7UM62_iec

Preface Table of Contents Introduction

SIPROTEC

Functions Installation and Commissioning

Multifunction Generator, Motor and Transformer Protection Relay 7UM62 V4.1 Manual

C53000-G1176-C149-3

Technical Data Appendix Index

1 2 3 4 A

Liability Statement

Copyright

We have checked the text of this manual against the hardware and software described. Exclusions and deviations cannot be ruled out; we accept no liability for lack of total agreement.

Copyright © Siemens AG 2002. All rights reserved.

The information in this manual is checked periodically, and necessary corrections will be included in future editions. We appreciate any suggested improvements.

Dissemination or reproduction of this document, or evaluation and communication of its contents, is not authorized except where expressly permitted. Violations are liable for damages. All rights reserved, particularly for the purposes of patent application or trademark registration. Registered trademarks

We reserve the right to make technical improvements without notice. Release V4.10.01

Siemens Aktiengesellschaft

SIPROTEC, SIMATIC®, SIMATIC NET ®, SINAUT ®, SICAM®, and DIGSI® are registered trademarks of Siemens AG. Other designations in this manual may be trademarks that if used by third parties for their own purposes may violate the rights of the owner.

Manual No. C53000-G1176-C149-3

Preface Purpose of This Manual

This manual describes the functions, operation, installation, and placing into service of the device. In particular, one will find: • Information regarding customizing of the device and descriptions of device functions and settings → Chapter 2; • Instructions for mounting and commissioning → Chapter 3; • Instructions for mounting and commissioning → Chapter 4; • As well as a compilation of the most significant data for experienced users in the Appendix A. For general information on the operation and configuration of SIPROTEC® 4 devices, please refer to theSIPROTEC® 4 System Manual (Order No.: E50417–H1176–C151).

Target Audience

Protection engineers, commissioning engineers, personnel concerned with adjustment, checking, and service of selective protective equipment, automatic and control facilities, and personnel of electrical facilities and power plants.

Applicability of This Manual

This manual is valid for: SIPROTEC® 4 7UM62 Multifunction Generator, Motor and Transformer Protections; firmware version 4.1. 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 equipment for use within certain voltage limits (Low-voltage Directive 73/23/EEC). This conformity is 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 with the standard EN 60255–6 for the lowvoltage directive. The product conforms with the international standard of the series IEC 60255 and the German standard DIN 57435 /Part 303 (corresponds to VDE 0435/Part 303).

This product is UL–certified with the data as stated in Section 4.1:

IND. CONT. EQ. TYPE 1 69CA

7UM62 Manual C53000-G1176-C149-3

IND. CONT. EQ. TYPE 1

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Preface

Additional Support

For questions regarding SIPROTEC® 4 devices, please contact your Siemens representative.

Training Courses

Individual course offerings may be found in our Training Catalog, or questions can be directed to our training center. Please contact your Siemens representative.

Instructions and Warnings

The following indicators and standard definitions are used:

DANGER means that death, severe personal injury, or considerable equipment damage will occur if safety precautions are disregarded.

WARNING means that death, severe personal injury, or considerable equipment damage will occur if safety precautions are disregarded.

Caution means that death, severe personal injury, or considerable equipment damage will occur if safety precautions are disregarded. This manual describes the functions, operation, installation, and placing into service of the device. Instruction is an important piece of information regarding the product or the part of the manual that deserves special attention.

WARNING During operation of electrical equipment, certain parts of these devices are under high voltage. Severe personal injury or significant equipment damage could result from improper behavior. Only qualified personnel should work on this equipment or in the vicinity of this equipment. These personnel must be familiar with all warnings and service procedures described in this manual, as well as with safety regulations. Prerequisites to proper and safe operation of this product are proper transport, proper storage, setup, installation, operation, and maintenance of the product, as well as careful operation and servicing of the device within the scope of the warnings and instructions of this manual. In particular, the general facility and safety regulations for work with high-voltage equipment (e.g. ANSI, IEC, EN, or other national or international regulations) must be observed. Noncompliance may result in death, injury, or significant equipment damage. QUALIFIED PERSONNEL Prerequisites to proper and safe operation of this product are proper transport, proper storage, setup, installation, operation, and maintenance of the product, as well as careful operation and servicing of the device within the scope of the warnings and instructions of this manual.

ii

G

Training and instruction (or other qualification) for switching, grounding, and designating devices and systems.

G

Training and instruction (or other qualification) for switching, grounding, and designating devices and systems.

G

First aid training.

7UM62 Manual C53000-G1176-C149-3

Preface

Typographic and Graphical Conventions

The following text formats are used to identify concepts giving device information described by the text flow: Parameter names, or identifiers for configuration or function parameters that appear in the device display or on the screen of a PC (with DIGSI® 4) are shown in monoscript (same point size) bold text. This also applies to header bars for selection menus. Parameter conditions, or possible settings of parameters that appear in the device display or on the screen of a PC (with DIGSI® 4), are additionally shown in italic style. This also applies to header bars for selection menus. “Annunciations”, or identifiers for information produced by the device or required by other devices or from the switch-gear is shown in mono-script (same point size) and placed into quotation marks. For diagrams in which the identifier type results from the representation itself, text conventions may differ from the above-mentioned.

The following symbols are used in diagrams:

device-internal (logical) input signal

GND Fault

GND Fault

IL1

device-internal (logical) input signal internal input signal of an analog quantity

F#

external binary input signal with function number F# (binary input, respective annunciation to the device)

>Release F#

Dev. Trip

external binary input signal with function number F# (binary input, from device)

Parameter address Parameter name

1234 FUNCTION On

example of a parameter switch FUNCTION with address 1234 and possible conditions On and Off

Off Parameter Conditions

Input signal of an analog quantity

≥1

&

OR

OR gate

AND gate

Signal inversion

7UM62 Manual C53000-G1176-C149-3

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Preface

Exclusive–OR gate: output is active, if only one of the inputs is active

=1

Coincidence gate: output is active, if both inputs

=

are active simultaneously

Input signals of dynamic quantity

Formation of one output signal from a number of analog inputs 1706 I2>>

Limit stage with parameter address and designator

I2>

1706 T I2>> T

0

0

T

Timer (pick up delayed) with parameter address and designator

Timer (dropout delayed)

Dynamic triggered pulse timer (monoflop)

T

S

Q

R

Q

Static memory (RS–flipflop) with setting input (S), resetting input (R), output (Q) and inverted output (Q)

n

iv

7UM62 Manual C53000-G1176-C149-3

Table of Contents 1

2

Introduction.......................................................................................................................................... 1 1.1

Overall Operation ................................................................................................................... 2

1.2

Applications ............................................................................................................................ 5

1.3

Features ................................................................................................................................. 7

Functions............................................................................................................................................ 13 2.1

Introduction, Reference Power System ................................................................................ 16

2.2

Functional Scope.................................................................................................................. 18

2.2.1

Description ........................................................................................................................... 18

2.2.2 2.2.2.1

Setting Hints ......................................................................................................................... 18 Settings .............................................................................................................................. 23

2.3

Power System Data 1........................................................................................................... 27

2.3.1

Functional Description .......................................................................................................... 27

2.3.2 2.3.2.1 2.3.2.2

Setting Hints ......................................................................................................................... 27 Settings 1 ............................................................................................................................. 33 List of Information ................................................................................................................ 34

2.4

Setting Groups ..................................................................................................................... 35

2.4.1


2.4.2 2.4.2.1 2.4.2.2

Setting Hints ......................................................................................................................... 35 Settings ................................................................................................................................ 35 Information .......................................................................................................................... 35

2.5

Power System Data 2........................................................................................................... 36

2.5.1


2.5.2 2.5.2.1 2.5.2.2

Setting Hints ......................................................................................................................... 36 Settings ................................................................................................................................ 36 Information ........................................................................................................................... 36

2.6

Definite-Time Overcurrent Protection (I>, ANSI 50/51) with Undervoltage Seal-In38

2.6.1


2.6.2 2.6.2.1 2.6.2.2

Setting Hints ......................................................................................................................... 39 Settings for the Definite-Time Overcurrent Protection (Stage I>)......................................... 40 Information from Definite-Time Overcurrent Protection (Stage I>)....................................... 41

2.7

Definite-Time Overcurrent Protection (I>>, ANSI 50, 51, 67) with Direction Detection........................................................................................................ 42

2.7.1


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2.7.2 2.7.2.1 2.7.2.2

Setting Hints ......................................................................................................................... 44 Settings for the I>> Stage of the Definite-Time Overcurrent Protection ............................... 47 Information for the I>> stage of the Definite-Time Overcurrent Protection .......................... 47

2.8

Inverse-Time Overcurrent Protection (ANSI 51V) ................................................................ 48

2.8.1


2.8.2 2.8.2.1 2.8.2.2

Setting Hints ......................................................................................................................... 52 Settings of the Inverse O/C Time Protection ........................................................................ 53 Information for the Inverse-Time Overcurrent Protection ..................................................... 54

2.9

Thermal Overload Protection (ANSI 49) ............................................................................... 55

2.9.1


2.9.2 2.9.2.1 2.9.2.2

Setting Hints ......................................................................................................................... 59 Thermal Overload Protection Settings.................................................................................. 63 Information List for the Thermal Overload Protection ........................................................... 64

2.10

Unbalanced Load (Negative Sequence) Protection (ANSI 46)............................................. 65

2.10.1


2.10.2 Setting Hints ......................................................................................................................... 67 2.10.2.1 Settings of the Unbalanced Load Protection ........................................................................ 69 2.10.2.2 Information for the Unbalanced Load Protection .................................................................. 70 2.11

Startup Overcurrent Protection (ANSI 51) ............................................................................ 71

2.11.1


2.11.2 Setting Hints ......................................................................................................................... 72 2.11.2.1 Settings of the Startup Overcurrent Protection ..................................................................... 74 2.11.2.2 Information for the Startup Overcurrent Protection............................................................... 74 2.12

Differential Protection (ANSI 87G/87M/87T)......................................................................... 75

2.12.1 2.12.1.1 2.12.1.2 2.12.1.3

Functional Description .......................................................................................................... 75 Protected Object Generator or Motor: Particularities............................................................ 77 Protected Object Transformer: Particularities....................................................................... 78 Evaluation of Measured Quantities....................................................................................... 81

2.12.2 2.12.2.1 2.12.2.2 2.12.2.3 2.12.2.4

Setting Hints ......................................................................................................................... 89 Differential Protection for Generators and Motors ................................................................ 89 Differential Protection for Transformers................................................................................ 91 Settings of the Differential Protection ................................................................................... 95 Information for the Differential Protection ............................................................................. 96

2.13

Earth Current Differential Protection (ANSI 87GN, TN)........................................................ 98

2.13.1


2.13.2 Setting Hints ....................................................................................................................... 103 2.13.2.1 Settings of the Earth Current Differential Protection........................................................... 105 2.13.2.2 Information for the Earth Current Differential Protection..................................................... 105 2.14

Underexcitation (Loss-of-Field) Protection (ANSI 40)......................................................... 106

2.14.1

Functional Description ........................................................................................................ 106

2.14.2 Setting Hints ....................................................................................................................... 109 2.14.2.1 Settings of the Underexcitation (Loss-of-Field) Protection ................................................. 113 2.14.2.2 Information for the Underexcitation (Loss-of-Field) Protection .......................................... 114

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2.15

Reverse Power Protection (ANSI 32R)............................................................................... 115

2.15.1


2.15.2

Setting Hints ....................................................................................................................... 116

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2.15.2.1 Settings of the Reverse Power Protection.......................................................................... 117 2.15.2.2 Information for the Reverse Power Protection.................................................................... 118 2.16

Forward Active Power Supervision (ANSI 32F).................................................................. 119

2.16.1


2.16.2 Setting Hints ....................................................................................................................... 120 2.16.2.1 Settings of the Forward Active Power Supervision............................................................. 120 2.16.2.2 Information for the Forward Power Supervision ................................................................. 121 2.17

Impedance Protection (ANSI 21)........................................................................................ 122

2.17.1 2.17.1.1 2.17.1.2 2.17.1.3 2.17.1.4

Functional Description ........................................................................................................ 122 Pickup................................................................................................................................. 122 Determination of the Short–Circuit Impedance................................................................... 123 Tripping Characteristic........................................................................................................ 125 Tripping Logic ..................................................................................................................... 126

2.17.2

Setting Hints ....................................................................................................................... 128

2.17.3 2.17.3.1 2.17.3.2 2.17.3.3

Power Swing Blocking ........................................................................................................ 131 Setting Hints ....................................................................................................................... 132 Settings of the Impedance Protection................................................................................. 135 Information from the Impedance Protection ....................................................................... 135

2.18

Out-of-Step Protection (ANSI 78) ....................................................................................... 137

2.18.1 Functional Description ........................................................................................................ 137 2.18.1.1 Measuring Principle ............................................................................................................ 137 2.18.1.2 Out-of-Step Logic ............................................................................................................... 139 2.18.2 Setting Hints ....................................................................................................................... 142 2.18.2.1 Settings of the Out-of-Step Protection................................................................................ 146 2.18.2.2 Information for the Out-of-Step Protection.......................................................................... 147 2.19

Undervoltage Protection (ANSI 27) .................................................................................... 148

2.19.1


2.19.2 Setting Hints ....................................................................................................................... 149 2.19.2.1 Settings of the Undervoltage Protection ............................................................................. 150 2.19.2.2 Information for the Undervoltage Protection....................................................................... 150 2.20

Overvoltage Protection (ANSI 59) ...................................................................................... 151

2.20.1


2.20.2 Setting Hints ....................................................................................................................... 151 2.20.2.1 Settings of the Overvoltage Protection ............................................................................... 152 2.20.2.2 Information for the Overvoltage Protection......................................................................... 152 2.21

Frequency Protection (ANSI 81)......................................................................................... 154

2.21.1


2.21.2 Setting Hints ....................................................................................................................... 155 2.21.2.1 Settings for the Frequency Protection ................................................................................ 157 2.21.2.2 Information for Frequency Protection ................................................................................. 157 2.22

Overexcitation (Volt/Hertz) Protection (ANSI 24) ............................................................... 159

2.22.1


2.22.2 Setting Hints ....................................................................................................................... 161 2.22.2.1 Settings of the Overexcitation Protection ........................................................................... 163 2.22.2.2 Information from the Overexcitation Protection .................................................................. 163 2.23

Inverse-Time Undervoltage Protection (ANSI 27) .............................................................. 164

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2.23.1


2.23.2 Setting Hints ....................................................................................................................... 165 2.23.2.1 Settings of the Inverse Undervoltage Protection ................................................................ 166 2.23.2.2 Information for the Inverse Undervoltage Protection .......................................................... 166 2.24

Rate-of-Frequency-Change Protection df/dt (ANSI 81R) ................................................... 167

2.24.1


2.24.2 Setting Hints ....................................................................................................................... 168 2.24.2.1 Settings of the Rate-of-Frequency-Change Protection....................................................... 170 2.24.2.2 Information for the Rate-of-Frequency-Change Protection................................................. 171 2.25

Jump of Voltage Vector ...................................................................................................... 172

2.25.1


2.25.2 Setting Hints ....................................................................................................................... 174 2.25.2.1 Settings of the Vector Jump Detection ............................................................................... 175 2.25.2.2 Information for the Vector Jump Detection ......................................................................... 176 2.26

90–%–Stator Earth Fault Protection (ANSI 59N, 64G, 67G) .............................................. 177

2.26.1


2.26.2 Setting Hints ....................................................................................................................... 181 2.26.2.1 Settings of the 90% Stator Earth Fault Protection .............................................................. 183 2.26.2.2 Information for the 90% Stator Earth Fault Protection ........................................................ 184 2.27

Sensitive Earth Fault Protection (ANSI 51GN, 64R)........................................................... 185

2.27.1


2.27.2 Setting Hints ....................................................................................................................... 187 2.27.2.1 Settings of the Sensitive Earth Fault Protection ................................................................. 188 2.27.2.2 Information for the Sensitive Earth Current Detection ....................................................... 188 2.28

100–%–Stator Earth Fault Protection with 3rd Harmonics (ANSI 27/59TN 3rd Harm.) ................................................................................................. 189

2.28.1


2.28.2 Setting Hints ....................................................................................................................... 191 2.28.2.1 Settings of the 100–%–Stator Earth Fault Protection with 3rd Harmonics ........................ 192 2.28.2.2 Information for the 100–% Stator Earth Fault Protection with 3rd Harmonics .................... 193 2.29

100–% Stator Earth Fault Protection with 20 Hz Voltage Injection (ANSI 64G - 100%)..... 194

2.29.1


2.29.2 Setting Hints ....................................................................................................................... 197 2.29.2.1 Settings of the 100-% Stator Earth Fault Protection ........................................................... 199 2.29.2.2 Information for the 100-% Stator Earth Fault Protection..................................................... 200 2.30

Rotor Earth Fault Protection R, fn (ANSI 64R) ................................................................... 201

2.30.1


2.30.2 Setting Hints ....................................................................................................................... 203 2.30.2.1 Settings of the Rotor Earth Fault Protection ....................................................................... 204 2.30.2.2 Information for the Rotor Earth Fault Protection ................................................................. 205 2.31

Sensitive Rotor Earth Fault Protection with 1 to 3 Hz Square Wave Voltage Injection (ANSI 64R - 1 to 3 Hz) .................................................................. 206

2.31.1


2.31.2 Setting Hints ....................................................................................................................... 211 2.31.2.1 Settings of the Sensitive Rotor Earth Fault Protection........................................................ 212

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Table of Contents

2.31.2.2 Information for the Sensitive Earth Fault Protection ........................................................... 212 2.32

Motor Starting Time Supervision (ANSI 48) ....................................................................... 213

2.32.1


2.32.2 Setting Hints ....................................................................................................................... 215 2.32.2.1 Settings of the Motor Starting Time Supervision ................................................................ 216 2.32.2.2 Information for the Motor Starting Time Supervision .......................................................... 216 2.33

Restart Inhibit for Motors (ANSI 66, 49Rotor)..................................................................... 217

2.33.1


2.33.2 Setting Hints ....................................................................................................................... 220 2.33.2.1 Settings of the Restart Inhibit for Motors ............................................................................ 223 2.33.2.2 Information for the Motor Restart Inhibit ............................................................................. 224 2.34

Breaker Failure Protection (ANSI 50BF) ............................................................................ 225

2.34.1


2.34.2 Setting Hints ....................................................................................................................... 227 2.34.2.1 Settings for Breaker Failure Protection............................................................................... 228 2.34.2.2 Information for the Breaker Failure Protection.................................................................... 229 2.35

Inadvertent Energization (ANSI 50, 27).............................................................................. 230

2.35.1


2.35.2 Setting Hints ....................................................................................................................... 231 2.35.2.1 Settings of the Inadvertent Energizing Protection .............................................................. 232 2.35.2.2 Information for the Inadvertent Energizing Function........................................................... 232 2.36

DC Voltage/DC Current Protection (ANSI 59NDC/51NDC) ............................................... 234

2.36.1


2.36.2 Setting Hints ....................................................................................................................... 236 2.36.2.1 Settings of the DC Voltage Protection ................................................................................ 238 2.36.2.2 Information from the DC Voltage Protection....................................................................... 238 2.37

Analog Outputs................................................................................................................... 239

2.37.1


2.37.2

Setting Hints ....................................................................................................................... 239

2.37.3

Settings of the Analog Outputs........................................................................................... 240

2.38

Measured Value Monitoring Functions ............................................................................... 241

2.38.1 2.38.1.1 2.38.1.2 2.38.1.3 2.38.1.4 2.38.1.5

Functional Description ........................................................................................................ 241 Hardware Monitoring .......................................................................................................... 241 Software Monitoring............................................................................................................ 243 Monitoring of External Current Transformer Circuits .......................................................... 243 Fuse Failure Monitoring...................................................................................................... 245 Malfunction Responses of the Monitoring Functions.......................................................... 247

2.38.2 2.38.2.1 2.38.2.2 2.38.2.3

Setting Hints ....................................................................................................................... 249 Settings .............................................................................................................................. 250 Information of the Monitoring Functions ............................................................................. 251 Sum Events of the Monitoring Functions............................................................................ 252

2.39

Trip Circuit Supervision ...................................................................................................... 254

2.39.1


2.39.2 Setting Hints ....................................................................................................................... 258 2.39.2.1 Settings for the Trip Circuit Supervision ............................................................................. 260

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2.39.2.2 Information.......................................................................................................................... 260 2.40

Threshold Supervision ........................................................................................................ 261

2.40.1


2.40.2 Setting Hints ....................................................................................................................... 263 2.40.2.1 Settings of the Threshold Supervision ................................................................................ 264 2.40.2.2 Information for the Threshold Supervision.......................................................................... 266 2.41

External Trip Coupling ........................................................................................................ 267

2.41.1


2.41.2 Setting Hints ....................................................................................................................... 267 2.41.2.1 Settings............................................................................................................................... 268 2.41.2.2 Information for the Function Control ................................................................................... 268 2.42

Temperature Detection by Thermoboxes ........................................................................... 270

2.42.1


2.42.2 Setting Hints ....................................................................................................................... 271 2.42.2.1 Settings of the Temperature Detection Function ................................................................ 273 2.42.2.2 Information for the Temperature Detection Function ......................................................... 277 2.43

Inversion of Phase Sequence (Phase Sequence Reversal)............................................... 279

2.43.1


2.43.2

Setting Hint ......................................................................................................................... 280

2.44

Protection Function Logic ................................................................................................... 281

2.44.1 Functional Description ........................................................................................................ 281 2.44.1.1 Processing Tripping Logic .................................................................................................. 281 2.44.2 Processing Tripping Logic .................................................................................................. 282 2.44.2.1 Functional Description ........................................................................................................ 282 2.44.2.2 Settings for the Tripping Logic ............................................................................................ 283 2.44.3 Fault Display on the LEDs/LCD .......................................................................................... 283 2.44.3.1 Principle of Function ........................................................................................................... 283 2.44.3.2 Settings............................................................................................................................... 283

x

2.44.4 2.44.4.1 2.44.4.2 2.44.4.3

Statistical Counters............................................................................................................. 284 Functional Description ........................................................................................................ 284 Setting/Resetting ................................................................................................................ 284 Information for the Statistical Counter ............................................................................... 285

2.45

Auxiliary Functions.............................................................................................................. 286

2.45.1 2.45.1.1 2.45.1.2 2.45.1.3 2.45.1.4 2.45.1.5

Processing of Messages..................................................................................................... 286 Operational Annunciations.................................................................................................. 287 Fault Annunciations ............................................................................................................ 287 General Interrogation.......................................................................................................... 288 Spontaneous Annunciations ............................................................................................... 288 Statistical Counters............................................................................................................. 288

2.45.2

Measurements .................................................................................................................... 289

2.45.3

Oscillographic Fault Recording (Waveform Capture) ......................................................... 292

2.45.4

Date and Time Stamping .................................................................................................... 293

2.45.5 2.45.5.1 2.45.5.2 2.45.5.3 2.45.5.4

Commissioning Aids ........................................................................................................... 294 Influencing Information on the System Interface During Test Operation ............................ 294 Testing the System Interface .............................................................................................. 294 Testing the States of the Binary Inputs/Outputs ................................................................. 295 Creating a Test Oscillographic Recording .......................................................................... 295

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Table of Contents

2.45.6 2.45.6.1 2.45.6.2 2.45.6.3

Setting Hints ....................................................................................................................... 295 Settings for Oscillographic Fault Recording ....................................................................... 296 Information for the Oscillographic Fault Recording ............................................................ 296 Information for Minimum and Maximum Values ................................................................. 297

2.46

Breaker Control .................................................................................................................. 298

2.46.1

Types of Commands .......................................................................................................... 299

2.46.2

Steps in the Command Sequence...................................................................................... 299

2.46.3 Interlocking ......................................................................................................................... 300 2.46.3.1 Interlocked / Non-Interlocked Switching ............................................................................. 301 2.46.4

3

Recording and Acknowledgement of Commands .............................................................. 308

Installation and Commissioning .................................................................................................... 309 3.1

Installation and Connections .............................................................................................. 310

3.1.1

Installation .......................................................................................................................... 310

3.1.2

Connections ....................................................................................................................... 314

3.1.3 3.1.3.1 3.1.3.2 3.1.3.3 3.1.3.4 3.1.3.5

Hardware Modifications ...................................................................................................... 316 General............................................................................................................................... 316 Disassembling the Device .................................................................................................. 318 Switching Elements on Printed Circuit Boards ................................................................... 321 Interface Modules ............................................................................................................... 332 To Reassemble the Device: ............................................................................................... 335

3.2

Checking Connections and System (Plant) Integration ...................................................... 336

3.2.1

Checking the Data Connections of Serial Interfaces .......................................................... 336

3.2.2

Checking the Device Connections...................................................................................... 338

3.2.3 3.2.3.1

Checking the Integration in the Plant.................................................................................. 343 General Hints ..................................................................................................................... 343

3.3

Commissioning ................................................................................................................... 346

3.3.1

Test Mode and Blocking Data Transmission ...................................................................... 347

3.3.2

Testing the System Interface.............................................................................................. 347

3.3.3

Checking the Binary Inputs and Outputs ............................................................................ 349

3.3.4

Testing the Breaker Failure Scheme .................................................................................. 351

3.3.5

Checking the Analog Outputs............................................................................................. 352

3.3.6

Testing User-Defined Functions (CFC) .............................................................................. 352

3.3.7 3.3.7.1 3.3.7.2

Checking the Rotor Earth Fault Protection at Stand-Still.................................................... 352 Rotor Earth Fault Protection (R, fn) .................................................................................... 352 Rotor Earth Fault Protection (1 to 3 Hz) ............................................................................. 354

3.3.8

Checking the 100–% Stator Earth Fault Protection ............................................................ 356

3.3.9

Checking the DC Voltage/DC Current Circuit..................................................................... 358

3.3.10

Trip/Close Tests for Primary Equipment............................................................................. 359

3.4

Primary Commissioning Tests with the Generator ............................................................. 360

3.4.1

General Hints ..................................................................................................................... 360

3.4.2

Checking the Current Circuits............................................................................................. 364

3.4.3

Checking the Differential Protection ................................................................................... 366

3.4.4

Checking the Earth Current Differential Protection............................................................. 368

3.4.5

Checking the Voltage Circuits ............................................................................................ 373

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xii

3.4.6 3.4.6.1 3.4.6.2

Checking the Stator Earth Fault Protection ........................................................................ 374 Unit Connection .................................................................................................................. 375 Busbar Connection ............................................................................................................. 378

3.4.7

Testing the 100–% Stator Earth Fault Protection ............................................................... 382

3.4.8

Checking the Sensitive Earth Fault Protection when Used for Rotor Earth Fault Protection .......................................................................................... 384

3.4.9 3.4.9.1 3.4.9.2

Checking the Rotor Earth Fault Protection During Operation............................................. 384 Rotor Earth Fault Protection (R, fn) .................................................................................... 384 Rotor Earth Fault Protection (1 to 3 Hz) ............................................................................. 385

3.4.10 3.4.10.1 3.4.10.2 3.4.10.3 3.4.10.4 3.4.10.5

Tests with the Generator Connected to the Network.......................................................... 386 Checking the Correct Connection Polarity.......................................................................... 386 Measurement of Motoring Power (Reverse Power) and Angle Error Correction................ 386 Calibrating the Reverse Power Protection.......................................................................... 387 Checking the Underexcitation Protection............................................................................ 388 Checking the Directional Function of the Overcurrent Time Protection.............................. 389

3.4.11

Triggering Oscillographic Recordings................................................................................. 389

3.5

Final Preparation of the Device .......................................................................................... 391

Technical Data.................................................................................................................................. 393 4.1

General Device Data .......................................................................................................... 395

