–C148–1
4.9.2 Hot Spot Calculation and Determination of the Ageing Rate
Temperature
Detectors Number of measuring points from 1 thermobox (up to 6 measuring
points) or
from 2 thermoboxes (up to 12 measuring
points)
For hot-spot calculation
one
temperature detector must be connected.
Cooling Cooling meth od ON (oil natur al)
OF (oil forced)
OD (oil directe d)
Oil exponent Y 1.6 to 2.0 (steps 0.1)
Hot-spot to top-oil gradient Hgr 22 to 29 (steps 1)
Annunciation
Thresholds Warning temperature hot-spot 98 °C to 140 °C (steps 1 °C)
or 208 °F to 284 °F (steps 1 °F)
Alarm temperature hot-spot 98 °C to 140 °C (steps 1 °C)
or 208 °F to 284 °F (steps 1 °F)
Warning aging rate 0.125 to 128.000 (steps 0.001)
Alarm aging rate 0.125 to 128.000 (steps 0.001)
4.10 Thermoboxes for Overload Protection
Temperature
Detectors Thermoboxes (connectable) 1 or 2
Number of temperature detectors
per thermobox max. 6
Measuring type Pt 100 Ω or Ni 100 Ω or Ni 120 Ω
Annunciation
Thresholds For each measuring point:
Warning temperature (stage 1) –50 °C to 250 °C (steps 1 °C)
or –58 °F to 482 °F (steps 1 °F)
or ∞ (no warning)
Alarm temperature (stage 2) –50 °C to 250 °C (steps 1 °C)
or –58 °F to 482 °F (steps 1 °F)
or ∞ (no alarm)
4 Technical Data
278 7UT612 Manual
C53000–G1176–C148–1
4.11 Circuit Breaker Failure Protection
Circuit Breaker
Supervision Current flow monitoring 0.04 A to 1.00 A 1) (steps 0.01 A)
for the respective side
Dropoff to pickup ratio approx. 0.9 for I ≥0.25 A 1)
Pickup tolerance 5 % of set value or 0.01 A 1)
Breaker status monitoring binary input for CB auxiliary contact
1) Secondary values based on IN = 1 A; for IN = 5 A they must be multiplied by 5.
Starting Conditions for beaker failure protection internal trip
external trip (via binary input)
Times Pickup time approx. 3 ms with measured quantities
present;
approx. 20 ms after switch-on of
measured quantities, fN = 50/60Hz;
approx. 60 ms after switch-on of
measured quantities, fN = 162/3Hz
Reset time (incl. output relay) ≤30 ms at fN = 50/60 Hz,
≤90 ms at fN = 162/3Hz
Delay times for all stages 0.00 s to 60.00 s; ∞(steps 0.01 s)
Time tolerance 1 % of setting value or 10 ms
4.12 External Trip Commands
Binary Inputs for
Direct Tripping Number 2
Operating time approx. 12.5 ms min.
approx. 25 ms typical
Dropout time approx. 25 ms
Delay time 0.00 s to 60.00 s (steps 0.01 s)
Expiration tolerance 1 % of set value or 10 ms
The set definite times are pure delay times.
Transformer
Annunciations External annunciations Buchholz warning
Buchholz tank
Buchholz tripping
4.13 Monitoring Functions
2797UT612 Manual
C53000–G1176–C148–1
4.13 Monitoring Functions
Measured
Quantities Current symmetry |Imin| / |Imax| < %$/)$.7 ,
(for each side) if Imax / IN > %$/,/,0,7 / IN
– BAL. FAKT. I 0.10 to 0.90 (steps 0.01)
– BAL. I LIMIT 0.10 A to 1.00 A 1) (steps 0.01 A)
Phase rotation IL1 before IL2 before IL3 (clockwi se) or
IL1 before IL3 before IL2 (counter-clockwise)
if |IL1|, |IL2|, |IL3| > 0.5 IN
1) Secondary values based on IN = 1 A; for IN = 5 A they must be multiplied by 5.
Trip Circuit
Supervision Number of supervised trip circuits 1
Operation of each trip circuit with 1 binary input or with 2 binary inputs
4 Technical Data
280 7UT612 Manual
C53000–G1176–C148–1
4.14 Ancillary Functions
Operational
Measured Values Operational measured values of currents IL1; IL2; IL3
3-phase for each side in A primary and secondary and % of INobj
– Tolerance at IN = 1 A or 5 A 1 % of measured value or 1 % of IN
– Tolerance at IN = 0.1 A 2 % of measured value or 2 % of IN
Operational measured values of currents 3I0; I1; I2
3-phase for each side in A primary and secondary and % of INobj
– Tolerance 2 % of measured value or 2 % of IN
Operational measured values of currents I1 to I7;
1-phase for each feeder in A primary and secondary and % of INobj
– Tolerance 2 % of measured value or 2 % of IN
Operational measured values of currents I8
for high-sensitivity input in A primary and mA secondary
– Tolerance 1 % of measured value or 2 mA
Phase angles of currents ϕ(IL1); ϕ(IL2); ϕ(IL3) in °
3-phase for each side referred to ϕ(IL1)
– Tolerance 1° at rated current
Phase angles of currents ϕ(IL1) to ϕ(IL7) in °
1-phase for each feeder referred to ϕ(IL1)
– Tolerance 1° at rated current
Operational measured values f
of frequency in Hz and % of fN
– Range 10 Hz to 75 Hz
– Tolerance 1 % within range fN±10 % at I = IN
Operational measured values of power S (apparent power)
with applied or nominal voltage in kVA; MVA; GVA primary
Operational measured values ΘL1; ΘL2; ΘL3; Θres
for thermal value referred to tripping temperature rise Θtrip
Operational measured values ΘRTD1 to ΘRTD12
(Temperature acc. IEC 60354) in °C or °F
relative aging rate, load reserve
Measured values of
differential protection IDIFFL1; IDIFFL2; IDIFFL3;
IRESTL1; IRESTL2; IRESTL3
in % of operational rated current
– Tolerance (with preset values) 2 % of meas. value or 2 % of IN (50/60 Hz)
3 % of meas. value or 3 % of IN (162/3Hz)
Measured values of IdiffREF; IRestREF
restricted earth fault protection in % of operational rated current
– Tolerance (with preset values) 2 % of meas. value or 2 % of IN (50/60 Hz)
3 % of meas. value or 3 % of IN (162/3Hz)
Fault Event
Data Log Storage of the messages
of the last 8 faults with a total of max. 200 messages
4.14 Ancillary Functions
2817UT612 Manual
C53000–G1176–C148–1
Fault Recording Number of stored fault records max. 8
Storage period max. 5 s for each fault
(start with pickup or trip) approx. 5 s in total
Sampli ng rat e at fN = 50 Hz 1.67 ms
Sampli ng rat e at fN = 60 Hz 1.83 ms
Sampli ng rat e at fN = 162/3Hz 5 ms
Statistics Number of trip events caused by
7UT612
Total of interrupted currents
caused by 7UT612 segregated for each pole and each side
Operating hours Up to 7 decimal digits
criterion Excess of current threshold
(%UHDNHU6,! or %UHDNHU6,!)
Real Time Clock
and Buffer Battery Resolution for operational messages 1 ms
Resoluti on for fault mes sages 1 ms
Buffer battery 3 V/1 Ah, type CR 1/2 AA
Self-discharging time approx. 10 years
Time
Synchronization Operation modes:
Internal Internal via RTC
IEC 60870–5–103 External via system interface
(IEC 60870–5–103)
Time signal IRIG B External via IRIG B
Time signal DCF77 External, via time signal DCF77
Time signal synchro- box External, via synchro-bo x
Pulse via binary input External with pulse via binary input
User-configurable
Functions (CFC) Processing times for fu nction blocks:
Block, Basic requirements 5 TICKS
Beginning with the 3rd additional input for
generic blocks per input 1 TICK
Logic function with input margin 6 TICKS
Logical function with output margin 7 TICKS
In addition to each chart 1 TICK
Maximu m number of TICKS in sequence levels:
0:B%($5% (processing of meas. values) 1200 TICKS
3/&B%($5% (slow PLC processing) 255 TICKS
3/&B%($5% (fast PLC processing) 90 TICKS
6)6B%($5% (switchgear interlocking) 1000 TICKS
4 Technical Data
282 7UT612 Manual
C53000–G1176–C148–1
4.15 Dimensions
Housing for Panel Flush Mounting or Cubicle Installation
Figure 4- 13 Dimensions 7UT612 for pan el flush mou nting or cubicle i nstallation
244
266
2
29.5 172
34
Mounting plate 150
145
146
+2
255.8
±
0.3
245
+ 1
5 or M4
6
Side Vie w (w ith sc rew e d te rm ina ls) Rear V iew
Panel Cut-Out
244
266
2
29.5 172 34
Mounting plate
29 30
Side View (with plug-in terminals)
105
±
0.5
131.5
±
0.3
13.2
7.3
5.4
Dimensions in mm
A
R
Q
F
C
B
4.15 Dimensions
2837UT612 Manual
C53000–G1176–C148–1
Housing for Panel Surface Mounting
Figure 4-14 Dimensions 7UT612 for panel surface mounting
Thermobox
Figure 4-15 Dimensions Thermobox 7XV5662–∗AD10–0000
n
280
165
144
150
320
344
10.5 260
29.5
71
266
Front View Side View
9
31 45
60
46
115
16 30
Dimensions in mm
90
16.5
25
48
58
45
105
3
98
116
140
61.8
3 Locks (Unlocked)
Side view
Front view
Dimensions in mm
for Wall Mounting
with Screws
Lock Hole 4.2 mm
3 Locks (Locked)
for Snap-on Mounting
on Standard Rail
3
4 Technical Data
284 7UT612 Manual
C53000–G1176–C148–1
2857UT612 Manual
C53000–G1176–C148–1
Appendix A
This appendix is primarily a reference for the experienced user. This Chapter provides
ordering information for the models of 7UT612. General diagrams indicating the termi-
nal connections of the 7UT612 models are included. Connection examples show the
proper connections of the device to primary equipment in typical power system con-
figurations. Tables with all settings and all information available in a 7UT612 equipped
with all options are provided.
A.1 Ordering Information and Accessories 286
A.2 General Diagrams 291
A.3 Connection Examples 293
A.4 Assignment of the Protection Functions to Protected Objects 304
A.5 Preset Configurations 305
A.6 Protocol Dependent Functions 307
A.7 List of Settings 308
A.8 List of Information 323
A.9 List of Measured Values 340
A Appendix
286 7UT612 Manual
C53000–G1176–C148–1
A.1 Ordering Information and Accessories
Rated Current
IN = 1 A 1
IN = 5 A 5
A
uxiliary Voltage (Power S upply, Pick-up Threshold of Binary Inputs)
DC 24 V to 48 V, binary input threshold 17 V 2)2
DC 60 V to 125 V 1), binary input threshold 17 V 2)4
DC 110 V to 250 V 1), AC 115 to 230 V, binary input threshold 73 V 2)5
Housing / Number of In- and Outputs
BI: Binary Inputs, BO: Binary Outputs
Surface mounting housing with two-tier terminals, 1/3 × 19", 3 BI, 4 BO, 1 life contact B
Flush mounting housing with plug-in terminals, 1/3 × 19", 3 BI, 4 BO, 1 life contact D
Flush mounting housing with screwed terminals, 1/3 × 19", 3 BI, 4 BO, 1 life c ontact E
Regio n-Specific Default / Languag e Settings and Function Versions
Region GE, 50/60 Hz, 16 2/3 Hz, language German (language can be changed) A
Region world, 50/60 Hz, 16 2/3 Hz, language English, (language can be changed) B
Region US, 60/50 Hz, language US-E nglish (language can be changed) C
Region world, 50/60 Hz, 16 2/3 Hz, language Spanish (language can be changed) E
System Interface: Functionality and Hardware (Por t B)
No system interface 0
IEC Protocol, electrical RS232 1
IEC Protocol, electrical RS485 2
IEC Protocol, optical 820 nm , ST-plug 3
Profibus FMS Slave, electrical RS485 4
Profibus FMS Slave, optical, single-ring, ST-connector 5
Profibus FMS Slave, optical, double-ring, ST-connector 6
For further interfaces see additional specification L 9
A
dditional Specification L
Profibus DP Slave, RS485 A
Profibus DP Slave, optical 820 nm, double-ring, ST-connector B
Modbus, RS485 D
Modbus, optical 820 nm, ST-connector E
DNP, RS485 G
DNP, optical 820 nm, ST–connector H
DIGSI / Modem Interface / Thermobox (Port C)
No DIGSI interface on the rear side 0
DIGSI / Modem, electrical RS232 1
DIGSI / M odem / Thermob ox, electrical RS485 2
DIGSI / M odem / Thermobox, optical 820 nm, ST-connector 3
1) with plug-in jumper one of 2 voltage ranges can be selected
2
) for each binary input one of 2 pickup threshold ranges can be selected with plug-in ju mpers
see page A-3
_
7UT612 7 8 13 1514
_
9101112
Differential Protection
L+
0
0
A16
A.1 Ordering Information and Accessories
2877UT612 Manual
C53000–G1176–C148–1
Functionality
Measured Values
Basic measured values 1
Basic measured values, transformer monitoring functions
(
connection to thermobox / hot spot, overload factor) 4
Differential Protection + Basic Functions A
Differential protection for transformer, generator, motor, busbar (87)
O
verload protection according to IEC for 1 winding (49)
Lock out (86)
T
ime overcurrent protection phases (50/51): I>, I>>, Ip (inrush stabilization)
T
ime overcurrent protection 3I0 (50N/51N): 3I0>, 3I0>>, 3I0p (inrush stabilization)
T
ime overcurrent protection earth (50G/51G): IE>, IE>>, IEp (inrush stabilization)
Differential Protection + Basic Functions + Additional Functions B
Restricted earth fault protection, low impedance (87G)
Restricted earth fault protection, high impedance (87G without resistor and varistor), O/C 1-phase
T
rip circuit supervision (74TC)
Unbalanced load protection (46)
Breaker failure protection (50BF)
High-sensitivity time overcurrent protection / tank leakage protection (64), O/C 1-phase
O
rdering example: 7UT6121–4EA91–1AA0 +L0A
Differential protection
here: pos. 11 = 9 pointing at L0A, i.e. version with Profibus-interface DP Slave, RS485
_
7UT612 7 8 13 1514
_
9101112
Differential Protection 0A16
A Appendix
288 7UT612 Manual
C53000–G1176–C148–1
A.1.1 Accessories
Thermobox For up to 6 temperature measuring points (at most 2 devices can be connected to
7UT612)
Matching /
Summation
Transformer
For single-phase busbar connection
Interface
Modules Exchange interface modules
Terminal Block
Covering Caps
Short-Circuit Links
Name Order No.
Thermobox, UN = 24 to 60 V AC/DC 7XV5662–2AD10
Thermobox, UN = 90 to 240 V AC/DC 7XV5662–5AD10
Name Order No.
Matching / summation transformer IN = 1 A 4AM5120–3DA00–0AN2
Matching / summation transformer IN = 5 A 4AM5120–4DA00–0AN2
Name Order No.
RS232 C53207–A351–D641–1
RS485 C53207–A351–D642–1
Optical 820 nm C53207–A351–D643–1
Profibus FM S RS485 C53207–A351–D603–1
Profibus FM S double ring C53207–A351–D606–1
Profibus FM S single ring C53207–A351–D609–1
Profibus DP RS485 C53207–A351–D611–1
Profibus DP double ring C53207–A351–D613–1
Modbus R S485 C53207– A35 1–D 6 21– 1
Modbus 820 nm C53207– A35 1–D 6 23– 1
DNP 3.0 RS485 C53207–A351–D631–1
DNP 3.0 820 nm C53207–A351–D633–1
Covering cap for terminal block type Order No.
18 terminal voltage block, 12 terminal current block C73334-A1–C31–1
12 terminal voltage block, 8 terminal current block C73334-A1–C32–1
Short-circuit links for purpose / terminal type Order No.
Voltage bloc k, 18 term ina l, 12 term ina l C73334-A 1–C34 –1
Current block,12 terminal, 8 terminal C73334-A1–C33–1
A.1 Ordering Information and Accessories
2897UT612 Manual
C53000–G1176–C148–1
Plug-in Socket
Boxes
Mounting Bracket
for 19"-Ra cks
Battery
Interface Cable An interface cable is necessary for the communication between the SIPROTEC
device and a computer. Requirements for the computer are Windows 95 or Windows
NT4 and the operating software DIGSI®4.
Operating Software
DIGSI®4 Software for setting and operating SIPROTEC®4 devices
Graphical Analysis
Program SIGRA Software for graphical visualization, analysis, and evaluation of fault data. Option
package of the complete version of DIGSI®4
Graphic Tools Software for graphically supported configuration of characteristic curves and provide
zone diagrams for overcurrent and distance protection devices.
(Option package for the complete version of DIGSI®4)
DIGSI REMOTE 4 Software for remotely operating protection devices via a modem (and possibly a star
connector) using DIGSI®4. (Option package for the complete version of DIGSI®4).
For Connector Type Order No.
2 pin C73334–A1–C35–1
3 pin C73334–A1–C36–1
Name Order No.
Angle strip (mounting rail) C73165-A63-C200-3
Li thium battery 3 V/1 Ah, Type CR 1/2 AA Order No.
VARTA 6127 101 501
Interface cable between PC or SIPROTEC device Order No.
Cable with 9-pin male / female connections 7XV5100–4
Operating Software DIGSI ®4 Order No.
DIGSI®4, basic version with license for 10 computers 7XS5400–0AA00
DIGSI®4, complete version with all option packages 7XS5402–0AA0
Graphical analysis program DIGRA® Order No.
Full version with license for 10 machines 7XS5410–0AA0
Graphic Tools 4 Order No.
Full version with license for 10 machines 7XS5430–0AA0
DIGSI REMOTE 4 Order No.
Full version with license for 10 machines 7XS5440–1AA0
A Appendix
290 7UT612 Manual
C53000–G1176–C148–1
SIMATIC CFC 4 Software for graphical configuration of interlocking (latching) conditions and creating
additional functions in SIPROTEC® 4 devices. (Option package for the complete
version of DIGSI®4).
Varistor Voltage arrester for high-impedance protection
SIMATIC CFC 4 Order No.
Full version with license for 10 machines 7XS5450–0AA0
Varistor Order No.