4.1.1

Analog Inputs...................................................................................................................... 395

4.1.2

Power Supply...................................................................................................................... 396

4.1.3

Binary Inputs and Outputs .................................................................................................. 396

4.1.4

Communications Interfaces ................................................................................................ 397

4.1.5

Electrical Tests ................................................................................................................... 401

4.1.6

Mechanical Stress Tests..................................................................................................... 403

4.1.7

Climatic Stress Tests .......................................................................................................... 403

4.1.8

Service Conditions.............................................................................................................. 404

4.1.9

Certifications ....................................................................................................................... 404

4.1.10

Construction........................................................................................................................ 405

4.2

Definite-Time Overcurrent Protection (ANSI 50, 67) .......................................................... 406

4.3

Inverse-Time Overcurrent Protection (ANSI 51, 67)........................................................... 407

4.4

Thermal Overload Protection (ANSI 49) ............................................................................. 412

4.5

Unbalanced Load (Negative Sequence) Protection (ANSI 46)........................................... 414

4.6

Startup Overcurrent Protection (ANSI 51) .......................................................................... 416

4.7

Differential Protection for Generators and Motors (ANSI 87G/87M)................................... 417

4.8

Differential Protection for Transformers (ANSI 87T)........................................................... 419

4.9

Earth Current Differential Protection (ANSI 87GN/TN)....................................................... 422

4.10

Underexcitation (Loss-of-Field) Protection (ANSI 40)......................................................... 423

4.11

Reverse Power Protection (ANSI 32R)............................................................................... 424

4.12

Forward Power Supervision (ANSI 32F)............................................................................. 425

7UM62 Manual C53000-G1176-C149-3

Table of Contents

A

4.13

Impedance Protection (ANSI 21)........................................................................................ 426

4.14

Out-of-Step Protection (ANSI 78) ....................................................................................... 427

4.15

Undervoltage Protection (ANSI 27) .................................................................................... 428

4.16

Overvoltage Protection (ANSI 59) ...................................................................................... 430

4.17

Frequency Protection (ANSI 81)......................................................................................... 431

4.18

Overexcitation (Volt/Hertz) Protection (ANSI 24) .............................................................. 432

4.19

Rate-of-Frequency-Change Protection (ANSI 81R) ........................................................... 434

4.20

Jump of Voltage Vector ...................................................................................................... 435

4.21

90–%–Stator Earth Fault Protection (ANSI 59N, 64G, 67G) .............................................. 436

4.22

Sensitive Earth Fault Protection (ANSI 51GN, 64R) .......................................................... 437

4.23

100–%–Stator Earth Fault Protection with 3rd Harmonics (ANSI 27/59TN 3rd Harm.) ................................................................................................. 438

4.24

100–% Stator Earth Fault Protection with 20 Hz Voltage Injection (ANSI 64G, –100 %)... 439

4.25

Rotor Earth Fault Protection (R, fn, ANSI 64R) .................................................................. 440

4.26

Sensitive Rotor Earth Fault Protection with 1 to 3 Hz (ANSI 64R) ..................................... 441

4.27

Motor Starting Time Supervision (ANSI 48) ....................................................................... 442

4.28

Restart Inhibit for Motors (ANSI 66, 49Rotor) ...................................................................... 443

4.29

Breaker Failure Protection (ANSI 50BF) ............................................................................ 444

4.30

Inadvertent Energization (ANSI 50/27)............................................................................... 445

4.31

DC Voltage/DC Current Protection (ANSI 59NDC/51NDC) ................................................. 446

4.32

Thermoboxes for Temperature Detection........................................................................... 447

4.33

Additional Functions ........................................................................................................... 448

4.34

Operating Ranges of the Protection Functions ................................................................ 455

4.35

Dimensions......................................................................................................................... 457

Appendix .......................................................................................................................................... 461 A.1

Ordering Information and Accessories .............................................................................. 462

A.1.1 A.1.1.1 1.1.1.2

Accessories ........................................................................................................................ 464 Schematic Diagram of the Accessories.............................................................................. 467 Dimensional Drawing of the Accessories ........................................................................... 471

A.2

General Diagrams (IEC) ..................................................................................................... 482

A.2.1

Housing for Panel Flush Mounting or Cubicle Installation .................................................. 482

A.2.2

Housing for Panel Surface Mounting.................................................................................. 484

A.3

General Diagrams (ANSI)................................................................................................... 486

7UM62 Manual C53000-G1176-C149-3

xiii

Table of Contents

A.4

Connection Examples......................................................................................................... 488

A.4.1

Connection Examples for RTD-Box.................................................................................... 498

A.5

100–% Stator Earth Fault Protection with Primary Load Resistor ...................................... 499

A.5.1

Protection Settings.............................................................................................................. 500

A.5.2

Commissioning ................................................................................................................... 500

A.6

Definition of the Active Power Measurement...................................................................... 502

A.7

Current Transformer Requirements.................................................................................... 504

A.8

Overview of the Masking Features of the User Defined Information .................................. 506

A.8.1

Source: BI, F, C; Destination: BO, LED, C ......................................................................... 506

A.8.2

Destination: Indication Buffer, System Interface................................................................. 510

A.9

Default Settings .................................................................................................................. 511

A.9.1

Binary Inputs....................................................................................................................... 511

A.9.2

Binary Outputs (output relays) ............................................................................................ 511

A.9.3

LED Indicators .................................................................................................................... 514

A.9.4

Function Keys ..................................................................................................................... 514

A.9.5

Establishing a Default Display ............................................................................................ 515

A.9.6

Spontaneous Display Messages ........................................................................................ 515

A.9.7

Pre–Defined CFC Charts.................................................................................................... 516

A.10

Interoperability List.............................................................................................................. 517

A.11

Functions Overview ............................................................................................................ 519

A.12

Settings............................................................................................................................... 522

A.13

List of Information ............................................................................................................... 548

A.14

List of Measured Values ..................................................................................................... 578

A.15

Protocol-Dependent Functions ........................................................................................... 584

Index.................................................................................................................................................. 585

xiv

7UM62 Manual C53000-G1176-C149-3

1

Introduction

The SIPROTEC® 4 7UM62 devices are introduced in this section. An overview of the devices is presented in their application, characteristics, and scope of functions.

7UM62 Manual C53000-G1176-C149-3

1.1

Overall Operation

2

1.2

Applications

5

1.3

Features

7

1

1 Introduction

1.1

Overall Operation The SIPROTEC® 4 7UM62 is a numerical, multi-functional, protective and control device equipped with a powerful microprocessor. All tasks, such as the acquisition of the measured quantities, issuing of commands to circuit breakers and other primary power system equipment, are processed in a completely digital way. Figure 1-1 illustrates the basic structure of the 7UM62.

Analog Inputs

The measuring inputs (MI) section consists of current and voltage transformers. They convert the signals from the primary transformers to levels appropriate for the internal processing of the 7UM62. Eight current inputs are available in the MI section. Three inputs are used on each side of the protected object for measuring of the phase currents. 2 current inputs are

MI

IA

AD

µC

∩

IL1, S1

AV Error

IL2, S1

Run

IL3, S1

Status

IEE1 IL1, S2

Output Relays, UserProgrammable

IL2, S2 IL3, S2

LEDs on the Front Panel, UserProgrammable

IEE2 UL1

µC

UL2 UL3

Display on the Front Panel

UN 3 Measuring Transducers

# Operator Control Panel ESC

ENTER

7 4 1 .

8 5 2 0

up to 15 Binary Inputs, Programmable

Uaux. Figure 1-1

2

~

9 6 3 +/-

Front Operator Interface (PC Port)

To PC

System Serial Interface

To SCADA

Rear Service Interface

PC/ Modem

Analog Outputs

Analog processing

Power Supply

Hardware Structure of the Numerical Device 7UM62 (Maximum Configuration)

7UM62 Manual C53000-G1176-C149-3

1.1 Overall Operation

equipped with sensitive input transformers (IEE) and can measure secondary currents in the mA range. A voltage measuring input is provided for each phase-earth voltage (connection to phase-to-phase voltages and voltage transformers in V connection is possible as well). A further voltage input (UN) may optionally be used to measure either the displacement voltage or any other voltage UX (for injected voltage of rotor protection). The analog-to-digital (AD) stage consists of memory components, a multiplexer, and an multichannel analog-to-digital converter. The A/D converter processes the analog signals from the IA stage. The digital signals from the converter are input to the microcomputer system where they are processed as numerical values in the residing algorithms. Microcomputer System

The actual protection and control functions of the 7UM62 are processed in the microcomputer system (µC). Specifically, the µC performs: − Filtering and preparation of the measured quantities − Permanent supervision of the measured quantities − Monitoring of the pickup conditions for the individual protection functions − Evaluation of limit values and sequences in time − Control of signals for the logic functions − Decision for trip commands − Signalling of protection behaviour via LED, LCD, relay or serial interface − Recording of messages and data for events, alarms, faults, and control actions, and provision of their data for analysis − Management of the operating system and the associated functions such as data recording, real-time clock, communications, interfaces, etc.

Adaptation of Sampling Frequency

The frequency of the measured quantities is continuously measured and used for determination of the actual sampling frequency. This ensures that the protection functions are always processed with algorithms matched to the actual frequency. Thus, a wide frequency range from 11 Hz to 69 Hz is specified with small frequency influence. The sampling frequency adaptation can, however, operate only when at least one a.c. measured quantity is present at one of the analog inputs, with an amplitude of at least 5 % of rated value (“operational condition 1”). If no suitable a.c. measured values are present, or if the frequency is below 11 Hz or above 70 Hz, the relay operates in mode “operational condition 0” (refer to Section 4.34).

Binary Inputs and Outputs

The µC obtains external information through the binary inputs such as blocking commands for protective functions or position indications of circuit breakers. The µC issues commands to external equipment via the output contacts. These output commands are generally used to operate circuit breakers or other switching devices. They can also be connected to other protective devices, annunciators, or external carrier equipment for use in Pilot-Relaying schemes.

Front Elements

Light-emitting diodes (LEDs) and a display screen (LCD) on the front panel provide information such as messages related to events and functional status of the 7UM62.

7UM62 Manual C53000-G1176-C149-3

3

1 Introduction

Integrated control and numeric keys in conjunction with the LCD facilitate local interaction with the 7UM62. All information of the device can be accessed using the integrated control and numeric keys. The information includes protective and control settings, operating and fault messages, and metering values (see also SIPROTEC® 4–System Manual). The settings can be modified; the procedures are discussed in Chapter 2. Serial Interfaces

A serial operator interface (PC port) on the front panel is provided for local communications with the 7UM62 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 modem, or local communications via a substation master computer that is permanently connected to the 7UM62. DIGSI® 4 is required. All 7UM62 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. A fourth interface is provided for time synchronization of the internal clock by external sources. Further communications protocols can be realized via additional interface modules.

Analog Outputs/ Temperature Input

Depending on the ordering variant and configuration, Port B and D can be equipped with analog output modules for the output of selected measured values (0 to 20 mA). If these ports are equipped with input modules (RS485 or optical) instead, temperatures can be fed in from an external temperature detection unit.

Power Supply

The 7UM62 can be supplied with any of the common power supply voltages from 24 VDC to 250 VDC. The device can also be supplied with 115 VAC. Momentary dips of the supply voltage up to 50 ms are bridged by a capacitor (see Technical Data, Subsection 4.1.2). Voltage dips can occur, for example, if the voltage supply system (substation battery) becomes short-circuited or experiences a severe variation in load.

4

7UM62 Manual C53000-G1176-C149-3

1.2 Applications

1.2

Applications SIPROTEC® 7UM62 is a numerical machine protection unit from the “7UM6 Numerical Protection series”. It provides all functions that are necessary for the protection of generators, motors and transformers. As the scope of functions of the 7UM62 can be customized, it is suited for small, medium-sized and large generators. It provides the scope of protection functions for the two typical basic applications: • Bus-bar connection • Unit connection

G

7UM62 Busbar connection

G

7UM62 Unit connection Figure 1-2

Typical Basic Connections

The integrated differential protection function can be used for longitudinal or transverse generator differential protection, for protection of the unit transformer or for overall differential protection. The scalable software allows to use the device for a wide range of applications, as function packages can be chosen individually for the application in hand. For instance, one 7UM62 is sufficient to provide for reliable all-round protection of generators with a small to medium output (about 5 MW). Additionally, the device forms the basis for the protection of larger generators. By adding a 7UM61 (further device of the 7UM6 protection series), all protection requirements encountered for the smallest to the largest machines can be met. This permits to implement a consistent concept for backup protection. Further applications are • Transformer protection, as the 7UM62 has in addition to differential and overcurrent protection a large variety of protection functions that allow, for instance, monitoring of the voltage and frequency load. • Protection of large synchronous and asynchronous motors.

7UM62 Manual C53000-G1176-C149-3

5

1 Introduction

Messages and Measured Values; Storage of Data for Fault Recordings

A series of operating messages provides information about conditions in the power system and the 7UM62 itself. Measurement quantities and values that are calculated can be displayed locally and communicated via the serial interfaces. Messages of the 7UM62 can be indicated by a number of programmable LEDs on the front panel, externally processed through programmable output contacts, and communicated via the serial interfaces (see “Communication” below). With the help of the CFC graphic tool (Continous Function Chart), user-defined annunciations and logical combinations of internal or external signals can also be generated. During a network fault (fault in the power system), important events and state changes are stored in a fault annunciation buffer. The instantaneous measured values during the fault are also stored in the device and are subsequently available for fault analysis.

Communication

Serial interfaces are available for communications with external operating, control, and storage systems.

Operator Interface on Front Panel

A serial operator interface on the front panel is provided for local communications with the through a personal computer. All of the operating and evaluation processes can be done via this operator interface using the DIGSI® 4 software. These processes include selecting and modifying the settings, allocation of the binary inputs and outputs, configuration of the user-definable logic functions, reading the event and fault data, retrieving the measured values, obtaining the oscillographic fault records, reading the states of the 7UM62 and the measurement quantities, and issuing control commands.

Interfaces on Back

Further interfaces are located on the back of the 7UM62 — dependent on the version of the device. Comprehensive communications are possible between these interfaces and other digital equipment used for operating, control, and data storage. The service interface can be operated through data lines. Also, a modem can be connected to this port. Servicing of the substation or plant is possible from a remote computer with DIGSI® 4. The system interface is for central communications between the 7UM62 and a control station. The service interface can be operated through data lines or optical fibres. Several standard protocols are available: − IEC 60870–5–103 Integration of the devices into the automation systems SINAUT® LSA and SICAM® also take place with this profile. − Profibus DP This protocol of automation technology allows to transmit annunciations and measured values. − Modbus ASCII/RTU This protocol of automation technology allows to transmit annunciations and measured values. − DNP 3.0 This protocol of automation technology allows to transmit annunciations and measured values. − It is also possible to provide an analog output (2 x 20 mA) for the output of measured values.

6

7UM62 Manual C53000-G1176-C149-3

1.3 Features

1.3

Features

General Features

• Powerful 32-bit microprocessor system. • Complete digital processing of measured values and control, from the sampling of the analog input quantities to the initiation of outputs for, as an example, tripping circuit breakers or other switch-gear devices. • Complete galvanic and reliable separation between the internal processing circuits of the 7UM62 and the external measurement, control, and DC supply circuits because of the design of the analog input transformers, binary inputs and outputs, and the DC converters. • Simple device operation using the integrated operator panel or by means of a connected personal computer running DIGSI® 4. • Continuous calculation and display of measured quantities. • Constant monitoring of the measurement quantities, as well as continuous selfdiagnostics covering the hardware and software. • Storage of operational data, fault data, and oscillographic fault records with information to be used for analysis and troubleshooting. • Communication with central control and data storage equipment via serial interfaces through the choice of data cable, modem, or optical fibers, as an option. • Battery-buffered real time clock that can be synchronized with an IRIG-B (or DCF77) signal, binary input signal, or system interface command. • Recording of circuit breaker statistics including the number of trip signals sent and the accumulated, interrupted currents of each pole of the circuit breaker. • Tracking of operating hours (time when load is supplied) of the equipment being protected. • Commissioning aids such as connection check, status information of binary inputs and relay outputs, and start of a fault record.

Definite-TimeOvercurrent Protection (I>) with Undervoltage SealIn Inverse-TimeOvercurrent Protection

• Two instantaneous (Definite-Time) overcurrent elements for phase protection; • Undervoltage seal-in for synchronous machines, the excitation voltage of which is derived from the machine terminals; • Optionally additional directional determination with the I>>–stage; • Blocking capability for reverse-interlocking bus-bar protection. • Common ANSI and IEC time overcurrent curves are available; • Optionally voltage controlled or voltage restraint alteration of pick-up value during undervoltage; • Undervoltage influence can be blocked by fuse failure monitor or via binary input, e.g. by a voltage transformer m.c.b.

Thermal Overload Protection

• Temperature rise of the protected equipment is calculated using a thermal homogeneous model that takes into account energy entering the equipment and energy losses. Thermal overload protection has full memory capability; • Adjustable warning levels based on temperature rise and current magnitude; • input of cooling medium or ambient temperature possible.

7UM62 Manual C53000-G1176-C149-3

7

1 Introduction

Unbalanced Load Protection

• Evaluation of negative sequence component of the three phase currents; • Alarm stage when a set unbalanced load is exceeded; • Thermal replica for rotor temperature rise with adjustable negative sequence factor K and adjustable time for cool down; • High-speed trip stage for large unbalanced loads (can be used for short-circuit protection).

Startup Overcurrent Protection

• I> stage for lower speed ranges (e.g. startup of generators with frequency starting converter).

Differential Protection

Used for generator, motor or transformer differential protection • Tripping characteristic with current restraint; • High degree of sensitivity; • Insensitivity to DC components and current transformer saturation; • High degree of stability even with different degrees of CT saturation; • Restraint feature against high inrush currents with 2nd harmonics; • Restraint feature against transient and steady-state fault currents with 3rd or 5th harmonics; • High-speed tripping in case of high-current faults; • Integrated matching of transformer vector group; • Integrated matching of transformation ratio with consideration of different c.t. rated currents.

Earth Current Differential Protection

• Tripping characteristic with restraining current; • Variable selection of measured quantities for all normal plant conditions; • High sensitivity; • Additional stabilisation measures against overfunction at external faults.

Underexcitation Protection

• Conductance measurement from positive sequence components; • Multi-step characteristic for steady-state and dynamic stability limits; • Detection of the excitation voltage.

Reverse Power Protection

• Calculation of power from positive sequence components; • Highly sensitive active power measurement (detection of small motoring powers even with small power factor cos ϕ, angle error correction); • Insensitive to power swings; • Independent long-time stage and short-time stage with stop valve tripped.

Forward Power Supervision

• Calculation of power from positive sequence components; • Supervision of over-power (P>) and/or under-power (P<) with individually adjustable power limits; • Optionally high-speed or high-accuracy power measurement.

8

7UM62 Manual C53000-G1176-C149-3

1.3 Features

Impedance Protection

• Phase selective overcurrent fault detection with undervoltage seal-in (for synchronous machines which take their excitation voltage from the terminal voltage); • 2 impedance zones, 1 overreach zone for zone extension (controlled via binary input), 4 time stages; • Polygonal tripping characteristics; • Additional power swing blocking.

Out-of-Step Protection

• Based on the well-proven impedance measurement method; • Measurement release by the positive sequence current, and measurement blocking by the negative sequence current; • Evaluation of the rate of change of the complex impedance vector; • Optimum matching to the system conditions by selectable slope of the characteristic; • Reliable distinction between the power swing centre being in the system or in the generator unit area.

Undervoltage Protection

• Two undervoltage elements, measuring positive sequence voltage.

Overvoltage Protection

• Two-stage overvoltage measurement, evaluation of the highest of the three voltages;

• Additional stage with settable, voltage-dependent time characteristic.

• Optionally with phase-to-phase voltages or with phase-to-earth voltages. Frequency Protection

• Four elements that are independently adjustable for function - underfrequency or overfrequency, pickup, and time delay; • Insensitive to harmonics and abrupt phase angle changes; • Adjustable undervoltage blocking.

Overexcitation Protection

• Calculation of the ratio U/f; • Adjustable warning and tripping stage; • Standard characteristic or either optional characteristic selectable for calculation of the thermal stress.

Rate-of-FrequencyChange Protection

• Monitors whether the frequency exceeds (df/dt>) and/or falls below (df/dt<) a set limit value, with 4 individually settable limit values or delay times; • Variable measuring windows; • Coupling to frequency protection pickup; • Settable undervoltage threshold.

Jump of Voltage Vector

• Sensitive phase jump detection to be used for network disconnection.

90–%–Stator Earth Fault Protection

• For machines in unit connection and for machines directly connected to busbars;

7UM62 Manual C53000-G1176-C149-3

9

1 Introduction

• Measurement of displacement voltage at the machine via the neutral transformers or earthing transformer or by calculation from phase-to-earth voltages; • Highly sensitive earth current detection, optional with or without directional determination with zero sequence components (I0, U0); • With adjustable slope of directional characteristic; • Discrimination of the earth-faulted phase. Sensitive Earth Current Protection

• Two sensitive earth fault instantaneous overcurrent elements: IEE>> and IEE>; • Pickup currents are adjustable and can be set very sensitive (as low as 2 mA); • Can be used for stator earth fault or rotor earth fault detection; • Measured circuit monitoring when used for rotor earth fault protection.

100–%–Stator Earth Fault Protection with 3rd Harmonics

• Detection of the 3rd harmonic of the voltage at the starpoint or open delta winding of an earthing transformer;

100–%–Stator Earth Fault Protection with 20 Hz Voltage Injection

• Evaluation of the 20 Hz measurement (7XT33 and 7XT34);

• In addition to the 90-%-stator earth fault protection there is a protection of the entire stator winding (protective range 100 %).

• Warning and trip stage R< and R<<; • Trip stage with earth current;. • High sensitivity also at large stator earth capacitances.

Rotor Earth Fault Protection

• 100 % protection for the entire excitation circuit; • Symmetrical capacitive coupling of a system-frequency AC voltage into the excitation circuit; • with consideration of operational earth impedances and brush resistances; • Calculation of the fault resistance from the total impedance; • Alarm stage and tripping stage directly adjustable in Ohms (rotor-earth resistance); • Measurement circuit supervision with alarm output.

Sensitive Rotor Earth Fault Protection with 1 to 3 Hz Square Wave Voltage Injection

• Evaluation of the 1 to 3 Hz square-wave voltage injected into the rotor circuit (7XT71);

Motor Starting Time Supervision

• Current dependent tripping based on an evaluation of the motor starting current;

Restart Inhibit for Motors

• Rotor temperature is calculated based on the stator currents;

• Warning and trip stage R< and R<<; • High sensitivity (max. 80 KΩ); • Integrated test function.

• Blocked rotor protection.

• Start-up is permitted only if the rotor has sufficient thermal reserves for a complete start-up; • Calculation of waiting time (till automatic reclosure is available);

10

7UM62 Manual C53000-G1176-C149-3

1.3 Features

• Different prolongation of cool-down time constants for rest/operation period is taken into consideration; • Disabling of the start inhibit is possible if an emergency start-up is required. Breaker Failure Protection

• Breaker failure condition determined by current flow after a trip signal has been issued, or the breaker position indication (binary input) can be evaluated; • Breaker failure protection initiated by the tripping of any integrated protective element that trips the circuit breaker (internal start); • Initiation possible through a binary input from an external protective device (external start).

Inadvertent Energization

• The inadvertent accidental energizing protection serves to limit damages by accidental connection of the standing generator by a fast actuation of the generator breaker; • Evaluation of negative sequence component of the three phase currents; • Released by operational condition check, undervoltage supervision, and fuse failure monitor.

DC Voltage/DC Current Protection

• DC voltage detection via integrated isolating amplifier (measuring transducer); • Suited for measurement of small DC currents; • Can be set for overvoltage (overcurrent) or undervoltage (undercurrent); • Optional average value or true r.m.s. value formation; the latter is suited to AC voltage measurement.

Analog Outputs

• Output of up to four analog operational measured values (depending on the variant ordered).

Threshold Supervision

• 6 freely assignable indications for threshold supervision;

Temperature Detection Using Thermoboxes

• Detection of any ambient or coolant temperature using external thermoboxes and external temperature detectors (RTDs).

Phase Rotation Changing

• Selectable L1, L2, L3 or L1, L3, L2 with a setting (static) or binary input (dynamic).

User-Defined Functions

• Internal and external signals can be logically combined to establish user-defined logic functions;

• Realization of fast supervision tasks with CFC.

• All common logic functions are available for programming (AND, OR, NOT, Exclusive OR, etc.); • Time delays and limit value inquiries are available; • Processing of measured values, including zero suppression, adding a knee characteristic for a transducer input, and live-zero monitoring.

7UM62 Manual C53000-G1176-C149-3

11

1 Introduction

Breaker Control

• Circuit breakers can be opened and closed via the programmable function keys on the front panel, through the SCADA, or through the front operator interface using a personal computer with DIGSI® 4); • Circuit breakers are monitored via the breaker auxiliary contacts; • Plausibility monitoring of the circuit breaker position and check of interlocking conditions.

Measuring Transducers

• If the 3 measuring transducers provided in the unit are not needed by the protection functions, they can be used to connect any type of analog signals (± 10 V, ± 20 mA); • Threshold processing and logical linking of measurement signals possible.

Monitoring Functions

• Availability of the 7UM62 is greatly increased because of self-monitoring of the internal measurement circuits, power supply, hardware, and software; • Current transformer and voltage transformer secondary circuits are monitored using summation and symmetry check techniques; • Trip circuit monitoring; • Phase Rotation. n

12

7UM62 Manual C53000-G1176-C149-3

2

Functions

This chapter describes the numerous functions available on the SIPROTEC® 7UM62 relay. The setting options for each function are explained, including instructions to determine setting values and formulae where required.

7UM62 Manual C53000-G1176-C149-3

2.1

Introduction, Reference Power System

16

2.2

Functional Scope

18

2.3

Power System Data 1

27

2.4

Setting Groups

35

2.5

Power System Data 2

36

2.6

Definite-Time Overcurrent Protection (I>, ANSI 50/51) with Undervoltage Seal-In 38

2.7

Definite-Time Overcurrent Protection (I>>, ANSI 50, 51, 67) with Direction Detection 42

2.8

Inverse-Time Overcurrent Protection (ANSI 51V)

48

2.9

Thermal Overload Protection (ANSI 49)

55

2.10

Unbalanced Load (Negative Sequence) Protection (ANSI 46)

65

2.11

Startup Overcurrent Protection (ANSI 51)

71

2.12

Differential Protection (ANSI 87G/87M/87T)

75

2.13

Earth Current Differential Protection (ANSI 87GN, TN)

98

2.14

Underexcitation (Loss-of-Field) Protection (ANSI 40)

106

2.15

Reverse Power Protection (ANSI 32R)

115

2.16

Forward Active Power Supervision (ANSI 32F)

119

2.17

Impedance Protection (ANSI 21)

122

2.18

Out-of-Step Protection (ANSI 78)

137

2.19

Undervoltage Protection (ANSI 27)

148

2.20

Overvoltage Protection (ANSI 59)

151

2.21

Frequency Protection (ANSI 81)

154

2.22

Overexcitation (Volt/Hertz) Protection (ANSI 24)

159

2.23

Inverse-Time Undervoltage Protection (ANSI 27)

164

2.24

Rate-of-Frequency-Change Protection df/dt (ANSI 81R)

167

2.25


172

13

Functions

14

2.26

90–%–Stator Earth Fault Protection (ANSI 59N, 64G, 67G)

177

2.27

Sensitive Earth Fault Protection (ANSI 51GN, 64R)

185

2.28

100–%–Stator Earth Fault Protection with 3rd Harmonics (ANSI 27/59TN 3rd Harm.) 189

2.29

100–% Stator Earth Fault Protection with 20 Hz Voltage Injection (ANSI 64G - 100%) 194

2.30

Rotor Earth Fault Protection R, fn (ANSI 64R)

2.31

Sensitive Rotor Earth Fault Protection with 1 to 3 Hz Square Wave Voltage Injection (ANSI 64R - 1 to 3 Hz) 206

2.32

Motor Starting Time Supervision (ANSI 48)

213

2.33

Restart Inhibit for Motors (ANSI 66, 49Rotor)

217

2.34

Breaker Failure Protection (ANSI 50BF)

225

2.35

Inadvertent Energization (ANSI 50, 27)

230

2.36

DC Voltage/DC Current Protection (ANSI 59NDC/51NDC)

234

2.37

Analog Outputs

239

2.38

Measured Value Monitoring Functions

241

2.39

Trip Circuit Supervision

254

2.40


261

2.41

External Trip Coupling

267

2.42

Temperature Detection by Thermoboxes

270

2.43

Inversion of Phase Sequence (Phase Sequence Reversal)

279

2.44

Protection Function Logic

281

2.45

Auxiliary Functions

286

2.46

Breaker Control

298

201

7UM62 Manual C53000-G1176-C149-3

Regionalization

The SIPROTEC® 7UM62 protective relays are offered in regional versions. The user should purchase only the functional scope that is needed. The prepared functions are adapted to the technical requirements of the regions. Table 2-1

Regionalization Function

Region DE Germany

Region Worldwide Worldwide

Region US USA

Language

German

English

American English

Frequency

50 Hz

50 Hz/ 60 Hz Default setting 50 Hz

60 Hz

X

X Default setting IEC characteristic curves

–

–

X

X

Characteristic curves for inverse-time overcurrent elements: IEC curves

ANSI curves

X Selectable option – Function not available for this region

7UM62 Manual C53000-G1176-C149-3

15

Functions

2.1

Introduction, Reference Power System The following chapters explain the individual protective and additional functions and provide information about on the setting values.

Generator

The calculation examples are based on two reference power systems with the two typical basic connections, i.e. the busbar connection and the unit connection (see Figure 2-1). All default settings of the relay are adapted accordingly. The allocation of measured quantities to side 1 and 2 respectively is shown in Figure 2-1.

Side 2

Side 1

5.27 MVA 6.3 kV 500 A/1 A

60/1 A

G

6.3 kV 100 V 100 V 3 √3 √3

3∼

Earthing transformer

RL

IL, S2

IEE

UL UE

IL, S1

7UM62

a) Busbar connection

Side 2 6.3 kV √3

/ 500 V

Side 1

5.3 MVA 5.27 MVA 6.3 kV 20 kV/6.3 kV 6.3 kV 100 V 500 A/1 A √3 √3 G

20 kV

3∼

UE

IL, S2

IEE1

UL

IL, S1

7UM62

b) Unit connection Figure 2-1

16

Reference Systems

7UM62 Manual C53000-G1176-C149-3

Introduction, Reference Power System

Technical Data of the Reference Power Systems

Generator:

SN, G = 5.27 MVA UN, G = 6.3 kV IN, G = 483 A cos ϕ = 0.8

Current transformer:

IN,prim

Toroidal current transformer IN,prim Voltage transformer:

Transformer

Motor

Transformer:

IN, sec= 1 A

= 60 A;

IN, sec = 1 A

UN, prim = (6.3/√3) kV

SN, T Uprim Usec usc

UN, sec = (100/√3) V Uen/3= (100/3) V

= 5.3 MVA = 20 kV = 6.3 kV =7%

Neutral transformer

6.3 kV 500 V √3

Resistor divider:

5:1

Motor:

UN, M IN, M ISTART Imax TSTART


= 500 A;

= 6600 V = 126 A = 624 A (Startup current) = 135 A (Admissible continuous stator current) = 8,5 s (Duration of startup with ISTART) IN,prim

= 200 A;

IN, sec= 1 A

Further technical data is provided within the framework of the functional setting specifications of the individual protective functions. The calculated setting values are secondary setting values related to the device and can be modified immediately by way of local operation. The use of the DIGSI® 4 operating program is recommended for complete reparameterization. In this way, the user has the possibility to specify primary values in addition to secondary settings. Within the framework of the 7UM62 the specification of primary values is performed as a setting related to the nominal quantities of the object to be protected (IN, G; UN, G; SN, G). This procedure has the advantage that system-independent, typical settings of the protective functions can be pre-specified. The data of the individual power system are updated in the power system data (see sections 2.3 and 2.5) and the conversion to secondary values is executed via a mouse click. All necessary conversion formula of the individual functions are stored in the operating program.

7UM62 Manual C53000-G1176-C149-3

17

Functions

2.2

Functional Scope

2.2.1

Description

General

The 7UM62 has numerous protective and additional functions. The hardware and firmware provided is designed for this scope of functions. Nevertheless a few restrictions apply to the use of the earth fault current and earth fault voltage inputs UE and IEE respectively. It is not possible to feed different measured quantities to one and the same input, i.e. to use the input, for example, for both rotor and stator earth fault protection. Table 2-2 gives an overview of the protective functions and the inputs they use. The command functions can be matched to the plant conditions. In addition, individual functions can be activated or deactivated during the configuration procedure, so that functions that are not needed can be disabled. The available protective and additional functions can be configured as Enabled or Disabled. For individual functions, the choice between several alternatives may be presented, as described below. Functions that are configured as Disabled are not processed by the 7UM62: There are no messages, and corresponding settings (functions, limit values) are not displayed during detailed settings.

Note: The functions and default settings depend of the variant ordered (for details refer to Table 2-1 and Appendix A.1). Also, not all combinations of protective functions are possible because of certain restrictions imposed by the hardware (see Table 2-2, “Allocation of Device Inputs to Protection Functions”).

Determination of Functional Scope

Configuration settings may be entered using a PC and the software program DIGSI® 4 and transferred via the operator interface on the device front, or via the rear serial service interface. Operation is described in the SIPROTEC® 4 System Manual. 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. The functional scope with the available options is set in the Device Configuration dialog box to match plant requirements.

2.2.2

Setting Hints

Special Cases

Most settings are self-explanatory. The special cases are described below. If the setting group change-over function is to be used, the setting in address 0103 Grp Chge OPTION must be set to enabled. In this case, it is possible to apply two groups of settings for the function parameters (refer also to Section 2.4) so that a convenient and fast switch-over between these setting groups is possible. The setting Disabled implies that only one function parameter setting group can be applied and used.

18

7UM62 Manual C53000-G1176-C149-3

Functional Scope

Parameter 0104 FAULT VALUE is used to specify whether the oscillographic fault recording should record Instantaneous values or RMS values. If RMS values are recorded, the available recording time increases by the factor 16. For some protective functions you can also choose the measuring inputs of the relay to which they will be allocated (side 1 or side 2); for other functions the allocation is fixed (see Table 2-2). For example, address 0112 O/C PROT. I> allows such a choice for the I> stage of the overcurrent protection (= Side 1, Side 2 or Disabled). For the high-current stage I>> of the overcurrent protection, address 0113 O/C PROT. I>> allows non-directional operation for side 1/side 2 or directional operation for side 1/side2. By setting Disabled, this overcurrent stage can be excluded altogether. For the inverse time overcurrent protection set in address 0114 O/C PROT. Ip, different sets of inverse characteristics are available, depending on the version ordered; they are either according to IEC or according to ANSI. This function, too, can be allocated to either side 1 or side 2 (= with IEC-characteristic on side 1, with ANSI-characteristic on side 1, with IECcharacteristic on side 2, with ANSI-characteristic on side 2). Inverse time overcurrent protection can be excluded altogether by setting Disabled. Table 2-2 shows the allocation of device inputs to the protection functions. The interdependencies shown here must be kept in mind when configuring the plant. This concerns the UE input, the two sensitive current inputs IEE1 and IEE2 as well as the 3 measuring transducer inputs (TD). Where the UE input is used e.g. by the stator earth fault protection functions, it is no longer available for rotor earth fault protection (R, fn) (see also Table 2-3). The same restrictions are true for measuring transducer inputs, which can only be used by one protection function at a time. Where the TDs are not used by any protection function, they are available for general processing by the measured value blocks in CFC. Table 2-2

Allocation of Device Inputs to Protection Functions

Side 1 Protection Function

Definite-time I>; I>> /nondirectional

ANSI

Side 2

UL1; UL2; UL3

IL1S1; IL2S1; IL3S1

IEE1

UE

IL1S2; IL2S2; IL3S2

IEE2

TD

Fixed

Selectable

-

-

Selectable

-

-

Fixed

Selectable

-

-

Selectable

-

-

ANSI 50

Definite-Time I>>/directional Inverse-Time Overcurrent Protection

ANSI 51, 67

Fixed

Selectable

-

-

Selectable

-

-


ANSI 49

-

-

-

-

Fixed

-

TD2

Negative Sequence Protection

ANSI 46

-

-

-

-

Fixed

-

-

Startup Overcurrent Protection

ANSI 51

-

-

-

-

Fixed

-

-

-

Fixed

-

-

Fixed

-

-


ANSI 87

Earth Fault Differential Protection

ANSI 87GN/TN

U0 calculated

Selectable

-

-

Selectable

Fixed

-

Underexcitation (Loss-of-Field) Protection

ANSI 40

Fixed

-

-

-

Fixed

-

TD3


ANSI 32R

Fixed

-

-

-

Fixed

-

-

Forward Active Power Supervision

ANSI 32F

Fixed

-

-

-

Fixed

-

-

7UM62 Manual C53000-G1176-C149-3

19

Functions

Table 2-2

Allocation of Device Inputs to Protection Functions

Side 1

Side 2

Protection Function

ANSI

UL1; UL2; UL3

IL1S1; IL2S1; IL3S1

IEE1

UE

IL1S2; IL2S2; IL3S2

IEE2

TD


ANSI 21

Fixed

-

-

-

Fixed

-

-


ANSI 78

Fixed

-

-

-

Fixed

-

-


ANSI 27

Fixed

-

-

-

-

-

-


ANSI 59

Fixed

-

-

-

-

-

-

Frequency Protection

ANSI 81

Fixed

-

-

Fixed

-

-

Overexcitation (Volt/Hertz) Protection

ANSI 24

Fixed

-

-

-

-

-

-

Inverse-Time Undervoltage Protection

ANSI 27

Fixed

-

-

-

-

-

-

Rate-of-Frequency-Change Protection

ANSI 81R

Fixed

-

-

-

-

-

-

Fixed

-

-

-

-

-

-

Jump of Voltage Vector 90–%–Stator Earth Fault Protection

ANSI 59N, 64G, 67G

U0 calculated if REFP is used

-

-

-

-

Fixed

-

Sensitive Earth Fault Protection

ANSI 51GN, 64R

-

-

Sele ct.

-

-

Select.

-

100–%–Stator Earth Fault Prot. with 3rd Harmonics

ANSI 27/ 59TN

Fixed

-

-

Fixed

Fixed

-

-

100–%–Stator Earth Fault Prot. with 20 Hz Voltage Injection

64G (100 %)

-

-

Fixed Fixed

-

-

-

ANSI 64R

-

-

Fixed Fixed

-

-

-

Sensitive Rotor Earth Fault Pro- ANSI 64R tection with 1 to 3 Hz Square Wave Voltage Injection

-

-

-

-

-

-

TD1 TD2


ANSI 48

-

-

-

-

Fixed

-

-


ANSI 66, 49Rotor

-

-

-

-

Fixed

-

-

Breaker Failure Protection

ANSI 50BF

-

Selectable

-

-

Selectable

-

-

Inadvertent Energization

ANSI 50/27

Fixed

-

-

-

Fixed

-

-

DC Voltage/DC Current Protection

ANSI 59N DC/51N DC

-

-

-

-

-

-

TD1

Fixed

-

-

-

Fixed

-

-

-

-

-

-

-

-

-

Fixed

-

-

-

Fixed

-

-

-

-

-

-

-

-

-

Rotor Earth Fault Protection REFP

Fuse Failure Monitor Trip Circuit Monitoring Threshold Supervision External Trip Commands

20

ANSI 74TC

7UM62 Manual C53000-G1176-C149-3

Functional Scope

For the differential protection, address 0120 DIFF. PROT. allows to specify the type of protected object (Generator/Motor or 3-phase Transformer); the function can be excluded altogether by setting Disabled.

Side 2

Side 1 G

3∼

Address 0120 DIFF. PROT. = Generator/Motor

7UM62

Figure 2-2

Use as Generator Differential Protection

Side 2

Side 1 G

3∼

Address 0120 DIFF. PROT. = 3-phase Transformer

7UM62

Figure 2-3

Use as Block Differential Protection (Overall Protection)

For the following application, the settings of the generator data under Power System Data 1 must be same as for the transformer data of side 2:

Side 1

Side 2 G

3∼

7UM62

Figure 2-4

7UM62 Manual C53000-G1176-C149-3


Use as Transformer Differential Protection

21

Functions

For the following application, the differential protection of device A must be set to Generator/Motor, and that of device B to 3-phase Transformer. Also, the settings of the generator data under Power System Data 1 must be same as for the transformer data of side:

(A) Side 2

(A) Side 1 (B) Side 2

(B) Side 1

G

3∼

A

Address 0120 DIFF. PROT. = Generator/Motor Figure 2-5

B

7UM62

7UM62


Use as Redundant Overall Protection

For earth fault protection, address 0150 S/E/F PROT. presents the options nondir. only U0, non-dir. U0&I0 and Directional, unless the whole function is Disabled. The first option evaluates only the displacement voltage (to be used with unit connection). The second option evaluates in addition to the displacement voltage the magnitude of the earth fault current (or the difference between the starpoint current and the total current of a toroidal CT, as is the case in busbar systems with low-ohmic switchable starpoint resistors). The third option considers as a third criterion the direction of the earth fault current in the case of machines in busbar connection where the magnitudes of displacement voltage and earth fault current alone are not sufficient to distinguish between system earth faults and machine earth faults. Address 0151 O/C PROT. Iee> is used to specify which input will be used for earth fault current measurement (IEE1 or IEE2). Address 0170 BREAKER FAILURE specifies whether the circuit breaker failure protection will apply for side 1 or side 2. If the 7UM62 is equipped with analog outputs and you want to use them, the addresses 0173, 0174, 0175 and 0176 allow to allocate the available measured values to the analog outputs. All parameters of the analog outputs are accessed under the block address 0173. For trip circuit monitoring, address 0182 Trip Cir. Sup. is used to specify whether two binary inputs (with 2 Binary Inputs) or only one binary input (with 1 Binary Input) should be utilized, or whether the function should be Disabled.

22

7UM62 Manual C53000-G1176-C149-3

Functional Scope

2.2.2.1 Addr.

Settings Setting Title

Setting Options

Default Setting

Comments

103

Grp Chge OPTION

Disabled Enabled

Disabled

Setting Group Change Option

104

FAULT VALUE

Disabled Instantaneous values RMS values

Instantaneous values

Fault values

105

DIFF. PROT.

Disabled Enabled

Enabled


106

PROT. OBJECT

Generator/Motor 3 phase Transformer

Generator/Motor

Protection Object

112

O/C PROT. I>

Disabled Side 1 Side 2

Side 2

Overcurrent Protection I>

113

O/C PROT. I>>

Disabled Non-Directional on side 1 Non-Directional on side 2 Directional on side 1 Directional on side 2

Non-Directional on Overcurrent Protection I>> side 2

114

O/C PROT. Ip

Disabled with IEC-characteristic on side 1 with ANSI-characteristic on side 1 with IEC-characteristic on side 2 with ANSI-characteristic on side 2

Disabled

Inverse O/C Time Protection

116

Therm.Overload

Disabled Enabled

Enabled


117

UNBALANCE LOAD Disabled Enabled

Enabled

Unbalance Load (Negative Sequence)

118

O/C STARTUP

Disabled Enabled

Enabled

Startup O/C protection

120

DIFF. PROT.

Disabled Generator/Motor 3 phase Transformer

Generator/Motor


121

REF PROT.

Disabled Generator/Motor with IEE2 Generator/Motor with 3I0 of Side 2 with Side 1 of Transformer with Side 2 of Transformer

Disabled

Restricted earth fault protection

130

UNDEREXCIT.

Disabled Enabled

Enabled


131

REVERSE POWER Disabled Enabled

Enabled


132

FORWARD POWER

Enabled


7UM62 Manual C53000-G1176-C149-3

Disabled Enabled

23

Functions

Addr.

Setting Title

Setting Options

Default Setting

Comments

133

IMPEDANCE PROT.

Disabled Enabled

Enabled


135

OUT-OF-STEP

Disabled Enabled

Enabled


140

UNDERVOLTAGE

Disabled Enabled

Enabled


141

OVERVOLTAGE

Disabled Enabled

Enabled


142

FREQUENCY Prot.

Disabled Enabled

Enabled

Over / Underfrequency Protection

143

OVEREXC. PROT.

Disabled Enabled

Enabled

Overexcitation Protection (U/f)

144

INV.UNDERVOLT.

Disabled Enabled

Enabled

Inverse Undervoltage Protection Up<

145

df/dt Protect.

Disabled with 2 df/dt stages with 4 df/dt stages

with 2 df/dt stages

Rate-of-frequency-change protection

146

VECTOR JUMP

Disabled Enabled

Enabled


150

S/E/F PROT.

Disabled non-directional only U0 non-directional with U0 & I0 directional

non-directional with U0 & I0

Stator Earth Fault Protection

151

O/C PROT. Iee>

Disabled with Iee1 with Iee2

with Iee2

Sensitive Earth Current Protection

152

SEF 3rd HARM.

Disabled Enabled

Enabled

Stator Earth Fault Prot. 3rd Harmonic

153

100% SEF-PROT.

Disabled Enabled

Enabled

100% Stator-Earth-Fault Protection

160

ROTOR E/F

Disabled Enabled

Enabled

Rotor Earth Fault Protection (R, fn)

161

REF 1-3Hz

Disabled Enabled

Enabled

Rotor Earth Fault Protection (13Hz)

165

STARTUP MOTOR

Disabled Enabled

Enabled


166

RESTART INHIBIT

Disabled Enabled

Enabled


170

BREAKER FAILURE


Side 2


171

INADVERT. EN.

Disabled Enabled

Enabled

Inadvertent Energisation

172

DC PROTECTION

Disabled Enabled

Enabled

DC Voltage/Current Protection

24

7UM62 Manual C53000-G1176-C149-3

Functional Scope

Addr.

Setting Title

Setting Options

Default Setting

Comments

173

ANALOGOUTPUT B1

Disabled Positive Sequence Current I1 [%] Negative Sequence Current I2 [%] Positive Sequence Voltage U1 [%] Active Power |P| [%] Reactive Power |Q| [%] Frequency f [%] |Power Factor| [%] p.u. Temperature of Rotor [%] p.u. Temperature of Stator [%]

Disabled

Analog Output B1 (Port B)

174

ANALOGOUTPUT B2


Disabled


175

ANALOGOUTPUT D1


Disabled

Analog Output D1 (Port D)

7UM62 Manual C53000-G1176-C149-3

25

Functions

Addr.

Setting Title

Setting Options

Default Setting

Comments

176

ANALOGOUTPUT D2


Disabled


180

FUSE FAIL MON.

Disabled Enabled

Enabled

Fuse Failure Monitor

181

M.V. SUPERV

Disabled Enabled

Enabled

Measured Values Supervision

182

Trip Cir. Sup.

Disabled with 2 Binary Inputs with 1 Binary Input

Disabled


185

THRESHOLD

Disabled Enabled

Enabled


186

EXT. TRIP 1

Disabled Enabled

Enabled

External Trip Function 1

187

EXT. TRIP 2

Disabled Enabled

Enabled


188

EXT. TRIP 3

Disabled Enabled

Enabled


189

EXT. TRIP 4

Disabled Enabled

Enabled


190

RTD-BOX INPUT

Disabled Port C Port D Port E

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 Connection Type

26

7UM62 Manual C53000-G1176-C149-3

Power System Data 1

2.3

Power System Data 1

2.3.1

Functional Description

General

2.3.2

The device requires certain basic data regarding the protected equipment, so that the device will be compatible with its desired application. These may be, for instance, rated power system and transformer data, measured quantity polarities and their physical connections, breaker properties etc. There are also certain parameters that are common to all functions, i.e. not associated with a specific protection, control or monitoring functions. The following section discusses these Power System Data 1.

Setting Hints The Power System Data 1 can be changed from the operator or service interface with a personal computer using DIGSI® 4. In DIGSI® 4, double-click Settings to display the data available.

Connection of the Current Transformer Sets

At address 0201 STRPNT->OBJ S1 you specify the polarity of the CTs of plant side 1, i.e. the location of the CT starpoint with reference to the protected object. At address 0210 STRPNT->OBJ S2 the polarity of the CTs of side 2 is specified. This setting determines the measuring direction of the 7UM62 (STRPNT->OBJ S2 = Yes = Forwards = line direction). Figure 2-6 shows the definition even in cases where there are no starpoint CTs.

Side 2

Side 1

Side 2

G

Side 1

G

a) STRPNT→OBJ S1 = YES

b) STRPNT→OBJ S1 = NO

STRPNT→OBJ S2 = YES

STRPNT→OBJ S2 = NO

Figure 2-6

Location of Starpoints for CTs of S1 and S2 - Addresses 0201 and 0210 -

If the device is to be used for transverse differential protection of generators or motors, a particularity must be observed in the connection of the current transformers. In this case, all currents flow in healthy operation into the protected object, as opposed to all other applications. Therefore, a “wrong” polarity must be set for one set of CTs. The “sides” here are equivalent to the machine winding sections.

7UM62 Manual C53000-G1176-C149-3

27

Functions

Figure 2-7 shows an example. Although the starpoints of both CT sets are turned towards the protected object, “side 2” is set to the opposite: 210 STRPNT->OBJ S2 = NO.

“Side 1“

“Side 2“

L1

L2

L3

0201 STRPNT–>OBJ S1 = YES

0210 STRPNT–>OBJ S2 = NO

Figure 2-7 Current Transformer Starpoints in Transverse Differential Protection - Example

Nominal Values of CTs and VTs

At addresses 0221 IN-PRI I-SIDE1 and 0222 IN-SEC I-SIDE1 information is entered regarding the primary nominal voltage and secondary nominal currents of the CTs of side 1. It is important to ensure that the rated secondary current of the current transformer matches the rated current of the device, otherwise the device will incorrectly calculate primary amperes.

W0 Correction Angle

A correction of the angle faults of the current transformers and voltage transformers is particularly important with regard to the reverse power protection, as in this case, a very low active power is calculated from a very high apparent power (for small cos ϕ (PF)). At address 0204 CT ANGLE W0 a constant correction angle can be entered for the CTs of side 2. The angle fault difference ∆ϕ between the current transformers and voltage transformers is particularly important in this context. As a correction, the sum of the mean angle errors of the current transformers and voltage transformers is set. The corrective value can be determined within the framework of machine commissioning (see Section 3.4.10.2).

Iee Transformation Ratios

For the conversion of the ground currents Iee in primary quantities, the device requires the primary/secondary transformation ratio of the earth CTs. The transformation ratio for input 1 is set at the address 0205 FACTOR IEE1, the ratio for input 2 at 0213 FACTOR IEE2.

Nominal Values of the Transformers on Side 2

At addresses 0211 IN-PRI I-SIDE2 and 0212 IN-SEC I-SIDE2 information is entered regarding the primary nominal voltage and secondary nominal currents of the CTs of side 2. It is important to ensure that the rated secondary current of the current transformer matches the rated current of the device, otherwise the device will incorrectly calculate primary amperes.

28

7UM62 Manual C53000-G1176-C149-3

Power System Data 1

Nominal Values of Voltage Transformers

At addresses 0221 Unom PRIMARY and 0222 Unom SECONDARY, information is entered regarding the primary nominal voltage and secondary nominal voltages (phase-to-phase) of the connected voltage transformers.

Voltage Connection UE

At address 0223 UE CONNECTION the user specifies to the device which type of voltage is connected to the UE input. The device derives from this information the way of processing the input signal. The UE input is used for either the various stator earth fault protection functions or for rotor earth fault protection using rated frequency voltage injection (see Section 2.30). Table 2-3 shows the interdependencies for each protection function.

Table 2-3

Setting Options for the UE Input and their Impact on the Protection Functions

Setting of UE CONNECTION

90-%-Stator Earth Fault Protection

(Addr. 0223)

(Section 2.26)

Stator Earth Fault Protection with 3rd Harmonics (Section 2.28)

100-%-Stator Earth Fault Protection (20 Hz) (Section 2.29)

Rotor Earth Fault Protection (R, fn) (Section 2.30)

not connected

Processing of U0 measured value (precisely: √3 U0)

Determination of 3rd har- – monics from calculated U0 voltage (Only U0 3rd harm > stage usable).

–

UE connected to loading resistor


–

Processing of UE input

–

UE connected to any Processing of UE intransformer put (e.g. earth fault protection on transformer side)

–

–

–

UE connected to Processing of UE inbroken delta winding put



–

UE connected to rotor


–

–


UE connected to neutral transformer




–

Transformation Ratio UE

For the conversion of the displacement voltage UE in primary quantities, the device requires the primary/secondary transformation ratio of the transformer delivering the UE voltage. With the exception of the rotor earth fault protection, the 0224 FACTOR UE has an impact on those protection functions which process the UE input directly, as shown in Table 2-3. For this ratio 0224 FACTOR UE the following general formula applies: 0224 FACTOR UE

U VT, prim = ----------------------U E, sec

In this context, UVT, prim is the primary voltage and UE, sec is the secondary displacement voltage applied to the device. If a voltage divider is used, its divider ratio also influences this factor. The following equation results for the example in Figure 21b with the power system data selected there and an 1:5 voltage divider ratio: 6.3 kV ⁄ ( 3 ) 0224 FACTOR UE = --------------------------------- = 36.4 500 V ⁄ 5

7UM62 Manual C53000-G1176-C149-3

29

Functions

Uph/Uen Adaption Factor

The address 0225A serves to communicate the adaptation factor between the phase voltage and the displacement voltage to the device. This information is relevant for measured-quantity monitoring. If the voltage transformer set has broken delta windings and if these windings are connected to the device (VN input), this must be specified accordingly in address 0223 (see below at side title ”Voltage Connection UE”). As the transformation ratio of the voltage transformers is usually: U Nprim ----------------3

Nsec Nsec - ⁄ -------------⁄ -------------3 3

U

U

the factor Uph/Uen (secondary voltage, address 0225A Uph / Udelta) in relation to 3/√3 = √3 = 1.73 must be used if the Uen voltage is connected. For other transformation ratios, i.e. the formation of the displacement voltage via an interconnected transformer set, the factor must be corrected accordingly. Protected Object: Transformer

If you have specified a transformer as the protected object during configuration of the differential protection, the parameter 0241 UN-PRI SIDE 1 appears in the Power System Data 1. It specifies the nominal primary voltage of side 1 of the protected object (transformer). At address 0242 STARPNT SIDE 1 you specify the whether the starpoint of side 1 is (Solid Earthed or Isolated). This setting has an influence on the measured value monitoring (summation current monitoring); in transformer differential protection, it is also important for the vector group correction and the treatment of the zero sequence current. The setting Isolated can be chosen if the starpoint has no earthing. If the transformer starpoint is connected to a Petersen coil or a surge voltage arrester, choose the setting Solid Earthed. The same applies to low-ohmic or solid starpoint earthing. The parameters 0243 UN-PRI SIDE 2 and 0244 STARPNT SIDE 2 determine respectively the rated primary voltage and the starpoint of side 2 of the transformer. Parameter 0246 VECTOR GRP S2 is used to specify the vector group numeral referred to side 1 of the transformer. It is not necessary to specify whether the connection is delta, wye or zigzag. At address 0249 SN TRANSFORMER the rated apparent power of the transformer is input. The nominal currents for side 1 and 2 are calculated on this basis as follows: S N, Transf I N, S1 = ---------------------------U N, S1 ⋅ 3

S N, Transf IN, S2 = ---------------------------U N, S2 ⋅ 3

These nominal currents are only considered for differential protection and can differ from the generator ratings. For the overcurrent protection functions (Sections 2.6, 2.7, and 2.8) and for the breaker failure protection, sides 1 and 2 can be allocated freely. With the differential protection set to 0120 3 phase transf., the following normalizing factors apply for the primary side protection settings in DIGSI. Side 1: I N, S1

30

S N, Transf = ---------------------------U N, S1 ⋅ 3

Side 2: S N, Generator I N, S2 = -------------------------------------------U N, Generator ⋅ 3

7UM62 Manual C53000-G1176-C149-3

Power System Data 1

Setting parameters: SN,Transf

0249 SN TRANSFORMER

UN, S1

0241 UN-PRI SIDE 1

SN, Generator

0252 SN GEN/MOTOR

UN, Generator

0251 UN GEN/MOTOR

These normalizing factors apply for transformer protection and overall protection (see Figures 2-3 and 2-4). Protected Object: Generator/Motor

Regardless of the configuration and intended use of the differential protection, the generator/motor ratings must be specified. Parameter 0251 UN GEN/MOTOR specifies the primary rated voltage of the protected generator or motor. At parameter 0252 SN GEN/MOTOR the rated apparent power is entered. From these values the nominal generator/motor current for plant side 2 is calculated: S N, Generator I N, Generator = -------------------------------------------U N, Generator ⋅ 3 Setting parameters: SN, Generator

0252 SN GEN/MOTOR

UN, Generator

0251 UN GEN/MOTOR

The above formula is also used by the DIGSI communication software to determine the normalizing factors for the primary side protection settings of the overcurrent protection functions (Sections 2.6, 2.7, and 2.8) and of the breaker failure protection, where the sides (side 1 and side 2) can be freely allocated. Normalization is active if the differential protection in the scope of functions is set to 0120 Disabled or Generator/Motor. It applies for both side 1 and side 2. Rated Frequency

The rated system frequency is set at address 0270 Rated Frequency. The setting is dependent on the model number of the relay purchased, and must be in accordance with the nominal frequency of the power system.