125 Vrms; 600 A; 1S/S256 C53207–A401–D76–1
240 Vrms; 600 A; 1S/S1088 C53207–A401–D77–1
A.2 General Diagrams
2917UT612 Manual
C53000–G1176–C148–1
A.2 General Diagrams
A.2.1 Panel Flush Mounting or Cubicle Mounting
7UT612∗–∗D/E
Figure A-1 General Diagram 7UT612*-*D/E (panel flush mounted or cubicle mounted)
Assignment of Pins of In-
terfaces see Table 3-8 and
3-9 in Subsection 3.1.3
Power
System interface B
A
Earthing on
supply
the rear wall
Operating interface
F1
F2
( )
~
+
-
Time synchronization
F14
F15 BI1
F16 BI2
Service interface/ C
F17
F18 BI3
F10
F11
BO3
F12
F13
BO4
F4
F5
F3
Life-
contact
Thermobox
Q1
Q2 IL1S1/I1
Q3
Q4 IL2S1/I2
Q5
Q6 IL3S1/I3
Q7
Q8 I7
R1
R2 IL1S2/I4
R3
R4 IL2S2/I5
R5
R6 IL3S2/I6
R7
R8 I8
F6
F7
12
32
BO1
F8
F9
12
32
BO2
Interference suppression
capacitors at the
Ceramic, 4.7 nF, 250 V
rel ay contacts,
A Appendix
292 7UT612 Manual
C53000–G1176–C148–1
A.2.2 Panel Surface Mounting
7UT612∗–∗B
Figure A-2 General diagram 7UT612∗–∗B (panel surface mounting)
Earthing
terminal (16)
2
17
3
19
18
4
1
Time synchronization
IN 12 V
IN SYN C
COM SYNC
COMMON
IN 24 V
Screen
IN 5 V
Power
System interface B
Earthing on
supply
the side wall
Operating interface
10
11
( )
~+
-
48
32 BI1
47 BI2
31
46 BI3
35
50
BO3
34
49
BO4
51
52
Life
contact
Service interface/ C
Thermobox
15
30 IL1S1/I1
14
29 IL2S1/I2
13
28 IL3S1/I3
12
27 I7
9
24 IL1S2/I4
8
23 IL2S2/I5
7
22 IL3S2/I6
6
21 I8
39
54
12
32
BO1
36
38
53
12
32
BO2
Interference suppression
capacitors at the
Ceramic, 4.7 nF, 250 V
relay contacts,
Assignment of Pins of In-
terfaces seeTable 3-8 in
Subsection 3.1.3
A.3 Connection Examples
2937UT612 Manual
C53000–G1176–C148–1
A.3 Connection Examples
Figure A-3 Connecti on example 7UT612 for a three-phase power transformer without
(above) and with (below) earthed starpoint
L1
L2
L3
L1
L2
L3
Panel surface mounted
Flush mounte d/cu bicl e
IL1S1
Q1
Q2
15
30
7UT612
Q3
Q4
14
29
Q5
Q6
13
28
IL3S1
IL2S1
IL1S2
R1
R2
9
24
R3
R4
8
23
R5
R6
7
22 IL3S2
IL2S2
Side 2 Side 1
P1P2
S1S2
L1
L2
L3
L1
L2
L3
Panel surface mounted
Flush mounte d/cu bicl e
IL1S1
Q1
Q2
15
30
7UT612
Q3
Q4
14
29
Q5
Q6
13
28
IL3S1
IL2S1
IL1S2
R1
R2
9
24
R3
R4
8
23
R5
R6
7
22 IL3S2
IL2S2
Side 2 Side 1
P1 P2
S1 S2
P1P2
S1S2
P1 P2
S1 S2
A Appendix
294 7UT612 Manual
C53000–G1176–C148–1
Figure A-4 Connection example 7UT612 for a three-phase power transformer with current
transformer between starpoint and earthing point
L1
L2
L3
L1
L2
L3
Panel surface mounted
Flush mounted/
IL1S1
Q1
Q2
15
30
7UT612
Q3
Q4
14
29
Q5
Q6
13
28
IL3S1
IL2S1
IL1S2
R1
R2
9
24
R3
R4
8
23
R5
R6
7
22 IL3S2
IL2S2
I7
Q8
27
Q7
12
Side 2 Side 1
P1
P2
S1
S2
cubicle
P1P2
S1S2
P1 P2
S1 S2
A.3 Connection Examples
2957UT612 Manual
C53000–G1176–C148–1
Figure A-5 Connecti on example 7UT612 for a three-phase power transformer with neutral
earthing reactor and current transformer between starpoint and earthing point
L1
L2
L3
L1
L2
L3
Panel surface mounting
Flush mounted/
IL1S1
Q1
Q2
15
30
7UT612
Q3
Q4
14
29
Q5
Q6
13
28
IL3S1
IL2S1
IL1S2
R1
R2
9
24
R3
R4
8
23
R5
R6
7
22 IL3S2
IL2S2
Q8
27
Q7
12
I7
Side 2 Side 1
P2
S2
P1
S1
cubicle
P1P2
S1S2
P1 P2
S1 S2
A Appendix
296 7UT612 Manual
C53000–G1176–C148–1
Figure A-6 Connection example 7UT612 for a three-phase auto-transformer with current
transformer between starpoint and earthing point
Figure A-7 Connection example 7UT612 for a single-phase power transformer with current
transformer between starpoint and earthing point
L
1
L
2
L
3
L
1
L
2
L
3
I
7
Panel surface mounted
Flush mounted/
I
L1S1
Q1
Q2
15
30
7UT612
Q3
Q4
14
29
Q5
Q6
13
28
I
L3S1
I
L2S1
I
L1S2
R1
R2
9
24
R3
R4
8
23
R5
R6
7
22 I
L3S2
I
L2S2
Q8
27
Q7
12
Sid
e
2
Side 1
cubicle
P1P2
S1S2
P1 P2
S1 S2
P1
P2
S1
S2
L
1
L
3
L
1
L
3
Panel surface mounted
Flush m oun ted /
I
L1S1
Q1
Q2
15
30
7UT612
Q3
Q4
14
29
Q5
Q6
13
28
I
L3S1
I
L2S1
I
L1S2
R1
R2
9
24
R3
R4
8
23
R5
R6
7
22 I
L3S2
I
L2S2
Q8
27
Q7
12
I
7
Side 2 Side 1
cubicle
P1P2
S1S2 P1
P2
S1
S2
P1 P2
S1 S2
A.3 Connection Examples
2977UT612 Manual
C53000–G1176–C148–1
Figure A-8 Connecti on example 7UT612 for a single-phase power transformer with on ly
one current transformer (right side)
Figure A-9 Connecti on example 7UT612 for a generator or motor
L1
L3
L1
L3
Panel surface mounted
Flush mounted/cubicle
IL1S1
Q1
Q2
15
30
7UT612
Q3
Q4
14
29
Q5
Q6
13
28
IL3S1
IL2S1
IL1S2
R1
R2
9
24
R3
R4
8
23
R5
R6
7
22 IL3S2
IL2S2
Side 2 Side 1
P1P2
S1S2
P1 P2
S1 S2
L1
L2
L3
Panel surface mounted
Flush mounted/cubicle
IL1S1
Q1
Q2
15
30
7UT612
Q3
Q4
14
29
Q5
Q6
13
28
IL3S1
IL2S1
IL1S2
R1
R2
9
24
R3
R4
8
23
R5
R6
7
22 IL3S2
IL2S2
Side 2 Side 1
P1P2
S1S2
P1 P2
S1 S2
A Appendix
298 7UT612 Manual
C53000–G1176–C148–1
Figure A-10 Connection example 7UT612 as transversal differential protection for a generator with two windings per
phase
L1
L2
L3
„Side 2“ „Side 1“
Panel surface mounted
Flush mounted/cubicle
IL1S1
Q1
Q2
15
30
7UT612
Q3
Q4
14
29
Q5
Q6
13
28
IL3S1
IL2S1
IL1S2
R1
R2
9
24
R3
R4
8
23
R5
R6
7
22 IL3S2
IL2S2
P1P2
S1S2
P1P2
S1S2
A.3 Connection Examples
2997UT612 Manual
C53000–G1176–C148–1
Figure A-11 C onnection example 7UT612 for an earthed shunt reactor with current trans-
former between starpoint and earthing point
L1
L2
L3
L1
L2
L3
I7
Panel surface mounted
Flush mounted/
IL1S1
Q1
Q2
15
30
7UT612
Q3
Q4
14
29
Q5
Q6
13
28
IL3S1
IL2S1
IL1S2
R1
R2
9
24
R3
R4
8
23
R5
R6
7
22 IL3S2
IL2S2
Q8
27
Q7
12
Side 1Side 2
cubicle
P1P2
S1S2
P1 P2
S1 S2
P1
P2
S1
S2
A Appendix
300 7UT612 Manual
C53000–G1176–C148–1
Figure A-12 Connection example 7UT612 as high-impedance protection on a transformer
winding with earthed starpoint (the illustration shows the partial connection of
the high-impedance protection)
L1
L2
L3
I8
Panel surface mounted
Flush mounted/
IL1S1
Q1
Q2
15
30
7UT612
Q3
Q4
14
29
Q5
Q6
13
28
IL3S1
IL2S1
IL1S2
R1
R2
9
24
R3
R4
8
23
R5
R6
7
22 IL3S2
IL2S2
Q8
27
Q7
12
V R
cubicle
P1 P2
S1 S2
P1
P2
S1
S2
A.3 Connection Examples
3017UT612 Manual
C53000–G1176–C148–1
Figure A-13 Connection example 7UT612 for a three-phase power transformer with current transformers between
starpoint and earthing point, additional connection for high-impedance protection
L1
L2
L3
L1
L2
L3
Panel surface mounted
IL1S1
Q1
Q2
15
30
7UT612
Q3
Q4
14
29
Q5
Q6
13
28
IL3S1
IL2S1
IL1S2
R1
R2
9
24
R3
R4
8
23
R5
R6
7
22 IL3S2
IL2S2
I7
Q8
27
Q7
12
Side 2 Side 1
R8
21
R7
6
I8
V
R
Flush mounted/
cubicle
P1P2
S1S2
P1 P2
S1 S2
P1
P2
S1
S2
P1
P2
S1
S2
P1 P2
S1 S2
A Appendix
302 7UT612 Manual
C53000–G1176–C148–1
Figure A-14 Connection example 7UT612 as single-phase busbar protection, illustrated for phase L1
L1
L2
L3
Feeder 1 Feeder 7Feeder 3
Panel surface mounted
Flush mounted/cubicle
I1
Q1
Q2
15
30
7UT612
Q3
Q4
14
29
Q5
Q6
13
28 I3
I2
I4
R1
R2
9
24
R3
R4
8
23
R5
R6
7
22
I5
Feeder 2 Feeder 4 Feeder 5 Feeder 6
I6
I7
Q7
Q8
12
27
P1
P2
S1
S2
P1
P2
S1
S2
P1
P2
S1
S2
P1
P2
S1
S2
P1
P2
S1
S2
P1
P2
S1
S2
P1
P2
S1
S2
A.3 Connection Examples
3037UT612 Manual
C53000–G1176–C148–1
Figure A-15 Connection e xampl e 7UT612 as busb ar protec tion, c onnec ted via externa l summ ation current tr ans formers
(SCT) — partial illustration for feeders 1, 2 and 7
L1
L2
L3
Feeder 1 Feeder 7
L1L2L3E
Feeder 2
L1L2L3E L1L2L3E
SCT
Panel surface mount ed
Flush mou nte d/cu bicle
I1
Q1
Q2
15
30
7UT612
Q3
Q4
14
29
Q5
Q6
13
28 I3
I2
I4
R1
R2
9
24
R3
R4
8
23
R5
R6
7
22
I5
I6
I7
Q7
Q8
12
27
SCT SCT
P1
P2
S1
S2
P1
P2
S1
S2
P1
P2
S1
S2
A Appendix
304 7UT612 Manual
C53000–G1176–C148–1
A.4 A ssignm ent of the Protection Functions to Protected Objects
Not every implemented protection function of 7UT612 is sensible or available for each
protected object. Table A-1 lists the corresponding protection functions for each pro-
tected object. Once a protected object is configured (according to Section 2.1.1), only
the corresponding protective functions specified in the table below will be available
and settable.
Table A-1 Overview of protection functions available in protected objects
Protection Function Two-Winding
Transformer 1-Phase
Transformer Auto-
Transformer Generator /
Motor Busbar
3-phase Busbar
1-phase
Differential protection X X X X X X
Restric ted eart h fault
protection X—XX— —
Time overcurrent
protection phases XXXXX —
Time overcurrent
protection 3I0X—XXX —
Time overcurrent
protection earth XXXXX X
Time overcurrent
protection 1-phase XXXXX X
Unbalanced load
protection X—XXX —
Overload protection
IEC 60255–8 XXXXX —
Overload protection
IEC 60354 XXXXX —
Circuit breaker failure
protection XXXXX —
Measured value
monitoring XXXXX —
Trip circui t supervision X X X X X X
External trip
command 1 XXXXX X
External trip
command 2 XXXXX X
Measured values X X X X X X
Legend: X Function available — Function not available
A.5 Preset Configurations
3057UT612 Manual
C53000–G1176–C148–1
A.5 Preset Configuratio ns
Binary Inputs
Binary Outputs
(Output Relays)
LED Indicators
Table A-2 Preset binary inputs
Binary Input LCD Text FNo Remarks
BI1 >Reset LED 00005 Reset of latched indications,
H–active
BI2 >Buchh. Trip 00392 Buchholz protection trip,
H–active
BI3 — — No presetting
Table A-3 Preset binary outputs
Binary
Output LCD Text FNo Remarks
BO1 Relay TRIP 00511 Device (general) trip command,
non-latched
BO2 Relay PICKUP 00501 Device (general) pickup,
non-latched
BO3 >Buchh. Trip 00392 Buchholz protection trip,
non-latched
BO4 Error Sum Alarm
Alarm Sum Event 00140
00160 Group alarm of errors and disturbances,
non-latched
Table A-4 Preset LED indicators
LED LCD Text FNo Remarks
LED1 Relay TRIP 00511 Device (general) trip command,
latched
LED2 Relay PICKUP 00501 Device (general) pick up,
latched
LED3 >Buchh. Trip 00392 Buchholz protection trip,
latched
LED4 — — no presetting
LED5 — — no presetting
LED6 Error Sum Alarm
Alarm Sum Event 00140
00160 Group alarm of errors and disturbances,
non-latched
LED7 Fault Configur. 00311 Errors during configuration or setting
(inconsistent settings), non-latched
A Appendix
306 7UT612 Manual
C53000–G1176–C148–1
Preset CFC–Charts 7UT612 provides worksheets with preset CFC-charts. Figure A-16 shows a chart
which changes binary input “!'DWD6WRS” from single point indication (SP) to internal
single point indication (IntSP). According to Figure A-17 an reclosure interlocking will
be produced. It interlocks the closure of the circuit breaker after tripping of the device
until manual acknowledgement.
Figure A-16 CFC-chart for transmission block and testing mode
Figure A-17 C FC chart for reclosure lockout
"OUT:
'HYLFH8QORFN'7,QW63
"
"IN:
'HYLFH!'DWD6WRS63
"
1(*
1HJDWRU
1HJDWRU
3/&B%($
²
%2; <%2
"OUT:
*7534XLW,Q
"
"IN:
5HOD\75,363
"
25
25²*DWH
25
3/&B%($
²
%2; <%2
%22/B72B,&
%RROWR,QWH
&20
3/&B%($
²
:25,*,1 ,(%2
%22/B72B
',B
%22/B72B
',
3/&B%($
²
,QWHU3RV <
%2;
6HO,QW
9$/
,7,0[P
:3523
%275,*
:9$/
0
0
0
0
0
"IN:
!4XLW*75363
"
additionally assigned
to the trip relays!
A.6 Protocol Dependent Functions
3077UT612 Manual
C53000–G1176–C148–1
A.6 Protocol Dependent Functions
Protocol →IEC 60870–5–103 Profibus FMS Profibus DP DNP3.0 Modbus ASCII/RTU Additional
Service Interf ace
(optional)
Function ⇓
Operational Measured
Values Yes Yes Yes Yes Yes Yes
Metered Values Yes Yes Yes Yes Yes Yes
Fault Recording Yes Yes No Only via additional
service interface No Only via additional
service interface No Only via additional
service interfa ce Yes
Protection Setting from
Remote No Only via additional
service interface Yes No Only via additional
service interface No Only via additional
service interface No Only via additional
service interfa ce Yes
User-specified
annunciations and
switching objects
Yes Yes “User-defined
annunciations” in CFC
(pre-defined)
“User-defined
annunciations” in CFC
(pre-defined)
“User-defined
annunciations” in CFC
(pre-defined)
Yes
Time Synchronization Via protocol;
DCF77/IRIG B;
Interface;
Binary inputs
Via protocol;
DCF77/IRIG B;
Interface;
Binary inputs
Via DCF77/IRIG B;
Interface;
Binary inputs
Via protocol;
DCF77/IRIG B;
Interface;
Binary inputs
Via DCF77/IRIG B;
Interface;
Binary inputs
–
Annunciations with
Time stamp Yes Yes No Yes No Yes
Commissioning Aids
•Alarm and Measured
Value Transmission
Blocking
Yes Yes No No No Yes
•Generate Test
Annunciations Yes Yes No No No Yes
Physical Mode Asynchronous Asynchronous Asynchronous Asynchronous Asynchronous –
Transmission Mode cyclical / event cyclical / event cyclical cyclical / event cyclical –
Baudrate 4800 to 38400 Up to 1.5 MBaud Up to 1.5 MBaud 2400 to 19200 2400 to 19200 2400 to 38400
Type RS232
RS485
Optical fibre
RS485
Optical fibre
•Single ring
•Double ring
RS485
Optical fibre
•Double ring
RS485
Optical fibre RS485
Optical fibre RS232
RS485
Optical fibre
Temperature
Measuring Device
7XV565
Yes
.
.
.
A Appendix
308 7UT612 Manual
C53000–G1176–C148–1
A.7 List of Settings
Notes:
Depending on the version and the variant ordered some addresses may be missing or have different default
settings.
The setting ranges and presettings listed in the following table refer to a nominal current value IN = 1 A. For a
secondary nominal current value IN = 5 A the current values are to be multiplied by 5. For setting primary values
the transformation ratio of the transformer also must be taken into consideration.
Addresses which have an “A” attached to its end can only be changed in DIGSI®4, under “Additional Set-
tings”.
Addr. Se tting Title Setting Options Default Setting Comments
103 Grp Chge OPTION Disabled
Enabled Disabled Setting Group Change Option
103 Grp Chge OPTION Disabled
Enabled Disabled Setting Group Change Option
105 PROT. OBJECT 3 phase Transformer
1 phase Transformer
Autotransformer
Generator/Motor
3 phase Busbar
1 phase Busbar
3 phase Transformer Protection Object
105 PROT. OBJECT 3 phase Transformer
1 phase Transformer
Autotransformer
Generator/Motor
3 phase Busbar
1 phase Busbar
3 phase Transformer Protection Object
106 NUMBER OF SIDES 2 2 Number of Sides for Multi Phase Object
106 NUMBER OF SIDES 2 2 Number of Sides for Multi Phase Object
107 NUMBER OF ENDS 3
4
5
6
7
7 Number of Ends for 1 Phase Busbar
107 NUMBER OF ENDS 3
4
5
6
7
7 Number of Ends for 1 Phase Busbar
108 I7-CT CONNECT. not used
Side 1
Side 2
not used I7-CT connected to
108 I7-CT CONNECT. not used
Side 1
Side 2
not used I7-CT connected to
112 DIFF. PROT. Disabled
Enabled Enabled Differential Protection
112 DIFF. PROT. Disabled
Enabled Enabled Differential Protection
113 REF PROT. Disabled
Side 1
Side 2
Disabled Restricted earth fault protection
A.7 List of Settings
3097UT612 Manual
C53000–G1176–C148–1
113 REF PROT. Disabled
Side 1
Side 2
Disabled Restricted earth fault protection
117 Coldload Pickup Disabled
Enabled Disabled Cold Load Pickup
117 Coldload Pickup Disabled
Enabled Disabled Cold Load Pickup
120 DMT/IDMT Phase Disabled
Side 1
Side 2
Disabled DMT / IDMT Phase
120 DMT/IDMT Phase Disabled
Side 1
Side 2
Disabled DMT / IDMT Phase
121 DMT/IDMT PH. CH Definite Time only
Time Overcurrent Curve IEC
Time Overcurrent Curve ANSI
User Defined Pickup Curve
User Defined Pickup and Reset Curve
Definite Time only DMT / IDMT Phase Pick Up Characteristic
121 DMT/IDMT PH. CH Definite Time only
Time Overcurrent Curve IEC
Time Overcurrent Curve ANSI
User Defined Pickup Curve
User Defined Pickup and Reset Curve
Definite Time only DMT / IDMT Phase Pick Up Characteristic
122 DMT/IDMT 3I0 Disabled
Side 1
Side 2
Disabled DMT / IDMT 3I0
122 DMT/IDMT 3I0 Disabled
Side 1
Side 2
Disabled DMT / IDMT 3I0
123 DMT/IDMT 3I0 CH Definite Time only
Time Overcurrent Curve IEC
Time Overcurrent Curve ANSI
User Defined Pickup Curve
User Defined Pickup and Reset Curve
Definite Time only DMT / IDMT 3I0 Pick Up Characteristic
123 DMT/IDMT 3I0 CH Definite Time only
Time Overcurrent Curve IEC
Time Overcurrent Curve ANSI
User Defined Pickup Curve
User Defined Pickup and Reset Curve
Definite Time only DMT / IDMT 3I0 Pick Up Characteristic
124 DMT/IDMT Earth Disabled
unsensitive Current Transformer I7 Disabled DMT / IDMT Earth
124 DMT/IDMT Earth Disabled
unsensitive Current Transformer I7 Disabled DMT / IDMT Earth
125 DMT/IDMT E CHR. Definite Time only
Time Overcurrent Curve IEC
Time Overcurrent Curve ANSI
User Defined Pickup Curve
User Defined Pickup and Reset Curve
Definite Time only DMT / IDMT Earth Pick Up Characteristic
125 DMT/IDMT E CHR. Definite Time only
Time Overcurrent Curve IEC
Time Overcurrent Curve ANSI
User Defined Pickup Curve
User Defined Pickup and Reset Curve
Definite Time only DMT / IDMT Earth Pick Up Characteristic
127 DMT 1PHASE Disabled
unsensitive Current Transformer I7
sensitive Current Transf ormer I8
Disabled DMT 1Phase
127 DMT 1PHASE Disabled
unsensitive Current Transformer I7
sensitive Current Transf ormer I8
Disabled DMT 1Phase
Addr. Setting Title Setting Options Default Setting Comments
A Appendix
310 7UT612 Manual
C53000–G1176–C148–1
140 UNBAL ANC E LOAD D isab l ed
Side 1
Side 2
Disabled Unbalance Load (Negative Sequence)
140 UNBAL ANC E LOAD D isab l ed
Side 1
Side 2
Disabled Unbalance Load (Negative Sequence)
141 UNBAL. LOAD CHR Definite Time only
Time Overcurrent Curve IEC
Time Overcurrent Curve ANSI
Definite Time only Unbalance Load (Neg. Sequ.) Characteris.