Phase Rotation (Phase Sequence)

Address 0271 PHASE SEQ. is used to establish phase rotation reversal. The default phase sequence is (L1 L2 L3 for clockwise rotation) can be changed if your power system permanently has an anti-clockwise phase sequence (L1 L3 L2). A temporary reversal of rotation is also possible using binary inputs (see Section 2.43). L1

L3

L1

L2

Clockwise rotation L1, L2, L3 Figure 2-8

Operating Mode

7UM62 Manual C53000-G1176-C149-3

L2

L3

Anti-clockwise rotation L1, L3, L2

Phase Sequences

The 0272 SCHEME setting is used for specifying if the generator to be protected is operated in the Unit transformer connected or in the Direct connected to busbar mode. This specification is important for the stator earth fault connection and for the inverse O/C time protection with undervoltage consideration, as different voltages are used here, depending on the corresponding operating mode (see ”Undervoltage Consideration” in Section 2.8.1).

31

Functions

ATEX100

Parameter 0274A ATEX100 allows compliance with PTB requirements (special requirements for Germany) for thermal replicas. If this parameter is set to YES, all thermal replicas of the 7UM62 are stored in case of a power supply failure. As soon as the supply voltage returns, the thermal replicas continue operating with the stored values. If the parameter is set to NO, the calculated overtemperature values of all thermal replicas are reset to zero in case of a power supply failure.

Trip Command Duration

Address 0280 is used to set the minimum time the tripping contacts will remain closed (TMin TRIP CMD). This setting applies to all protective functions that initiate tripping.

Current Flow Monitoring

Address 0281 BkrClosed I MIN corresponds to the threshold value of the integrated current flow monitoring feature. This setting is used for the elapsed-time meter and the overload protection. If the set threshold current is exceeded, the circuit breaker is considered closed and the power system is considered to be in operation. In the case of overload protection, this criterion serves for distinguishing between the standstill and the motion of the machine to be protected.

Measuring Transducer 1

Measuring transducer 1 is provided for DC voltage/DC current protection or the rotor earth fault protection with 1 to 3 Hz (UControl). Depending on the intended application, select at address 0295 TRANSDUCER 1 either 10 V, 4–20 mA or 20 mA. In the first case, the measuring range is between –10 V and +10 V. The 4–20 mA interface is designed for operation with sign, i.e. a current of 12 mA corresponds to an input value of 0 (see Figure 2-9). With currents in excess of < 2 mA, the device signals a wire break. The alarm drops out at currents below > 3 mA. If the alternative 20 mA is selected, the measuring range is between –20 mA and + 20 mA.

Wire break

–8

0

+8

4

12

20

Represented input value I/mA

0

2

Figure 2-9

Measured quantity

Relationship between Measured Quantity and Represented Input Value at Measuring Transducer TD 1 with Setting 4–20 mA


Measuring transducer 2 is provided for overload protection. In combination with an (external) temperature sensor and measuring transducer, it allows input of an ambient or coolant temperature. It is matched to the upstream measuring transducer by selecting at the address 0296 TRANSDUCER 2 one of the standard alternatives 10 V, 4–20 mA or 20 mA.


Measuring transducer 3 is provided for underexcitation protection or the rotor earth fault protection with 1 to 3 Hz (UControl) and is therefore designed for voltage input (10 V). The excitation voltage is fed to the measuring transducer via a voltage divider. Where the excitation DC voltage may contain a large amount of superimposed harmonics (e.g. owing to thyristor control), the integrated digital filter should be used; it is selected at the address 0297 TRANSDUCER 3 by setting with filter.

32

7UM62 Manual C53000-G1176-C149-3

Power System Data 1

2.3.2.1 Addr.

Settings 1 Setting Title

Setting Options

Default Setting

Comments

270

Rated Frequency

50 Hz 60 Hz

50 Hz

Rated Frequency

271

PHASE SEQ.

L1 L2 L3 L1 L3 L2

L1 L2 L3

Phase Sequence

272

SCHEME

Direct connected to busbar Unit transformer connected

Direct connected to busbar

Scheme Configuration

274A

ATEX100

YES NO

NO

Storage of th. Replicas w/o Power Supply

275

FACTOR R SEF

1.0..200.0

37.0

Ratio Prim./Sec. R SEF

276

TEMP. UNIT

Degree Celsius Degree Fahrenheit

Degree Celsius

Unit of temparature measurement

251

UN GEN/MOTOR

0.40..800.00 kV

6.30 kV

Rated Primary Voltage Generator/Motor

252

SN GEN/MOTOR

0.20..5000.00 MVA

5.27 MVA

Rated Apparent Power of the Generator

242

STARPNT SIDE 1

Isolated Solid Earthed

Isolated

Starpoint of Side 1 is

244

STARPNT SIDE 2


Isolated

Starpoint of side 2 is

241

UN-PRI SIDE 1

0.40..800.00 kV

20.00 kV

Rated Primary Voltage Side 1

243

UN-PRI SIDE 2

0.40..800.00 kV

6.30 kV

Rated Primary Voltage side 2

246

VECTOR GRP S2

0..11

0

Vector Group Numeral of Side 2

249

SN TRANSFORMER

0.20..5000.00 MVA

5.30 MVA

Rated Apparent Power of the Transformer

201

STRPNT->OBJ S1

YES NO

YES

CT-Strpnt. Side1 in Direct. of Object

202

IN-PRI I-SIDE1

1..100000 A

500 A

CT Rated Primary Current Side 1

203

IN-SEC I-SIDE1

1A 5A

1A

CT Rated Secondary Current Side 1

204

CT ANGLE W0

-5.00..5.00 °

0.00 °

Correction Angle CT W0

205

FACTOR IEE1

1.0..100000.0

60.0

CT Ratio Prim./Sec. IEE1

210

STRPNT->OBJ S2

YES NO

YES


211

IN-PRI I-SIDE2

1..100000 A

500 A


212

IN-SEC I-SIDE2

1A 5A

1A


213

FACTOR IEE2

1.0..100000.0

60.0


214

GRD TERM. IEE2

Terminal Q7 Terminal Q8

Terminal Q7

Grounded Terminal CT IEE2

7UM62 Manual C53000-G1176-C149-3

33

Functions

Addr.

Setting Title

Setting Options

Default Setting

Comments

221

Unom PRIMARY

0.10..400.00 kV

6.30 kV

Rated Primary Voltage

222

Unom SECONDARY

100..125 V

100 V

Rated Secondary Voltage (PhPh)

223

UE CONNECTION

UE connected to neutral transformer UE connected to broken delta winding not connected UE connected to any VT UE connected to Rotor UE connected to Loading Resistor

UE connected to UE Connection neutral transformer

224

FACTOR UE

1.0..2500.0

36.4

VT Ratio Prim./Sec. Ue

225A

Uph / Udelta

1.00..3.00

1.73

Matching Ratio Ph.-VT to Broken-Delta-VT

280

TMin TRIP CMD

0.01..32.00 sec

0.15 sec

Minimum TRIP Command Duration

281

BkrClosed I MIN

0.04..1.00 A

0.04 A

Closed Breaker Min. Current Threshold

295

TRANSDUCER 1

10 V 4-20mA 20mA

10 V

Transducer 1

296

TRANSDUCER 2

10 V 4-20mA 20mA

10 V

Transducer 2

297

TRANSDUCER 3

with filter without filter

with filter

Transducer 3

2.3.2.2

List of Information

F.No.

Alarm

Comments

05145 >Reverse Rot.

>Reverse Phase Rotation

05147 Rotation L1L2L3

Phase Rotation L1L2L3

05148 Rotation L1L3L2

Phase Rotation L1L3L2

00361 >FAIL:Feeder VT

>Failure: Feeder VT (MCB tripped)

05002 Operat. Cond.

Suitable measured quantities present

34

7UM62 Manual C53000-G1176-C149-3

Setting Groups

2.4

Setting Groups

2.4.1


Purpose of Setting Groups

Two independent groups of parameters can be set for the device functions. The user can switch back and forward 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 Enabled during configuration (see Section 2.2). In the 7UM62 relay, two independent setting groups (A and B) are available. While setting values may vary among the two setting groups, the selected functions of each setting group remain the same. Where different settings are required for operational reasons, e.g. in pumped storage power stations with a machine operating alternately as a generator and a motor, these settings are made in the setting groups and stored in the device. Every time the operating mode changes, the applicable setting group is activated, usually by a binary input. If multiple setting groups are not required, Group A is the default selection, and the following paragraph is not applicable.

2.4.2

Setting Hints If multiple setting groups are desired, Grp Chge OPTION = Enabled must have been set (address 0103). When setting the function parameters, you configure first setting group A, then setting group B. To find out how to proceed for this, how to copy and to reset settings groups, and how to switch between setting groups during operation, please refer to the DIGSI® 4System Manual, Order No. E50417–H1176–C151. Section 3.1.2 describes how to switch between setting groups from outside the device, using binary inputs.

2.4.2.1

Settings

Addr. 302

2.4.2.2

Setting Title CHANGE

Setting Options Group A Group B Binary Input Protocol

Default Setting Group A

Comments Change to Another Setting Group

Information

F.No.

Alarm

00007 >Set Group Bit0

Comments >Setting Group Select Bit 0

Group A

Group A

Group B

Group B

7UM62 Manual C53000-G1176-C149-3

35

Functions

2.5

Power System Data 2

2.5.1

Functional Description General protective data (P.SYSTEM DATA2) includes settings associated with all functions rather than a specific protective or monitoring function. In contrast to the P.SYSTEM DATA1 as discussed in Sub-section 2.3, these settings can be changed over with the setting groups.

Setting Groups

2.5.2

In the 7UM62 relay, two independent setting groups (A and B) are possible. While setting values may vary among the two setting groups, the selected functions of each setting group remain the same.

Setting Hints To enter these group-specific general protection data (Power System Data 2), select in the menu SETTINGS the item P-Group A and there the item P.Systemdata2. The second setting group is accessed in P–Group B. Address 1108 ACTIVE POWER is used to specify the active power direction in the normal mode (Generator = output or Motor = input) or to adapt it to the power system conditions without any recabling on the device.

Active Power Direction

2.5.2.1

Settings

Addr.

Setting Title

1108

2.5.2.2

ACTIVE POWER

Setting Options Generator Motor

Default Setting Generator

Measurement of Active Power for

Information

F.No.

Alarm

Comments

00576 IL1 S1:

Primary fault current IL1 Side1

00577 IL2 S1:


00578 IL3 S1:


00579 IL1 S2:


00580 IL2 S2:


00581 IL3 S2:


05012 UL1E:

Voltage UL1E at trip

05013 UL2E:


05014 UL3E:


05015 P:

Active power at trip

05016 Q:

Reactive power at trip

36

Comments

7UM62 Manual C53000-G1176-C149-3

Power System Data 2

F.No. 05017 f:

7UM62 Manual C53000-G1176-C149-3

Alarm

Comments Frequency at trip

37

Functions

2.6

Definite-Time Overcurrent Protection (I>, ANSI 50/51) with Undervoltage Seal-In

General

The overcurrent protection is used as backup protection for the short-circuit protection of the protected object. It also provides backup protection for downstream network faults which are not promptly disconnected and thus may endanger the protected object. The 7UM62 relay allows to choose between the input transformers of side 1 and side 2 for allocation of the overcurrent protection function. This choice is made during configuration (see Section 2.2). Initially, the currents are numerically filtered so that only the fundamental-frequency currents are used for the measurement. This makes the measurement insensitive to transient conditions at the inception of a short-circuit and to asymmetrical short-circuit currents (d.c. component). In generators where the excitation voltage is derived from the machine terminals, the short-circuit current subsides quickly in the event of close-up faults (i.e. in the generator or unit transformer range) due to the absence of excitation voltage the current decreases within a few seconds to a value below the pick-up value of the overcurrent time protection. To avoid that the relay drops out again, the I> stage monitors the positive-sequence component of the voltages and uses it as an additional criterion for detecting a short-circuit. The undervoltage influencing can be switched off and made ineffective by means of a binary input.

2.6.1


I> stage

Each phase current is compared individually with the I> common setting value. Currents above these value are recorded and signalled individually. As soon as the corresponding T I> time delay has elapsed, a trip signal is transmitted to the matrix. In the delivery status of the device, the drop-out value is set to ± 95 % below the pickup value. For special applications, it is also possible to specify a higher value.

Undervoltage SealIn

The I> stage has an undervoltage stage that can be disabled. This stage maintains the pick-up signal for a settable seal-in time if the value falls below a settable threshold of the positive-sequence component of the voltages after an overcurrent pickup - even if the current falls again below the overcurrent pick-up value. This will ensure that the 50-1 timer is sealed in, and will time-out to trip the associated circuit-breakers. If the voltage recovers before the seal-in time has elapsed or if the undervoltage seal-in is blocked via a binary input, e.g. when the voltage transformer miniature circuit breaker (m.c.b.) trips or if the machine is tripped, the function will drop out immediately. The seal-in logic operates separately for each phase. The first pickup of a phase overcurrent starts the timer T-SEAL-IN.

38

7UM62 Manual C53000-G1176-C149-3


Figure 2-10 shows the logic diagram of the overcurrent time protection I> with undervoltage seal-in. FNo. 01722

FNo. 01966

>BLOCK I>

I> BLOCKED FNo. 01970

U< seal in *) Pickup IL1> *) Pickup IL2>

OR OR

Tripping matrix

FNo. 01811

&

II> Fault L1 1203 T I>

&

OR

FNo. 01815

I> TRIP

FNo. 01812

*) Pickup IL3>

OR

&

I> Fault L2

TMin TRIP CMD

FNo. 01813

I> Fault L3

OR 1204 U< SEAL-IN

*) seal-in logic operates separately for each phase

&

Pickup U1<

S

Fuse Failure

&

≥1

Q R

1205 T-SEAL-IN

FNo. 01950

>Useal-in BLK

Figure 2-10

2.6.2

Logic Diagram of the Overcurrent Stage I> with Undervoltage Seal-In

Setting Hints

General

The overcurrent protection feature is only effective and accessible if address 0112 O/ C PROT. I> = Side 1 or Side 2 was specified. Select Disabled if the function is not needed.

Overcurrent Stage I>

Address 1201 O/C I> is used to switch the definite time-overcurrent stage I> ON or OFF, or to block only the trip command (Block Relay. The setting of the I> stage is mainly determined by the maximum operating current. Pickup due to overload should never occur since the protection may trip if short command times are set. For this reason, a setting equal to 20 % to 30 % over the expected peak load is recommended for generators, and a setting equal to 40 % over the expected peak load is recommended for transformers and motors. The trip time delay (parameter 1203 T I>) must be coordinated with the time grading of the network in order to ensure that the protective equipment closest to the corresponding fault location trips first (selectivity). The settable time is only an additional time delay and does not include the operating time (measuring time, drop-out time). The delay can be set to infinity ∞. If set to infinity, the stage will not trip after pickup. However, the pickup is signalled. If the I> stage is not required at all, 1201 O/C I> = OFF is set. For this setting, there is neither a pickup signal generated nor a trip.

7UM62 Manual C53000-G1176-C149-3

39

Functions

The 1205 U< undervoltage stage (positive-sequence voltage) is set to a value below the lowest phase-to-phase voltage permissible during operation, e.g. 80 V.

Undervoltage Seal–In

The seal-in time 1206 T-SEAL-IN limits the pickup seal-in introduced by the overcurrent/undervoltage. It must be set to a value higher than the T I> time delay. The dropout ratio r = IPU/IDO of the overcurrent pickup I> is specified at the address 1207A I> DOUT RATIO. The recommended value is r = 0.95. For special applications, e.g. overload warning, it can be set to a higher value (0.98). Example: Pickup value

1.4 ⋅ IN Gen.

Tripping time delay

3s

Undervoltage seal-in

0.8 ⋅ UN Gen.

Seal-in time of U<

4s

Drop-out ratio

0.95

Nominal current IN, Gen

483 A

Nominal voltage UN, Gen

6.3 kV

Nominal current IN, CT, prim500 A

Nominal voltage UN, VT, prim 6.3 kV

Nominal current IN, sec

Nominal voltage UN, sec

1A

100 V

The following secondary setting values result from this specification:

2.6.2.1

I>

1.4 ⋅ I N, Gen 1.4 ⋅ 483 A = ----------------------------- ⋅ I N, sec = ---------------------------- ⋅ 1 A = 1.35 A 500 A I N, CT, prim

U<

0.8 ⋅ U N, Gen 0.8 ⋅ 6,3 kV = -------------------------------- ⋅ c = ----------------------------- ⋅ 100 V = 80 V U N, VT, prim 6.3 kV

Settings for the Definite-Time Overcurrent Protection (Stage I>) The following list indicates the setting ranges and the default settings of a IN = 1 A secondary nominal current. For a secondary nominal current of IN = 5 A, these values must be multiplied by 5.

Addr.

Setting Title

Setting Options

Default Setting

Comments

1201

O/C I>

OFF ON Block relay for trip commands

OFF

Overcurrent Time Protection I>

1202

I>

0.05..20.00 A

1.35 A

I> Pickup

1203

T I>

0.00..60.00 sec; ∞

3.00 sec

T I> Time Delay

1204

U< SEAL-IN

ON OFF

OFF

State of Undervoltage Seal-in

1205

U<

10.0..125.0 V

80.0 V

Undervoltage Seal-in Pickup

1206

T-SEAL-IN

0.10..60.00 sec

4.00 sec

Duration of Undervoltage Seal-in

1207A

I> DOUT RATIO

0.90..0.99

0.95

I> Drop Out Ratio

40

7UM62 Manual C53000-G1176-C149-3


2.6.2.2

Information from Definite-Time Overcurrent Protection (Stage I>)

F.No.

Alarm

Comments

01722 >BLOCK I>

>BLOCK I>

01950 >Useal-in BLK

>O/C prot. : BLOCK undervoltage seal-in

01965 I> OFF

O/C prot. stage I> is switched OFF

01966 I> BLOCKED

O/C prot. stage I> is BLOCKED

01967 I> ACTIVE

O/C prot. stage I> is ACTIVE

01811 I> Fault L1

O/C fault detection stage I> phase L1

01812 I> Fault L2


01813 I> Fault L3


01970 U< seal in

O/C prot. undervoltage seal-in

01815 I> TRIP

O/C I> TRIP

7UM62 Manual C53000-G1176-C149-3

41

Functions

2.7

Definite-Time Overcurrent Protection (I>>, ANSI 50, 51, 67) with Direction Detection The overcurrent protection is used as backup protection for the short-circuit protection of the protected object. It also provides backup protection for downstream network faults which are not promptly disconnected and thus may endanger the protected object. The 7UM62 relay allows to choose between the input transformers of side 1 and side 2 for allocation of the overcurrent protection function. This choice is made during configuration (see Section 2.2). In order to ensure that pick-up always occurs even with internal faults, the protection - for generators - is usually connected to the current transformer set in the neutral leads of the machine (side 2). If this is not the case for an individual power system, the I>> stage can be combined with a short-circuit direction determination and switch off a generator short circuit by way of an undelayed tripping; the selectivity is not affected by this. Initially, the currents are numerically filtered so that only the fundamental-frequency currents are used for the measurement. This makes the measurement insensitive to transient conditions at the inception of a short-circuit and to asymmetrical short-circuit currents (d.c. component).

2.7.1


I>> Stage

Each phase-to-phase current of side 1 or 2 (depending on the configuration) is compared individually with the I>> common setting value. Currents above these value are recorded and signalled individually. A trip signal is transmitted to the matrix as soon as the corresponding T I>> time delays have elapsed. The drop-out value is ± 95 % below the pick-up value.

Direction Detection

If this protection function has been assigned to the input transformers of side 1, the I>> stage is equipped with a (disconnectable) direction element permitting a tripping only for faults in backward (i.e. machine) direction. For this reason, this stage can be used especially in applications where no current transformers exist in the generator starpoint and undelayed tripping is nevertheless required in case of generator faults (see figure 2-11).

reverse

G Figure 2-11

Selectivity via Short-Circuit Direction Detection

The direction is detected phase-selectively by means of a cross-polarized voltage. The phase-to-phase voltage located vertical to the vector of the fault current is

42

7UM62 Manual C53000-G1176-C149-3

Definite-Time Overcurrent Protection (I>>, ANSI 50, 51, 67) with Direction Detection

typically used as the cross-polarized voltage (Figure 2-12). This is considered during the calculation of the directional vector in the clockwise rotating phase sequence by way of a rotation by +90° and in the anti-clockwise and in the anti-clockwise rotating phase by way of a rotation by –90°. For phase-to-phase faults, the position of the direction straight line may change in relation to the collapse of the short-circuit voltage.

U L1

U L1

U L1-L2 U L3-L1

U L2

U L3

U L2

U L3

U L2-L3

Local phase sequences

U L2-L3

Remote phase sequences

Short circuit in phase L2–L3; cross-polarized voltage UL3 - L1 Figure 2-12

Cross-Polarized Voltages for Direction Determination

The phase carrying the highest current is selected for the direction decision. In case of equal current levels, the phase with the smaller number is chosen (IL1 before IL2 before IL3). Table 2-4 shows the assignment of voltage and current values for the determination of the fault direction for various types of short-circuit faults. Table 2-4

Voltage and Current Values for the Determination of Fault Direction Pickup L1

Selected Current IL1

L2

IL2

Associated Voltage UL2 – UL3 UL3 – UL1

L3

IL3

UL1 – UL2

L1, L2 with IL1>IL2

IL1

UL2 – UL3

L1, L2 with IL1=IL2

IL1

L1, L2 with IL1
IL2

UL2 – UL3 UL3 – UL1

L2, L3 with IL2>IL3

IL2

UL3 – UL1

L2, L3 with IL2=IL1

IL2

UL3 – UL1

L2, L3 with IL2
IL3

L3, L1 with IL3>IL1

IL3


L3, L1 with IL3=IL1

IL1

UL2 – UL3

L3, L1 with IL3
IL1

UL2 – UL3

L1, L2, L3 with IL1>(IL2, IL3) IL1 L1, L2, L3 with IL2>(IL1, IL3) IL1


If the phase-to-phase voltage used for the direction decision is below the minimum value of approx. 7 V, the voltage is taken from a voltage memory. This voltage also allows an unambiguous direction determination if the short-circuit voltage has collapsed (short circuit close to generator terminals). After the expiration of the storage

7UM62 Manual C53000-G1176-C149-3

43

Functions

period (2 cycles), the detected direction is stored, as long as no sufficient measuring voltage is available. If a short circuit already exists at generator startup (or, in case of motors or transformers, during connection), so that no voltage is present in the memory and no direction can be determined, a trip is issued. The direction detection can be blocked via a binary input. Figure 2-13 indicates the I>> stage logic diagram with the direction element.

FNo. 01801

I>> Fault L1 FNo. 01802



Pickup IL1>>

&

Tripping matrix

I>> picked up 1303 T I>>

Pickup IL2>>

&

OR

& FNo. 01809

Pickup IL3>>

I>> TRIP

&

FNo. 01721

FNo. 01956

>BLOCK I>>

I>> BLOCKED

UL

Direction detection Ix

TMin TRIP CMD

OR

&

undeterminable

&

forward

&

reverse

non direct. ”1”

1304 Phase Direction

FNo. 01806

&

I>> forward

&

I>> backward

FNo. 01807

FNo. 01720

>BLOCK dir..

Figure 2-13

2.7.2 General

Logic Diagram of I>> Stage with Direction Element

Setting Hints The high-current stage I>> of the overcurrent protection is only effective and accessible if it has been assigned within the framework of configuration at address0113 O/C PROT. I>> to either side 1 or side e, i.e. if either = Non-dir. Side 1 side 2, Dir. Side 1 or Dir. side 2 was set. Disabled is selected if the function is not needed. If you use the direction element, make sure that the CT and VT set are consistent.

44

7UM62 Manual C53000-G1176-C149-3


I>>TimeOvercurrent Stage

Address 1301 O/C I>> is used to switch the definite time I>> stage for phase currents ON or OFF, or to block only the trip command (Block Relay). The highcurrent stage I>> (parameter 1302 and its associated delay time T I>>, 1303) is used for current grading with large impedances existing for example with transformers, motors or generators. The definite time-overcurrent stage must be specified in a way ensuring that it picks up for short circuits up to this impedance.