141 UNBAL. LOAD CHR Definite Time only
Time Overcurrent Curve IEC
Time Overcurrent Curve ANSI
Definite Time only Unbalance Load (Neg. Sequ.) Characteris.
142 Therm.Overload Disabled
Side 1
Side 2
Disabled Thermal Overload Protection
142 Therm.Overload Disabled
Side 1
Side 2
Disabled Thermal Overload Protection
143 Therm.O/L CHR. classical (according IEC60255)
accord ing IEC 35 4 classical (according IEC60255) Thermal Overload Protec. Characteristic
143 Therm.O/L CHR. classical (according IEC60255)
accord ing IEC 35 4 classical (according IEC60255) Thermal Overload Protec. Characteristic
170 BREAKER FAILURE Disabled
Side 1
Side 2
Disabled Breaker Failure Protection
170 BREAKER FAILURE Disabled
Side 1
Side 2
Disabled Breaker Failure Protection
181 M.V. SUPERV Disabled
Enabled Enabled Measured Value s Supervision
181 M.V. SUPERV Disabled
Enabled Enabled Measured Value s Supervision
182 Trip Cir. Sup. Disabled
with 2 Binary Inputs
with 1 Binary Input
Disabled Trip Circuit Supervision
182 Trip Cir. Sup. Disabled
with 2 Binary Inputs
with 1 Binary Input
Disabled Trip Circuit Supervision
186 EXT. TRIP 1 Disabled
Enabled Disabl ed External Trip Function 1
186 EXT. TRIP 1 Disabled
Enabled Disabl ed External Trip Function 1
187 EXT. TRIP 2 Disabled
Enabled Disabl ed External Trip Function 2
187 EXT. TRIP 2 Disabled
Enabled Disabl ed External Trip Function 2
190 RTD-BOX INPUT Disabled
Port C Disabled External Temperature Input
190 RTD-BOX INPUT Disabled
Port C Disabled External Temperature Input
191 RTD CONNECTION 6 RTD simplex operation
6 RTD half duplex oper atio n
12 RTD half duplex operation
6 RTD simplex operation Ext. Temperature Input Connection Type
191 RTD CONNECTION 6 RTD simplex operation
6 RTD half duplex oper atio n
12 RTD half duplex operation
6 RTD simplex operation Ext. Temperature Input Connection Type
Addr. Se tting Title Setting Options Default Setting Comments
A.7 List of Settings
3117UT612 Manual
C53000–G1176–C148–1
Addr
.Setting Title Function Setting Options Default Setting Comments
201 STRPNT->OBJ S1 Power System Data 1 YES
NO YES CT-Strpnt. Side1 in Direct. of Object
202 IN-PRI CT S1 Power System Data 1 1..100000 A 200 A CT Rated Primary Current Side 1
203 IN-SEC CT S1 Power System Data 1 1A
5A 1A CT Rated Secondary Current Side 1
206 STRPNT->OBJ S2 Power System Data 1 YES
NO YES CT-Strpnt. Side2 in Direct. of Object
207 IN-PRI CT S2 Power System Data 1 1..100000 A 2000 A CT Rated Primary Current Side 2
208 IN-SEC CT S2 Power System Data 1 1A
5A 1A CT Rated Secondary Current Side 2
211 STRPNT->BUS I1 Power System Data 1 YES
NO YES CT-Starpoint I1 in Direction of Busbar
212 IN-PRI CT I1 Power System Data 1 1..100000 A 200 A CT Rated Primary Current I1
213 IN-SEC CT I1 Power System Data 1 1A
5A
0.1A
1A CT Rated Secondary Current I1
214 STRPNT->BUS I2 Power System Data 1 YES
NO YES CT-Starpoint I2 in Direction of Busbar
215 IN-PRI CT I2 Power System Data 1 1..100000 A 200 A CT Rated Primary Current I2
216 IN-SEC CT I2 Power System Data 1 1A
5A
0.1A
1A CT Rated Secondary Current I2
217 STRPNT->BUS I3 Power System Data 1 YES
NO YES CT-Starpoint I3 in Direction of Busbar
218 IN-PRI CT I3 Power System Data 1 1..100000 A 200 A CT Rated Primary Current I3
219 IN-SEC CT I3 Power System Data 1 1A
5A
0.1A
1A CT Rated Secondary Current I3
221 STRPNT->BUS I4 Power System Data 1 YES
NO YES CT-Starpoint I4 in Direction of Busbar
222 IN-PRI CT I4 Power System Data 1 1..100000 A 200 A CT Rated Primary Current I4
223 IN-SEC CT I4 Power System Data 1 1A
5A
0.1A
1A CT Rated Secondary Current I4
224 STRPNT->BUS I5 Power System Data 1 YES
NO YES CT-Starpoint I5 in Direction of Busbar
225 IN-PRI CT I5 Power System Data 1 1..100000 A 200 A CT Rated Primary Current I5
226 IN-SEC CT I5 Power System Data 1 1A
5A
0.1A
1A CT Rated Secondary Current I5
227 STRPNT->BUS I6 Power System Data 1 YES
NO YES CT-Starpoint I6 in Direction of Busbar
228 IN-PRI CT I6 Power System Data 1 1..100000 A 200 A CT Rated Primary Current I6
229 IN-SEC CT I6 Power System Data 1 1A
5A
0.1A
1A CT Rated Secondary Current I6
230 EARTH. ELECTROD Power System Data 1 Terminal Q7
Terminal Q8 Terminal Q7 Earthing Electrod versus
A Appendix
312 7UT612 Manual
C53000–G1176–C148–1
231 STRPNT->BUS I7 Power S ystem Data 1 YES
NO YES CT-Starpoint I7 in Direction of Busbar
232 IN-PRI CT I7 Power System Data 1 1..100000 A 200 A CT Rated Primary Current I7
233 IN-SEC CT I7 Power System Data 1 1A
5A
0.1A
1A CT Rated Secondary Current I7
235 Factor I8 Power System Data 1 1.0..300.0 60.0 Factor: Prim. Current over Sek. Curr.
I8
240 UN-PRI SIDE 1 Power System Data 1 0.4..800.0 kV 110.0 kV Rated Primary Voltage Side 1
241 STARPNT SIDE 1 Power System Data 1 Solid Earthed
Isolated Solid Earthed Starpoint of Side 1 is
242 CONNECTION S1 Power System Data 1 Y (Wye)
D (Delta)
Z (Zig-Zag)
Y (Wye) Transf. Winding Connection Side 1
243 UN-PRI SIDE 2 Power System Data 1 0.4..800.0 kV 11.0 kV Rated Primary Voltage side 2
244 STARPNT SIDE 2 Power System Data 1 Solid Earthed
Isolated Solid Earthed Starpoint of side 2 is
245 CONNECTION S2 Power System Data 1 Y (Wye)
D (Delta)
Z (Zig-Zag)
Y (Wye) Transf. Winding Connection Side 2
246 VECTOR GRP S2 Power System Data 1 0..11 0 Vector Group Numeral of Side 2
249 SN TRANSFORMER Power System Data 1 0.20..5000.00 MVA 38.10 MVA Rated Apparent Power of the Trans-
former
251 UN GEN/MOTOR Power System Data 1 0.4..800.0 kV 21.0 kV Rated Primary Voltage Generator/
Motor
252 SN GEN/MOTOR Power System Data 1 0.20..5000.00 MVA 70.00 MVA Rated Apparent Power of the Genera-
tor
261 UN BUSBAR Power System Data 1 0.4..800.0 kV 110.0 kV Rated Primary Voltage Busbar
265 I PRIMARY OP. Power System Data 1 1..100000 A 200 A Primary Operating Current
266 PHASE SELECTION Power System Data 1 Phase 1
Phase 2
Phase 3
Phase 1 Phase sele ction
270 Rated Frequency Power System Data 1 50 Hz
60 Hz
16 2/3 Hz
50 Hz Rated Frequency
271 PHASE SEQ. Power System Data 1 L1 L2 L3
L1 L3 L2 L1 L2 L3 Phase Se quence
276 TEMP. UNIT Power System Data 1 Degree Celsius
Degree Fahrenheit Degree Celsius Unit of temparature measurement
280A TMin TRIP CMD Power System Data 1 0.01..32.00 sec 0.15 sec Minimum TRIP Command Duration
283 Breaker S1 I> Power System Data 1 0.04..1.00 A 0.04 A Clos. Breaker Min. Current Thresh. S1
284 Breaker S2 I> Power System Data 1 0.04..1.00 A 0.04 A Clos. Breaker Min. Current Thresh. S2
285 Breaker I7 I> Power System Data 1 0.04..1.00 A 0.04 A Clos. Breaker Min. Current Thresh. I7
302 CHANGE Change Group Group A
Group B
Group C
Group D
Binary Inpu t
Protoc ol
Group A Change to Another Setting Group
Addr
.Setting Title Function Setting Options Default Setting Comments
A.7 List of Settings
3137UT612 Manual
C53000–G1176–C148–1
401 WAVEFORMTRIGGER Oscillographic Fault
Records Save with Pickup
Save with TRIP
Start with TRIP
Save with Pickup Waveform Capture
403 MAX. LENGTH Oscillographic Fault
Records 0.30..5.00 sec 1.00 sec Max. length of a Waveform Capture
Record
404 PRE. TRIG. TIME Oscillographic Fault
Records 0.05..0.50 sec 0.10 sec Captured Waveform Prior to Trigger
405 POST REC. TIME Oscillographic Fault
Records 0.05..0.50 sec 0.10 sec Captured Waveform after Event
406 BinIn CAPT.TIME Oscillographic Fault
Records 0.10..5.00 sec; ∞ 0.50 sec Capture Time via Binary Input
1201 DIFF. PROT. Differential Protection OFF
ON
Block relay for trip com-
mands
OFF Differential Protection
1205 INC.CHAR.START Differential Protection OFF
ON OFF Increase of Trip Char. During Start
1206 INRUSH 2.HARM. Differential Protection OFF
ON ON Inrush with 2. Harmonic Restraint
1207 RESTR. n.HARM. Differential Protection OFF
3. Harmonic
5. Harmonic
OFF n-th Harmonic Restraint
1208 I-DIFF> MON. Differential Protection OFF
ON ON Differential Current monitoring
1210 I> CURR. GUARD Differential Protection 0.20..2.00 I/InO; 0 0.00 I/InO I> for Current Guard
1211A DIFFw.IE1-MEAS Differential Protection NO
YES NO Diff-Prot. with meas. Earth Current S1
1212A DIFFw.IE2-MEAS Differential Protection NO
YES NO Diff-Prot. with meas. Earth Current S2
1221 I-DIFF> Differential Protection 0.05..2.00 I/InO 0.20 I/InO Pickup Value of Differential Curr.
1226A T I-DIFF> Differential Protection 0.00..60.00 sec; ∞ 0.00 sec T I-DIFF> Time Delay
1231 I-DIFF>> Differential Protection 0.5..35.0 I/InO; ∞ 7.5 I/InO Pickup Value of High Set Trip
1236A T I-DIFF>> Differential Protection 0.00..60.00 sec; ∞ 0.00 sec T I-DIFF>> Time Delay
1241A SLOPE 1 Differential Protection 0.10..0.50 0.25 Slope 1 of Tripping Characteristic
1242A BASE POINT 1 Differential Protection 0.00..2.00 I/InO 0.00 I/InO Base Point for Slope 1 of Charac.
1243A SLOPE 2 Differential Protection 0.25..0.95 0.50 Slope 2 of Tripping Characteristic
1244A BASE POINT 2 Differential Protection 0.00..10.00 I/InO 2.50 I/InO Base Point for Slope 2 of Charac.
1251A I-REST. STARTUP Differential Protection 0.00..2.00 I/InO 0.10 I/InO I-RESTRAINT for Start Detection
1252A START-FACTOR Differential Protection 1.0..2.0 1.0 Factor for Increasing of Char. at Start
1253 T START MAX Differential Protection 0.0..180.0 sec 5.0 sec Maximum Permissible Starting Time
1256A I-ADD ON STAB. Differential Protection 2.00..15.00 I/InO 4.00 I/InO Pickup for Add-on Stabilization
1257A T ADD ON-STAB. Differential Protection 2..250 Cycle; ∞ 15 Cycle Duration of Add-on Stabilization
1261 2. HARMONIC Differential Protection 10..80 % 15 % 2nd Harmonic Content in I-DIFF
1262A CROSSB. 2. HARM Differential Protection 2..1000 Cycle; 0; ∞ 3 Cycle Time for Cross-blocking 2nd Harm.
1271 n. HARMONIC Differential Protection 10..80 % 30 % n-th Harmonic Content in I-DIFF
1272A CROSSB. n.HARM Diff erential Protection 2..1000 Cycle; 0; ∞ 0 Cycle Time for Cross-blocking n-th Harm.
Addr
.Setting Title Function Setting Options Default Setting Comments
A Appendix
314 7UT612 Manual
C53000–G1176–C148–1
1273A IDIFFmax n.HM Differential Protection 0.5..20.0 I/InO 1.5 I/InO Limit IDIFFmax of n-th Harm.Restraint
1281 I-DIFF> MON. Differ ential Protection 0.15 ..0. 80 I/InO 0.20 I/InO Pickup Value of diff. Curren t Monito -
ring
1282 T I-DIFF> MON. Differential Protection 1..10 sec 2 sec T I-DIFF> Monitoring Time Delay
1301 REF PROT. Restricted Earth Fault
Protection OFF
ON
Block relay for trip com-
mands
OFF Restricted Earth Fault Protection
1311 I-REF> Restricted Earth Fault
Protection 0.05..2.00 I / In 0.15 I / In Pick up value I REF>
1312A T I-REF> Restricted Earth Fault
Protection 0.00..60.00 sec; ∞ 0.00 sec T I-REF> Time Delay
1313A SLOPE Restricted Earth Fault
Protection 0.00..0.95 0.00 Slope of Charac. I-REF> = f(I-SUM)
1701 COLDLO AD PIKKU P Cold Loa d Pikku p O FF
ON OFF Cold-Load-Pic kup Fu nctio n
1702 Start CLP Phase Cold Load Pikkup No Current
Breaker Contact No Current Start Condition CLP for O/C Phase
1703 Start CLP 3I0 Cold Load Pikkup No Current
Breaker Contact No Current Start Condition CLP for O/C 3I0
1704 Start CLP Earth Cold Load Pikkup No Current
Breaker Contact No Current Start Condition CLP for O/C Earth
1711 CB Open Time Cold Load Pikkup 0..21600 sec 3600 sec Circuit Breaker OPEN Time
1712 Active Time Cold Load Pikkup 1..21600 sec 3600 sec Active Time
1713 Stop Time Cold Load Pikkup 1..600 sec; ∞ 600 sec Stop Time
2001 PHASE O/C Time overcurrent
Phase ON
OFF OFF Phase Time Overcurrent
2002 InRushRest. Ph Time overcurrent
Phase ON
OFF OFF InRush Restrained O/C Phase
2008A MANUAL CLOSE Time overcurrent
Phase I>> instantaneously
I> instantaneo usl y
Ip instantaneously
Inactive
I>> instantaneously O/C Manual Close Mode
2011 I>> Time overcurrent
Phase 0.10..35.00 A; ∞ 2.00 A I>> Pickup
2012 T I>> Time overcurrent
Phase 0.00..60.00 se c; ∞ 0.00 sec T I>> Time Delay
2013 I> Time overcurrent
Phase 0.10..35.00 A; ∞ 1.00 A I> Pickup
2014 T I> Time overcurrent
Phase 0.00..60.00 se c; ∞ 0.50 sec T I> Time Delay
2021 Ip Time overcurrent
Phase 0.10..4.00 A 1.00 A Ip Pickup
2022 T Ip Time overcurrent
Phase 0 . 05 ..3. 20 sec; ∞ 0.50 sec T Ip Time Dial
2023 D Ip Time overcurrent
Phase 0.50..15.00; ∞ 5.00 D Ip Time Dial
2024 TOC DROP-OUT Time overcurrent
Phase Instantaneous
Disk Emulation Disk Emulation TOC Drop-out characteristic
Addr
.Setting Title Function Setting Options Default Setting Comments
A.7 List of Settings
3157UT612 Manual
C53000–G1176–C148–1
2025 IEC CURVE Time overcurrent
Phase Normal Inverse
Very Inverse
Extremely Inverse
Long Inverse
Normal Inverse IEC Curve
2026 ANSI CURVE Time overcur rent
Phase Very Inverse
Inverse
Short Inverse
Long Inverse
Moderately Inverse
Extremely Inverse
Definite Inverse
Very Inverse ANSI Curve
2031 I/Ip PU T/Tp Time overcurrent
Phase 1.00..20.00 I / Ip; ∞
0.01..999.00 Time Dial Pickup Curve I/Ip - TI/TIp
2032 MofPU Res T/Tp Time overcurrent
Phase 0.05..0.95 I / Ip; ∞
0.01..999.00 Time Dial Multiple of Pickup <-> TI/TIp
2041 2.HARM. Phase Time overcurrent
Phase 10..45 % 15 % 2nd harmonic O/C Ph. in % of funda-
mental
2042 I Max InRr. Ph. Time overcurrent
Phase 0.30..25.00 A 7.50 A Maximum Current for Inr. Rest. O/C
Phase
2043 CROSS BLK.Phase Time overcurrent
Phase NO
YES NO CROSS BLOCK O/C Phase
2044 T CROSS BLK.P h T im e over cur ren t
Phase 0.00..180.00 sec 0.00 sec CROSS BLOCK Time O/C Phase
2111 I>> Time overcurrent
Phase 0.10..35.00 A; ∞ 10.00 A I>> Pickup
2112 T I>> Time overcurrent
Phase 0.00..60.00 sec; ∞ 0.00 sec T I>> Time Delay
2113 I> Time overcurrent
Phase 0.10..35.00 A; ∞ 2.00 A I> Pickup
2114 T I> T ime over cur ren t
Phase 0.00..60.00 sec; ∞ 0.30 sec T I> Time Delay
2121 Ip Time overcurrent
Phase 0.10..4.00 A 1.50 A Ip Pickup
2122 T Ip Time overcurrent
Phase 0.05..3.20 sec; ∞ 0.50 sec T Ip Time Dial
2123 D Ip Time overcurrent
Phase 0.50..15.00; ∞ 5.00 D Ip Time Dial
2201 3I0 O/C Time overcurrent 3I0 ON
OFF OFF 3I0 Time Overcurrent
2202 InRushRest. 3I0 Time overcurrent 3I0 ON
OFF OFF InRush Restrained O/C 3I0
2208A 3I0 MAN. CLOSE Time overcurrent 3I0 3I0>> instantaneously
3I0> instanta neo usly
3I0p instantaneously
Inactive
3I0>> instantaneously O/C 3I0 Manual Close Mode
2211 3I0>> Time overcurrent 3I0 0.05..35.00 A; ∞ 0. 50 A 3I0>> Pickup
2212 T 3I0>> Time overcurrent 3I0 0.00..60.00 sec; ∞ 0.10 sec T 3I0>> Time Delay
2213 3I0> Time overcurrent 3I0 0.05..35.00 A; ∞ 0.20 A 3I0> Pickup
2214 T 3I0> Time overcurrent 3I0 0.00..60.00 sec; ∞ 0.50 sec T 3I0> Time Delay
2221 3I0p Time overcurrent 3I0 0.05..4.00 A 0.20 A 3I0p Pickup
2222 T 3I0p Time overcurrent 3I0 0.05..3.20 sec; ∞ 0.20 sec T 3I0p Time Dial
2223 D 3I0p Time overcurrent 3I0 0.50..15.00; ∞ 5.00 D 3I0p Time Dial
Addr
.Setting Title Function Setting Options Default Setting Comments
A Appendix
316 7UT612 Manual
C53000–G1176–C148–1
2224 TOC DROP-OUT Time overcurrent 3I0 Instantaneous
Disk Emulation Disk Emulation TOC Drop-out Characteristic
2225 IEC CURVE Time overcurrent 3I0 Normal Inverse
Very Inverse
Extremely Inverse
Long Inverse
Normal Inverse IEC Curve
2226 ANSI CURVE Time overcurrent 3I0 Very Inverse
Inverse
Short Inve rse
Long Inverse
Modera tely Inve rse
Extremely Inverse
Definite Inverse
Very Inverse ANSI Curve
2231 I/I0p PU T/TI0p Time overcurrent 3I0 1.00..20.00 I / Ip; ∞
0.01..999.00 Time Dial Pickup Curve 3I0/3I0p - T3I0/T3I0p
2232 MofPU ResT/TI0p Time overcurrent 3I0 0.05..0.95 I / Ip; ∞
0.01..999.00 Time Dial Multiple of Pickup <-> T3I0/T3I0p
2241 2.HARM. 3I0 Time overcurrent 3I0 10..45 % 15 % 2nd harmonic O/C 3I0 in % of funda-
mental
2242 I Max InRr. 3I0 Time overcurrent 3I0 0.30..25.00 A 7.50 A Maximum Current for Inr. Rest. O/C
3I0
2311 3I0>> Time overcurrent 3I0 0.05..35.00 A; ∞ 7.00 A 3I0>> Pickup
2312 T 3I0>> Time overcurrent 3I0 0.00..60.00 sec; ∞ 0.00 sec T 3I0>> Time Delay
2313 3I0> Time overcurrent 3I0 0.05..35.00 A; ∞ 1.5 0 A 3I0> Pickup
2314 T 3I0> Time overcurrent 3I0 0.00..60.00 sec; ∞ 0.30 sec T 3I0> Time Delay
2321 3I0p Time overcurrent 3I0 0.05..4.00 A 1.00 A 3I0p Pickup
2322 T 3I0p Time overcurrent 3I0 0.05..3.20 sec; ∞ 0.50 sec T 3I0p Time Dial
2323 D 3I0p Time overcurrent 3I0 0.50..15.00; ∞ 5.00 D 3I0p Time Dial
2401 EARTH O/C Time overcurrent
Earth ON
OFF OFF Earth Time Overcurrent
2402 InRushRestEarth Time overcurrent
Earth ON
OFF OFF InRush Restrained O/C Earth
2408A IE MAN. CLOSE Time overcurrent
Earth IE>> instantaneously
IE> instantaneously
IEp instantaneously
Inactive
IE>> instantaneously O/C IE Manual Close Mode
2411 IE>> Time overcurrent
Earth 0.05..35.00 A; ∞ 0.50 A IE>> Pickup
2412 T IE>> Time overcurrent
Earth 0.00..60.00 sec; ∞ 0.10 sec T IE>> Time Delay
2413 IE> Time overcurrent
Earth 0.05..35.00 A; ∞ 0.20 A IE> Pickup
2414 T IE> Time overcurrent
Earth 0.00..60.00 sec; ∞ 0.50 sec T IE> Time Delay
2421 IEp Time overcurrent
Earth 0.05..4.00 A 0.20 A IEp Pickup
2422 T IEp Time overcurrent
Earth 0.05 ..3. 20 sec; ∞ 0.20 sec T IEp Time Dial
2423 D IEp Time overcurrent
Earth 0.50..15.00; ∞ 5.00 D IEp Time Dial
2424 TOC DROP-OUT Time overcurrent
Earth Instantaneous
Disk Emulation Disk Emulation TOC Drop-out Characteristic
Addr
.Setting Title Function Setting Options Default Setting Comments
A.7 List of Settings
3177UT612 Manual
C53000–G1176–C148–1
2425 IEC CURVE Time overcurrent
Earth Normal Inverse
Very Inverse
Extremely Inverse
Long Inverse
Normal Inverse IEC Curve
2426 ANSI CURVE Time overcur rent
Earth Very Inverse
Inverse
Short Inverse
Long Inverse
Moderately Inverse
Extremely Inverse
Definite Inverse
Very Inverse ANSI Curve
2431 I/IEp PU T/TEp T ime over cur ren t
Earth 1.00..20.00 I / Ip; ∞
0.01..999.00 Time Dial Pickup Curve IE/IEp - TIE/TIEp
2432 MofPU Res T/TEp Time overcurrent
Earth 0.05..0.95 I / Ip; ∞
0.01..999.00 Time Dial Multiple of Pickup <-> TI/TIEp
2441 2.HARM. Earth Time overcurrent
Earth 10..45 % 15 % 2nd harmonic O/C E in % of funda-
mental
2442 I Max InRr. E Time overcurrent
Earth 0.30..25.00 A 7.50 A Maximum Current for Inr. Rest. O/C
Earth
2511 IE>> Time overcurrent
Earth 0.05..35.00 A; ∞ 7.00 A IE>> Pickup
2512 T IE>> Time over cur ren t
Earth 0.00..60.00 sec; ∞ 0.00 sec T IE>> Time Delay
2513 IE> Time overcurrent
Earth 0.05..35.00 A; ∞ 1.50 A IE> Pickup
2514 T IE> Time over cur rent
Earth 0.00..60.00 sec; ∞ 0.30 sec T IE> Time Delay
2521 IEp Time overcurrent
Earth 0.05..4.00 A 1.00 A IEp Pickup
2522 T IEp Time overcur ren t
Earth 0.05..3.20 sec; ∞ 0.50 sec T IEp Time Dial
2523 D IEp Time overcurrent
Earth 0.50..15.00; ∞ 5.00 D IEp Time Dial
2701 1Phase O/C Time overcurrent
1Phase OFF
ON OFF 1Phase Time Overcurrent
2702 1Phase I>> Time overcurrent
1Phase 0.05..35.00 A; ∞ 0.50 A 1Phase O/C I>> Pickup
2703 1Phase I>> Time overcurrent
1Phase 0.003.. 1.5 00 A; ∞ 0.300 A 1Phase O/C I>> Pickup
2704 T 1Phase I>> Time overcurrent
1Phase 0.00..60.00 sec; ∞ 0.10 sec T 1Phase O/C I>> Time Delay
2705 1Phase I> Time overcurrent
1Phase 0.05..35.00 A; ∞ 0.20 A 1Phase O/C I> Pickup
2706 1Phase I> Time overcurrent
1Phase 0.003.. 1.5 00 A; ∞ 0.100 A 1Phase O/C I> Pickup
2707 T 1Phase I> Time overcurrent
1Phase 0.00..60.00 sec; ∞ 0.50 sec T 1Phase O/C I> Time Delay
4001 UNBALANCE LOAD Unbalance Load
(Negative Sequence) OFF
ON OFF Unbalance Load (Negative Sequence)
4002 I2> Unbalance Load
(Negative Sequence) 0.10..3.00 A 0.10 A I2> Pickup
4003 T I2> Unb alan c e Loa d
(Negative Sequence) 0.00..60.00 sec; ∞ 1.50 sec T I2> Time Delay
Addr
.Setting Title Function Setting Options Default Setting Comments
A Appendix
318 7UT612 Manual
C53000–G1176–C148–1
4004 I2>> Unbalance Load
(Negative Sequence) 0.10..3.00 A 0.50 A I2>> Pickup
4005 T I2>> Unbalance Load
(Negative Sequence) 0.00..60.00 sec; ∞ 1.50 sec T I2>> Time Delay
4006 IEC CURVE Unbalance Load
(Negative Sequence) Normal Inverse
Very Inverse
Extremely Inverse
Extremely Inverse IEC Curve
4007 ANSI CURVE Unbalance Load
(Negative Sequence) Extremely Inverse
Inverse
Modera tely Inve rse
Very Inverse
Extremely Inverse ANSI Curve
4008 I2p Unbalance Load
(Negative Sequence) 0.10..2.00 A 0.90 A I2p P ickup
4009 D I2p Unbalance Load
(Negative Sequence) 0.50..15.00; ∞ 5.00 D I2p Time Dial
4010 T I2p Unbalance Load
(Negative Sequence) 0.05 ..3. 20 sec; ∞ 0.50 sec T I2p Time Dial
4011 I2p DROP-OUT Unbalance Load
(Negative Sequence) Instantaneous
Disk Emulation Instantaneous I2p Drop-out Characteristic
4201 Ther. OVER LOAD Thermal Overload
Protection OFF
ON
Alarm Only
OFF Thermal Overload Protection
4202 K-FACTOR Thermal Overload
Protection 0.10..4.00 1.10 K-Factor
4203 TIME CONS TAN T Therm al Ov er load
Protectio n 1.0..999.9 min 100.0 min Time Constant
4204 Θ ALA RM Thermal O ver l oad
Protectio n 50..100 % 90 % Thermal Alarm Stage
4205 I ALARM Thermal Overload
Protection 0.10..4.00 A 1.00 A Current Overload Alarm Setpoint
4207A Kτ-FACTOR Thermal Overload
Protection 1.0..10.0 1.0 Kt-FACTOR when motor stops
4208A T EMERGENCY Thermal Overload
Protection 10..15000 sec 100 sec Emergency Time
4209 A I MOTOR STA RT Therm al Over l oad
Protectio n 0.60..10.00 A ; ∞ ∞ A Current Pickup Value of Motor Starting
4221 OIL-DET. RTD Thermal Overload
Protection 1..6 1 Oil-Detector conected at RTD
4222 HOT SPOT ST. 1 Thermal Overload
Protection 98..140 °C 98 °C Hot Spot Temperature Stage 1 Pickup
4223 HOT SPOT ST. 1 Thermal Overload
Protection 208..284 °F 208 °F Hot Spot Temperature Stage 1 Pickup
4224 HOT SPOT ST. 2 Thermal Overload
Protection 98..140 °C 108 °C Hot Spot Temperature Stage 2 Pickup
4225 HOT SPOT ST. 2 Thermal Overload
Protection 208..284 °F 226 °F Hot Spot Temperature Stage 2 Pickup
4226 AG. RATE ST. 1 Thermal Overload
Protection 0.125..128.000 1.000 Aging Rate STAGE 1 Pikkup
4227 AG. RATE ST. 2 Thermal Overload
Protection 0.125..128.000 2.000 Aging Rate STAGE 2 Pikkup
4231 METH. COOLING Thermal Overload
Protection ON (Oil-Natural)
OF (Oil-Forced)
OD (Oil-Direc ted)
ON (Oil-Natural) Method of Cooling
Addr
.Setting Title Function Setting Options Default Setting Comments
A.7 List of Settings
3197UT612 Manual
C53000–G1176–C148–1
4232 Y-WIND.EXPONENT Thermal Overload
Protection 1.6..2.0 1.6 Y-Winding Exponent
4233 HOT-SPOT GR Thermal Overload
Protection 22..29 22 Hot-spot to top-oil gradient
7001 BREAKER FAILURE Breaker Failure Pro-
tection OFF
ON OFF Breaker Failure Protection
7004 Chk BRK CONTACT Breaker Failure Pro-
tection OFF
ON OFF Check Breaker contacts
7005 TRIP-Timer Breaker Failure Pro-
tection 0.06..60.00 sec; ∞ 0.25 sec TRIP-Timer
7110 FltDisp.LED/LCD Device Display Targets on every
Pickup
Display Targets on TRIP
only
Display Targets on every
Pickup Fault Display on LED / LCD
7601 POWER CALCUL. Measurement with V setting
with V measuring with V setting Calculation of Power
8101 BALANCE I Measurement Super-
vision ON
OFF OFF Current Balance Supervision
8102 P HASE ROTATION Measurement Super-
vision ON
OFF OFF Phase Rotation Supervision
8111 BAL. I LIMIT S1 Measurement Super-
vision 0.10..1.00 A 0.50 A Current Balance Monitor Side 1
8112 BAL. FACT. I S1 Measurement Super-
vision 0.10..0.90 0.50 Balance Factor for Current Monitor S1
8121 BAL. I LIMIT S2 Measurement Super-
vision 0.10..1.00 A 0.50 A Current Balance Monitor Side 2
8122 BAL. FACT. I S2 Measurement Super-
vision 0.10..0.90 0.50 Balance Factor for Current Monitor S2
8201 TRIP Cir. SUP. Trip Circuit Supervi-
sion ON
OFF OFF TRIP Circuit Supervision
8601 EXTERN TRIP 1 External Trip
Functions ON
OFF OFF External Trip Function 1
8602 T DELAY External Trip
Functions 0.00..60.00 sec; ∞ 1.00 sec Ext. Trip 1 Time Delay
8701 EXTERN TRIP 2 External Trip
Functions ON
OFF OFF External Trip Function 2
8702 T DELAY External Trip
Functions 0.00..60.00 sec; ∞ 1.00 sec Ext. Trip 2 Time Delay
9011A R TD 1 TYPE RTD-Box not con nect ed
Pt 100 Ohm
Ni 120 Ohm
Ni 100 Ohm
Pt 100 Ohm RTD 1: Type
9012A RTD 1 LOCATION RTD-Box Oil
Ambient
Winding
Bearing
Other
Oil RTD 1: Location
9013 RTD 1 STAGE 1 RTD-Box -50..250 °C; ∞ 100 °C RTD 1: Temperature Stage 1 Pickup
9014 RTD 1 STAGE 1 RTD-Box -58..482 °F; ∞ 212 °F RTD 1: Temperature Stage 1 Pickup
9015 RTD 1 STAGE 2 RTD-Box -50..250 °C; ∞ 120 °C RTD 1: Temperature Stage 2 Pickup
9016 RTD 1 STAGE 2 RTD-Box -58..482 °F; ∞ 248 °F RTD 1: Temperature Stage 2 Pickup
Addr
.Setting Title Function Setting Options Default Setting Comments
A Appendix
320 7UT612 Manual
C53000–G1176–C148–1
9021A RTD 2 TYPE RTD-Box not connected
Pt 100 Ohm
Ni 120 Ohm
Ni 100 Ohm
not connected RTD 2: Type
9022A RTD 2 LOCATION RTD-Box Oil
Ambient
Winding
Bearing
Other
Other RTD 2: Location
9023 RTD 2 STAGE 1 RTD-Box -50..250 °C; ∞ 100 °C RTD 2: Temperature Stage 1 Pickup
9024 RTD 2 STAGE 1 RTD-Box -58..482 °F; ∞ 212 °F RTD 2: Temperature Stage 1 Pickup
9025 RTD 2 STAGE 2 RTD-Box -50..250 °C; ∞ 120 °C RTD 2: Temperature Stage 2 Pickup
9026 RTD 2 STAGE 2 RTD-Box -58..482 °F; ∞ 248 °F RTD 2: Temperature Stage 2 Pickup
9031A RTD 3 TYPE RTD-Box not connected
Pt 100 Ohm
Ni 120 Ohm