Current Transformer in the Starpoint (without direction detection)

Example: Unit connection Rated apparent power - generator

SN, Gen = 5.27 MVA

Rated voltage - generator

UN, Gen = 6.3 kV

Direct-axis transient reactance

x’d = 29 %

Transient synchronous generated voltage (Salient-pole generator) Rated apparent power - transformer

U’P =1.2 ⋅ UN, Gen SN, T = 5.3 MVA

Rated voltage, on the generator side

UN, VT prim = 6.3 kV

Short-circuit voltage

usc = 7 %

Current transformer

IN, CT, prim =500 A IN, sec =1 A

a) Short-circuit calculation Three-pole short circuit U’ P ⁄ ( 3 ) 1.2 ⋅ 6.3 kV ⁄ ( 3 ) I SC 3pol ≈ ----------------------------------------------------------------------------------------------------------------- ≈ ---------------------------------------------- ≈ 1789 A 2 2 2.18 Ω + 0.26 Ω U N, Gen u sc U N, VT prim x’ d ---------------- ⋅ ------------------ ⋅ ------------------------------ + 0.5 ⋅ ---------------100 % S N, Gen 100 % S N, Gen b) Setting value: The setting value is achieved by means of a conversion on the secondary side. In order to exclude an unwanted operation caused by overvoltages or transient phenomena, an additional safety factor of about 1.2 to 1.3 is recommended. I>> =

I SC 3pol 1789 A 1.2 ⋅ -------------------------- ⋅ I N, sec = 1.2 ⋅ ------------------- ⋅ 1 A = 4.3 A 500 A I N, CT, prim

A value of T I>> = 0.1 s is recommended as tripping time delay, in order to enable preferred tripping of the differential protection. Current Transformers at the Output Side (with direction detection)

7UM62 Manual C53000-G1176-C149-3

If at address 0113 O/C PROT. I>> was configured as directional, the addresses 1304 Phase Direction and 1305 LINE ANGLE are accessible. The inclination of the direction straight line (see figure 2-14) representing the separating line between the tripping and the blocking zone can be adapted to the network conditions by way of the LINE ANGLE parameter. To do this, the line angle of the network is set. The direction straight line is perpendicular to the set direction angle. Together with the parameter 1304 Phase Direction = Forward oder Reverse, this parameter covers the entire impedance level. This is the reverse direction, provided that the protective relay has been connected correctly according to one of the diagrams in Appendix A.4. A small zone is located between the forward and the reverse zone. Due to phase displacement angles of the transformers, a safe direction decision is not possible in this small zone. Consequently, there is no tripping in the selected preferred direction in this zone.

45

Functions

.

FO (l RW in AR e) D

ZLine UL1

ϕL = LINE

ANGLE

IL1

(G RE en VE er RS at E or

)

Direction straight line

Figure 2-14

Definition of the Parameters 1304 Phase Direction and 1305 LINE ANGLE

The setting value of the direction straight line results from the short-circuit angle of the feeding network. As a rule, it will be > 60°. The current pick-up value results from the short-circuit current calculation. Acceptable pick-up values are situated at about (1.5 to 2) ⋅ IN, G. A tripping time delay of (TI>> ≈ 0.05 s to 0.1 s). is required to ensure that the effect of the transient phenomena is eliminated. Application Example: Motor Protection

For motors that have no separate current transformers in the starpoint, Figure 2-15 shows how to use the I>> stage as ”differential protection”. The configuration of the protection function depends on the transformers. Since this application is most likely to be used for replacements in an existing system, the settings of that system should be the basis for this.

Motor IL, S1

IL, S2

I>> Stage

Stage I>, Ip>

7UM62 Figure 2-15

46

I>> Stage Used as “Differential Protection”

7UM62 Manual C53000-G1176-C149-3


2.7.2.1

Settings for the I>> Stage of the Definite-Time Overcurrent Protection The following list indicates the setting ranges and the default settings of a IN = 1 A secondary nominal current. For a secondary nominal current of IN = 5 A, these values must be multiplied by 5. Consider the current transformer ratios when setting the device with primary values.

Addr.

Setting Title

Setting Options

Default Setting

Comments

1301

O/C I>>


OFF

Overcurrent Time Protection I>>

1302

I>>

0.05..20.00 A

4.30 A

I>> Pickup

1303

T I>>

0.00..60.00 sec; ∞

0.10 sec

T I>> Time Delay

1304

Phase Direction

Forward Reverse

Reverse

Phase Direction

1305

LINE ANGLE

-90..90 °

60 °

Line Angle

2.7.2.2

Information for the I>> stage of the Definite-Time Overcurrent Protection

F.No.

Alarm

Comments

01721 >BLOCK I>>

>BLOCK I>>

01720 >BLOCK dir.

>BLOCK direction I>> stage

01955 I>> OFF

O/C prot. stage I>> is switched OFF

01956 I>> BLOCKED

O/C prot. stage I>> is BLOCKED

01957 I>> ACTIVE

O/C prot. stage I>> is ACTIVE

01806 I>> forward

O/C I>> direction forward

01807 I>> backward

O/C I>> direction backward

01801 I>> Fault L1

O/C fault detection stage I>> phase L1

01802 I>> Fault L2


01803 I>> Fault L3


01808 I>> picked up

O/C prot. I>> picked up

01809 I>> TRIP

O/C I>> TRIP

7UM62 Manual C53000-G1176-C149-3

47

Functions

2.8


2.8.1


General

The overcurrent time protection represents the short-circuit protection for small or lowvoltage machines. For larger machines it is used as back-up protection for the machine short-circuit protection (differential protection and/or impedance protection). It provides back-up protection for network faults which are not promptly disconnected and thus may endanger the machine. The 7UM62 relay allows to choose between the input transformers of side 1 and side 2 for allocation of the inverse-time overcurrent protection function. This choice is made during configuration (see Section 2.2). In generators where the excitation voltage is derived from the machine terminals, the short-circuit current subsides quickly in the event of close-up faults (i.e. in the generator or unit transformer range) due to the absence of excitation voltage the current decreases within a few seconds to a value below the pick-up value of the overcurrent time protection. In order to avoid a drop out of the pickup, the positivesequence component is monitored additionally. This component can influence the overcurrent detection according to two different methods. The influence of the undervoltage can be switched off. The protective function operates, depending on the ordering variant, with an inverse current-tripping characteristic according to the IEC or ANSI standards. The characteristic curves and the corresponding formulas are represented in Technical Data (Figures 4-1 to 4-3 in Section 4.3). If one of the inverse characteristics (IEC or ANSI) are configured, the definite-time stages I>> and I> can be additionally effective (see Section 2.6 and 2.7).

Pickup / Trip

Each phase current is compared individually with the common Ip setting value. If a current exceeds 1.1 times the set value, the stage picks up and is signalled on a per phase basis. The r.m.s. values of the fundamental component are used for the pickup. During the pickup of an Ip stage, the tripping time is calculated from the flowing fault current by means of an integrated measuring procedure, depending on the selected tripping characteristic. A trip command is transmitted after this time expires.

Dropout

The dropout of a picked up stage is performed as soon as the value falls below approximately 95 % of the pickup value (i.e. 0.95 ⋅1.1 = 1.045 ⋅ setting value). The timer will start again for all new pickups.

Undervoltage Consideration

The inverse O/C time protection is equipped with a undervoltage detection that can be disabled. This function can influence the overcurrent detection in two different ways: • Voltage controlled: If the value falls below a settable voltage threshold, an overcurrent stage with a lower pick-up value is enabled. • Voltage restraint: The pickup threshold of the overcurrent stage depends on the voltage level. A lower voltage reduces the current pick-up value (see Figure 2-16). A linear, directly proportional dependency is realized in the zone between U/UNom = 1.00 and 0.25. Consequently, the following rule applies:

48

7UM62 Manual C53000-G1176-C149-3


:

Factor 1.0

I ( U ) pickup = I p ⋅ 1.00

U for 1.00 ≤ ------------- ≤ ∞ U nom

U I ( U ) pickup = I p ⋅ -------------U nom

U for 0.25 ≤ ------------- ≤ 1.00 U nom

I ( U ) pickup = I p ⋅ 0.25

U for 0.00 ≤ ------------- ≤ 0.25 U nom

0.75

0.5

0.25

0.25

0.5

where

Figure 2-16

0.75

1.0

U⁄U

nom

Unom

– Generator nominal voltage = parameter 0251 UN GEN/MOTOR

I(U)pickup

– Voltage-influenced pickup value

Ip

– Pick-up value of inverse characteristic parameter = parameter 1402 Ip

Pick-up Value Voltage Restraint

The Ip reference value is decreased proportional to the voltage decrease. Consequently, for a constant current I the I/Ip ratio is increased and the trip time is reduced. Compared with the standard characteristics represented in Section 4.3, the tripping characteristic shifts to the left side in relation to the decreasing voltage. The changeover to the lower pick-up value or the reduction of the pickup threshold are performed on a per phase basis. The assignments of voltages to the current-carrying phases are represented in Table 2-5. As the protection used in the generator range is incorporated in the network grading plan, the phase shift of the voltages by the unit transformer must also be considered. This facts requires principle distinction between a unit connection and a busbar connection, which must be communicated to the device by means of the parameter 0213 SCHEME. As phase-to-phase voltages are referred to in any case, faulty measurements in case of earth faults are avoided. Table 2-5

Control Voltages in Relation to the Fault Currents

Current

Voltage Busbar connection

Unit connection

IL1

UL1 – UL2

((UL1 – UL2) – (UL3 – UL1)) / √3

IL2

UL2 – UL3

((UL2 – UL3) – (UL1 – UL2)) / √3

IL3

UL3 – UL1

((UL3 – UL1) – (UL2 – UL3)) / √3

In order to avoid an unwanted operation for a voltage transformer fault, a blocking function miniature circuit breaker as well as via the device-internal measuring voltages failure detection (”Fuse–Failure–Monitor”, also refer to section 2.38.1.4). Figure 2-17 illustrates the logic diagram of the inverse O/C time protection without undervoltage influencing, whereas the Figures 2-18 and 2-19 illustrate the logic diagrams with undervoltage influencing.

7UM62 Manual C53000-G1176-C149-3

49

Functions

FNo. 01899

OR

O/C Ip pick.up

FNo. 01896

O/C Ip Fault L1 1403 T Ip

Pickup IL1

& FNo. 01897

FNo. 01900

O/C Ip Fault L2

O/C Ip TRIP

Tripping matrix

1403 T Ip

(Pickup)

&

OR

FNo. 01898

O/C Ip Fault L3

TMin TRIP CMD

1403 T Ip

(Pickup)

FNo. 01883

FNo. 01892

>BLOCK O/C Ip

O/C Ip BLOCKED

Figure 2-17

50

&

Logic Diagram of the Voltage-Controlled Inverse O/C Time Protection without Undervoltage Influencing

7UM62 Manual C53000-G1176-C149-3


FNo. 01899

OR

O/C Ip pick.up

FNo. 01896

O/C Ip Fault L1

1402 Ip

1403 T Ip

&

IL1

FNo. 01897

FNo. 01900

O/C Ip Fault L2

1402 Ip

Tripping

O/C Ip TRIP matrix

1403 T Ip

IL2

&

OR FNo. 01898

O/C Ip Fault L3

1402 Ip

TMin TRIP CMD

1403 T Ip

IL3

UL1 UL2 UL3

&

Loop release

Fuse Failure

OR

FNr. 000361

>FAIL:Feeder VT FNo. 01883

FNo. 01892

>BLOCK O/C Ip

O/C Ip BLOCKED

Figure 2-18

Logic Diagram of the Voltage-Controlled Inverse O/C Time Protection

The changeover to the lower current pick-up value in case of decreasing voltage (loop release) is performed on a phase by phase basis according to table 2-5.

7UM62 Manual C53000-G1176-C149-3

51

Functions

FNo. 01899

OR

O/C Ip pick.up

FNo. 01896

O/C Ip Fault L1

1402 Ip

1403 T Ip

&

IL1

FNo. 01897

FNo. 01900

O/C Ip Fault L2

1402 Ip

Tripping

O/C Ip TRIP matrix

1403 T Ip

&

IL2

OR TMin TRIP CMD

FNo. 01898

O/C Ip Fault L3

1402 Ip

1403 T Ip

&

IL3

UL1 UL2 UL3

Control voltages in Ux1 relation to Ux2 the fault Ux3 current

Fuse Failure

OR

Ux=Un

FNr. 000361

>FAIL:Feeder VT FNo. 01883

FNo. 01892

>BLOCK O/C Ip

O/C Ip BLOCKED

Figure 2-19

Logic Diagram of the Voltage-Restraint Inverse O/C Time Protection

The reduction of the current pick-up threshold in case of a decreasing voltage (control voltage assignment) is performed phase by phase according to Table 2-5.

2.8.2

Setting Hints

General

The inverse O/C time protection is only effective and accessible if this function was allocated to the input CTs of either side 1 or side 2 during configuration (see Section 2.2), i.e. if address 0114 O/C PROT. Ip = with IEC-characteristic on side 1, with ANSI-characteristic on side 1, with IEC-characteristic on side 2 or with ANSI-characteristic on side 2 was set. Disabled is selected if the function is not needed.

Ip overcurrent stage

Address 1401 O/C Ip is used to switch the function ON or OFF, or to block only the trip command (Block Relay). It must be noted that, for the inverse O/C time protection, a safety factor of about 1.1 has been included between the pick-up value and the setting value. This means that a pickup will only occur if a current of about 1.1

52

7UM62 Manual C53000-G1176-C149-3


times of the setting value is present. The function will reset as soon as the value falls below 95 % of the pick-up value. The current is set at address1402 Ip. The maximum operating current is of primary importance for the setting. A pickup caused by an overload must be excluded, as the device operates in this mode as short-circuit protection with correspondingly short relay times and not as overload protection. The corresponding time multiplier for configuration of IEC characteristics (address 0114 O/C PROT. Ip = IEC Side n) is accessible at address 1403 T Ip. At address 1405 IEC CURVE, 3 IEC characteristics can be set. The time multiplier for configuring ANSI characteristics (address 0114 O/C PROT. Ip= ANSI Side n) can be found at address 1404 TIME DIAL: TD; parameter 1406 ANSI CURVE offers a choice between 5 ANSI characteristics. The time multipliers must be coordinated with the network grading plan. The time multipliers can also be set to ∞. If set to infinity, the stage will not trip after pickup. However, the pickup is signalled. If the Ip stage is not required at all, set at the address 0114 O/C PROT. Ip = Disabled, or switch the function out by setting 1401 O/C Ip = OFF during configuration (see Section 2.2). The address 1408 serves to predefine the U< pick-up value for the undervoltage trip of the Ip pickup value for voltage-controlled inverse O/C time protection/AMZ (parameter 1407 VOLT. INFLUENCE = Voltage controlled). The parameter is set to a value situated just below the lowest phase-to-phase voltage permissible during operation, e.g. from 75 to 80 V. In this context, the same rules apply as for the undervoltage seal-in of the definite O/C time protection (see also subsection 2.6.2). If at address 1407 VOLT. INFLUENCE = Without or Voltage restraint is set, the parameter 1408 has no function.

2.8.2.1

Settings of the Inverse O/C Time Protection The following list indicates the setting ranges and the default settings of a IN = 1 A secondary nominal current. For a secondary nominal current of IN = 5 A, these values must be multiplied by 5. Consider the current transformer ratios when setting the device with primary values.

Addr.

Setting Title

Setting Options

Default Setting

Comments

1401

O/C Ip


OFF

Inverse O/C Time Protection Ip

1402

Ip

0.10..4.00 A

1.00 A

Ip Pickup

1403

T Ip

0.05..3.20 sec; ∞

0.50 sec

T Ip Time Dial

1404

TIME DIAL: TD

0.50..15.00; ∞

5.00

TIME DIAL: TD

1405

IEC CURVE

Normal Inverse Very Inverse Extremely Inverse

Normal Inverse

IEC Curve

7UM62 Manual C53000-G1176-C149-3

53

Functions

Addr.

Setting Title

1406

ANSI CURVE

1407

1408

2.8.2.2

Setting Options Very Inverse Inverse Moderately Inverse Extremely Inverse Definite Inverse

Default Setting

Comments

Very Inverse

ANSI Curve

VOLT. INFLUENCE without Voltage controlled Voltage restraint

without

Voltage Influence

U<

75.0 V

U< Threshold for Release Ip

10.0..125.0 V

Information for the Inverse-Time Overcurrent Protection

F.No.

Alarm

Comments

01883 >BLOCK O/C Ip

>BLOCK inverse O/C time protection

01891 O/C Ip OFF

O/C protection Ip is switched OFF

01892 O/C Ip BLOCKED

O/C protection Ip is BLOCKED

01893 O/C Ip ACTIVE

O/C protection Ip is ACTIVE

01896 O/C Ip Fault L1

O/C fault detection Ip phase L1





01899 O/C Ip pick.up

O/C Ip picked up

01900 O/C Ip TRIP

O/C Ip TRIP

54

7UM62 Manual C53000-G1176-C149-3


2.9


2.9.1


General

The thermal overload protection feature of the 7UM61 is designed to prevent overloads from damaging the protected equipment. The device is capable of projecting excessive operating temperatures for the protected equipment in accordance with a thermal model, based on the following differential equation: 1 2 1 dΘ 1 -------- + --- ⋅ Θ = --- ⋅ I + --- ⋅ Θ K τ τ dt τ where Θ

– Actual operating temperature expressed in per cent of the operating temperature corresponding to the maximum permissible operating current k · IN

ΘK – Coolant temperature or ambient temperature as a difference to the 40 °C reference temperature τ – Thermal time constant for the heating of the equipment being protected I – Operating current expressed in per cent of the maximum permissible operating current Imax = k · IN The thermal overload protection feature models a heat image of the equipment being protected. Both the previous history of an overload and the heat loss to the environment are taken into account. The solution of this equation is in steady-state operation an e-function whose asymptote represents the final temperature ΘEnd. The thermal overload protection calculates the operating temperature of the protected equipment in per cent of the maximum allowable operating temperature. When the calculated operating temperature reaches a settable percentage of the maximum allowable operating temperature, a warning message is issued to allow time for the load reduction measures to take place. If the second temperature threshold, i.e. end temperature = trip temperature, is reached, the protected equipment is disconnected from the network. It is also possible, however, to set the overload protection to Alarm only. If this option is set, the device only outputs an alarm, even if the end temperature is reached. The temperature rise is calculated from the highest of the three phase currents. Since the calculation is based on the r.m.s. values of the currents, it also considers harmonics which contribute to a temperature rise of the stator winding. The maximum thermally permissible continuous current Imax is described as a multiple of the rated current I N of the protected object: Imax = k · IN In addition to the k factor (parameter K-FACTOR), the TIME CONSTANT τ and the alarm temperature Q ALARM (in percent of the trip temperature ΘTRIP) must be specified. The thermal overload protection also features a current warning element I ALARM in addition to the temperature warning stage. The current warning element may report an overload current prematurely (before Imax is exceeded), even if the calculated operating temperature has not yet attained the warning or tripping levels.

7UM62 Manual C53000-G1176-C149-3

55

Functions

Coolant Temperature/ Ambient Temperature

The thermal model of the 7UM62 considers an external temperature value. Depending on the application, this temperature can be the coolant or ambient temperature or, in the case of gas turbines, the entry temperature of the cold gas. The temperature to be considered can be fed in by one of the following: − Measuring transducer (TD 2) − Profibus DP interface/Modbus − Temperature detection unit (Thermobox, RTD 1) An external temperature sensor measures e.g. the coolant temperature and converts it into a current or voltage that is proportional to the temperature. This output quantity can be fed into the 7UM62 via the integrated measuring transducer TD 2. If a signal level between 4 mA and 20 mA is used, the measuring circuit for temperature input can additionally be monitored for interruptions. If the measured currents of the external amplifier drops to less than 2 mA, the relay outputs an alarm, and switches at the same time to the internal coolant temperature of 40 °C (which is the temperature assumed if there is no coolant temperature detection). The ambient or coolant temperature can also be detected by an external temperature sensor, digitized and fed to the 7UM62 via the Profibus DP interface/ Modbus. If a temperature supervision feature is implemented by means of the thermobox (see section 2.42) the RTD1 input can be used for temperature inclusion considered by the thermal replica. Where the coolant temperature detection exists, the maximum permissible current Imax is influenced by the temperature difference of the coolant. If the ambient or coolant temperature is low, the machine can support a higher current than it does when the temperature is high.

Current Limiting

In order to avoid that the thermal overload protection reaches extremely short trip times on occurrence of high short-circuit currents (and on selection of a small time constant) and thus perhaps affects the time grading of the short-circuit protection, it is possible to determine a current limiting of the overload protection. Currents exceeding the value specified at parameter 1615A I MAX THERM. are limited to this value. For this reason, they do not further reduce trip time in the thermal image.

Standstill Time Constant

The above differential equation assumes a constant cooling that is expressed by the time constant τ = Rth · Cth (thermal resistance and thermal capacitance). In a selfventilated machine, however, the thermal time constant at standstill can differ considerably from the constant of a steadily running machine, since with the machine running the ventilation provides for cooling whereas at standstill only the natural convection occurs. Therefore, two time constants must be considered in such cases for setting. In this context, a machine standstill represents the moment when the current falls below the threshold value BkrClosed I MIN (see side title”Current Flow Monitoring” in Section 2.3).

Blocking

The thermal overload protection feature may be reset via a binary input (”>RM th.rep. O/L”). The current-induced overtemperature value is reset to zero. The same is achieved by entering a blocking (”>BLK ThOverload”); in that case the overload protection is blocked completely, including the current warning stage. When machines must be started for emergency reasons, operating temperatures above the maximum permissible operating temperatures can be allowed by blocking

56

7UM62 Manual C53000-G1176-C149-3


the tripping signal via a binary input (”>Emer.Start O/L”). Since the calculated operating temperature may be higher than the maximum allowable operating temperature after drop out of the binary input has taken place, the thermal overload protection function features a programmable run-on time interval run-on time interval (T EMERGENCY) which is started when the binary input drops out. Tripping will be defeated until this time interval elapses. The binary input used for emergency starting affects only the tripping signal. There is no effect on the fault event protocol, nor does the thermal memory reset. Behaviour in the Case of a Power Supply Failure

For the overload protection, together with all other thermal protection functions of the 7UM62, you can set in the Power System Data 1 (parameter 0274A ATEX100, see Section 2.3) whether the calculated overtemperature will be buffered in case of a power supply failure, or reset to zero. This second option is the default setting. Figure 2-20 shows the logic diagram for thermal overload protection.

7UM62 Manual C53000-G1176-C149-3

57

Functions

CB closed 0281

BkrClosed I MIN

I> 1615A I MAX THERM. IL3

IL2

Θ

IL1

1612A Kt-FACTOR

kτ x τ

I

1610A I ALARM

1602 K-FACTOR 1603 TIME CONSTANT

OR

FNo. 01515

&

O/L I Alarm

1604 Q ALARM FNo. 01516

dΘ 1 1 2 1 -------- + --- ⋅ Θ = --- ⋅ I + --- ⋅ Θ K τ dt τ τ

L1

O/L Q Alarm

Θmax

Θ=0 FNo. 01521

ThOverload TRIP 100 % (fixed)

1607 TEMP. INPUT

RTD 1 Profibus DP 4-20 mA

Tripping matrix

&

Disabled

(ΘK = 40 °C)

TMin TRIP CMD

FNo. 01508

&

>Fail.Temp.inp

&

FNo. 01517

O/L Th. pick.up

FNo. 01503

FNo. 01512

>BLK ThOverload

Th.Overload BLK

FNo. 01506

OR

>RM th.rep. O/L

FNo. 01519

RM th.rep. O/L FNo. 01513 1601 Ther. OVER LOAD

OR

OR

Overload ACT FNo. 01511

Th.Overload OFF

OFF ON Block relay

”1”

Alarm Only

1616A T EMERGENCY

FNo. 01507

>Emer.Start O/L

Figure 2-20

58

Logic diagram of the Overload protection

7UM62 Manual C53000-G1176-C149-3


2.9.2

Setting Hints

General

Thermal overload protection is only effective and accessible if address 0116 Therm.Overload was set to Enabled. Set Disabled if the function is not required. Transformers and generators are prone to damage by overloads which last for an extended period of time. For this reason, short circuit protection elements such as the overcurrent protection should not be used to protect against overload. The short time delays associated with short circuit protection do not allow sufficient time for the orderly curtailment of load by operating personnel. In addition, short circuit protection set to trip for overload will not allow short-duration, non-damaging overloads – a practice which is often required in real operating situations. The 7UM62 protective relay features an thermal overload protective function with a thermal tripping characteristic curve which may be adapted to the overload tolerance of the equipment being protected. At the address 1601 Ther. OVER LOAD you can set the thermal overload protection OFF or ON, you can block the trip command (Block relay for trip commands); or set the protection function to Alarm Only. In that last case no fault record is created n case of an overload. If the overload protection is switched ON, tripping is also possible.

K–Factor

The overload protection is set in per unit quantities. The nominal current IN, machine of the object to be protected (generator, motor, transformer) is typically used as base current. The thermally permissible continuous current Imax prim can be used to calculate a factor kprim: I max prim k prim = -------------------------I N, Machine The thermally permissible continuous current for the equipment being protected is indicated in the manufacturer’s specifications. If no specifications are available, a value of 1.1 times the nominal current rating is assumed. The K-FACTOR to be set at the 7UM62 (address 1602) refers to the secondary nominal current (= device current). The following applies for the conversion: Setting value K-FACTOR =

I max prim I N Machine -----------------------⋅ -----------------------I N Machine I NCT prim

IN Machine

Maximum permissible continuous motor current in primary amperes Nominal machine current

IN CT prim

Current transformer nominal primary current

where Imax prim

Example: Generator and current transformer with the following data: Permissible continuous current:

Imax prim= 1.15 · IN, Machine

Generator nominal current

IN Machine= 483 A

Current transformer

500 A/1 A

483 A Settingxvalue K–FACTOR = 1, 15 ⋅ --------------- ≈ 1.11 500 A

7UM62 Manual C53000-G1176-C149-3

59

Functions

Time Constant τ

The thermal overload protection element tracks excessive temperature progression, employing a thermal differential equation that uses an exponential function. The TIME CONSTANT τ (address 1603) is used in the calculation to determine the operating temperature. If the overload characteristic of the generator to be protected is pre-determined, the user must select the protection trip characteristic in a way that it covers the overload characteristic to a large extent, at least with small overloads. This is also the case if the permissible power-up time corresponding to a certain overload value is indicated.

Warning Temperature Levels

By setting the thermal warning level Q ALARM (address 1604), a warning message can be issued prior to tripping, thus allowing time for load curtailment procedures to be implemented. This warning level simultaneously represents the dropout level for the tripping signal. In other words, the tripping signal is interrupted only when the calculated operating temperature falls below the warning level, thus allowing the protected equipment to be placed back into service. The thermal warning level is given in % of the tripping temperature level (maximum allowable operating temperature). Note: With the typical value of K-FACTOR = 1.1, the following final tripping overtemperature value results in case of the application of the nominal machine current and adapted primary transformer current: 1 Θ ⁄ Θ Trip = ------------ = 83 % 2 1, 1 of the tripping temperature. Consequently, the warning stage should be set between the final overtemperature with the nominal current (in this case 83 %) and the tripping overtemperature (100 %). In the present example, the thermal memory reaches the following value if the nominal current is applied: 1 Θ ⁄ Θ Trip = --------------- = 76 % 2 1, 15 A current warning level (parameter 1610A I ALARM) is also available. The level is set in secondary amperes, and should be set equal to, or slightly less than, the permissible continuous current K-FACTOR · IN sec. The current warning level may be used in lieu of the thermal warning level by setting the thermal warning level 100 %, which makes it practically ineffective.

Extension of Time Constants at Machine Standstill

The time constant programmed at address 1603 is valid for a running machine. On slowing down or standstill, the machine may cool down much slower. This behaviour can be modeled by means of a prolongation of the time constant by the Kt-FACTOR (address 1612A) on machine standstill. In this context, a machine standstill represents the moment when the current falls below the threshold value BkrClosed I MIN (see side title ”Current Flow Monitoring” in Section 2.3). If no distinguishing of the time constants is necessary, the Kt-FACTOR is left at 1 (default setting).

Current Limiting

60

The parameter 1615A I MAX THERM. specifies up to which current value the trip times are calculated according to the pre-defined thermal formula. In the trip characteristics of Figure 4-4 in Section 4.4, this limit value determines the transition to the horizontal part of the characteristics, in which there is no further trip time reduction

7UM62 Manual C53000-G1176-C149-3


despite increasing current values. The limit value must be specified at a value ensuring that, even for the highest possible short-circuit current, the trip times of the overload protection exceed the trip times of the short-circuit protective relays (differential protection, impedance protection, time overcurrent protection). As a rule, this parameter can be set to three times the nominal generator current. Emergency Starting

The run-on time to be entered at address 1616A T EMERGENCY must be sufficient to ensure that after an emergency startup and dropout of binary input >Emer.Start O/ L” the trip command is blocked until the thermal replica is again below the dropout threshold.

Ambient or Coolant Temperature

The indications specified up to now are sufficient for the modeling of the overtemperature. In addition to this, the machine protection can also process the ambient or coolant temperature. This temperature value can be fed to the relay via measuring transducer TD2 as a temperature-proportional DC current from a measuring transducer with a live zero signal between 4 and 20 mA, or communicated to the relay as digitalized measuring via the Fieldbus. Address 1607 TEMP. INPUT serves to select the temperature input procedure. If there is no coolant temperature detection, the address1607 is set to Disabled. The assignment between the input signal and the temperature can be set at address 1608 (in °C) or 1609 (in °F) TEMP. SCAL.. The value set there is equivalent to 100 % of the Profibus DP/Modbus value, or full-scale deflection (20 mA) of the measuring transducer. In the default setting, 100 % (Profibus DP/Modbus) or 20 mA (measuring transducer TD2) correspond to 100 °C. Is under address 1607 TEMP. INPUT the setting temperature of RTD 1 selected, the temperature scaling of addresses 1608, 1609 is ineffective. Neither of the parameters is considered in the calculation. If the ambient temperature detection is used, the user must be aware that the KFACTOR to be set refers to an ambient temperature of 40 °C, i.e. it corresponds to the maximum permissible current at a temperature of 40 °C. All calculations are performed with standardized quantities. The ambient temperature must also be standardized. The temperature with the nominal machine current is used as standardization quantity. If the nominal machine current deviates from the nominal primary CT current, the temperature must be adapted according to the following formula. At address 1605 or 1606 TEMP. RISE I the temperature adapted to the nominal transformer current is set. This setting value is used as standardization quantity of the ambient temperature input. I Nprim 2 Θ Nsec = Θ NMach ⋅ æ ------------------ö è I NMachø where ΘNsec

– Machine temperature with nominal secondary current = setting at the 7UM62 (address 1605 or 1606)

ΘNMach – Machine temperature with nominal machine current INprim

– Nominal primary current of the current transformers

INMach

– Nominal machine current

If the temperature input is not used, the address 1607 TEMP. INPUT must be set to Disabled. In this case, the settings of the addresses1605 or 1606 and 1608 or 1609 are not considered.

7UM62 Manual C53000-G1176-C149-3

61

Functions

If the temperature input is used, the trip times change if the coolant temperature deviates from the internal reference temperature of 40 °C. The following formula can be used to calculate the trip time: I ö 2 Θ K – 40 °C æ I pre ö 2 æ -----------+ ---------------------------- – -----------è k ⋅ I Nø è k ⋅ I Nø 2 k ⋅ ΘN t = τ ⋅ ln ----------------------------------------------------------------------------------I ö 2 Θ K – 40 °C æ -----------+ ---------------------------- – 1 è k ⋅ I Nø 2 k ⋅ ΘN whereτ

– TIME CONSTANT (address 1603)

k

– K-FACTOR (address 1602)

IN

– Nominal device current

I

– Actually flowing secondary current

Ipre – Previous load current ΘN – Temperature with nominal current IN (address 1605 TEMP. RISE I) ΘK – Coolant temperature input(scaling with address 1608 or 1609) Example: Machine:

INMach

= 483 A

ImaxMach = 1.15 IN at ΘK = 40 °C ΘNMach

= 93° C Temperature at INMach

τ

= 600 s (thermal machine time constant)

Current transformer: 500 A / 1 A 483 A K-FACTOR = 1, 15 ⋅ --------------- ≈ 1, 11 500 A 2

500 Θ Nsec = 93° C ⋅ æ ----------ö ≈ 100° C è 483ø

62

(to be set at address 1602)

(to be set at address 1605 or 1606 TEMP. RISE I)

7UM62 Manual C53000-G1176-C149-3


The following trip times result for different ambient temperatures ΘK with a supposed load current of I = 1.5 ⋅ IN, device and a preload Ipre = 0

2.9.2.1

with ΘK = 40 °C:

2 40 °C – 40 °C æ æ 1.5 --------ö + ------------------------------------ – 0ö÷ ç è 1.1ø 2 1.1 ⋅ 100 °C t = çç 600 s ⋅ ln ---------------------------------------------------------------------÷÷ ≈ 463 s 2 40 °C – 40 °C æ 1.5 ç --------ö + ------------------------------------ – 1÷ 2 è ø 1.1 è ø 1.1 ⋅ 100 °C

with ΘK = 80 °C:

2 80 °C – 40 °C æ æ 1.5 ö + ----------------------------------- – 0ö÷ ------ç 2 è 1.1ø 1.1 ⋅ 100 °C t = ç 600 s ⋅ ln ---------------------------------------------------------------------÷ ≈ 366 s ç ÷ 2 80 °C – 40 °C æ 1.5 ç --------ö + ------------------------------------ – 1÷ è 1.1ø 2 è ø 1.1 ⋅ 100 °C

with ΘK = 0 °C:

2 0 °C – 40 °C æ æ 1.5 ö + --------------------------------------- – 0ö÷ ç è 1.1ø 2 1.1 ⋅ 100 °C t = ç 600 s ⋅ ln -------------------------------------------------------------------÷ ≈ 637 s ç ÷ 2 0 °C – 40 °C æ 1.5 ç --------ö + ---------------------------------- – 1÷ è 1.1ø 2 è ø 1.1 ⋅ 100 °C

Thermal Overload Protection Settings The following list indicates the setting ranges and the default settings of an IN = 1 A secondary nominal current. For a secondary nominal current of IN = 5 A, these values must be multiplied by 5. Consider the current transformer ratios when setting the device with primary values.

Addr.

Setting Title

Setting Options

Default Setting

Comments

1601

Ther. OVER LOAD

OFF ON Block relay for trip commands Alarm Only

OFF


1602

K-FACTOR

0.10..4.00

1.11

K-Factor

1603

TIME CONSTANT

30..32000 sec

600 sec

Thermal Time Constant

1604

Θ ALARM

70..100 %

90 %

Thermal Alarm Stage

1610A

I ALARM

0.10..4.00 A

1.00 A

Current Overload Alarm Setpoint

1612A

Kτ-FACTOR

1.0..10.0

1.0

Kt-Factor when Motor Stops

1615A

I MAX THERM.

0.50..8.00 A

3.30 A

Maximum Current for Thermal Replica

1616A

T EMERGENCY

10..15000 sec

100 sec

Emergency Time

1605

TEMP. RISE I

40..200 °C

100 °C

Temperature Rise at Rated Sec. Curr.

1606

TEMP. RISE I

104..392 °F

212 °F


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63

Functions

Addr.

Setting Title

Setting Options

Default Setting

Comments

1607

TEMP. INPUT

Disabled 4-20 mA Fieldbus Temp. of RTD 1

Disabled

Temperature Input

1608

TEMP. SCAL.

40..300 °C

100 °C

Temperature for Scaling

1609

TEMP. SCAL.

104..572 °F

212 °F


2.9.2.2

Information List for the Thermal Overload Protection

F.No.

Alarm

Comments

01503 >BLK ThOverload

>BLOCK thermal overload protection

01506 >RM th.rep. O/L

>Reset memory for thermal replica O/L

01507 >Emer.Start O/L

>Emergency start O/L

01508 >Fail.Temp.inp

>Failure temperature input

01511 Th.Overload OFF

Thermal Overload Protection OFF

01512 Th.Overload BLK

Thermal Overload Protection BLOCKED

01513 Overload ACT

Overload Protection ACTIVE

01514 Fail.Temp.inp

Failure temperature input

01519 RM th.rep. O/L

Reset memory for thermal replica O/L

01515 O/L I Alarm

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

64

7UM62 Manual C53000-G1176-C149-3


2.10


General

Unbalanced load protection detects unbalanced loads. The negative sequence currents associated with unbalanced loads create reverse fields in three-phase induction machines, which act on the rotor at double frequency. Eddy currents are induced at the rotor surface, and local overheating of the rotor end zones and the slot wedges begins to take place. Another effect of unbalanced loads is an overheating of the damper winding. In addition, it may be used to detect interruptions, faults, and polarity problems with current transformers. It is particularly useful in detecting phaseto-ground, phase-to-phase, and double phase-to-ground faults with magnitudes lower than the maximum load current.

2.10.1 Functional Description Unbalanced Load Determination

The unbalanced load protection feature of the 7UM62 relay uses filtering to calculate the symmetrical components from the phase currents. It evaluates the negative-phase sequence system, the negative phase-sequence current I2. If the negative phasesequence current exceeds a set threshold value, the trip timer starts. A trip command is transmitted as soon as this trip time has expired.

Warning stage

If the value of the continuously permissible, negative phase-sequence current I2> is exceeded, a warning message ”I2> Warn” is transmitted after a selectable time T WARN (see Figure 2-21).

Thermal Characteristic

The machine manufacturers indicate the permissible unbalanced load by means of the following formula: K t zul = ------------I2 2 æ -----ö è I Nø

where tperm =maximum permissible application time of the negative-sequence current I2 K

=Asymmetry factor (machine constant)

I2/IN =Unbal. load (ratio neg. phase-sequ. I2 nom. cur. IN)

The asymmetry factor depends on the machine and represents the time in seconds during which the generator can be loaded with a 100 % unbalanced load. This factor is typically in a range between 5 s and 30 s. The heating up of the object to be protected is calculated in the relay as soon as the I2> permissible unbalanced load is exceeded. The current-time-area is calculated constantly to ensure a correct consideration of the changing load. The thermal characteristic is tripped as soon as the current-time-area ((I2/IN)2 ⋅ t) has reached the K asymmetry factor. Limitation

The model of the heating of the object to be protected is limited to a 200 % trip temperature overrange.

Cool Down

A settable cool-down time starts as soon as the value falls below the constantly permissible unbalanced load I2>. The parameter T COOL DOWN is defined as the time required by the thermal image to cool down from 100 % to 0 %. The cool-down time depends on the construction type of the generator, and especially on the damper winding. Preloading is taken into consideration when unbalanced loading occurs during the cool-down period. The protective relay will thus trip in a shorter time.

7UM62 Manual C53000-G1176-C149-3

65

Functions

Definite-Time Trip Stage

High negative phase-sequence currents can only be caused by a two-pole power system short circuit which must be covered in accordance with the network grading plan. For this reason, the thermal characteristic is cut by a selectable, definite-time, negative phase-sequence current stage (address 1706 I2>> and 1707 T I2>>) (see Figure 2-21). Please also observe the instructions regarding the phase rotation (phase sequence) provided in Sections 2.3 and 2.43.

t Unbalanced load stage I2adm. T WARN

Thermal trip stage

Unbalanced load Tripping zone I2>>

T I2>>

Figure 2-21

Tripping Zone of the Unbalanced Load Protection

FNo.05161

1704 FACTOR K

IL1

I2 ICO

IL2 IL3

1

0

å

I2 --In

2

⋅ ∆t

I2 Q TRIP

&

Reset I2=0

FNo. 05146

>RM th.rep. I2

I2

I2>>

I2 adm

FNr.05158

RM th.rep. I2

OR

Tripping matrix

FNr.05165

I2> picked up 1702 I2>

1703 T WARN

FNr.05156

& 1705 I2>>

I2> Warn 1707 T I2>>

TMin TRIP CMD

FNr.05160

I2>> TRIP

& FNr.05159

I2>> picked up FNo. 05143

FNr.05152

>BLOCK I2

I2 BLOCKED

Figure 2-22

66

Logic Diagram of the Unbalanced Load Protection

7UM62 Manual C53000-G1176-C149-3


Logic

Figure 2-22 shows the logic diagram of the unbalanced load protection. The protection may be blocked via a binary input (”>BLOCK I2”). Pickups and time stages are reset and the metered values in the thermal model are cleared. The binary input ”>RM th.rep. I2” only serves to clear metered values of the thermal characteristic.

2.10.2 Setting Hints General

The unbalance load protection is only effective and accessible if it was selected at address0117 UNBALANCE LOAD = Enabled within the framework of project configuration. Set Disabled if the function is not required. The function can be switched ON or OFF at address 1701 UNBALANCE LOAD. As an alternative, the user can only block the trip signal (Block Relay). The maximum permissible, constant negative phase-sequence current is required by the thermal model. For machines of up to 100 MVA with non-salient pole rotors, this current typically amounts to a value in a range from 6 % to 8 %. With salient-pole rotors, it is at least 12 % of the nominal machine current. For larger machines and in cases of doubt, please observe the instructions of the machine manufacturer. It is important to ensure that the values given by the manufacturer represent the primary values of the machine. For example, if the long-time allowable thermal inverse current —with respect to the nominal machine current — is given, this value must be used to calculate the settings for the unbalanced load time-overcurrent element. For the settings on the protective relay, this information is converted to the secondary inverse current. For this situation I 2max prim I N Machine æ -----------------------ö ⋅ -----------------------Pickup Setting I2> = è I N Machineø I N CT prim where I2 max prim Permissible long-term thermal inverse current of the machine IN Machine Nominal machine current IN CT prim

Pickup Threshold / Warning Stage

Nominal primary CT current

The value for I2> is set at address 1702. It is at the same time the pickup value for a current warning stage the delay time for which T WARN is set at address 1703. Example: Machine:

Negative Sequence Factor K

7UM62 Manual C53000-G1176-C149-3

IN Machine

= 483 A

I2 perm prim / IN Machine

= 11 % continuous (salient-pole machine, see Figure 2-23)


IN CT prim

= 500 A

Setting value

I2 perm.

= 11 % · (483 A/500 A) = 10.6 %

If the machine manufacturer has indicated the loadability duration due to an unbalanced load by means of the constant K = (I2/IN)2 ⋅ t, it is set immediately at the address 1704 FACTOR K. The constant K is proportional to the permissible energy loss.

67

Functions

Conversion to Secondary Values

The factor K can be derived from the unbalanced load characteristic according to Figure 2-23 by reading the time corresponding to the FACTOR K at the point I2/IN = 1. Example: tperm = 20 s for I2/IN = 1 The constant Kprimary = 20 s determined in this way is valid for the machine side (primary side). The factor Kprimary can be converted to the secondary side by means of the following formula: I N Machine 2 K sec = K primary ⋅ æ ------------------------ö è I N CT prim ø The calculated asymmetry factor Ksec is set as FACTOR K at address 1704. Example:

IN Machine

= 483 A

IN CT prim

= 500 A

Factor Kprimary

= 20 s

Setting value at address1704: 483 A FACTOR K = 20 s ⋅ æè ---------------öø 500 A

2

= 18,7 s

max. perm. I2/IN in permanent operation

I2/IN

max. perm. I2/IN in case of a system fault

1.0

0.5 0.4 0.3

0.2

0.11 0.1

0.06 10

Figure 2-23

68

20

30

40 50

100

500

1000

t/s

Example of an Unbalanced Load Characteristic Specified by the Machine Manufacturer

7UM62 Manual C53000-G1176-C149-3


Time for Cool Down

The parameter 1705 T COOL DOWN is defined as the time required by the thermal image to cool down from 100 % to 0 %. If the machine manufacturer does not provide this information, the setting value can be calculated by assuming an equal value for the cool-down time and the heating time of the object to be protected. The formula below shows the relation between the K asymmetry factor and the cool-down time: K t Cooldown = --------------------------------2 ( I 2 perm ⁄ I N ) Example: The following cool-down time results for a K = 20 s and a permissible constant unbalanced load I2/IN = 11 %. 20 s t Cooldown = -------------------- ≈ 1650 s 2 ( 0, 11 ) This value T COOL DOWN is set at address 1705.

Definite-Time Tripping Characteristic

Asymmetrical system faults also cause high negative phase-sequence currents. A definite-time negative phase-sequence current–stage 1706 I2>> can detect asymmetrical power system short circuits. A setting to about 60 % to 65 % ensures that a trip is always performed according to the thermal characteristic in case of a phase failure (unbalanced load always less than 100/√3 %, i.e. I2 < 58 %). On the other hand, a two-pole short circuit can be supposed for an unbalanced load of more than 60 % to 65 %. The delay time T I2>> (address 1707) must be coordinated with the system grading of phase-to-phase short circuits. Contrary to the time-overcurrent protection, the I2>> stage is able to detect fault currents under nominal current. The following conditions are valid: − A phase-to-phase fault (I) results in the following negative sequence current 1 I 2 = ------- ⋅ I = 0.58 ⋅ I 3 − A phase-to-ground fault I) corresponds to the following negative sequence current 1 I 2 = --- ⋅ I = 0.33 ⋅ I 3 With an isolated starpoint, the I current value is particularly low and can be neglected. With a low-resistance grounding, however, it is determined by the ground resistance.

2.10.2.1 Settings of the Unbalanced Load Protection

Addr.

Setting Title

Setting Options

Default Setting

Comments

1701

UNBALANCE LOAD OFF ON Block relay for trip commands

OFF

Unbalance Load Protection

1702

I2>

10.6 %

Continously Permissible Current I2

7UM62 Manual C53000-G1176-C149-3

3.0..30.0 %

69

Functions

Addr.

Setting Title

Setting Options

Default Setting

Comments

1703

T WARN

0.00..60.00 sec; ∞

20.00 sec

Warning Stage Time Delay

1704

FACTOR K

2.0..100.0 sec; ∞

18.7 sec

Negativ Sequence Factor K

1705

T COOL DOWN

0..50000 sec

1650 sec

Time for Cooling Down

1706

I2>>

10..100 %

60 %

I2>> Pickup

1707

T I2>>

0.00..60.00 sec; ∞

3.00 sec

T I2>> Time Delay

2.10.2.2 Information for the Unbalanced Load Protection F.No.

Alarm

Comments

05143 >BLOCK I2

>BLOCK I2 (Unbalance Load)

05146 >RM th.rep. I2

>Reset memory for thermal replica I2

05151 I2 OFF

I2 switched OFF

05152 I2 BLOCKED

I2 is BLOCKED

05153 I2 ACTIVE

I2 is ACTIVE

05158 RM th.rep. I2

Reset memory of thermal replica I2

05156 I2> Warn

Unbalanced load: Current warning stage

05165 I2> picked up

I2> picked up

05159 I2>> picked up

I2>> picked up

05160 I2>> TRIP

Unbalanced load: TRIP of current stage

05161 I2 Θ TRIP

Unbalanced load: TRIP of thermal stage

70

7UM62 Manual C53000-G1176-C149-3


2.11


General

Gas turbines can be started by means of a frequency starting converter. A switchedmode converter feeds a current into the generator and creates a rotating field whose frequency gradually increases. This causes the rotor to turn and thus to drive the turbine. At approx. 70 % of the rated speed, the turbine is ignited and further accelerated until it attains rated speed. The startup converter is switched off. Figure 2-24 shows the characteristic quantities to be considered during startup. Please note that all quantities are normalized to the rated values.

U

f

UN

fN n nN

-P SN

Startup converter switched off 0.04

0.8

I IN U UN

0.05

1.0

0.6

n nN

U

f

UN

fN

0.03 -P SN 0.02

0.4

0.2

I IN

0.01

U UN 60

120

180 t (s)

Figure 2-24 Characteristic Quantities to be Considered during Startup of a Gas Turbine (SN = 150 MVA; UN = 10.5 kV; PStartup converter = 2.9 MW)

Assuming that a short-circuit can occur in the generator during startup, a short-circuit protection is necessary over the entire frequency range. The 7UM62 offers for this a highly useful feature, namely its automatic adaption of the sampling frequency to the current generator frequency, which ensures the same sensitivity over the entire frequency range. This adaption starts at the transition from 10 Hz to 11 Hz. As a result, all short-circuit protection functions, such as overcurrent protection (Sections 2.6 to 2.8), impedance protection (Section 2.17) and differential protection (Section 2.12) are active with the same sensitivity as with nominal frequency. The startup overcurrent protection is a short-circuit protection function that works below 10 Hz. Its operating range is designed for 2 Hz to approx. 10 Hz (change to operational condition 1). At higher frequencies, the above short-circuit protection functions are active.

7UM62 Manual C53000-G1176-C149-3

71

Functions

The function is also active above 70 Hz because at that frequency the protection is again in operational condition 0.

2.11.1 Functional Description Measuring Principle

At frequencies below 10 Hz, the protection works in operating condition 0, with the sampling frequency automatically set to nominal conditions (fS = 800 Hz for 50 Hz networks and 960 Hz for 60 Hz networks). From the sampled phase currents, a special algorithm determines the peak values. These are converted into values proportional to the r.m.s. values, and compared with the set threshold value. Figure 2-25 shows the logic diagram.

Operating state 1=1

5575 O/C Start L1 PU

1802 STARTUP I> IST-L1

&

IST-L2

&

1803 STARTUP T I> 5578 O/C Start TRIP Tripping matrix

OR 5576 O/C Start L2 PU 5577 O/C Start L3 PU

&

IST-L3 5571 >BLOCK O/C St

Tmin TRIP CMD

5573 O/C Start BLK

Figure 2-25 Logic Diagram of the Startup Overcurrent Protection


The startup overcurrent protection is only effective and accessible if it has been set to Enabled at address 118 during configuration of the protection functions. Address 1801 O/C STARTUP is used to switch the function ON or OFF, or to block only the trip command (Block relay).

Pickup Value

Figure 2-24 shows that the currents during startup amount to approx. 20 % of the nominal currents. This allows to set the protection routinely to less than nominal current. As can be seen in Figure 2-25, the function is blocked when the operating condition changes from 0 to 1. Additionally, blocking by binary input should be provided for. Figure 2-26 shows an example of the estimated short-circuit currents at different frequencies. As the short-circuit currents can amount to a multiple of the nominal current, the pickup value could also be set to more than the nominal current, i.e. around the usual values between 1.2 and 1.4 I/ING.

72

7UM62 Manual C53000-G1176-C149-3


6 5

I/InG

4 3 2 1 0 0

0.2

0.4

0.6

0.8

1

1.2

f/fn Figure 2-26 Short-Circuit Currents in the Generator during the Startup (Generator: 300 MVA, 15.75 kV, 50 Hz)

Delay Times

Since the generator circuit breaker is open during startup, there is no need to coordinate the delay time with the network. Wherever possible, no delay time should be effective at all since the operating time of the protection function is extended proportionally to the lower frequency (see Chapter 4, Technical Data). Where a sensitive setting is selected, a delay time may be useful to avoid overfunctioning. This delay time should be based on the lowest detectable frequency of 2 Hz, and set to 0.5 s.

Short-Circuit Coordination

Figure 2-27 shows the interaction between the short-circuit protection functions, such as: − Startup overcurrent function − Differential protection − I>> stage as back-up stage for 10 Hz and higher The pickup thresholds in this figure are for orientation only. The differential protection Idiff and the overcurrent protection I>> are effective from approx. 10 - 11 Hz. The startup overcurrent protection I-ANF provides additional protection in the lower frequency range. The result is a short-circuit protection concept in which the functions complement one another.

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73

Functions

3 2.5

I/InG

2 1.5 1 0.5 0 0

0.2

0.6

0.4

1

0.8

1.2

f/fn Idiff

I>>

O/C START

Figure 2-27 Operating Range and Possible Pickup Threshold of Short-Circuit Protection Functions

2.11.2.1 Settings of the Startup Overcurrent Protection Addr.

Setting Title

Setting Options

Default Setting

Comments

1801

O/C STARTUP


OFF


1802

STARTUP I>

0.10..20.00 A

1.30 A

I> Pickup

1803

STARTUP T I>

0.00..60.00 sec; ∞

0.50 sec

T I> Time Delay

2.11.2.2 Information for the Startup Overcurrent Protection F.No.

Alarm

Comments

05571 >BLOCK O/C St

>BLOCK startup O/C protection

05572 O/C Start OFF

Startup O/C protection is switched OFF

05573 O/C Start BLK

Startup O/C protection is BLOCKED

05574 O/C Start ACT

Startup O/C protection is ACTIVE


Startup O/C phase L1 picked up





05578 O/C Start TRIP

Startup O/C protection TRIP

74

7UM62 Manual C53000-G1176-C149-3


2.12


General

The numerical current differential protection of the 7UM62 is a fast and selective shortcircuit protection for generators, motors and transformers. The individual application can be configured, which ensures optimum matching to the protected object. The protected zone is selectively limited by the CTs at its ends.

2.12.1 Functional Description The processing of the measured values depends on the way the differential protection is used. This section discusses first the differential protection function in general, regardless of the type of protected object, for a single-phase system. It then deals with the particularities of individual objects that can be protected. Basic Principle

Differential protection systems operate according to the principle of current comparison (Kirchhoff’s current law). They utilize the fact that in a healthy protected object the current leaving the object is the same as that which entered it (current Ip, dotted in Figure 2-28). Any measured current difference is a certain indication of a fault somewhere within the protected zone. The secondary windings of current transformers CT1 and CT2, which have the same transformation ratio, may be so connected that a closed circuit is formed. If now a measuring element M is connected at the electrical balance point, it reveals the current difference. Under healthy conditions (e.g. on-load operation) no current flows in the measuring element. In the event of a fault in the protected object, the summation current Ip1+Ip2flows on the primary side. The currents on the secondary side, I1 and I2 flow through the measuring element M. as a summation current I1+I2 (see Figure 2-28).

Ip1

Ip

Ip2 Ip Protected object

CT1 I I1

CT2 I

Ip1+Ip2

I2 M I1+I2

Figure 2-28

Current Stabilization

7UM62 Manual C53000-G1176-C149-3

Basic Principle of Differential Protection (Single-Phase Representation) (Ipx = primary current, Ix = secondary current)

When an external fault causes a heavy current to flow through the protected zone, differences in the magnetic characteristics of the current transformers CT1 and CT2 under conditions of saturation may cause a significant current to flow through the element M. If the magnitude of this current lies above the response threshold, the element would issue a trip signal. To prevent the protection from such erroneous operation, a stabilizing current is brought in.

75

Functions

The stabilizing quantity is derived from the arithmetical sum of the absolute values of |I1| + |I2|. The following definitions apply: The differential current Idiff = |I1 + I2| and the stabilization or restraining current Istab = |I1| + |I2| Idiff is derived from the fundamental frequency current and produces the tripping effect quantity, Istab counteracts this effect. To clarify the situation, three important operating conditions with ideal and matched measurement qualities should be examined:

Ip1

Ip2

Protected object

CT1 I1

CT2 I2

M I1 + I2 Figure 2-29

Definitions of Currents

1. Through flowing current through a healthy transformer or 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 Istab= |I1|+ |I2| = |I1| + |I1| = 2 ⋅ |I1| No tripping effect (Idiff); stabilization (Istab) corresponds to twice the through flowing current. 2. Internal short-circuit, e.g. fed with equal currents each side: In this case I2 = I1; and consequently |I2| = |I1| Idiff = |I1+ I2| = |I1 + I1| = 2 ⋅ |I1| Istab =|I1|+ |I2| = |I1| + |I1| = 2 ⋅ |I1| Tripping effect (Idiff) and stabilizing (Istab) quantities are equal and correspond to the total fault. 3. Internal short-circuit, fed from one side only: In this case I2 = 0 Idiff = |I1 + I2| = |I1 – 0| = |I1| Istab =|I1|+ |I2| = |I1| + 0 = |I1| Tripping effect (Idiff) and stabilizing (Istab) quantities are equal and correspond to the fault current fed from one side.

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7UM62 Manual C53000-G1176-C149-3


This result shows that for internal fault and under ideal conditions Idiff = Istab. Consequently, the characteristic of internal faults is a straight line with a upward slope of 45° (dot-and-dash line in Figure 2-30). The currents Idiff and Istab are compared by the differential protection with the operating characteristic according to Figure 2-30. If the quantities result into a locus in the tripping area, a trip signal is given.