Ni 100 Ohm
not connected RTD 3: Type
9032A RTD 3 LOCATION RTD-Box Oil
Ambient
Winding
Bearing
Other
Other RTD 3: Location
9033 RTD 3 STAGE 1 RTD-Box -50..250 °C; ∞ 100 °C RTD 3: Temperature Stage 1 Pickup
9034 RTD 3 STAGE 1 RTD-Box -58..482 °F; ∞ 212 °F RTD 3: Temperature Stage 1 Pickup
9035 RTD 3 STAGE 2 RTD-Box -50..250 °C; ∞ 120 °C RTD 3: Temperature Stage 2 Pickup
9036 RTD 3 STAGE 2 RTD-Box -58..482 °F; ∞ 248 °F RTD 3: Temperature Stage 2 Pickup
9041A RTD 4 TYPE RTD-Box not connected
Pt 100 Ohm
Ni 120 Ohm
Ni 100 Ohm
not connected RTD 4: Type
9042A RTD 4 LOCATION RTD-Box Oil
Ambient
Winding
Bearing
Other
Other RTD 4: Location
9043 RTD 4 STAGE 1 RTD-Box -50..250 °C; ∞ 100 °C RTD 4: Temperature Stage 1 Pickup
9044 RTD 4 STAGE 1 RTD-Box -58..482 °F; ∞ 212 °F RTD 4: Temperature Stage 1 Pickup
9045 RTD 4 STAGE 2 RTD-Box -50..250 °C; ∞ 120 °C RTD 4: Temperature Stage 2 Pickup
9046 RTD 4 STAGE 2 RTD-Box -58..482 °F; ∞ 248 °F RTD 4: Temperature Stage 2 Pickup
9051A RTD 5 TYPE RTD-Box not connected
Pt 100 Ohm
Ni 120 Ohm
Ni 100 Ohm
not connected RTD 5: Type
9052A RTD 5 LOCATION RTD-Box Oil
Ambient
Winding
Bearing
Other
Other RTD 5: Location
9053 RTD 5 STAGE 1 RTD-Box -50..250 °C; ∞ 100 °C RTD 5: Temperature Stage 1 Pickup
9054 RTD 5 STAGE 1 RTD-Box -58..482 °F; ∞ 212 °F RTD 5: Temperature Stage 1 Pickup
9055 RTD 5 STAGE 2 RTD-Box -50..250 °C; ∞ 120 °C RTD 5: Temperature Stage 2 Pickup
9056 RTD 5 STAGE 2 RTD-Box -58..482 °F; ∞ 248 °F RTD 5: Temperature Stage 2 Pickup
Addr
.Setting Title Function Setting Options Default Setting Comments
A.7 List of Settings
3217UT612 Manual
C53000–G1176–C148–1
9061A R TD 6 TYPE RTD-Box not con nect ed
Pt 100 Ohm
Ni 120 Ohm
Ni 100 Ohm
not connected RTD 6: Type
9062A RTD 6 LOCATION RTD-Box Oil
Ambient
Winding
Bearing
Other
Other RTD 6: Location
9063 RTD 6 STAGE 1 RTD-Box -50..250 °C; ∞ 100 °C RTD 6: Temperature Stage 1 Pickup
9064 RTD 6 STAGE 1 RTD-Box -58..482 °F; ∞ 212 °F RTD 6: Temperature Stage 1 Pickup
9065 RTD 6 STAGE 2 RTD-Box -50..250 °C; ∞ 120 °C RTD 6: Temperature Stage 2 Pickup
9066 RTD 6 STAGE 2 RTD-Box -58..482 °F; ∞ 248 °F RTD 6: Temperature Stage 2 Pickup
9071A R TD 7 TYPE RTD-Box not con nect ed
Pt 100 Ohm
Ni 120 Ohm
Ni 100 Ohm
not connected RTD 7: Type
9072A RTD 7 LOCATION RTD-Box Oil
Ambient
Winding
Bearing
Other
Other RTD 7: Location
9073 RTD 7 STAGE 1 RTD-Box -50..250 °C; ∞ 100 °C RTD 7: Temperature Stage 1 Pickup
9074 RTD 7 STAGE 1 RTD-Box -58..482 °F; ∞ 212 °F RTD 7: Temperature Stage 1 Pickup
9075 RTD 7 STAGE 2 RTD-Box -50..250 °C; ∞ 120 °C RTD 7: Temperature Stage 2 Pickup
9076 RTD 7 STAGE 2 RTD-Box -58..482 °F; ∞ 248 °F RTD 7: Temperature Stage 2 Pickup
9081A R TD 8 TYPE RTD-Box not con nect ed
Pt 100 Ohm
Ni 120 Ohm
Ni 100 Ohm
not connected RTD 8: Type
9082A RTD 8 LOCATION RTD-Box Oil
Ambient
Winding
Bearing
Other
Other RTD 8: Location
9083 RTD 8 STAGE 1 RTD-Box -50..250 °C; ∞ 100 °C RTD 8: Temperature Stage 1 Pickup
9084 RTD 8 STAGE 1 RTD-Box -58..482 °F; ∞ 212 °F RTD 8: Temperature Stage 1 Pickup
9085 RTD 8 STAGE 2 RTD-Box -50..250 °C; ∞ 120 °C RTD 8: Temperature Stage 2 Pickup
9086 RTD 8 STAGE 2 RTD-Box -58..482 °F; ∞ 248 °F RTD 8: Temperature Stage 2 Pickup
9091A R TD 9 TYPE RTD-Box not con nect ed
Pt 100 Ohm
Ni 120 Ohm
Ni 100 Ohm
not connected RTD 9: Type
9092A RTD 9 LOCATION RTD-Box Oil
Ambient
Winding
Bearing
Other
Other RTD 9: Location
9093 RTD 9 STAGE 1 RTD-Box -50..250 °C; ∞ 100 °C RTD 9: Temperature Stage 1 Pickup
9094 RTD 9 STAGE 1 RTD-Box -58..482 °F; ∞ 212 °F RTD 9: Temperature Stage 1 Pickup
9095 RTD 9 STAGE 2 RTD-Box -50..250 °C; ∞ 120 °C RTD 9: Temperature Stage 2 Pickup
9096 RTD 9 STAGE 2 RTD-Box -58..482 °F; ∞ 248 °F RTD 9: Temperature Stage 2 Pickup
Addr
.Setting Title Function Setting Options Default Setting Comments
A Appendix
322 7UT612 Manual
C53000–G1176–C148–1
9101A RTD10 TYPE RTD-Box not connected
Pt 100 Ohm
Ni 120 Ohm
Ni 100 Ohm
not connected RTD10: Type
9102A RTD10 LOCATION RTD-Box Oil
Ambient
Winding
Bearing
Other
Other RTD10: Location
9103 RTD10 STAGE 1 RTD-Box -50..250 °C; ∞ 100 °C RTD10: Temperature Stage 1 Pickup
9104 RTD10 STAGE 1 RTD-Box -58..482 °F; ∞ 212 °F RTD10: Temperature Stage 1 Pickup
9105 RTD10 STAGE 2 RTD-Box -50..250 °C; ∞ 120 °C RTD10: Temperature Stage 2 Pickup
9106 RTD10 STAGE 2 RTD-Box -58..482 °F; ∞ 248 °F RTD10: Temperature Stage 2 Pickup
9111A RTD11 TYPE RTD-Box not connected
Pt 100 Ohm
Ni 120 Ohm
Ni 100 Ohm
not connected RTD11: Type
9112A RTD11 LOCATION RTD-Box Oil
Ambient
Winding
Bearing
Other
Other RTD11: Location
9113 RTD11 STAGE 1 RTD-Box -50..250 °C; ∞ 100 °C RTD11: Temperature Stage 1 Pickup
9114 RTD11 STAGE 1 RTD-Box -58..482 °F; ∞ 212 °F RTD11: Temperature Stage 1 Pickup
9115 RTD11 STAGE 2 RTD-Box -50..250 °C; ∞ 120 °C RTD11: Temperature Stage 2 Pickup
9116 RTD11 STAGE 2 RTD-Box -58..482 °F; ∞ 248 °F RTD11: Temperature Stage 2 Pickup
9121A RTD12 TYPE RTD-Box not connected
Pt 100 Ohm
Ni 120 Ohm
Ni 100 Ohm
not connected RTD12: Type
9122A RTD12 LOCATION RTD-Box Oil
Ambient
Winding
Bearing
Other
Other RTD12: Location
9123 RTD12 STAGE 1 RTD-Box -50..250 °C; ∞ 100 °C RTD12: Temperature Stage 1 Pickup
9124 RTD12 STAGE 1 RTD-Box -58..482 °F; ∞ 212 °F RTD12: Temperature Stage 1 Pickup
9125 RTD12 STAGE 2 RTD-Box -50..250 °C; ∞ 120 °C RTD12: Temperature Stage 2 Pickup
9126 RTD12 STAGE 2 RTD-Box -58..482 °F; ∞ 248 °F RTD12: Temperature Stage 2 Pickup
Addr
.Setting Title Function Setting Options Default Setting Comments
A.8 List of Information
3237UT612 Manual
C53000–G1176–C148–1
A.8 List of Information
F.No. Description Function Type
of
Infor-
ma-
tion
Log-Buffers Configurable in Matrix IEC 60870-5-103
Event Log On/Off
Trip (F aul t) Log On /Off
Ground Fault Log On/Off
Marked in Oscill. Record
LED
Binary Input
Function Key
Binary Output
Chatter Blocking
Type
Information-No
Data Unit (ASDU)
General Interrogation
00003 >Synchronize Internal Real Time
Clock (>Time Synch) Device SP_Ev * * LED BI BO 135 48 1
00004 >Trigger Waveform Capture
(>Trig.Wave.Cap.) Oscillographic Fault
Records SP * * M LED BI BO 135 49 1 GI
00005 >Reset LED (>Reset LED) Device SP * * LED BI BO 135 50 1 GI
00007 >Setting Group Select Bit 0 (>Set
Group Bit0) Change Group SP * * LED BI BO 135 51 1 GI
00008 >Setting Group Select Bit 1 (>Set
Group Bit1) Change Group SP * * LED BI BO 135 52 1 GI
00015 >Test mode (>Test mode) Device SP * * LED BI BO 135 53 1 GI
00016 >Stop data transmission (>DataStop) Device SP * * LED BI BO 135 54 1 GI
00051 Device is Operational and Protecting
(Device OK) Device OUT ON
OFF
* LED BO 135 81 1 GI
00052 At Least 1 Protection Funct. is Active
(ProtActive) Device IntSP ON
OFF
* LED BO 176 18 1 GI
00055 Reset Device (Reset Device) Device OUT * * LED BO 176 4 5
00056 Initial Start of Device (Initial Start) Device OUT ON * LED BO 176 5 5
00060 Reset LED (Reset LED) Device OUT_
Ev ON * LED BO 176 19 1
00067 Resume (Resume) Device OUT ON * LED BO 135 97 1
00068 Clock Synchronization Error (Clock
SyncError) Supervision OUT ON
OFF
* LED BO
00069 Daylight Saving Time (DayLightSav-
Time) Device OUT ON
OFF
* LED BO
00070 Setting calculation is running (Settings
Calc.) Device OUT ON
OFF
* LED BO 176 22 1 GI
00071 Settings Check (Settings Check) Device OUT * * LED BO
00072 Level-2 change (Level-2 change) Device OUT ON
OFF * LED BO
00109 Frequency out of range (Frequ. o.o.r.) Device OUT ON
OFF * LED BO
00110 Event lost (Event Lost) Supervision OUT_
Ev ON * LED BO 135 130 1
00113 Flag Lost (Flag Lost) Supervision OUT ON * M LED BO 135 136 1 GI
00125 Chatter ON (Chatter ON) Device OUT ON
OFF * LED BO 135 145 1 GI
A Appendix
324 7UT612 Manual
C53000–G1176–C148–1
00126 Protection ON/OFF (via system port)
(ProtON /OF F) Power System Data
2 IntSP ON
OFF
* LED BO
00140 Error with a summary alarm (Error
Sum Alarm) Supervision OUT * * LED BO 176 47 1 GI
00160 Alarm Summary Ev ent (A lar m Su m
Event) Supervision OUT * * LED BO 176 46 1 GI
00161 Failure: General Current Supervision
(Fail I Superv.) Measurement
Supervision OUT ON
OFF
* LED BO
00163 Failure: Current Balance (Fail I
balance) Measurement
Supervision OUT ON
OFF
* LED BO 135 183 1 GI
00175 Failure: Phase Sequence Current (Fail
Ph. Seq. I) M ea s ur eme nt
Super vision OUT ON
OFF
* LED BO 135 191 1 GI
00177 Failure: Battery empty (Fail Battery) Supervision OUT ON
OFF * LED BO 135 193 1 GI
00181 Error: A/D converter (Error A/D-conv.) Supervision OUT ON
OFF * LED BO 135 178 1 GI
00183 Error Board 1 (Error Board 1) Supervision OUT ON
OFF * LED BO 135 171 1 GI
00190 Error Board 0 (Error Board 0) Supervision OUT ON
OFF * LED BO 135 210 1 GI
00191 Error: Offset (Error Offset) Supervision OUT ON
OFF * LED BO
00192 Error:1A/5Ajumper different from set-
ting (Error1A/5Awrong) Supervision OUT ON
OFF
* LED BO 135 169 1 GI
00193 Alarm: NO calibration data available
(Alarm NO calibr) Supervision OUT ON
OFF
* LED BO 135 181 1 GI
00198 Error: Communication Module B (Err.
Module B) Supervision OUT ON
OFF
* LED BO 135 198 1 GI
00199 Error: Communication Module C (Err.
Module C) Supervision OUT ON
OFF
* LED BO 135 199 1 GI
00203 Waveform data deleted (Wave. dele-
ted) Oscillographic Fault
Records OUT_
Ev ON * LED BO 135 203 1
00264 Failure: RTD-Box 1 (Fail: RTD-Box 1) Supervision OUT ON
OFF * LED BO 135 208 1 GI
00265 Failure: Phase Sequence I side 1
(FailPh.Seq I S1) Measurement
Supervision OUT ON
OFF
* LED BO
00266 Failure: Phase Sequence I side 2
(FailPh.Seq I S2) Measurement
Supervision OUT ON
OFF
* LED BO
00267 Failure: RTD-Box 2 (Fail: RTD-Box 2) Supervision OUT ON
OFF * LED BO 135 209 1 GI
00272 Set Point Operating Hours (SP. Op
Hours>) Set Points (Stati-
stic) OUT ON
OFF
* LED BO 135 229 1 GI
00311 Fault in configuration of the Protection
(Fault Configur.) Power System Data
2 OUT ON * LED BO
F.No. Description Function Type
of
Infor-
ma-
tion
Log-Buffers Configurable in Matrix IEC 60870-5-103
Event Log On/Off
Trip (Fau lt) Lo g On/Off
Ground Fault Log On/Off
Marked in Oscill. Record
LED
Binary Input
Function Key
Binary Output
Chatter Blocking
Type
Information-No
Data Unit (ASDU)
General Interrogation
A.8 List of Information
3257UT612 Manual
C53000–G1176–C148–1
00356 >Manual close signal (>Manual Close) Power System Data
2 SP * * LED BI BO 150 6 1 GI
00390 >Warning stage from gas in oil detec-
tor (>Gas in oil) External Annuncia-
tions of Transfor-
mer
SP ON
OFF
* LED BI BO
00391 >Warning stage from Buchholz protec-
tion (>Buchh. Warn) External Annuncia-
tions of Transfor-
mer
SP ON
OFF
* LED BI BO 150 41 1 GI
00392 >Tripp. stage from Buchholz protec-
tion (>Buchh. Trip) External Annuncia-
tions of Transfor-
mer
SP ON
OFF
* LED BI BO 150 42 1 GI
00393 >Tank supervision from Buchh. pro-
tect. (>Buchh. Tank) External Annuncia-
tions of Transfor-
mer
SP ON
OFF
* LED BI BO 150 43 1 GI
00409 >BLOCK Op Counter (>BLOCK Op
Count) Statistics SP ON
OFF
* LED BI BO
00410 >CB1 aux. 3p Closed (>CB1 3p Clo-
sed) Power System Data
2 SP on
off
* LED BI BO 150 80 1 GI
00411 >CB1 aux. 3p Open (>CB1 3p Open) Power System Data
2 SP on
off
* LED BI BO 150 81 1 GI
00413 >CB2 aux. 3p Closed (>CB2 3p Clo-
sed) Power System Data
2 SP on
off
* LED BI BO 150 82 1 GI
00414 >CB2 aux. 3p Open (>CB2 3p Open) Power System Data
2 SP on
off
* LED BI BO 150 83 1 GI
00501 Relay PICKUP (Relay PICKUP) Power System Data
2 OUT * ON M LED BO 150 151 2 GI
00511 Relay GENERAL TRIP command
(Relay TRIP ) Power System Data
2 OUT * ON M LED BO 150 161 2 GI
00561 Manual close signal detected
(Man.Clos.Dete ct) Power System Data
2 OUT ON * LED BO 150 211 1
00571 Fail.: Current symm. supervision side
1 (Fail. Isym 1) Measurement
Supervision OUT ON
OFF
* LED BO
00572 Fail.: Current symm. supervision side
2 (Fail. Isym 2) Measurement
Supervision OUT ON
OFF
* LED BO
00576 Primary fault current IL1 side1
(IL1S1:) Power System Data
2 OUT * ON
OFF 150 193 4
00577 Primary fault current IL2 side1
(IL2S1:) Power System Data
2 OUT * ON
OFF 150 194 4
00578 Primary fault current IL3 side1
(IL3S1:) Power System Data
2 OUT * ON
OFF 150 195 4
00579 Primary fault current IL1 side2
(IL1S2:) Power System Data
2 OUT * ON
OFF 150 190 4
00580 Primary fault current IL2 side2
(IL2S2:) Power System Data
2 OUT * ON
OFF 150 191 4
00581 Primary fault current IL3 side2
(IL3S2:) Power System Data
2 OUT * ON
OFF 150 192 4
F.No. Description Function Type
of
Infor-
ma-
tion
Log-Buffers Configurable in Matrix IEC 60870-5-103
Event Log On/Off
Trip (Fau lt) Lo g On/Off
Ground Fault Log On/Off
Marked in Oscill. Record
LED
Binary Input
Function Key
Binary Output
Chatter Blocking
Type
Information-No
Data Unit (ASDU)
General Interrogation
A Appendix
326 7UT612 Manual
C53000–G1176–C148–1
00582 Primary fault current I1 (I1:) Power System Data
2 OUT * ON
OFF
00583 Primary fault current I2 (I2:) Power System Data
2 OUT * ON
OFF
00584 Primary fault current I3 (I3:) Power System Data
2 OUT * ON
OFF
00585 Primary fault current I4 (I4:) Power System Data
2 OUT * ON
OFF
00586 Primary fault current I5 (I5:) Power System Data
2 OUT * ON
OFF
00587 Primary fault current I6 (I6:) Power System Data
2 OUT * ON
OFF
00588 Primary fault current I7 (I7:) Power System Data
2 OUT * ON
OFF
00888 Pulsed Energy Wp (active) (Wp(puls)) Energy PMV BI 133 55 20
5
00889 Pulsed Ener gy Wq (reactive)
(Wq(puls)) Energy PMV BI 133 56 20
5
01000 Number of breaker TRIP commands
(# TRIPs=) Statistics OUT
01020 Counter of operating hours
(Op.Hours=) Statistics OUT
01403 >BLOCK Breaker failure (>BLOCK
BkrFail) Breaker Failure
Protection SP * * LED BI BO 166 103 1 GI
01431 >Breaker failure initiated externally
(>BrkFail extSRC) Breaker Failure
Protection SP ON
OFF
* LED BI BO 166 104 1 GI
01451 Breaker failure is switched OFF
(BkrFail OFF) Breaker Failure
Protection OUT ON
OFF
* LED BO 166 151 1 GI
01452 Breaker failure is BLOCKED (BkrFail
BLOCK) Breaker Failure
Protection OUT ON
OFF
ON
OFF
LED BO 166 152 1 GI
01453 Breaker failure is ACTIVE (BkrFail
ACTIVE) Breaker Failure
Protection OUT ON
OFF
* LED BO 166 153 1 GI
01456 Breaker failur e (internal) PICKUP
(BkrFail int PU) Breaker Failure
Protection OUT * ON
OFF LED BO 166 156 2 GI
01457 Breaker failure (external) PICKUP
(BkrFail ext PU) Breaker Failure
Protection OUT * ON
OFF LED BO 166 157 2 GI
01471 Breaker failure TRIP (BrkFailure
TRIP) Breaker Failure
Protection OUT * ON M LED BO 166 171 2 GI
01480 Breaker failure (internal) TRIP (BkrFail
intTRIP) Breaker Failure
Protection OUT * ON LED BO 166 180 2 GI
01481 Breaker failure (external) TRIP
(BkrFail extTRIP) Breaker Failure
Protection OUT * ON LED BO 166 181 2 GI
01488 Breaker failure Not aval. for this obj.
(BkrFail Not av.) Breaker Failure
Protection OUT ON * LED BO
F.No. Description Function Type
of
Infor-
ma-
tion
Log-Buffers Configurable in Matrix IEC 60870-5-103
Event Log On/Off
Trip (Fau lt) Lo g On/Off
Ground Fault Log On/Off
Marked in Oscill. Record
LED
Binary Input
Function Key
Binary Output
Chatter Blocking
Type
Information-No
Data Unit (ASDU)