I diff --------- 10 IN

Fault characteristic

9 2031 8 I DIFF >>

7 6

Trip area

5 4 3

Block area

2 1

2021 I DIFF>

1

2

3

4

5

6

7

8

9

10 11 12 13 14 15 16 17 18

I stab ----------IN Figure 2-30

Matching the Values of Measured Quantities

Operation Characteristics of the Differential Protection with Fault Characteristic

The rated CT currents are matched to the rated current of the protected object, regardless of what that object is. As a result, all currents are referred to the protected object. To match the currents, the characteristic values of the protected object (apparent power, rated voltage) and the rated primary currents of the CTs are entered in the protective device for each side of the protected object.

2.12.1.1 Protected Object Generator or Motor: Particularities Definition and Matching of Measured Quantities

7UM62 Manual C53000-G1176-C149-3

The differential protection function of the 7UM62 can be used as longitudinal or as transverse differential protection. The operation modes differ from each other only by the definition of the measured current and the limits of the protected zone. Since the current direction is normally defined as positive in the direction of the protected object, the definitions as illustrated in Figure 2-31 result. The protected zone is limited by the CTs in the neutral point of generator and the CTs at the terminal side. The differential protection feature of the 7UM62 refers all currents to the rated current of the protected object. The characteristic values of the protected object (apparent power, rated voltage) and the primary rated currents of the CTs are entered in the protective device for each side of the protected object. The measured quantity matching is thus limited to the factors for the absolute current values.

77

Functions

Due to their predominantly inductive component, faults in the proximity of the generator have relatively high short-circuit time constants that cause a magnetization of the current transformers. The CTs should be designed accordingly (see Appendix A.7).

Figure 2-31

Definition of Current Direction for Longitudinal Differential Protection

For use as a transverse differential protection, there is a particularity. Figure 2-32 shows the definition of the measuring currents for this application. In the transverse differential protection, the phases connected in parallel constitute the limit between the protected zone and the network. A differential current appears in this type of circuit always if there is a current difference within the phases, and only in that case, so that a fault current in that phase can be assumed. Since in this case, unlike the other applications, all currents flow into the protected object in healthy operation, a “wrong” polarity is set for one set of CTs, as described in Section 2.3.2 under “Connection of the Current Transformer Sets“.

L1

L2

L3 Figure 2-32

Definition of Current Direction for Transverse Differential Protection

The CTs also determine the limits of sensitivity in the case of motors. In asynchronous motors, the startup operation may be modeled in different ways by the CTs, so that major differential currents occur (see also side title ”Increase of Pickup Value on Startup”).

2.12.1.2 Protected Object Transformer: Particularities Transformers are subject to a number of influences that induce differential currents even during normal operation:

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7UM62 Manual C53000-G1176-C149-3


Mismatching of CTs

Differences in the matching of CTs to the transformer rated current are not uncommon. These differences result in an error that leads to a differential current.

Voltage Control by Tap Changers

Voltage control tap changers (usually in-phase regulators) change the transformation ratio and the rated current of the transformer. They cause mismatching of the CTs and thus a differential current.

Inrush Current

Transformers may absorb on power-up considerable magnetizing currents (inrush currents) that enter the protected zone but do not leave it. They act therefore like fault currents entering on one side. 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.

Overexcitation (Overflux)

Where a transformer is operated with an excessive voltage, the non-linear magnetizing curve leads to increased magnetizing currents, which cause an additional differential current.

Vector Group

Depending on their application, transformers have different vector groups, which cause a shift of the phase angles between the primary and the secondary side. Without adequate correction, this phase shift would cause a differential current. The following paragraphs describe the main functional blocks of the differential protection that allow to control the above influences.

Matching the Values of Measured Quantities

The digitized currents are matched the transformer rated current. The characteristic values of the transformer, i.e. rated apparent power, rated voltages and primary rated CT currents, are entered in the protective device, and a correction factor kCT is calculated according to the following formula: I p, CT ⋅ 3 ⋅ U N I p, CT k CT = --------------- = -------------------------------------I N,Obj. SN where Ip, CT -

Primary rated CT current

IN,Obj. -

Primary rated current of protected object

SN

-

Rated apparent power of protected object

UN

-

Rated voltage

kCT

-

Correction factor

This correction is performed for each side of the protected object. Once the vector group has been entered, the protective device is capable of performing the current comparison according to fixed formulae. Vector Group Matching

7UM62 Manual C53000-G1176-C149-3

Unit transformers often have a wye-delta connection, with the delta connection being on the generator side. To allow a maximum of versatility in the use of the 7UM62, all imaginable vector group combinations have been provided for in the software. The following paragraph explains the basic principle of numerical vector group correction in an exemplary way for a Y(N)d5 transformer.

79

Functions

The higher voltage side has a wye connection and the lower voltage side a delta connection. The phase rotation is n ⋅ 30° (i.e. 5 ⋅ 30° = 150°). Side 1 (higher voltage side) is the reference system. The vector group correction feature transforms the currents flowing from side 2 to side 1. Isolated Starpoint

Figure 2-33 shows the vector group, the vector diagram for symmetrically flowing currents and the transformation rules for a system with an isolated starpoint.

Side 1

Side 2

L1

L1

L2

L2

L3

L3 IL1 IL3 √3 ⋅ IA

IL2

IA

IL1 IL3

IL2 IA

I L1 1 0 0 I B = 1 ⋅ 0 1 0 ⋅ I L2 0 0 1 IC I L3 Figure 2-33

I L1 –1 0 1 1 I B = ------- ⋅ 1 – 1 0 ⋅ I L2 3 0 1 –1 IC I L3 IA

Vector Group Matching for a Y(N) d5 Transformer (Isolated Starpoint)

Deducting on side 2 the currents IL3 – IL1 results in the current IA, which has the same direction as IA on side 1. Multiplying it with 1/√3 matches the absolute values. The matrix describes the conversion for all three phases. Earthed Transformer Starpoint

Figure 2-34 shows an example of a YNd5 vector group with earthed starpoint on the Y-side. The zero sequence currents are eliminated in this case. In Figure 2-34 on the right side, the zero sequence currents are automatically eliminated by the current difference formation, just as in the transformer there can be no zero sequence currents outside the delta winding. On the left-hand side, the elimination of the zero sequence current results from the matrix equation, e.g. 1/ · (2 I – 1 I – 1 I ) = 1/ · (3 I – I – I – I ) = 1/ · (3 I – 3 I ) = (I – I ). 3 L1 L2 L3 3 L1 L1 L2 L3 3 L1 0 L1 0 Because of the zero sequence current elimination, fault currents which flow through the CTs during earth faults in the network if there is an earthing point in the protected zone (transformer starpoint or starpoint earthing transformer) are neutralized without any special measures from outside.

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7UM62 Manual C53000-G1176-C149-3


Side 1

Side 2

L1

L1

L2

L2

L3

L3 IL1 IL3 √3 ⋅ IA

IL2

IA

IL1 IL3

IL2

IA

I L1 2 – 1 –1 1 IB = --- ⋅ – 1 2 – 1 ⋅ I L2 3 –1 –1 2 IC I L3 Figure 2-34

I L1 –1 0 1 1 I B = ------- ⋅ 1 – 1 0 ⋅ I L2 3 0 1 –1 IC I L3 IA

Vector Group Matching for Y(N) d5 (with Earthed Starpoint)

In Figure 2-35 on the left-hand side, a zero sequence current will occur in case of e.g. an external fault; on the right-hand side, it will not. If the currents were compared without first eliminating the zero sequence current, the result would be wrong (differential current despite external fault). Therefore, the zero sequence current must be eliminated on side 1. The zero sequence current is deducted from the phase currents. The rule for calculation is shown in the left-hand matrix in Figure 2-34.

L1

L1

L2

L2

L3

L3

Figure 2-35

Example of an Earth Fault Outside the Transformer with Distribution of Currents

2.12.1.3 Evaluation of Measured Quantities The 7UM62 performs the above calculations (matching of absolute values, vector group matching in the case of transformers) at every sampling and derives from them the instantaneous values of differential and stabilizing current. From the differential current, the fundamental component is determined by means of a Fourier filter, which provides for effective damping of any interference and aperiodic DC components.

7UM62 Manual C53000-G1176-C149-3

81

Functions

The stabilizing quantity is calculated from the arithmetic average of a rectified quantity, so that the filter effect is less for it. As a result, the stabilization component in interference components, especially aperiodic DC components, will be higher than their differential current. Tripping Characteristic

This result shows that for an internal fault Idiff = Istab. Thus the characteristic of internal faults in the tripping diagram (see Figure 2-36) is a straight line with a slope of 45°. Figure 2-36 shows the complete operation characteristic of the 7UM62. Branch a represents the sensitivity threshold of the differential protection (setting I-DIFF>) and considers constant error currents such as magnetizing currents. Branch b considers current-proportional errors which may result from transformation errors of the main CTs or the input CTs of the relay, or which may be caused by mismatching or by the influence of tap changers in transformers with voltage control. In the range of high currents which may give rise to current transformer saturation, branch c provides for additional stabilization. In the presence of differential currents above branch d a trip command is issued regardless of the stabilizing current and the harmonic stabilization. This is the operating range of the ”High-Speed Trip Stage IDiff >>”.

I diff --------- 10 IN


9 d d

2031 8 I DIFF>>

7 6

Trip area

5

Block area 2043 SLOPE 2

c

4 3

2041 SLOPE 1

2 1

2021 I DIFF>

Add-on stabilization

b a

Saturation

1

2

3

4

5

6

7

8

9

10 11 12 13 14 15 16 17 18

2044 BASE POINT 2 2042 BASE POINT 1

Figure 2-36

I stab ----------IN

Operating Characteristic of the Differential Protection

The area of add-on stabilization is determined by the saturation indicator (see side title ”Add-on Stabilization During Current Transformer Saturation”. The currents Idiff and Istab are compared by the differential protection with the operating characteristic according to Figure 2-36. If the quantities result into a locus in the tripping area, a trip signal is given.

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7UM62 Manual C53000-G1176-C149-3


High-Speed Trip Stage IDiff >>

The high-speed trip stage IDiff >> clears high-current internal faults instantaneously. As soon as the differential current rises above the threshold IDiff >> (branch d), a trip signal is issued regardless of the magnitude of the stabilizing current. This stage can operate even when, for example, a considerable second harmonic is present in the differential current, which is caused by current transformer saturation by a DC component in the short-circuit current, and which could be interpreted by the inrush stabilization function as an inrush current. This high-current stage evaluates the fundamental component of the differential current as well as the instantaneous values. Instantaneous value processing ensures fast tripping even in case the fundamental component of the current is strongly reduced by current transformer saturation. High-current faults in the protected transformer may be cleared instantaneously without regard of the magnitude of the stabilizing currents when the amplitude of the differential currents can exclude that it is an external fault. This is always the case when the short-circuit current is higher than 1/usc ⋅ IN Transf.

Add-on Stabilization During Current Transformer Saturation

During an external fault which produces a high through flowing short-circuit current causing current transformer saturation, a considerable differential current can be simulated, especially when the degree of saturation is different at the two measuring points. If the quantities Idiff/Istab result in an operating point which lies in the trip area of the operating characteristic (Figure 2-37), a trip signal would be the consequence if no special measures were taken.

I diff --------- 10 IN


9 8 D

7 6

Trip area

5

Block area

C

4 3 2


1

B Saturation A 1

2

3

4

5

2044 BASE POINT 2 2042 BASE POINT 1

Figure 2-37

6

7

8

9

10 11 12 13 14 15 16 17 18

I stab ----------IN

Operation Characteristics of the Differential Protection with Fault Characteristic

The 7UM62 provides a saturation indicator which detects such phenomena and initiates add-on stabilization measures. The saturation indicator evaluates the dynamic behaviour of the differential and stabilizing current. The dotted line in Figure 2-37 shows the instantaneous development of currents in case of a external fault with transformer saturation on one side.

7UM62 Manual C53000-G1176-C149-3

83

Functions

Immediately after the fault (A), the short-circuit currents rise strongly, causing a equally high stabilizing current (2xthrough-flowing current). Saturation occurring on one side (B) now causes a differential current and reduces the stabilizing current, so that the operating point Idiff/Istab may move into the tripping area (C). In contrast, the operating point moves immediately along the fault characteristic (D) when an internal fault occurs since the stabilization current will barely be higher than the differential current. Therefore, an internal fault is assumed as soon as the ratio Idiff/ Istab has exceeded an internal threshold for a fixed minimum time. Current transformer saturation in case of an external fault is thus characterized by a high stabilizing current flowing at the beginning, i.e. by the operating point (diagram see Figure 2-37) moving into an area that is typical for a high-current external fault (”add-on stabilization). The add-on stabilization area is limited by the parameter IADD ON STAB. and the first straight line of the characteristic (with BASE POINT 1 and SLOPE 1) (see Figure 2-38). The saturation indicator makes its decision within the first quarter of a period after fault inception. When an external fault is detected, the differential protection is blocked for a selectable time. The blocking is cancelled as soon as the operating point Idiff/Istab moves steadily (i.e. over 2 periods) within the tripping area. This allows to detect evolving faults in the protected area reliably even during an external fault with current transformer saturation.

I diff --------------INObj 10


9 2031 8 I DIFF>>

d

7 6

Trip area 5 c

4

Block area

2043 SLOPE 2

2041 SLOPE 1

3 2 1

2021 I–DIFF>

a 1


b 2

3

4

5

2044 BASE POINT 2 2042 2056 BASE POINT 1 EXF–STAB

Figure 2-38

Harmonic Stabilization

84

6

7

8

9

10 11 12 13 14 15 16 17 18 I stab --------------I NObj


In transformers in particular, high short-time magnetizing currents may be present during power-up (inrush currents). These currents enter the protected zone but do not leave it again, so that they act like fault currents entering from one side (Figure 2-39).

7UM62 Manual C53000-G1176-C149-3


Unwanted differential currents may also be cause by parallel connection of transformers or by transformer overexcitation due to excessive voltage. 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 selectable threshold, tripping is blocked.

Figure 2-39

Inrush Current – Example Recording of the Three Higher-Voltage Currents

Besides the second harmonic, another harmonic can be selected in the 7UM62 to cause blocking. A choice can be made between the third and fifth harmonic as harmonic stabilization. Steady-state overexcitation of the transformer is characterized by odd harmonic content. The third or fifth harmonic is suitable to provide stabilization. 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. Converter transformers also produce odd harmonic content which is practically absent in the case of internal short-circuits. The differential currents are analyzed with regard to their harmonics content. Numerical filters are used to perform a Fourier analysis of the differential current. As soon as the harmonics content exceeds the set thresholds, a stabilization of the respective phase evaluation is started. The filter algorithms are optimized with regard to their transient behaviour such that additional measures for stabilization during dynamic conditions are not necessary. The harmonic stabilization is maintained for two periods after decrease of the differential current. This prevents an unwanted under-stabilization when external faults are cleared and the higher-order harmonics disappear. Since the inrush stabilization operates individually per phase, the protection is fully operative even when the transformer is switched onto a single-phase fault, while inrush currents may possibly be present in one of the healthy phases. In ”modern type” transformers in particular, the 2nd harmonics content may not exceed the threshold value in all three phases on switch-on. To avoid spurious tripping, the so-called “crossblock” function must be activated. As soon as an inrush current is detected in one phase, the other phases of the differential protection stage IDIFF> are blocked. The cross-block function can be limited to a selectable duration. After this cross-block time has elapsed, no more cross-block is possible for as long as a running fault

7UM62 Manual C53000-G1176-C149-3

85

Functions

condition lasts, i.e. cross-blocking is possible only once after a fault has occurred, and only for the set cross-block time. The further harmonic stabilizations operate individually per phase. However, it is also possible – as it is for the inrush stabilization – to set the protection such that not only the phase with harmonics content in excess to the permissible value is stabilized but also the other phases of the differential stage I-DIFF> are blocked. The cross-block feature with 3rd or 5th harmonics works in the same way as with 2nd harmonics. Increase of Pickup Value on Startup

An increase of the pickup value on startup provides additional security against overfunctioning when a non-energized protection object is switched in. As soon as the stabilizing current of one phase has dropped below a settable value I-REST. STARTUP, the increase of the pickup value is activated for the I-DIFF> stage. As the stabilizing current is twice the through-flowing current in normal operation, its dropping below that threshold is a criterion for detecting that the protected object is not energized. The pickup value I–DIFF is now increased by a settable factor (see Figure 2-40); the other branches of the Idiff> stage are shifted proportionally. This is done by dividing the DIFF current of the respective phase by the factor STARTFACTOR before the characteristic monitoring. The differential current for fault recording, tripping current etc. is not affected by this. The return of the stabilizing current indicates the startup. After a settable time T START MAX the increase of the characteristic is cancelled.

I diff --------IN

Trip area

5 4

Startup characteristic

Increase of pickup value

3

Steady-state Characteristic

2

Block area

1

2021 I DIFF>

1 Figure 2-40

Pickup, Dropout

2

3

4

5

6

7

8

I stab -----------IN

Increase of Pickup Value for Stage IDIFF> on Startup

The differential protection does not normally use a ”pickup”, since the detection of a fault is identical with the tripping condition. Like all SIPROTEC® devices, however, the differential protection feature of the 7UM62 has a pickup that is the starting point for a number of ulterior activities. The pickup marks the inception of a fault. This is necessary e.g. for creating fault events and fault records. The pickup also controls internal functions for both internal and external faults (such as necessary actions of the saturation indicator). A pickup is detected as soon as the fundamental wave of the differential current has attained 85 % of the setting value I-DIFF> or more than 85 % of the stabilizing current are in the add-on stabilization area (see Figure 2-41). A pickup signal is also issued when the high-speed trip stage for high-current faults picks up.

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7UM62 Manual C53000-G1176-C149-3


I diff --------------I NObj

Pickup

Steady-state characteristic

I–DIFF> 0.85 · I–DIFF>

Beginning of add-on stabilization

0.85 EXF–STAB

Figure 2-41

I stab ---------------INObj

Pickup of the Differential Protection

If stabilization by higher-order harmonics is activated, the system first performs a harmonics analysis (for about 1 period) to check the stabilization conditions, if required. If it is not, the trip command is issued as soon as the tripping conditions are fulfilled (hatched area in Figure 2-36). For special cases, the trip command can be delayed. Figure 2-42 shows a simplified diagram of the tripping logic. Reset is initiated when, during 2 periods, pick-up is no longer recognized in the differential values, i.e. the differential current has fallen below <70 % of the set value, and the other pickup conditions are no longer fulfilled either. If a trip command has not been initiated, the fault is considered to be over. If a trip command had been initiated, it is maintained for the minimum command duration set in the general device data for all protection functions (see also Section 2.3).

7UM62 Manual C53000-G1176-C149-3

87

Functions

FNo 05631

Diff picked up

)

1)

FNo 05691

Diff 2.Harm L1 Diff 2.Harm L2 Diff 2.Harm L3

FNo

Diff> TRIP

FNo

OR

Diff

OR

Diff

OR

Diff

TRIP

FNo

1)

TRIP

OR FNo

Diff n.Harm L1 Diff n.Harm L2 Diff n.Harm L3

Harmonic stabilization (3rd or 5th)*)

T

OR

FNr

)

Diff> L1 Diff> L2 Diff> L3

2026A T I-DIFF>

1

Inrush stabilization (2nd harm.)*)

1

FNo

&

Characteristic

TRIP

Tripping matrix

Add-on stabilization (ext. fault) Diff Bl. exF.L1 Diff Bl. exF.L2 Diff Bl. exF.L3

FNo

TMin TRIP CMD

FNo

OR

Diff TRIP FNo

&

I DIFF>>Stage

Diff>> L1 Diff>> L2 Diff>> L3

2036A T I-DIFF>>

T FNo 05692

OR L1 L2

Diff>>

Meas. release Meas. release

L3

Meas. release

FNo 05616

FNo 05603

Diff BLOCKED

>Diff BLOCK

FNo 05617

Diff ACTIVE 2001 DIFF. PROT.

OR

ON “1”

Block relay

FNo 05615

OFF

Diff OFF

1)

Figure 2-42

88

&

not with generators or motors

Logic Diagram of the Tripping Logic in Differential Protection

7UM62 Manual C53000-G1176-C149-3



The differential protection is only effective and accessible if the type of protected object for this function was set within the framework of the protective function configuration (Section 2.2, address 0120, DIFF. PROT. = Generator/Motor or Three-phase trans.). Only the relevant parameters for that object are offered, all others are hidden. Disabled is set if the function is not required. At the address 2001 DIFF. PROT. the user can switch the function ON or OFF, or only block the trip command (Block Relay).

Note: When the device is delivered, the differential protection function is switched OFF. This is because this protection function must not be used before at least the vector groups and matching values have been correctly set. Without these settings the device may show unpredictable behaviour (e.g. tripping)! The primary rated current Ip, CT of the used CTs should normally be higher than the rated current IN, Object of the object to be protected. However, at least the following condition should be observed with regard to the upper limit of the linear zone of the 7UM62, which is 20 ⋅ ΙN: Ip, CT > 0.75 ⋅ I N, Object

2.12.2.1 Differential Protection for Generators and Motors Precondition

A precondition for the functioning of the generator or motor differential protection is that during configuration at the address 0120 DIFF. PROT. = Generator/Motor has been set. One important setting is the location of the CT starpoints on both sides of the protected object (addresses 0201 STRPNT->OBJ S1 for side 1 and 0210 STRPNT->OBJ S2 for side 2, see Section 2.3). Also, the nominal values (SN GEN/MOTOR, UN GEN/MOTOR) of the machine to be protected, and the primary and secondary nominal currents of the main CTs on both sides must be entered. The settings are referred to these values. They are also used e.g. for determining the primary measured values. Information as to the treatment of the starpoint on both sides is required for the measured value monitoring; it has already been entered during configuration at the addresses 0241 STARPNT SIDE 1 and 0244 STARPNT SIDE 2 (see Section 2.3.2).

Increase of Pickup Value on Startup

For additional security against overfunctioning when a non-energized protection object is switched in, an increase of the pickup value on startup can be set at address 2005 INC.CHAR.START. On delivery of the device, this function is switched OFF. The associated parameters can be found at addresses 2051A, 2052A and 2053. Address 2051A I-REST. STARTUP is used to set the pickup value for startup detection. The function is disabled by setting I/InO = 0. The START-FACTOR specifies the increase factor of the pickup values on startup. For generator and motor protection, a setting of 2052A START-FACTOR = 2.0 is recommended.

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Functions

Tripping Characteristic

The parameters for the tripping characteristic are set at the addresses 2021 through 2044A. The meaning of the parameters is shown in Figure 2-43. The numerical values at the branches are the parameter addresses. Address 2021 I-DIFF> is the pickup value for the differential current. The pickup value is referred to the nominal current of the generator or motor. For generators and motors, a setting between 0.1 and 0.2 is recommended. In addition to the pickup threshold I-DIFF>, a second pickup threshold is considered. When this threshold (2031 I-DIFF>>) is exceeded, a trip signal is issued regardless of the magnitude of the stabilizing current (non-stabilized high-speed tripping). This stage must be set higher than I-DIFF>. Recommendation: Set a value above the steady-state value of the transient short-circuit current, i.e.:. 1 > ------ ⋅ I N, Generator x' d

I-DIFF>>

With values for xd’ between 0.15 and 0.35, the resulting setting values for IDIFF>> are approx. (3 to 7) ⋅ IN, Generator. The tripping characteristic has two more branches (Figure 2-43). Address 2041A SLOPE 1 determines the slope of the first branch, whose starting point is specified in the parameter 2042A BASE POINT 1. This branch considers current-proportional error currents. These are mainly transformation errors of the main CTs and of the input CTs. If the CTs are identical, the default setting of 0.25 can be reduced to 0.15. 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 at address 2044A BASE POINT 2. The slope is set at address 2043A SLOPE 2. The stability of the relay during current transformer saturation can be influenced by this parameter. A higher slope results in a higher stability. The default setting of 0.5 has proven to be a good value.

I diff 10 --------------INObj

9 2031 8 I–DIFF>>

d

7 6

Trip area 5 c

4

2043 SLOPE 2


3 2 1

2021 I–DIFF>

a 1


b 2

3

4

5


Figure 2-43

90

6

7

8

9

10 11 12 13 14 15 16 17 18 I stab --------------I NObj

Parameters Determining the Shape of the Tripping Characteristic

7UM62 Manual C53000-G1176-C149-3



Where very high currents flow through the protected object during external shortcircuits, an add-on stabilization takes effect that is set at address 2056A I-ADD ON STAB. (stabilization in case of saturation). Please note that the stabilizing current is the arithmetical sum of the currents entering and leaving the protected zone, i.e. that it is twice the actually flowing current. The default setting of 4.00 I/InO should be kept. The maximum duration of the add-on stabilization is set at address 2057A T ADD ON-STAB. in multiples of one period. This time is the maximum duration of the blocking after leaving the add-on stabilization area in case of high-current external faults. The setting depends, for instance, on the disconnecting time of the upstream protection. The default setting 15 *1P is a good value.

Time Delays

In special cases it may be advantageous to delay the trip signal of the differential protection with an additional time stage. The timer is started 2026A T I-DIFF> is started when an internal fault in the generator or the motor has been detected. 2036A T I-DIFF> is the time delay of trip stage I DIFF>>. A separate time stage is provided for each differential protection level and each phase. The dropout delay is linked to the minimum trip command duration that is valid for all protection functions. All setting times are additional time delays which do not include the operating times (measuring time, drop-out time) of the protective function.

2.12.2.2 Differential Protection for Transformers Precondition

A precondition for the operation of the transformer differential protection is that during configuration address 0120 DIFF. PROT. was set to = Three-phase transf.. To ensure the correct polarity for the formation of the differential current, the polarity of the sets of CTs must be specified. This has been done during the configuration, when entering the location of the starpoints of the sets of CTs on both sides of the transformer at addresses 0201 STRPNT->OBJ S1 for side 1 and 0210 STRPNT>OBJ S2 for side 2, see Section 2.3). Also, the nominal data (SN TRANSF, UN WIND S1, UN WIND S2) of both sides of the transformer, as well as the primary and secondary rated currents of the main CTs on both sides were requested. The settings are referred to these values. They are also used e.g. for determining the primary measured values. Information as to the treatment of the starpoint on both sides is required for the elimination of the zero sequence current and for the measured value monitoring (summation current monitoring); it has already been entered during configuration at the 0241 STARPNT SIDE 1 and 0244 STARPNT SIDE 2 (see Section 2.3.2).

Matching of Absolute Values and Vector Group Matching

When used as transformer protection, the 7UM62 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 circuitry is required for matching of the vector group and no manual calculations for converting of rated currents are normally necessary. The unit requires the following data for each winding − MVA rating (apparent power) SN in MVA (see above), − Rated voltage UN in kV (see above) − Vector group numeral

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− Rated current of the current transformer set in A (see above). Winding 1 is defined as the reference winding and therefore needs no numeral; the other windings are referred to winding 1. The reference winding is normally that of the higher voltage. If not the higher voltage side is used as reference winding, it must be considered that the vector group changes: e.g. a Dy5 transformer is regarded from the Y side as Yd7. If a 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. U max ⋅ U min 2 U N = 2 ⋅ --------------------------------- = ---------------------------------Voltage to be set U max + U min 1 1 ------------- + -------------U min U max If the setting of the protection should be performed with secondary values only (e.g. because external matching transformers are present), the factory-set parameters for transformer data can remain unchanged. The presets for transformer data apply for a ratio of 1: 1 without phase displacement Zero Sequence Current Treatment

The treatment of the winding starpoint is of no concern if the zero sequence currents are eliminated from the phase currents. Because of the zero sequence current elimination, fault currents which flow through the CTs during earth faults in the network if there is an earthing point in the protected zone (transformer starpoint or starpoint earthing transformer) are neutralized without any special measures from outside. The elimination of the zero sequence currents is selected by setting STARPNT SIDE* = earthed (see Figure 2-34). In networks with isolated or arc compensated starpoint, the elimination of the zero sequence current may be set ineffective provided that the starpoint of the protected transformer winding has no connection to earth, not even via a Petersen coil or a surge arrester. In this case, each double earth fault with one base point in the protected zone will be cleared by the relay, regardless of any double earth fault priority (see side title ”Isolated Starpoint” and Figure 2-33).