General Interrogation
A.8 List of Information
3277UT612 Manual
C53000–G1176–C148–1
01503 >BLOCK Thermal Overload Protection
(>B LK ThOverload) Thermal Overload
Protection SP * * LED BI BO 167 3 1 GI
01507 >Emergency start Th. Overload Pro-
tection (>Emer.Start O/L) Thermal Overload
Protection SP ON
OFF
* LED BI BO 167 7 1 GI
01511 Thermal Overload Protection OFF
(Th. Overload OFF) Thermal Overload
Protection OUT ON
OFF
* LED BO 167 11 1 GI
01512 Thermal Overload Protection BLOK-
KED (Th.Overload BLK) Thermal Overload
Protection OUT ON
OFF
ON
OFF
LED BO 167 12 1 GI
01513 Thermal Overload Protection ACTIVE
(Th.Overload ACT) Thermal Overload
Protection OUT ON
OFF
* LED BO 167 13 1 GI
01515 Th. Overload Current Alarm (I alarm)
(O/L I Alarm) Thermal Overload
Protection OUT ON
OFF
* LED BO 167 15 1 GI
01516 Thermal Overload Alarm (O/L Θ
Alarm) Thermal Overload
Protection OUT ON
OFF
* LED BO 167 16 1 GI
01517 Thermal Overl oad picked up (O/L Th.
pick.up) Thermal Overload
Protection OUT ON
OFF
* LED BO 167 17 1 GI
01521 Thermal Overload TRIP (ThOverload
TRIP) Thermal Overload
Protection OUT * ON
OFF M LED BO 167 21 2 GI
01541 Thermal Overload hot spot Th. Alarm
(O/L ht.spot A l.) Thermal Overload
Protection OUT ON
OFF
* LED BO 167 41 1 GI
01542 Thermal Overload hot spot Th. TRIP
(O/L h.spot TRIP) Thermal Overload
Protection OUT ON
OFF
* LED BO 167 42 2 GI
01543 Thermal Overload aging rate Al arm
(O/L ag.rate Al.) Thermal Overload
Protection OUT ON
OFF
* LED BO 167 43 1 GI
01544 Thermal Overload aging rate TRIP (O/
L ag.rt. TRIP) Thermal Overload
Protection OUT ON
OFF
* LED BO 167 44 1 GI
01545 Th. Overload No temperature mesu-
red (O/L No Th.meas.) Thermal Overload
Protection OUT ON * LED BO
01549 Th. Overload Not avaliable for this obj.
(O/L Not avalia.) Thermal Overload
Protection OUT ON * LED BO
01704 >BLOCK Phase time overcurrent
(>BLK Phase O/C) Time overcurrent
Phase SP * * LED BI BO
01714 >BLOCK Earth time overcurrent
(>BLK Earth O/C) Time overcurrent
Earth SP * * LED BI BO
01721 >BLOCK I>> (>BLOCK I>>) Time overcurrent
Phase SP * * LED BI BO 60 1 1 GI
01722 >BLOCK I> (>BLOCK I>) Time overcurrent
Phase SP * * LED BI BO 60 2 1 GI
01723 >BLOCK Ip (>BLOCK Ip) Time overcurrent
Phase SP * * LED BI BO 60 3 1 GI
01724 >BLOCK IE>> (>BLOCK IE>>) Time overcurrent
Earth SP * * LED BI BO 60 4 1 GI
01725 >BLOCK IE> (>BLOCK IE>) Time overcurrent
Earth SP * * LED BI BO 60 5 1 GI
F.No. Description Function Type
of
Infor-
ma-
tion
Log-Buffers Configurable in Matrix IEC 60870-5-103
Event Log On/Off
Trip (Fau lt) Lo g On/Off
Ground Fault Log On/Off
Marked in Oscill. Record
LED
Binary Input
Function Key
Binary Output
Chatter Blocking
Type
Information-No
Data Unit (ASDU)
General Interrogation
A Appendix
328 7UT612 Manual
C53000–G1176–C148–1
01726 >BLOCK IEp (>BLOCK IEp) Time overcurrent
Earth SP * * LED BI BO 60 6 1 GI
01730 >BLOCK Cold-Load-Pickup (>BLOCK
CLP) Cold Load Pickup SP * * LED BI BO
01731 >BLOCK Cold-Load-Pickup stop timer
(>BLK CLP stpTim) Cold Load Pickup SP ON
OFF ON
OFF LED BI BO 60 243 1 GI
01741 >BLOCK 3I0 time overcurrent (>BLK
3I0 O/C) Time overcurrent
3I0 SP * * LED BI BO
01742 >BLOCK 3I0>> time overcurrent
(>BLOCK 3I0>>) Time overcurrent
3I0 SP * * LED BI BO 60 9 1 GI
01743 >BLOCK 3I0> time overcurrent
(>BLOCK 3I0>) Time overcurrent
3I0 SP * * LED BI BO 60 10 1 GI
01744 >BLOCK 3I0p time overcurrent
(>BLOCK 3I0p) Time overcurrent
3I0 SP * * LED BI BO 60 11 1 GI
01748 Time Overcurrent 3I0 is OFF (O/C 3I0
OFF) Time overcurrent
3I0 OUT ON
OFF
* LED BO 60 151 1 GI
01749 Time Overcurrent 3I0 is BLOCKED
(O/C 3I0 BLK) Time overcurrent
3I0 OUT ON
OFF
ON
OFF
LED BO 60 152 1 GI
01750 Time Overcurrent 3I0 is ACTIVE (O/C
3I0 ACTIVE) Time overcurrent
3I0 OUT ON
OFF
* LED BO 60 153 1 GI
01751 Time Overcurrent Phase is OFF (O/C
Phase OF F) Time overcurrent
Phase OUT ON
OFF
* LED BO 60 21 1 GI
01752 Time Overcurrent Phase is BLOCKED
(O/C Phase BLK) Time overcurrent
Phase OUT ON
OFF
ON
OFF
LED BO 60 22 1 GI
01753 Time Overcurrent Phase is ACTIVE
(O/C Phase ACT) Time overcurrent
Phase OUT ON
OFF
* LED BO 60 23 1 GI
01756 Time Overcurrent Earth is OFF (O/C
Earth OFF) Time overcurrent
Earth OUT ON
OFF
* LED BO 60 26 1 GI
01757 Time Overcurrent Earth is BLOCKED
(O/C Earth BLK) Time overcurrent
Earth OUT ON
OFF
ON
OFF
LED BO 60 27 1 GI
01758 Time Overcurrent Earth is ACTIVE (O/
C Earth ACT) Time overcurrent
Earth OUT ON
OFF
* LED BO 60 28 1 GI
01761 Time Overcurrent picked up (Overcur-
rent PU) General O/C OUT * ON
OFF LED BO 60 69 2 GI
01762 Time Overcurrent Phase L1 picked up
(O/C Ph L1 PU) Time overcurrent
Phase OUT * ON
OFF M LED BO 60 112 2 GI
01763 Time Overcurrent Phase L2 picked up
(O/C Ph L2 PU) Time overcurrent
Phase OUT * ON
OFF M LED BO 60 113 2 GI
01764 Time Overcurrent Phase L3 picked up
(O/C Ph L3 PU) Time overcurrent
Phase OUT * ON
OFF M LED BO 60 114 2 GI
01765 Time Overcurrent Earth picked up (O/
C Earth PU) Time overcurrent
Earth OUT * ON
OFF M LED BO 60 67 2 GI
01766 Time Overcurrent 3I0 picked up (O/C
3I0 PU) Time overcurrent
3I0 OUT * ON
OFF M LED BO 60 154 2 GI
F.No. Description Function Type
of
Infor-
ma-
tion
Log-Buffers Configurable in Matrix IEC 60870-5-103
Event Log On/Off
Trip (Fau lt) Lo g On/Off
Ground Fault Log On/Off
Marked in Oscill. Record
LED
Binary Input
Function Key
Binary Output
Chatter Blocking
Type
Information-No
Data Unit (ASDU)
General Interrogation
A.8 List of Information
3297UT612 Manual
C53000–G1176–C148–1
01791 Time Overcurrent TRIP (Overcurrent-
TRIP) General O/C OUT * ON M LED BO 60 68 2 GI
01800 I>> picked up (I>> picked up) Time overcurrent
Phase OUT * ON
OFF LED BO 60 75 2 GI
01804 I>> Time Out (I>> Time Out) Time overcurrent
Phase OUT * * LED BO 60 49 2 GI
01805 I>> TRIP (I>> TRIP) Time overcurrent
Phase OUT * ON LED BO 60 70 2 GI
01810 I> picked up (I> picked up) Time overcurrent
Phase OUT * ON
OFF LED BO 60 76 2 GI
01814 I> Time Out (I> Time Out) Time overcurrent
Phase OUT * * LED BO 60 53 2 GI
01815 I> TRIP (I> TRIP) Time overcurrent
Phase OUT * ON LED BO 60 71 2 GI
01820 Ip picked up (Ip picked up) Time overcurrent
Phase OUT * ON
OFF LED BO 60 77 2 GI
01824 Ip Time Out (Ip Time Out) Time overcurrent
Phase OUT * * LED BO 60 57 2 GI
01825 Ip TRIP (Ip TRIP) Time overcurrent
Phase OUT * ON LED BO 60 58 2 GI
01831 IE>> picked up (IE>> picked up) Time overcurrent
Earth OUT * ON
OFF LED BO 60 59 2 GI
01832 IE>> Time Out (IE>> Time Out) Time overcurrent
Earth OUT * * LED BO 60 60 2 GI
01833 IE>> TRIP (IE>> TRIP) Time overcurrent
Earth OUT * ON LED BO 60 61 2 GI
01834 IE> picked up (IE> picked up) Time overcurrent
Earth OUT * ON
OFF LED BO 60 62 2 GI
01835 IE> Time Out (IE> Time Out) Time overcurrent
Earth OUT * * LED BO 60 63 2 GI
01836 IE> TRIP (IE> TRIP) Time overcurrent
Earth OUT * ON LED BO 60 72 2 GI
01837 IEp picked up (IEp picked up) Time overcurrent
Earth OUT * ON
OFF LED BO 60 64 2 GI
01838 IEp Time Out (IEp TimeOut) Time overcurrent
Earth OUT * * LED BO 60 65 2 GI
01839 IEp TRIP (IEp TRIP) Time overcurrent
Earth OUT * ON LED BO 60 66 2 GI
01843 Cross blk: PhX blocked PhY (INRUSH
X-BLK) Time overcurrent
Phase OUT * ON
OFF LED BO
01851 I> BLOCKED (I> BLOCKED) Time overcurrent
Phase OUT ON
OFF
ON
OFF
LED BO 60 105 1 GI
01852 I>> BLOCKED (I>> BLOCKED) Time overcurrent
Phase OUT ON
OFF
ON
OFF
LED BO 60 106 1 GI
F.No. Description Function Type
of
Infor-
ma-
tion
Log-Buffers Configurable in Matrix IEC 60870-5-103
Event Log On/Off
Trip (Fau lt) Lo g On/Off
Ground Fault Log On/Off
Marked in Oscill. Record
LED
Binary Input
Function Key
Binary Output
Chatter Blocking
Type
Information-No
Data Unit (ASDU)
General Interrogation
A Appendix
330 7UT612 Manual
C53000–G1176–C148–1
01853 IE> BLOCKED (IE> BLOCKED) Time overcurrent
Earth OUT ON
OFF
ON
OFF
LED BO 60 107 1 GI
01854 IE>> BLOCKED (IE>> BLOCKED) Time overcurrent
Earth OUT ON
OFF
ON
OFF
LED BO 60 108 1 GI
01855 Ip BLOCKED (Ip BLOCKED) Time overcurrent
Phase OUT ON
OFF
ON
OFF
LED BO 60 109 1 GI
01856 IEp BLOCKED (IEp BLOCKED) Time overcurrent
Earth OUT ON
OFF
ON
OFF
LED BO 60 110 1 GI
01857 3I0> BLO CK ED (3I 0> BLOC KED ) Time overcu rrent
3I0 OUT ON
OFF
ON
OFF
LED BO 60 159 1 GI
01858 3I0> > BLO CK ED (3I 0>> BLOC KED ) Time overcu rrent
3I0 OUT ON
OFF
ON
OFF
LED BO 60 155 1 GI
01859 3I0p BLOCKED (3I0p BLOCKED) Time overcurrent
3I0 OUT ON
OFF
ON
OFF
LED BO 60 163 1 GI
01860 O/C Phase Not avali. for this objekt
(O/C Ph. Not av.) Time overcurrent
Phase OUT ON * LED BO
01861 O/C 3I0 Not avali. for this objekt (O/C
3I0 Not av.) Time overcurrent
3I0 OUT ON * LED BO
01901 3I0> > pic ked up (3I 0> > pic ked up) Time overcu rr ent
3I0 OUT * ON
OFF LED BO 60 156 2 GI
01902 3I0>> Time Out (3I0>> Time Out) Time overcurrent
3I0 OUT * * LED BO 60 157 2 GI
01903 3I0>> TRIP (3I0>> TRIP) Time overcurrent
3I0 OUT * ON LED BO 60 158 2 GI
01904 3I0> pick ed up (3I 0> pic ked up) T ime overcu rrent
3I0 OUT * ON
OFF LED BO 60 160 2 GI
01905 3I0> Time Out (3I0> Time Out) Time overcurrent
3I0 OUT * * LED BO 60 161 2 GI
01906 3I0> TRIP (3I0> TRIP) Time overcurrent
3I0 OUT * ON LED BO 60 162 2 GI
01907 3I0p picked up (3I0p picked up) Time overcurrent
3I0 OUT * ON
OFF LED BO 60 164 2 GI
01908 3I0p Time Out (3I0p TimeOut) Time overcurrent
3I0 OUT * * LED BO 60 165 2 GI
01909 3I0p TRIP (3I0p TRIP) Time overcurrent
3I0 OUT * ON LED BO 60 166 2 GI
01994 Cold- Load- Picku p swit ched OFF ( CLP
OFF) Cold Load Pickup OUT ON
OFF * LED BO 60 244 1 GI
01995 Cold-Load-Pickup is BLOCKED (CLP
BLOCKED) Cold Load Pickup OUT ON
OFF ON
OFF LED BO 60 245 1 GI
01996 Cold-Load-Pickup is RUNNING (CLP
running) Cold Load Pickup OUT ON
OFF * LED BO 60 246 1 GI
01998 Dynamic settings O/C Phase are
ACTIVE (I Dyn.set. ACT) Cold Load Pickup OUT ON
OFF ON
OFF LED BO 60 248 1 GI
F.No. Description Function Type
of
Infor-
ma-
tion
Log-Buffers Configurable in Matrix IEC 60870-5-103
Event Log On/Off
Trip (Fau lt) Lo g On/Off
Ground Fault Log On/Off
Marked in Oscill. Record
LED
Binary Input
Function Key
Binary Output
Chatter Blocking
Type
Information-No
Data Unit (ASDU)
General Interrogation
A.8 List of Information
3317UT612 Manual
C53000–G1176–C148–1
01999 Dynamic settings O/C 3I0 are ACTIVE
(3I0 Dyn.set.ACT) Cold Load Pickup OUT ON
OFF ON
OFF LED BO 60 249 1 GI
02000 Dynamic settings O/C Earth are
ACTIVE (IE Dyn.set. ACT) Cold Load Pickup OUT ON
OFF ON
OFF LED BO 60 250 1 GI
04523 >Block external trip 1 (>BLOCK Ext 1) External Trip
Functions SP * * LED BI BO
04526 >Trigger external trip 1 (>Ext trip 1) External Trip
Functions SP ON
OFF
* LED BI BO 51 126 1 GI
04531 External trip 1 is switched OFF (Ext 1
OFF) External Trip
Functions OUT ON
OFF
* LED BO 51 131 1 GI
04532 External trip 1 is BLOCKED (Ext 1
BLOCKED) E xternal Trip
Functions OUT ON
OFF
ON
OFF
LED BO 51 132 1 GI
04533 External trip 1 is ACTIVE (Ext 1
ACTIVE) External Trip
Functions OUT ON
OFF
* LED BO 51 133 1 GI
04536 External trip 1: General picked up (Ext
1 picked up) External Trip
Functions OUT * ON
OFF LED BO 51 136 2 GI
04537 External trip 1: General TRIP (Ext 1
Gen. TRIP) External Trip
Functions OUT * ON LED BO 51 137 2 GI
04543 >BLOCK external trip 2 (>BLOCK Ext
2) External Trip
Functions SP * * LED BI BO
04546 >Trigger external trip 2 (>Ext trip 2) External Trip
Functions SP ON
OFF
* LED BI BO 51 146 1 GI
04551 External trip 2 is switched OFF (Ext 2
OFF) External Trip
Functions OUT ON
OFF
* LED BO 51 151 1 GI
04552 External trip 2 is BLOCKED (Ext 2
BLOCKED) E xternal Trip
Functions OUT ON
OFF
ON
OFF
LED BO 51 152 1 GI
04553 External trip 2 is ACTIVE (Ext 2
ACTIVE) External Trip
Functions OUT ON
OFF
* LED BO 51 153 1 GI
04556 External trip 2: General picked up (Ext
2 picked up) External Trip
Functions OUT * ON
OFF LED BO 51 156 2 GI
04557 External trip 2: General TRIP (Ext 2
Gen. TRIP) External Trip
Functions OUT * ON LED BO 51 157 2 GI
05143 >BLOCK I2 (Unbalance Load)
(>BLOCK I2) Unbalance Load
(Negative
Sequence)
SP * * LED BI BO 70 126 1 GI
05145 >Reverse Phase Rotation (>Reverse
Rot.) Power System Data
1 SP ON
OFF
* LED BI BO 71 34 1 GI
05147 Phase Rotation L1L2L3 (Rotation
L1L2L3) Power System Data
1 OUT ON
OFF
* LED BO 70 128 1 GI
05148 Phase Rotation L1L3L2 (Rotation
L1L3L2) Power System Data
1 OUT ON
OFF
* LED BO 70 129 1 GI
05151 I2 switched OFF (I2 OFF) Unbalance Load
(Negative
Sequence)
OUT ON
OFF
* LED BO 70 131 1 GI
F.No. Description Function Type
of
Infor-
ma-
tion
Log-Buffers Configurable in Matrix IEC 60870-5-103
Event Log On/Off
Trip (Fau lt) Lo g On/Off
Ground Fault Log On/Off
Marked in Oscill. Record
LED
Binary Input
Function Key
Binary Output
Chatter Blocking
Type
Information-No
Data Unit (ASDU)
General Interrogation
A Appendix
332 7UT612 Manual
C53000–G1176–C148–1
05152 I2 is BLOCKED (I2 BLOCKED) Unbalance Load
(Negative
Sequence)
OUT ON
OFF
ON
OFF
LED BO 70 132 1 GI
05153 I2 is ACTIVE (I2 ACTIVE) Unbalance Load
(Negative
Sequence)
OUT ON
OFF
* LED BO 70 133 1 GI
05159 I2>> picked up (I2>> picked up) Unbalance Load
(Negative
Sequence)
OUT * ON
OFF LED BO 70 138 2 GI
05165 I2> picked up (I2> picked up) Unbalance Load
(Negative
Sequence)
OUT * ON
OFF LED BO 70 150 2 GI
05166 I2p picked up (I2p picked up) Unbalance Load
(Negative
Sequence)
OUT * ON
OFF LED BO 70 141 2 GI
05170 I2 TRI P (I2 TRI P) U n ba lance Load
(Neg ative
Seque nce )
OUT * ON M LED BO 70 149 2 GI
05172 I2 Not avaliable for this objekt (I2 Not
avalia.) Unbalance Load
(Negative
Sequence)
OUT ON * LED BO
05603 >BLOCK differential protection (>Diff
BLOCK) Differential Protec-
tion SP * * LED BI BO
05615 Differential protection is switched OFF
(Diff OFF) Differential Protec-
tion OUT ON
OFF
* LED BO 75 15 1 GI
05616 Differential protection is BLOCKED
(Diff BLOCKED) Differential Protec-
tion OUT ON
OFF
ON
OFF
LED BO 75 16 1 GI
05617 Differential protection is ACTIVE (Diff
ACTIVE) Differential Protec-
tion OUT ON
OFF
* LED BO 75 17 1 GI
05620 Diff: adverse Adaption factor CT (Diff
Adap.fact.) Differential Protec-
tion OUT ON * LED BO
056 3 1 Differential protection picked up (Diff
picked up) Differential Protec-
tion OUT * ON
OFF M LED BO 75 31 2 GI
05644 Diff: Blocked by 2.Harmon. L1 (Diff
2.Harm L1) Differential Protec-
tion OUT * ON
OFF LED BO 75 44 2 GI
05645 Diff: Blocked by 2.Harmon. L2 (Diff
2.Harm L2) Differential Protec-
tion OUT * ON
OFF LED BO 75 45 2 GI
05646 Diff: Blocked by 2.Harmon. L3 (Diff
2.Harm L3) Differential Protec-
tion OUT * ON
OFF LED BO 75 46 2 GI
05647 Diff: Blocked by n.Harmon. L1 (Diff
n.Harm L1) Differential Protec-
tion OUT * ON
OFF LED BO 75 47 2 GI
05648 Diff: Blocked by n.Harmon. L2 (Diff
n.Harm L2) Differential Protec-
tion OUT * ON
OFF LED BO 75 48 2 GI
05649 Diff: Blocked by n.Harmon. L3 (Diff
n.Harm L3) Differential Protec-
tion OUT * ON
OFF LED BO 75 49 2 GI
05651 Diff. prot.: Blocked by ext. fault L1 (Diff
Bl. exF.L1) Differential Protec-
tion OUT * ON
OFF LED BO 75 51 2 GI
F.No. Description Function Type
of
Infor-
ma-
tion
Log-Buffers Configurable in Matrix IEC 60870-5-103
Event Log On/Off
Trip (Fau lt) Lo g On/Off
Ground Fault Log On/Off
Marked in Oscill. Record
LED
Binary Input
Function Key
Binary Output
Chatter Blocking
Type
Information-No
Data Unit (ASDU)
General Interrogation
A.8 List of Information
3337UT612 Manual
C53000–G1176–C148–1
05652 Diff. prot.: Blocked by ext. fault L2 (Diff
Bl. exF.L2) Differential Protec-
tion OUT * ON
OFF LED BO 75 52 2 GI
05653 Diff. prot.: Blocked by ext. fault.L3 (Diff
Bl. exF.L3) Differential Protec-
tion OUT * ON
OFF LED BO 75 53 2 GI
05657 Diff: Crossblock by 2.Harmonic
(DiffCrosBlk2HM) Differential Protec-
tion OUT * ON
OFF LED BO
05658 Diff: Crossblock by n.Harmonic (Diff-
CrosBlknHM) Differential Protec-
tion OUT * ON
OFF LED BO
05662 Diff. prot.: Blocked by CT fault L1
(Block Iflt.L1) Differential Protec-
tion OUT ON
OFF
ON
OFF
LED BO 75 62 2 GI
05663 Diff. prot.: Blocked by CT fault L2
(Block Iflt.L2) Differential Protec-
tion OUT ON
OFF
ON
OFF
LED BO 75 63 2 GI
05664 Diff. prot.: Blocked by CT fault L3
(Block Iflt.L3) Differential Protec-
tion OUT ON
OFF
ON
OFF
LED BO 75 64 2 GI
05666 Diff: Increase of char. phase L1 (Diff
in.char.L1) Differential Protec-
tion OUT ON
OFF
ON
OFF
LED BO
05667 Diff: Increase of char. phase L2 (Diff
in.char.L2) Differential Protec-
tion OUT ON
OFF
ON
OFF
LED BO
05668 Diff: Increase of char. phase L3 (Diff
in.char.L3) Differential Protec-
tion OUT ON
OFF
ON
OFF
LED BO
05670 Diff: Curr-Release for Trip (Diff I-
Release) Differential Protec-
tion OUT * ON
OFF LED BO
05671 Differential protection TRIP (Diff TRIP) Differential Protec-
tion OUT * * LED BO 176 68 2
05672 Differential protection: TRIP L1 (Diff
TRIP L1) Differential Protec-
tion OUT * * LED BO 176 86 2
05673 Differential protection: TRIP L2 (Diff
TRIP L2) Differential Protec-
tion OUT * * LED BO 176 87 2
05674 Differential protection: TRIP L3 (Diff
TRIP L3) Differential Protec-
tion OUT * * LED BO 176 88 2
05681 Diff. prot.: IDIFF> L1 (without Tdelay)
(Diff> L1) Differential Protec-
tion OUT * ON
OFF LED BO 75 81 2 GI
05682 Diff. prot.: IDIFF> L2 (without Tdelay)
(Diff> L2) Differential Protec-
tion OUT * ON
OFF LED BO 75 82 2 GI
05683 Diff. prot.: IDIFF> L3 (without Tdelay)
(Diff> L3) Differential Protec-
tion OUT * ON
OFF LED BO 75 83 2 GI
05684 Diff. prot: IDIFF>> L1 (without Tdelay)
(Diff>> L1) Differential Protec-
tion OUT * ON
OFF LED BO 75 84 2 GI
05685 Diff. prot: IDIFF>> L2 (without Tdelay)
(Diff>> L2) Differential Protec-
tion OUT * ON
OFF LED BO 75 85 2 GI
05686 Diff. prot: IDIFF>> L3 (without Tdelay)
(Diff>> L3) Differential Protec-
tion OUT * ON
OFF LED BO 75 86 2 GI
05691 Differential prot.: TRIP by IDIFF>
(Diff> TRIP) Differential Protec-
tion OUT * ON M LED BO 75 91 2 GI
F.No. Description Function Type
of
Infor-
ma-
tion
Log-Buffers Configurable in Matrix IEC 60870-5-103
Event Log On/Off
Trip (Fau lt) Lo g On/Off
Ground Fault Log On/Off
Marked in Oscill. Record
LED
Binary Input
Function Key
Binary Output
Chatter Blocking
Type
Information-No
Data Unit (ASDU)
General Interrogation
A Appendix
334 7UT612 Manual
C53000–G1176–C148–1
05692 Differential prot.: TRIP by IDIFF>>
(Diff>> TRIP) Differential Protec-
tion OUT * ON M LED BO 75 92 2 GI
05701 Diff. curr. in L1 at trip without Tdelay
(Dif L1 :) Differential Protec-
tion OUT * ON
OFF 75 101 4
05702 Diff. curr. in L2 at trip without Tdelay
(Dif L2 :) Differential Protec-
tion OUT * ON
OFF 75 102 4
05703 Diff. curr. in L3 at trip without Tdelay
(Dif L3 :) Differential Protec-
tion OUT * ON
OFF 75 103 4
05704 Restr.curr. in L1 at trip without Tdelay
(Res L1 :) Differential Protec-
tion OUT * ON
OFF 75 104 4
05705 Restr.curr. in L2 at trip without Tdelay
(Res L2 :) Differential Protec-
tion OUT * ON
OFF 75 105 4
05706 Restr.curr. in L3 at trip without Tdelay
(Res L3 :) Differential Protec-
tion OUT * ON
OFF 75 106 4
05803 >BLOCK restricted earth fault prot.
(>BLOCK REF) Restricted Earth
Fault Protection SP * * LED BI BO
05811 Restricted earth fault is switched OFF
(REF OFF) Restricted Earth
Fault Protection OUT ON
OFF
* LED BO 76 11 1 GI
05812 Restricted earth fault is BLOCKED
(REF BLOCKED) Restricted Earth
Fault Protection OUT ON
OFF
ON
OFF
LED BO 76 12 1 GI
05813 Restricted earth fault is ACTIVE (REF
ACTIVE) Restricted Earth
Fault Protection OUT ON
OFF
* LED BO 76 13 1 GI
05816 Restr. earth flt.: Time delay started
(REF T start) Restricted Earth
Fault Protection OUT * ON
OFF LED BO 76 16 2 GI
05817 Restr. earth flt.: picked up (REF pik-
ked up) Restricted Earth
Fault Protection OUT * ON
OFF M LED BO 76 17 2 GI
05821 Restr. earth flt.: TRIP (REF TRIP) Restricted Earth
Fault Protection OUT * ON M LED BO 176 89 2
05826 REF: Value D at trip (without Tdelay)
(REF D:) Restricted Earth
Fault Protection OUT * ON
OFF 76 26 4
05827 REF: Value S at trip (without Tdelay)
(REF S:) Restricted Earth
Fault Protection OUT * ON
OFF 76 27 4
05830 REF err.: No starpoint CT (REF Err
CTstar) Restricted Earth
Fault Protection OUT ON * LED BO
05835 REF err: Not avaliable for this objekt
(REF Not avalia.) Restricted Earth
Fault Protection OUT ON * LED BO
05836 REF: adverse Adaption factor CT
(REF Adap.fact.) Restricted Earth
Fault Protection OUT ON * LED BO
05951 >BLOCK Time Overcurrent 1Phase
(>BLK 1Ph. O/C) Time overcurrent
1Phase SP * * LED BI BO
05952 >BLOCK Time Overcurrent 1Ph. I>
(>BLK 1Ph. I> ) Time overcurrent
1Phase SP * * LED BI BO
05953 >BLOCK Time Overcurrent 1Ph. I>>
(>BLK 1Ph. I> >) Time overcurrent
1Phase SP * * LED BI BO
F.No. Description Function Type
of
Infor-
ma-
tion
Log-Buffers Configurable in Matrix IEC 60870-5-103
Event Log On/Off
Trip (Fau lt) Lo g On/Off
Ground Fault Log On/Off
Marked in Oscill. Record
LED
Binary Input
Function Key
Binary Output
Chatter Blocking
Type
Information-No
Data Unit (ASDU)
General Interrogation
A.8 List of Information
3357UT612 Manual
C53000–G1176–C148–1
05961 Time Overcurrent 1Phase is OFF (O/C
1Ph. OFF) Time overcurrent
1Phase OUT ON
OFF
* LED BO 76 161 1 GI
05962 Time Overcurrent 1Phase is BLOK-
KED (O/C 1Ph. BLK) Time overcurrent
1Phase OUT ON
OFF
ON
OFF
LED BO 76 162 1 GI
05963 Time Overcurrent 1Phase is ACTIVE
(O/C 1Ph. ACT) Time overcurrent
1Phase OUT ON
OFF
* LED BO 76 163 1 GI
05966 Time Overcurrent 1Phase I> BLOK-
KED (O/C 1Ph I> BLK) Time overcurrent
1Phase OUT ON
OFF
ON
OFF
LED BO 76 166 1 GI
05967 Time Overcurrent 1Phase I>> BLOK-
KED (O/C 1Ph I>> BLK) Time overcurrent
1Phase OUT ON
OFF
ON
OFF
LED BO 76 167 1 GI
05971 Time Overcurrent 1Phase picked up
(O/C 1Ph PU) Time overcurrent
1Phase OUT * ON
OFF LED BO 76 171 2 GI
05972 Time Overcurrent 1Phase TRIP (O/C
1Ph TRIP) Time overcurrent
1Phase OUT * ON LED BO 76 172 2 GI
05974 Time Overcurrent 1Phase I> picked
up (O/C 1Ph I> PU) Time overcurrent
1Phase OUT * ON
OFF LED BO 76 174 2 GI
05975 Time Overcurrent 1Phase I> TRIP (O/
C 1Ph I> TRIP) Time overcurrent
1Phase OUT * ON M LED BO 76 175 2 GI
05977 Time Overcurrent 1Phase I>> picked
up (O/C 1Ph I>> PU) Time overcurrent
1Phase OUT * ON
OFF LED BO 76 177 2 GI
05979 Time Overcurrent 1Phase I>> TRIP
(O/C1Ph I>> TRIP) Time overcurrent
1Phase OUT * ON M LED BO 76 179 2 GI
05980 Time Over c urr en t 1P ha s e: I at p ic k up
(O/C 1Ph I:) Time overcurrent
1Phase OUT * ON
OFF 76 180 4
06851 >BLOCK Trip circuit supervision
(>BLOCK TripC) Trip Circuit Supervi-
sion SP * * LED BI BO
06852 >Trip circuit supervision: trip relay
(>TripC trip rel) Trip Circuit Supervi-
sion SP ON
OFF
* LED BI BO 170 51 1 GI
06853 >Trip circuit supervision: breaker relay
(>TripC brk rel.) Trip Cir cuit Supervi-
sion SP ON
OFF
* LED BI BO 170 52 1 GI
06861 Trip circuit supervision OFF (TripC
OFF) Trip Circuit Supervi-
sion OUT ON
OFF
* LED BO 170 53 1 GI
06862 Trip circuit supervision is BLOCKED
(TripC BLOCKED) Trip Circuit Supervi-
sion OUT ON
OFF
ON
OFF
LED BO 153 16 1 GI
06863 Trip circuit supervision is ACTIVE
(TripC ACTIVE ) Trip Circuit Supervi-
sion OUT ON
OFF
* LED BO 153 17 1 GI
06864 Trip Circuit blk. Bin. input is not set
(TripC ProgFail) Trip Circuit Supervi-
sion OUT ON
OFF
* LED BO 170 54 1 GI
06865 Failure Trip Circuit (FAIL: Trip cir.) Trip Circuit Supervi-
sion OUT ON
OFF
* LED BO 170 55 1 GI
07551 I> InRush picked up (I> InRush PU) Time overcurrent
Phase OUT * ON
OFF LED BO 60 80 2 GI
07552 IE> InRush picked up (IE> InRush PU) Time overcurrent
Earth OUT * ON
OFF LED BO 60 81 2 GI
F.No. Description Function Type
of
Infor-
ma-
tion
Log-Buffers Configurable in Matrix IEC 60870-5-103
Event Log On/Off
Trip (Fau lt) Lo g On/Off
Ground Fault Log On/Off
Marked in Oscill. Record
LED
Binary Input
Function Key
Binary Output
Chatter Blocking
Type
Information-No
Data Unit (ASDU)
General Interrogation
A Appendix
336 7UT612 Manual
C53000–G1176–C148–1
07553 Ip InRush picked up (Ip InRush PU) Time overcurrent
Phase OUT * ON
OFF LED BO 60 82 2 GI
07554 IEp InRush picked up (IEp InRush PU) Time overcurrent
Earth OUT * ON
OFF LED BO 60 83 2 GI
07564 Earth InRush picked up (Earth InRush
PU) Time overcurrent
Earth OUT * ON
OFF LED BO 60 88 2 GI
07565 Phase L1 InRush picked up (L1
InRush PU) Time overcurrent
Phase OUT * ON
OFF LED BO 60 89 2 GI
07566 Phase L2 InRush picked up (L2
InRush PU) Time overcurrent
Phase OUT * ON
OFF LED BO 60 90 2 GI
07567 Phase L3 InRush picked up (L3
InRush PU) Time overcurrent
Phase OUT * ON
OFF LED BO 60 91 2 GI
07568 3I0 InRush picked up (3I0 InRush PU) Time overcurrent
3I0 OUT * ON
OFF LED BO 60 95 2 GI
07569 3I0> InRush picked up (3I0> InRush
PU) Time overcurrent
3I0 OUT * ON
OFF LED BO 60 96 2 GI
07570 3I0p InR us h pic ked up (3I 0p InR u sh
PU) Time overcurrent
3I0 OUT * ON
OFF LED BO 60 97 2 GI
07571 >BLOCK time overcurrent Phase
InRush (>BLK Ph.O/C Inr) Time overcurrent
Phase SP ON
OFF
ON
OFF
LED BI BO 60 98 1 GI
07572 >BLOCK time overcurrent 3I0 InRush
(>BLK 3I0O/C Inr) Time overcurrent
3I0 SP ON
OFF
ON
OFF
LED BI BO 60 99 1 GI
07573 >BLOCK time overcurrent Earth
InRush (>BLK E O/C Inr) Time overcurrent
Earth SP ON
OFF
ON
OFF
LED BI BO 60 100 1 GI
07581 Phase L1 InRush detected (L1 InRush
det.) Time overcurrent
Phase OUT * ON
OFF LED BO
07582 Phase L2 InRush detected (L2 InRush
det.) Time overcurrent
Phase OUT * ON
OFF LED BO
07583 Phase L3 InRush detected (L3 InRush
det.) Time overcurrent
Phase OUT * ON
OFF LED BO
14101 Fail: RTD (broken wire/shorted) (Fail:
RTD) RTD-Box OUT ON
OFF
* LED BO
14111 Fail: RTD 1 (broken wire/shorted)
(Fail: RTD 1) RTD-Box OUT ON
OFF
* LED BO
14112 RTD 1 Temperature stage 1 picked up
(RTD 1 St.1 p.up) RTD-Box OUT ON
OFF
* LED BO
14113 RTD 1 Temperature stage 2 picked up
(RTD 1 St.2 p.up) RTD-Box OUT ON
OFF
* LED BO
14121 Fail: RTD 2 (broken wire/shorted)
(Fail: RTD 2) RTD-Box OUT ON
OFF
* LED BO
14122 RTD 2 Temperature stage 1 picked up
(RTD 2 St.1 p.up) RTD-Box OUT ON
OFF
* LED BO
14123 RTD 2 Temperature stage 2 picked up
(RTD 2 St.2 p.up) RTD-Box OUT ON
OFF
* LED BO
F.No. Description Function Type
of
Infor-
ma-
tion
Log-Buffers Configurable in Matrix IEC 60870-5-103
Event Log On/Off
Trip (Fau lt) Lo g On/Off
Ground Fault Log On/Off
Marked in Oscill. Record
LED
Binary Input
Function Key
Binary Output
Chatter Blocking
Type
Information-No
Data Unit (ASDU)
General Interrogation
A.8 List of Information
3377UT612 Manual
C53000–G1176–C148–1
14131 Fail: RTD 3 (broken wire/shorted)
(Fail: RTD 3) RTD-Box OUT ON
OFF
* LED BO
14132 RTD 3 Temperature stage 1 picked up
(RTD 3 St.1 p.up) RTD-Box OUT ON
OFF
* LED BO
14133 RTD 3 Temperature stage 2 picked up
(RTD 3 St.2 p.up) RTD-Box OUT ON
OFF
* LED BO
14141 Fail: RTD 4 (broken wire/shorted)
(Fail: RTD 4) RTD-Box OUT ON
OFF
* LED BO
14142 RTD 4 Temperature stage 1 picked up
(RTD 4 St.1 p.up) RTD-Box OUT ON
OFF
* LED BO
14143 RTD 4 Temperature stage 2 picked up
(RTD 4 St.2 p.up) RTD-Box OUT ON
OFF
* LED BO
14151 Fail: RTD 5 (broken wire/shorted)
(Fail: RTD 5) RTD-Box OUT ON
OFF
* LED BO
14152 RTD 5 Temperature stage 1 picked up
(RTD 5 St.1 p.up) RTD-Box OUT ON
OFF
* LED BO
14153 RTD 5 Temperature stage 2 picked up
(RTD 5 St.2 p.up) RTD-Box OUT ON
OFF
* LED BO
14161 Fail: RTD 6 (broken wire/shorted)
(Fail: RTD 6) RTD-Box OUT ON
OFF
* LED BO
14162 RTD 6 Temperature stage 1 picked up
(RTD 6 St.1 p.up) RTD-Box OUT ON
OFF
* LED BO
14163 RTD 6 Temperature stage 2 picked up
(RTD 6 St.2 p.up) RTD-Box OUT ON
OFF
* LED BO
14171 Fail: RTD 7 (broken wire/shorted)
(Fail: RTD 7) RTD-Box OUT ON
OFF
* LED BO
14172 RTD 7 Temperature stage 1 picked up
(RTD 7 St.1 p.up) RTD-Box OUT ON
OFF
* LED BO
14173 RTD 7 Temperature stage 2 picked up
(RTD 7 St.2 p.up) RTD-Box OUT ON
OFF
* LED BO
14181 Fail: RTD 8 (broken wire/shorted)
(Fail: RTD 8) RTD-Box OUT ON
OFF
* LED BO
14182 RTD 8 Temperature stage 1 picked up
(RTD 8 St.1 p.up) RTD-Box OUT ON
OFF
* LED BO
14183 RTD 8 Temperature stage 2 picked up
(RTD 8 St.2 p.up) RTD-Box OUT ON
OFF
* LED BO
14191 Fail: RTD 9 (broken wire/shorted)
(Fail: RTD 9) RTD-Box OUT ON
OFF
* LED BO
14192 RTD 9 Temperature stage 1 picked up
(RTD 9 St.1 p.up) RTD-Box OUT ON
OFF
* LED BO
14193 RTD 9 Temperature stage 2 picked up
(RTD 9 St.2 p.up) RTD-Box OUT ON
OFF
* LED BO
14201 Fail: RTD10 (broken wire/shorted)
(Fail: RTD10) RTD-Box OUT ON
OFF
* LED BO
F.No. Description Function Type
of
Infor-
ma-
tion
Log-Buffers Configurable in Matrix IEC 60870-5-103
Event Log On/Off
Trip (Fau lt) Lo g On/Off
Ground Fault Log On/Off
Marked in Oscill. Record
LED
Binary Input
Function Key
Binary Output
Chatter Blocking
Type
Information-No
Data Unit (ASDU)
General Interrogation
A Appendix
338 7UT612 Manual
C53000–G1176–C148–1
14202 RTD10 Temperature stage 1 picked
up (RTD10 St.1 p.up) RTD-Box OUT ON
OFF
* LED BO
14203 RTD10 Temperature stage 2 picked
up (RTD10 St.2 p.up) RTD-Box OUT ON
OFF
* LED BO
14211 Fail: RTD11 (broken wire/shorted)
(Fail: RTD11) RTD-Box OUT ON
OFF
* LED BO
14212 RTD11 Temperature stage 1 picked
up (RTD11 St.1 p.up) RTD-Box OUT ON
OFF
* LED BO
14213 RTD11 Temperature stage 2 picked
up (RTD11 St.2 p.up) RTD-Box OUT ON
OFF
* LED BO
14221 Fail: RTD12 (broken wire/shorted)
(Fail: RTD12) RTD-Box OUT ON
OFF
* LED BO
14222 RTD12 Temperature stage 1 picked
up (RTD12 St.1 p.up) RTD-Box OUT ON
OFF
* LED BO
14223 RTD12 Temperature stage 2 picked
up (RTD12 St.2 p.up) RTD-Box OUT ON
OFF
* LED BO
30607 Accumulation of interrupted curr. L1
S1 (ΣIL1S1:) Statistics OUT
30608 Accumulation of interrupted curr. L2
S1 (ΣIL2S1:) Statistics OUT
30609 Accumulation of interrupted curr. L3
S1 (ΣIL3S1:) Statistics OUT
30610 Accumulation of interrupted curr. L1
S2 (ΣIL1S2:) Statistics OUT
30611 Accumulation of interrupted curr. L2
S2 (ΣIL2S2:) Statistics OUT
30612 Accumulation of interrupted curr. L3
S2 (ΣIL3S2:) Statistics OUT
30620 Accumulation of interrupted curr. I1
(ΣI1:) Statistics OUT
30621 Accumulation of interrupted curr. I2
(ΣI2:) Statistics OUT
30622 Accumulation of interrupted curr. I3
(ΣI3:) Statistics OUT
30623 Accumulation of interrupted curr. I4
(ΣI4:) Statistics OUT
30624 Accumulation of interrupted curr. I5
(ΣI5:) Statistics OUT
30625 Accumulation of interrupted curr. I6
(ΣI6:) Statistics OUT
30626 Accumulation of interrupted curr. I7
(ΣI7:) Statistics OUT
>Back Light on (>Light on) Device SP ON
OFF * LED BI BO
F.No. Description Function Type
of
Infor-
ma-
tion
Log-Buffers Configurable in Matrix IEC 60870-5-103
Event Log On/Off
Trip (Fau lt) Lo g On/Off
Ground Fault Log On/Off
Marked in Oscill. Record
LED
Binary Input
Function Key
Binary Output
Chatter Blocking
Type
Information-No
Data Unit (ASDU)
General Interrogation
A.8 List of Information
3397UT612 Manual
C53000–G1176–C148–1
>Quitt Lock Out: General Trip
(>QuitG-TRP) Power System Data
2 IntSP * * LED BI FK BO
Clock Synchronization (SynchClock) Device IntSP_
Ev * * LED BO
Control Authority (Cntrl Auth) Control Authoriza-
tion IntSP ON
OFF
* LED 101 85 1 GI
Controlmode LOCAL (ModeLOCAL) Control Authoriza-
tion IntSP ON
OFF
* LED 101 86 1 GI
Controlmode REMOTE (ModeRE-
MOTE) Control Authoriza-
tion IntSP ON
OFF
* LED
Error FMS FO 1 (Error FMS1) Supervision OUT ON
OFF * LED BO
Error FMS FO 2 (Error FMS2) Supervision OUT ON
OFF * LED BO
Error Systeminterface (SysIntErr.) Supervision IntSP ON
OFF * LED BO
Fault Recording Start (FltRecSta) Oscillographic Fault
Records IntSP ON
OFF
* LED BO
Group A (Group A) Change Group IntSP ON
OFF * LED BO 176 23 1 GI
Group B (Group B) Change Group IntSP ON
OFF * LED BO 176 24 1 GI
Group C (Group C) Change Group IntSP ON
OFF * LED BO 176 25 1 GI
Group D (Group D) Change Group IntSP ON
OFF * LED BO 176 26 1 GI
Hardware Test Mode (HWTestMod) Device IntSP ON
OFF * LED BO
Lock Out: General TRIP (G-TRP Quit) Power System Data
2 IntSP * * LED BO
Stop data transmission (DataStop) Device IntSP ON
OFF * LED BO 176 20 1 GI
Test mode (Test mode) Device IntSP ON
OFF * LED BO 176 21 1 GI
Threshold Value 1 (ThreshVal1) Threshold-Switch IntSP ON
OFF * LED BI FK BO CB
Unlock data transmission via BI
(UnlockDT) Device IntSP * * LED BO
F.No. Description Function Type
of
Infor-
ma-
tion
Log-Buffers Configurable in Matrix IEC 60870-5-103
Event Log On/Off
Trip (Fau lt) Lo g On/Off
Ground Fault Log On/Off
Marked in Oscill. Record
LED
Binary Input
Function Key
Binary Output
Chatter Blocking
Type
Information-No
Data Unit (ASDU)
General Interrogation
A Appendix
340 7UT612 Manual
C53000–G1176–C148–1
A.9 List of Measured Values
F.No. Description Function IEC 60870-5-103 Configurable in
Matrix
Function type
Information-No
Compatibility
Data Unit (ASDU)
Position
CFC
Control Display
Default Display
00644 Frequency (Freq=) Measurement CFC CD DD
00645 S (apparent power) (S =) Measurement CFC CD DD
00721 Operat. meas. current IL1 side 1 (IL1S1=) Measurement 134 139 priv 9 1 CFC CD DD
00722 Operat. meas. current IL2 side 1 (IL2S1=) Measurement 134 139 priv 9 5 CFC CD DD
00723 Operat. meas. current IL3 side 1 (IL3S1=) Measurement 134 139 priv 9 3 CFC CD DD
00724 Operat. meas. current IL1 side 2 (IL1S2=) Measurement 134 139 priv 9 2 CFC CD DD
00725 Operat. meas. current IL2 side 2 (IL2S2=) Measurement 134 139 priv 9 6 CFC CD DD
00726 Operat. meas. current IL3 side 2 (IL3S2=) Measurement 134 139 priv 9 4 CFC CD DD
00801 Temperat. rise for warning and trip (Θ /Θtrip =) Thermal Measurement CFC CD DD
00802 Temperature rise for phase L1 (Θ /ΘtripL1=) Thermal Measurement CFC CD DD
00803 Temperature rise for phase L2 (Θ /ΘtripL2=) Thermal Measurement CFC CD DD
00804 Temperature rise for phase L3 (Θ /ΘtripL3=) Thermal Measurement CFC CD DD
01060 Hot spot temperature of leg 1 (Θ leg 1=) Thermal Measurement CFC CD DD
01061 Hot spot temperature of leg 2 (Θ leg 2=) Thermal Measurement CFC CD DD
01062 Hot spot temperature of leg 3 (Θ leg 3=) Thermal Measurement CFC CD DD
01063 Aging Rate (Ag.Rate=) Thermal Measurement CFC CD DD
01066 Load Reserve to warning level (ResWARN=) Thermal Measurement CFC CD DD
01067 Load Reserve to alarm level (ResALARM=) Thermal Measurement CFC CD DD
01068 Tempe rat ure of RTD 1 (Θ RTD 1 =) Thermal Measurement 134 146 priv 9 1 CFC CD DD
01069 Tempe rat ure of RTD 2 (Θ RTD 2 =) Thermal Measurement 134 146 priv 9 2 CFC CD DD
01070 Tempe rat ure of RTD 3 (Θ RTD 3 =) Thermal Measurement 134 146 priv 9 3 CFC CD DD
01071 Tempe rat ure of RTD 4 (Θ RTD 4 =) Thermal Measurement 134 146 priv 9 4 CFC CD DD
01072 Tempe rat ure of RTD 5 (Θ RTD 5 =) Thermal Measurement 134 146 priv 9 5 CFC CD DD
01073 Tempe rat ure of RTD 6 (Θ RTD 6 =) Thermal Measurement 134 146 priv 9 6 CFC CD DD
01074 Tempe rat ure of RTD 7 (Θ RTD 7 =) Thermal Measurement 134 146 priv 9 7 CFC CD DD
01075 Tempe rat ure of RTD 8 (Θ RTD 8 =) Thermal Measurement 134 146 priv 9 8 CFC CD DD
01076 Tempe rat ure of RTD 9 (Θ RTD 9 =) Thermal Measurement 134 146 priv 9 9 CFC CD DD
01077 Tempe rat ure of RTD1 0 (Θ RTD10 =) Thermal Measurement 134 146 priv 9 10 CFC CD DD
01078 Tempe rat ure of RTD1 1 (Θ RTD11 =) Thermal Measurement 134 146 priv 9 11 CFC CD DD
01079 Tempe rat ure of RTD1 2 (Θ RTD12 =) Thermal Measurement 134 146 priv 9 12 CFC CD DD
07740 Phase angle in phase IL1 side 1 (ϕIL1S1=) Measurement CFC CD DD
07741 Phase angle in phase IL2 side 1 (ϕIL2S1=) Measurement CFC CD DD
07742 IDiffL1(I/Inominal object [%]) (IDiffL1=) Diff- and Rest. Measurement CFC CD DD
A.9 List of Measured Values
3417UT612 Manual
C53000–G1176–C148–1
07743 IDiffL2(I/Inominal object [%]) (IDiffL2=) Diff- and Rest. Measurement CFC CD DD
07744 IDiffL3(I/Inominal object [%]) (IDiffL3=) Diff- and Rest. Measurement CFC CD DD
07745 IRestL1(I/Inominal object [%]) (IRestL1=) Diff- and Rest. Measurement CFC CD DD
07746 IRestL2(I/Inominal object [%]) (IRestL2=) Diff- and Rest. Measurement CFC CD DD
07747 IRestL3(I/Inominal object [%]) (IRestL3=) Diff- and Rest. Measurement CFC CD DD
07749 Phase angle in phase IL3 side 1 (ϕIL3S1=) Measurement CFC CD DD
07750 Phase angle in phase IL1 side 2 (ϕIL1S2=) Measurement CFC CD DD
07759 Phase angle in phase IL2 side 2 (ϕIL2S2=) Measurement CFC CD DD
07760 Phase angle in phase IL3 side 2 (ϕIL3S2=) Measurement CFC CD DD
30633 Phase angle of current I1 (ϕI1=) Measurement CFC CD DD
30634 Phase angle of current I2 (ϕI2=) Measurement CFC CD DD
30635 Phase angle of current I3 (ϕI3=) Measurement CFC CD DD
30636 Phase angle of current I4 (ϕI4=) Measurement CFC CD DD
30637 Phase angle of current I5 (ϕI5=) Measurement CFC CD DD
30638 Phase angle of current I6 (ϕI6=) Measurement CFC CD DD
30639 Phase angle of current I7 (ϕI7=) Measurement CFC CD DD
30640 3I0 (zero sequence) of side 1 (3I0S1=) Measurement CFC CD DD
30641 I1 (positive sequence) of side 1 (I1S1=) Measurement CFC CD DD
30642 I2 (negative sequence) of side 1 (I2S1=) Measurement CFC CD DD
30643 3I0 (zero sequence) of side 2 (3I0S2=) Measurement CFC CD DD
30644 I1 (positive sequence) of side 2 (I1S2=) Measurement CFC CD DD
30645 I2 (negative sequence) of side 2 (I2S2=) Measurement CFC CD DD
30646 Operat. meas. current I1 (I1=) Measurement CFC CD DD
30647 Operat. meas. current I2 (I2=) Measurement CFC CD DD
30648 Operat. meas. current I3 (I3=) Measurement CFC CD DD
30649 Operat. meas. current I4 (I4=) Measurement CFC CD DD
30650 Operat. meas. current I5 (I5=) Measurement CFC CD DD
30651 Operat. meas. current I6 (I6=) Measurement CFC CD DD
30652 Operat. meas. current I7 (I7=) Measurement CFC CD DD
30653 Operat. meas. current I8 (I8=) Measurement CFC CD DD
30654 Idiff REF (I/Inominal object [%]) (IdiffREF=) Diff- and Rest. Measurement CFC CD DD
30655 Irest REF (I/Inominal object [%]) (IrestREF=) Diff- and Rest. Measurement CFC CD DD
30656 Operat. meas. voltage Umeas. (Umeas.=) Measurement CFC CD DD
Operating hours greater than (OpHour>) CFC CD DD
F.No. Description Function IEC 60870-5-103 Configurable in
Matrix
Function type
Information-No
Compatibility
Data Unit (ASDU)
Position
CFC
Control Display
Default Display
A Appendix
342 7UT612 Manual
C53000–G1176–C148–1
n
3437UT612 Manual
C53000–G1176–C148–1
Index
A
Accessories 288
Acknowledgement of commands 194
Additional support ii
Ageing rate 136
Alter nati ng vo lta ge 249
Ambient temperatures 256
Applicability of manual i
Applications 5
Auto-transformers 15, 46
Auxiliary contacts of the CB 108, 153, 163, 203,
229
Auxiliary voltag e supervision 160
B
Back up batter y 160
Battery 160, 281, 289
Binary inputs 3, 249
Binary outputs 3, 175, 249
Block data transmission 223
Branch-points 15, 22, 50, 262
Breaker failure protection 152, 228, 278
Buffer battery 281, 289
Busbar protection 50, 52, 81
Busbars 15, 22, 23, 50, 52, 262
C
Caution (defi niti on ) ii
CFC 10, 281, 290
Changeover of setting groups 202
Circuit breaker auxiliary contacts 108, 153, 163,
203, 229
Circuit breaker failure pro tection 152, 228, 278
Circuit breaker status 27, 108
Climatic tests 256
Cold load pickup 108, 272
Command ac kn owle dge men t 194
Command dur ation 27
Command pr oc essi ng 189
Command sequence 190
Command types 189
Commissioning 222
Communication interfaces 250
Configuration 14
Scope of functions 14
Conformity i
Connection examples 293
Construction 257
Control and numeric keys 4
Copyright ii
Cubicle mounting 199
Current balance supervision 161
Current comparison 33
Current gr ading 82
Current guard 51, 56
Current restraint 34
Current transformer data 23, 25, 26, 27, 118
Current transformer requirements 248
D
Danger (definition) ii
DCF77 281
Definite time overcurrent protection 73, 97
Differential current monitoring 51, 56
Differe nti al protec ti on 33, 258
for branch-points 50, 262
for busbars 50, 52, 262
for generators 48, 261
for lines 50, 262
for mini-busbars 50, 262
for motors 48, 261
for reactors 48, 49, 261
for series reactors 48
for short lines 50, 262
for shunt reactors 49
for transformers 42
restricted earth fault protection 64, 263
Differential protection values 181
DIGSI 4 289
DIGSI REMOTE 4 289
Dimensions 282
Index
344 7UT612 Manual
C53000–G1176–C148–1
Direct trip 278
Direct voltage 248
Disassembling the device 207
Disk emulation 78, 100, 124
Display of measured values 179
Dynamic cold load pickup 108, 272
E
Earthing reactor (starpoint former) 15, 44, 45, 49,
64
Electrical tests 253
EMC t ests 254, 255
Emergency starting 132
Event log 177
External signals 278
External trip 278
F
Fault detection 39, 171
Fault detection logic 171
Fault messages 177
Fault reactions 165
Fault recording 183, 281
Features 7
Feeder current guard 51, 56
Flush mounting 198
Front elemen ts 4
Function control 171
G
Gener al dia gr ams 291
General fault detection 171
Gener al inte r ro gatio n 178
General pickup 171
General protection data 32
General tripping 172
Generators 15, 22, 48, 261
Graphic tools 289
Graph ic al ana ly si s pr ogr am SIGRA 289
Graph ic al sy mb ols iii
Group alarms 166
H
Hardware modifications 205
Hardware monitoring 160
Hardware structure 2
Harmoni c restra in t 37
High-curr ent trip 37
High-impedance differential protection 115
High-impedance principle 115
High-impedance protection 118
Hot-spot calculation 135, 277
Humidity 256
I
IBS-tool 181
Increase of pickup value on startup 38, 108
Information list 323
Inrush current 37, 79, 101
Inrush restraint 37, 79, 101
Installation 198
in cubicles 199
in panels (flush) 198
in racks 199
on panels (surface) 200
Insulation tests 253
Interface cable 289
Interface modules 213, 288
Interlocking 191
Inverse time overcurrent protection 76, 99
IRIG B 281
L
LCD 4
LED 4
Lines 15, 22, 42, 50, 262
List of information 323
List of measured values 340
List of settings 308
Lock-out 172
M
Manual close 79, 101
Measur ed qua ntit ies sup er vision 161
Measur ed va lue s 179, 180, 280
Mechani c al tes ts 255
Memory modules 160
Mini-busbars 15, 22, 50, 262
Modem interface 250
Monitoring functions 160, 279
Motors 15, 22, 48, 261
Mounting brackets 289
Index
3457UT612 Manual
C53000–G1176–C148–1
N
No trip no flag 173
Nominal current 23, 24, 25, 26, 248
Nominal currents, alteration 205, 211
Nominal frequency 20
Note (definition) ii
O
Oper ating interface 4, 250
Operating measured values 180
Oper ating messages 177
Operating software DIGSI 289
Ordering code 286
Ordering information 286
Ordering number 286
Output re lays 175, 249
Overload protection 131, 275
P
Panel f lush mou nting 198
Panel surface mounting 200
Parameter names iii
Parameter options iii
Phase se quen ce 20, 162
Phase se quen ce supervisio n 162
Pickup of the entire device 171
Plug- in sock et box es 289
Power supply 4, 205, 248
Power system data 1 20
Power system data 2 32
Power transfor me rs 15, 20, 42, 259
auto-transformers 15, 46
single-phase transformers 15, 46
with isolated windings 15
Preset configurations 305
Processing of commands 189
Processing of messages 175
Protection function control 171
Protocol dependent functions 307
Q
Qualified personnel (definition) ii
R
Rack mounting 199
Rated current 23, 24, 25, 26, 248
Rated currents, alteration 205, 211
Rated frequency 20
Reactions to fault 165
Reactors 15, 22, 48, 49, 261
Reassembling the device 217
Reclosure interlocking 172
Relative ageing 136
Reset time curves
time overcurrent protection (ANSI) 269
unbalanced load protection (ANSI) 269
user defined 16, 87
Resi s tanc e sta bil iz ation 116
Resis tanc e temp er ature detect or 17
Restraint
add-on sta bil iz at ion 36
current stabilization 34
differe ntial pr otec ti on 34
harmonic restraint 37
inrush restraint 37, 79, 101
resistance stabilization 116
restricted earth fault protection 67
Restricted earth fault protection 64, 263
Reverse interlocking 81
RTD 17
S
Sampling frequency 161
SCADA interface 4, 251
Scope of functions 7, 14
Serial interfaces 4
Series reactors 15, 22, 48, 261
Service conditions 256
Service interface 4, 250
Set-points 182
Setting consistency 167, 227
Setting errors 167
Setting groups 30
Changeover 202
Setting list 308
Shock and vibration 255
Short li nes 15, 22, 50, 262
Short-circuit links 288
Shunt reactors 15, 22, 49, 261
SIGRA 4 289
Singl e- pha se dif f erent ial prot ect ion 52
Single-phase time overcurrent protection 113, 273
Singl e-pha se tr ans forme rs 15, 46
Index
346 7UT612 Manual
C53000–G1176–C148–1
Software monitoring 161
Spare parts 206
Spontaneous annunciations 178
Spontaneous displays 171, 177
Standard interlocking 192
Starpoi nt co ndi tio n 21, 26, 42, 46, 47, 57
Starpoint former (earthing reactor) 15, 44, 45, 49,
64
Startup 38, 108, 132
Statistics 173, 178, 281
Sudden pre ssur e relay s 157
Summation CT’s 52
Support ii
Surface mounting 200
Symbol conventions iii
System interface 4, 251
T
Tank leakage protection 117, 121
Target audience of manual i
Temperature unit 20
Temperatures 256
Terminal block covering caps 288
Termination variants 201
Test operation 223
Test recordings 243
Thermal differential equation 131
Thermal over load protection 131, 275
Thermal replica 131, 275
Thermal set-points 143
Thermal time constant 131
Thermal values 181
Thermobox 17, 143, 250, 277, 288
Time overcurrent protection
cold load pickup 108
for earth current 97
for phase currents 73
for residual current 73
for starpoint current 97
single-phase 113, 273
Time synchron ization 4, 253
Traction transformers 15, 46
Transformer messages 157
Transformers 15, 20, 42, 259
auto-transformers 15, 46
power transformers 42
single-phase transformers 15, 46
with isolated windings 15
Transmission blocking 223
Transmission of measured values 179
Transverse differential protection 48
Trip circuit supervision 162, 203
Trip command duration 27
Trip log 177
Tripping characteristic
dif ferential protection 39, 258
restricted earth fault protection 69, 263
thermal overloa d protection 276
time overcurrent protection (ANSI) 267, 268
time overcurrent protection (IEC) 266
unbalanced load protection (ANSI) 267
unbalanced load protection (IEC) 266
Tripping logic 172
Types of commands 189
Typogra phic co nventions iii
U
Unbalanced load protection 123, 274
User defined functions 10, 281
User defined reset time curves 16, 87
User defined set-points 182
User specified curves 86, 105
V
Vibration and shock 255
Voltage measurement 179
W
Warning (definition) ii
Watchdog 161
n
Corrections
7UT612 Manual
C53000–G1176–C148–1
To
Siemens AG
Dept. PTD PA D DM
D–13623 Berlin
Germany
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Order-no.: C53000–G1176–C148–1
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358