Increase of Pickup Value on Startup

For additional security against overfunctioning when a non-energized protection object is switched in, an increase of the pickup value on startup can be set at address 2005 INC.CHAR.START. As this option is mainly provided for generator and motor protection, the default setting is OFF if a 2-winding transformer has been selected as protected object. The associated parameters can be found at addresses 2051A, 2052A and 2053. Address 2051A I-REST. STARTUP is used to set the pickup value for detecting a startup. The function is disabled by setting I/InO = 0. The START-FACTOR specifies the increase factor of the pickup values on startup. For transformer protection, a setting of 2052A START-FACTOR = 1.0 is recommended. For switching of external loads such as motors or transformers, it should be increased to 2.0. Due to the high time constants, branch b of the characteristic may well be exceeded for a short time.

Harmonic Restraint

92

The inrush restraint of the device can be activated and deactivated at address 2006 INRUSH 2.HARM.. It is based on an evaluation of the 2nd harmonics present in the inrush current. When the device is delivered from the factory, a ratio I2fN/IfN of 15 % is set and can normally be maintained. However, the component required for restraint can be parameterized. To provide for more restraint in exceptional cases, where switch-on conditions are particularly unfavourable, a smaller value can be set at address 2061 2. HARMONIC.

7UM62 Manual C53000-G1176-C149-3


Cross-Blocking

The inrush restraint can be extended by the so-called ”cross-block” function. This means that not only the phase with inrush current exhibiting harmonics content in excess of the permissible value is stabilized but also the other phases of the differential stage IDIFF> are blocked. The duration for which the cross-block function is operative after the differential current threshold has been exceeded is set at address 2062A CROSSB. 2. HARM. Setting is in multiples of one cycle. Setting to 0 means that the protection can initiate a tripping when the transformer is switched onto a single-phase fault, even if an inrush current is flowing in another phase. When set to ∞, the cross-block function is always effective. The duration of the blocking is specified during commissioning. The default setting of 3 cycles has proven to be a good value. Besides the second harmonic, the 7UM62 can provide restraint with a further harmonic. Address 2007 RESTR. n.HARM. is used to disable this harmonics restraint, or to select the harmonic for it. The 3rd or the 5th harmonic are available. Steady-state overexcitation of the transformer is characterized by odd harmonics content. The third or fifth harmonic is suitable to provide stabilization. As the third harmonic is often eliminated in transformers (e.g. in a delta winding), the fifth harmonic is more commonly used. Converter transformers also produce a content of odd harmonics which is practically absent in the case of internal short-circuits. The harmonic content which blocks the differential protection is set at address 2071 n. HARMONIC. For example, if the 5th harmonic stabilization is used to avoid trip during overexcitation, 30 % (default setting) are convenient. Nth harmonic restraint operates individually per phase. However, it is also possible – as it is for the inrush restraint – to set the protection such that not only the phase with harmonics content in excess of the permissible value is stabilized but also the other phases of the differential stage > are blocked (”cross-block” function). The duration for which the cross-block function is operative after the differential current threshold has been exceeded is set at address 2072A CROSSB. n.HARM. Setting is in multiples of one cycle. Setting to 0 (default setting) means that the protection can initiate a tripping when the transformer is switched onto a single-phase fault, even if a high harmonics content is present in another phase. When set to ∞, the cross-block function is always effective. If the differential current exceeds a multiple of the rated transformer current stated at address 2073A IDIFFmax n.HM, no nth harmonic restraint takes place.


The parameters of the tripping characteristic are set at addresses 2021 to 2044A. Figure 2-44 illustrates the meaning of the different parameters. The numerical values at the branches are the parameter addresses. Address 2021 I-DIFF> is the pickup value for the differential current. This is the total fault current, regardless of the way it is divided between the windings of the protected transformer. The pickup value is referred to the rated current corresponding to the rated apparent power. For transformers, the setting should be between 0.2 and 0.4. It should be checked during commissioning that the selected pickup value is at least twice the maximum differential current present in steady-state operation. In addition to the pickup threshold I-DIFF>, the differential current is subjected to a second pickup threshold. If this threshold (2031 I-DIFF>>) is exceeded, tripping is initiated regardless of the magnitude of the restraint current (unstabilized high-speed trip stage). This stage must be set higher than the I-DIFF> stage. As a guide: above 1/usc of the transformer. The tripping characteristic forms two more branches (Figure 2-44). Address 2041A SLOPE 1 determines the slope of the first branch, whose starting point is specified in

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the parameter 2042A BASE POINT 1. This branch considers current-proportional error currents. These are mainly transformation errors of the main CTs and, especially, the differential currents which may occur in the final tap changer positions due to the transformer regulation range. This branch of the characteristic limits the stabilization area. The preset slope of 0.25 should be sufficient for regulating ranges up to 20 %. If the transformer has a larger regulated range, the slope must be increased accordingly.

I diff --------------- 10 I NObj

9 2031 8 I–DIFF>>

d

7 6

Trip area 5 c

4

2043 SLOPE 2


3 2 1

2021 I–DIFF>


b a 1

2

3

4

5


Figure 2-44

6

7

8

9

10 11 12 13 14 15 16 17 18 Istab --------------I NObj

Parameters Determining the Shape of the Tripping Characteristic

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 at address 2044A BASE POINT 2 and is referred to the rated power transformer current. The slope is set at address 2043A SLOPE 2. The stability of the relay during current transformer saturation can be influenced by this parameter. A higher slope results in a higher stability. Add-on Stabilization During Current Transformer Saturation

Where very high currents flow through the protected object during external shortcircuits, an add-on stabilization takes effect that is set at address 2057A I-ADD ON STAB. (stabilization in case of saturation). Please note that the stabilizing current is the arithmetical sum of the currents entering and leaving the protected zone, i.e. that it is twice the actually flowing current. The default setting of 4.00 I/InO should be kept. The maximum duration of the add-on stabilization is set at address 2056 T ADD ON-STAB. in multiples of one cycle. This time is the maximum duration of the blocking after leaving the add-on stabilization area in case of high-current external faults. The setting depends, for instance, on the disconnecting time of the upstream protection. The default setting 15 *1P is a good value.

Time Delays

In special cases it may be advantageous to delay the trip signal of the differential protection with an additional time stage. The time delay 2026 T I-DIFF> is started when an internal fault in the generator or the motor has been detected. 2036 T IDIFF>> is the time delay for the trip stage I DIFF>>. A separate time stage is provided

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for each differential protection level and each phase. The dropout delay is linked to the minimum trip command duration that is valid for all protection functions. All setting times are additional time delays which do not include the operating times (measuring time, drop-out time) of the protective function.

2.12.2.3 Settings of the Differential Protection Addr.

Setting Title

Setting Options

Default Setting

Comments

2001

DIFF. PROT.


OFF


2005

INC.CHAR.START

OFF ON

OFF

Increase of Trip Char. During Start

2006

INRUSH 2.HARM.

OFF ON

ON

Inrush with 2. Harmonic Restraint

2007

RESTR. n.HARM.

OFF 3. Harmonic 5. Harmonic

OFF

n-th Harmonic Restraint

2021

I-DIFF>

0.05..2.00 I/InO

0.20 I/InO

Pickup Value of Differential Curr.

2026A

T I-DIFF>

0.00..60.00 sec; ∞

0.00 sec

T I-DIFF> Time Delay

2031

I-DIFF>>

0.5..12.0 I/InO; ∞

7.5 I/InO

Pickup Value of High Set Trip

2036A

T I-DIFF>>

0.00..60.00 sec; ∞

0.00 sec

T I-DIFF>> Time Delay

2041A

SLOPE 1

0.10..0.50

0.25

Slope 1 of Tripping Characteristic

2042A

BASE POINT 1

0.00..2.00 I/InO

0.00 I/InO

Base Point for Slope 1 of Charac.

2043A

SLOPE 2

0.25..0.95

0.50


2044A

BASE POINT 2

0.00..10.00 I/InO

2.50 I/InO


2051A

I-REST. STARTUP

0.00..2.00 I/InO

0.10 I/InO

I-RESTRAINT for Start Detection

2052A

START-FACTOR

1.0..2.0

1.0

Factor for Increasing of Char. at Start

2053

T START MAX

0.0..180.0 sec

5.0 sec

Maximum Permissible Starting Time

2056A

I-ADD ON STAB.

2.00..15.00 I/InO

4.00 I/InO

Pickup for Add-on Stabilization

2057A

T ADD ON-STAB.

2..250 Cycle; ∞

15 Cycle

Duration of Add-on Stabilization

2061

2. HARMONIC

10..80 %

15 %

2nd Harmonic Content in I-DIFF

2062A

CROSSB. 2. HARM 2..1000 Cycle; 0; ∞

3 Cycle

Time for Cross-blocking 2nd Harm.

2071

n. HARMONIC

10..80 %

30 %

n-th Harmonic Content in I-DIFF

2072A

CROSSB. n.HARM

2..1000 Cycle; 0; ∞

0 Cycle

Time for Cross-blocking n-th Harm.

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Addr. 2073A

Setting Title IDIFFmax n.HM

Setting Options 0.5..12.0 I/InO

Default Setting 1.5 I/InO

Comments Limit IDIFFmax of n-th Harm.Restraint

2.12.2.4 Information for the Differential Protection 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

05631 Diff picked up

Differential protection picked up

05644 Diff 2.Harm L1

Diff: Blocked by 2.Harmon. L1





05647 Diff n.Harm L1

Diff: Blocked by n.Harmon. L1





05651 Diff Bl. exF.L1

Diff. prot.: Blocked by ext. fault L1


Diff. prot.: Blocked by ext. fault L2


Diff. prot.: Blocked by ext. fault.L3

05657 DiffCrosBlk2HM

Diff: Crossblock by 2.Harmonic

05658 DiffCrosBlknHM

Diff: Crossblock by n.Harmonic

05666 Diff in.char.L1

Diff: Increase of char. phase L1





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


05674 Diff TRIP L3


05681 Diff> L1

Diff. prot.: IDIFF> L1 (without Tdelay)

05682 Diff> L2


05683 Diff> L3


05684 Diff>> L1

Diff. prot: IDIFF>> L1 (without Tdelay)

05685 Diff>> L2


05686 Diff>> L3


05691 Diff> TRIP

Differential prot.: TRIP by IDIFF>

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F.No.

Alarm

Comments

05692 Diff>> TRIP

Differential prot.: TRIP by IDIFF>>

05620 Diff Adap.fact.

Diff: adverse Adaption factor CT

05713 Diff CT-S1:

Diff. prot: Adaptation factor CT side 1

05714 Diff CT-S2:

Diff. prot: Adaptation factor CT side 2

05701 Diff L1:

Diff. current in phase L1 at trip

05702 Diff L2:


05703 Diff L3:


05704 Res L1:

Restr. current in phase L1 at trip

05705 Res L2:


05706 Res L3:


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2.13


General

The earth current differential protection detects earth faults in generators and transformers with a low-ohmic or solid starpoint earthing. It is selective, and more sensitive than the classical differential protection (see Section 2.12). A typical application of this protection function are configurations where multiple generators are connected to one busbar and one generator has a low-ohmic earthing. Another application would be transformer windings in wye connection. For applications such as auto-transformers, starpoint earthing transformers and shunt reactors, Siemens recommends to use the 7UT612 protective relay instead. For high-ohmic earthing of generators, the earth fault protection function (Section 2.26) is used. Figure 2-45 shows two typical implementations. In connection scheme 1, the zero sequence current is calculated from the measured phase currents, whereas the starpoint current is measured directly. This application is the version for transformers and for the generator with direct (low-ohmic) earthing. In connection scheme 2, both zero sequence currents are calculated from the measured phase currents. The protected object is located between the current transformers. This measuring method should be used for generators in busbar connection, where multiple generators feed the busbar and any one of the generators is earthed.

Connection scheme 1

Connection scheme 2

Protected object

Protected object

Figure 2-45 Connection Schemes of the Earth Current Differential Protection


98

As can be seen in Figure 2-45, there are 2 possible implementations of the earth fault differential protection which differ only in their method of determining the zero sequence current. This is shown in Figure 2-46, along with the definition of the current direction. The general definition is: Reference arrows run in positive direction to the protected object.

7UM62 Manual C53000-G1176-C149-3


Protected object: Generator

iL1S1

iL1S2

iL2S1

iL2S2

iL3S1

iL3S2

3I 01

1

iEE2

3I 02

Figure 2-46 Connection Scheme and Definition of Current Vectors

In both measuring principles, there is a vector addition of the phase currents on the line side (always side 1 in the 7UM62), which yields the zero sequence current. The rule of calculation for side 1 is: 3I01 = IL1S1 + IL2S1 + IL3S1 For the second zero sequence current, two methods of determination are possible: Method 1 is to measure it directly as the starpoint current at input IEE2 (ISt = IEE2). Method 2 is to calculate the zero sequence current from the CTs on the starpoint side (always side 2 in the 7UM62). The pertinent formulae are: 3I02 = ISt = IEE2 or 3I02 = IL1S2 + IL2S2 + IL3S2 When an earth fault occurs in the protected zone (Figure 2-46 fault location 1), there is always a starpoint current ISt or zero sequence current flowing through the CTs of side 2 (3I02). Depending on the network earthing conditions, there may also be an earthing current (3I01) flowing through the CTs of side 1 to the fault location (dashed arrow). Due to the definition of the current direction, however, the zero sequence current 3I01 is more or less in phase with the starpoint current. When an earth fault occurs outside the protected zone (Figure 2-47 fault location 2), there is also a starpoint current ISt or zero sequence current flowing through the CTs of side 2 (3I02), as well as a zero sequence current flowing through the CTs of side 1 (3I01). The zero sequence current must be the same at all three possible measurement locations. As the current flowing into the protected object is defined as positive, the zero sequence current flowing on side 1 (3I01) is in phase opposition to the starpoint current ISt or to the calculated zero phase current of side 2 (3I02). iL1S1

Protected object: Generator

iL1S2

iL2S1

iL2S2

iL3S1

iL3S2

2

3I 01

iEE2

3I 02

Figure 2-47 Example of an External Fault

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When an external non-earthed fault causes a heavy current to flow through the protected zone, differences in the magnetic characteristics of the phase current transformers under conditions of saturation may cause a significant summation current which may simulate an earth current flowing into the protected zone. Measures must be taken to prevent this current from causing a trip. The same may happen if, for example, significant loads with a high inductive component (and thus high time constants), such as motors or transformers, are switched on. The earth current differential protection provides a number of restraint features which differ significantly from conventional restraint methods (see margin heading „Restraining Measures“). Evaluation of Measured Quantities

The earth current differential protection compares the fundamental wave of the zero currents on both sides (3I01 and 3I02) and calculates from them the differential and the restraint current. I0-Diff = | 3I01 + 3I02 | I0-Res = | 3I01 | + | 3I02 | Depending on the application, the current 3I02 may be the calculated zero sequence current of side 2 or the directly measured starpoint current ISt. Under no-fault conditions, and with ideal CTs, the zero sequence currents would be zero, and consequently the differential and the restraint current would be zero as well. To eliminate the influence of CT errors, the restraint is determined by the characteristic (see Figure 2-48). In case of an external earth fault, the differential current is zero or small, and the restraint current is twice the fault current. The measured quantities are inside the restraint zone. An internal earth fault, on the other hand, causes a fairly equal differential and restraint current, which are both in the trip zone (along the dashed line). The pickup threshold is set with the I-REF> stage.

I0Diff with [I/InO] 1

Tripping zone Restraint zone Zone not considered

I-EDP> 1

I 0Res with [I/InO]

Figure 2-48 Tripping and Restraint Characteristic

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In applications with direct measurement of the starpoint current (e.g. earth current differential protection for transformers), the starpoint current is queried to the evaluation of the characteristics. This provides additional restraint against CT problems such as wrong zero sequence current modeling of the phase current transformers on side 1. The starpoint current must also have exceeded the pickup current I-REF> (see the logic diagram in Figure 2-50). In order to compensate differences in the primary CT current ratings, the currents are matched to the current ratings of the protected object. Restraining Measures

The purpose of the earth current differential protection is the detection of low-current faults. This implies a sensitive setting. A significant source of errors of the protection function are differences in the transient magnetic characteristics of the phase CTs. Factors to be considered here are different DC transformation characteristics and the behaviour under conditions of saturation. Spurious tripping of the protection in the presence of external earth faults must be avoided. One elementary rule for this is the use of phase current transformers that are balanced to one another, so that their CT error (resulting zero sequence current) under steadystate conditions is minimized. Further restraining measures include: • Additional evaluation of the starpoint current (see above) Only in the presence of an earth fault can a current flow through the starpoint CTs. This helps to avoid under no-fault conditions spurious tripping due to transformation errors of the phase current transformers. This measure is also effective for faults without earth involvement. A prerequisite for using this measure is the presence of a starpoint CT in the application. It cannot be used for most generators in busbar connection. • Evaluation of the zero sequence current direction This monitoring functions aims at preventing spurious tripping in the presence of external earth faults. It does so by evaluation of the zero sequence current direction. Under ideal conditions, the currents are defined to be in phase in the presence of an internal earth fault, and in phase opposition in the presence of an external earth fault. The threshold angle is 90°. Figure 2-49 shows that monitoring is divided into 2 zones. Where fault conditions are unambiguous, tripping is immediately released (zone I) or blocked (zone III). In zone II, an additional measurement is performed before a decision is taken. Where the zero phase currents are too small (zone IV), the direction criterion is ineffective, and 0° is assumed.

90 ° 115 °

65 °

II III 180 °

I IV

| ∆ϕ | = 0 °

Figure 2-49 Operating Ranges of the Direction Criterion

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• Phase current monitoring To preclude spurious tripping due to CT saturation in the presence of external faults, the protection function is blocked as soon as a maximum phase current is reached. To do so, the phase currents of side 1 are monitored. As soon as one phase current exceeds the threshold, the blocking takes effect. This blocking is no drawback, since high-current faults are sufficiently controlled by other protection functions such as differential protection, impedance protection and overcurrent protection. • Zero voltage monitoring Where the phase current transformers model zero sequence currents on the secondary side after loads have been switched in, and where there is no direct evaluation of the starpoint current, zero voltage monitoring should be used. It also provides additional restraint in the presence of external faults without earth involvement. The zero voltage is calculated from the phase-to-earth voltages. On detection of a zero voltage, a release signal is output. Logic

The logic interconnection of all signals and the most important settings, as well as the indications output, are shown in Figure 2-50. The function can be blocked with the input “>BLOCK REF”. This input also allows to block other features using the CFC, for instance if the measured zero voltage is to be injected via the UE input. This is necessary if the voltage inputs are connected to a voltage transformer in V connection (open delta connection). Figure 2-50 shows the blocking of the phase currents and their release on the basis of the calculated zero voltage. This is followed by the monitoring of the operating characteristic with possibly an additional query of the starpoint current, and the angle release. When all conditions are met, the earth current differential protection picks up. The subsequent timer T I-REF> is usually set to zero.

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5812 REF BLOCKED

5803 >BLOCK REF 2102 REF I> BLOCK

5817 REF picked up

1) IL1Sm 5840 REF I> blocked

1)

2112 T I-REF>

OR

IL2Sm

&

5821 REF TRIP

Tripping matrix

& Tmin TRIP CMD

1) IL3Sm

5841 REF U0> releas.

2103 REF U0>RELEASE U0 "1"

1.0...100.0 V OR

0.0 V 2110 I-REF> 2113 SLOPE

2114 BASE POINT I0DIFF I0RES I02

Pickup decision, DIFF/RESTR characteristic with I02 threshold criterion

| ∆ϕ |

1)

Use in generators: Use in transformers:

ILxSm always side 1 ILxSm depending on side allocation

Angle difference evaluation

Figure 2-50 Logic Diagram of the Earth Current Differential Protection


A precondition for the operation of the earth current differential protection is that during the configuration of the scope of functions (Section 2.2) the correct selection for the application in hand has been made at address “0121 REF PROT.”. If the protected object is a generator, the user can select either direct measurement of the starpoint current via IEE2 (Gen. with IEE2), or current calculation (Gen. w. 3I0-S2). For transformers, the method used is always direct measurement of the zero sequence current, but the user can choose the allocation of sides (Transformer S1 or Transformer S2). A number of parameter settings must be made in Power System Data 1. They are required for normalization and for the definition of the current direction (see also Sections 2.3 and 2.12). If the IEE2 input is used, the protection device must be told the neutral transformer transformation ratio (prim./sec.) and the terminal of the earthingside CT to which the IEE2 input is connected (see comments in Section 2.3).

Note: When using the IEE2 input, it must be kept in mind that this is a sensitive current input. The current amplitude is limited to approx. √2 1.6 A. The neutral transformer should have a rated secondary current of 1 A. Where a 5 A transformer is used, a commensurately higher transformation ratio must be chosen (preferably factor 5).

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Address 2101 REF PROT. is used to switch the function ON or OFF, or to block only the trip command (Block relay). Note: When the device is delivered, the earth current differential protection is set to OFF. This is because this protection must not be used before at least the allocation and polarity of the CTs have been correctly set. Without these settings, the device may show unpredictable behaviour (including spurious tripping)!

Pickup Values

The sensitivity of the protection is determined by the setting of I-REF> (address 2110). This is the earth fault current flowing in from the starpoint of the protected object (transformer, generator), and in some cases also from the network. This value should be chosen on the basis of the most unfavourable case, i.e. fault currents entering from one side only. The current set refers to the nominal current of the protected object or the protected side. The limit of sensitivity will in most cases be defined by the CTs. A setting between 0.1 and 0.15 I/InO is a good value. For the operating characteristic, the default settings can be used. If necessary, these settings can be changed with the DIGSI communication software. The advanced parameters define the slope (2113A SLOPE) and the base point (2114A BASE POINT) of the characteristic. To stabilize the protection function, address 2102 can be set to blocking by the phase current (REF I> BLOCK). As a rule of thumb, the pickup value should never be more than twice the nominal current. With low-ohmic starpoint earthing, the formula is: nominal current + earth current resulting from the starpoint resistance. The zero voltage release depends on the operating range of the protection function. 95 % of a generator stator winding is a good value. Therefore, the secondary-side value has been set to 5.0 V (2103 REF U0>RELEASE). Where the zero voltage release is not used, it must be set to 0.0 V. Note: For the protection function, the zero voltage calculated from the phase-to-earth voltages has been multiplied with √3, which corresponds to the voltage present in a broken delta winding. No settings need to be made for the angle release and the additional evaluation of the directly measured starpoint current (where used). For special applications, it may be advantageous to delay the trip command of the protection. This can be done by setting an additional delay time (address 2112 T IREF>). This delay time is normally set to 0. A minimum trip command duration has been set for all protection functions in common (see Section 2.3.2 under “Trip Command Duration”).

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7UM62 Manual C53000-G1176-C149-3


2.13.2.1 Settings of the Earth Current Differential Protection Addr.

Setting Title

Setting Options

Default Setting

Comments

2101

REF PROT.


OFF

Restricted Earth Fault Protection

2102

REF I> BLOCK

1.0..2.5 I/InO

1.5 I/InO

REF Pickup of Phase Current Blocking

2103

REF U0>RELEASE

1.0..100.0 V; 0

5.0 V

REF Pickup of U0> Release

2110

I-REF>

0.05..2.00 I/InO

0.10 I/InO

I-REF> Pickup

2112

T I-REF>

0.00..60.00 sec; ∞

0.00 sec

T I-REF> Time Delay

2113A

SLOPE

0.00..0.95

0.25

Slope of Charac. I-REF> = f(I0Rest)

2114A

BASE POINT

0.00..2.00 I/InO

0.00 I/InO

Base Point for Slope of Characteristic

2.13.2.2 Information for the Earth Current Differential Protection 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

05840 REF I> blocked

REF is blocked by phase current

05841 REF U0> releas.

REF Release by U0>

05817 REF picked up

REF protection picked up

05821 REF TRIP

REF protection TRIP

05836 REF Adap.fact.

REF: adverse Adaption factor CT

05847 I0-Diff:

I0-Diff at REF-Trip

05848 I0-Res:

I0-Restraint at REF-Trip

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Functions

2.14


General

The underexcitation or loss of field protection protects a synchronous generator/motor from asynchronous operation in the event of a malfunction in the excitation system and from local overheating of the rotor. Furthermore, it ensures that the network stability is not endangered due to the underexcitation of large synchronous generators.

2.14.1 Functional Description Underexcitation Determination

In order to detect underexcitation, the unit processes all three terminal phase currents and all three terminal voltages to form the stator circuit criterion. It also processes the excitation voltage and/or the signal from an external excitation voltage monitor to form the rotor circuit criterion. For the stator circuit criterion, the reciprocal of the impedance (equal the admittance) is calculated from the positive sequence system of the currents and voltages. In the admittance plane, the stability limit of the machine is independent of the voltage: thus, the protection characteristic can be optimally matched to the stability characteristic of the machine. By evaluating the positive sequence system, underexcitation conditions are reliably detected even during asymmetrical faults within or outside of the machine.

Characteristics

Figure 2-51 shows the loading diagram of the synchronous generator in the admittance plane (P/U2; Q/–U2) with the steady-state stability limit which intersects the reactive axis in close proximity to 1/Xd (reciprocal value of the synchronous direct reactance). Iw P ------- = ------- = G 2 U U

I EN -------UN IN ------UN

ϕN ϑN underexcited

overexcited

1 Xd

---------

UN

Rated voltage

Iw

Active current

IN

Nominal Current

Ib

Reactive current

IEN

Rated excitation current

G

Conductance

ϑN

Rated pole angle (rotor angle)

B

Susceptance

ϕN

Rated load angle

P

Active power

Xd

Synchronous reactance

Q

Reactive power

U

Terminal voltage

Figure 2-51

106

–I b –Q ------- = -------- = –B 2 U U

Admittance Diagram of Turbo Generators

7UM62 Manual C53000-G1176-C149-3


Note: The generator diagram can be visualized in more than one way. Figure 2-51 shows a form that is quite common at Siemens Power Generation, with a rotation of 90° and mirroring at the active power axis.

The 7UM62 underexcitation protection provides three independent characteristics which can be freely combined. As illustrated in Figure 2-52, it is, for example, possible to model the static machine stability characteristic by means of two partial characteristics with the same time delays (T CHAR. 1 = T CHAR. 2). The partial characteristics are distinguished by the corresponding distance from the zero point (1/ xd CHAR. 1) and (1/xd CHAR. 2) the corresponding inclination angle α1 and α2. If the resulting characteristic (1/xd CHAR.1)/α1; (1/xd CHAR.2)/α2 is exceed (in Figure 2-52 to the left side), a delayed warning (e.g. by 10 s) or a trip signal are transmitted. The delay is necessary to ensure that the voltage regulator is given enough time to increase the excitation voltage.

G [p.u.] Charact. 2 Characteristic 1

Charact. 3

E/U

I/U α1

B [p.u.]

α3

α2

δ

1/xd CHAR.1 1/xd CHAR.2 1/xd CHAR.3

where P ⁄ SN G [p.u.] = -----------------------2 ( U ⁄ UN )

Conductance per unit

–Q ⁄ S N B [p.u.] = -----------------------2 ( U ⁄ UN )

Susceptance per unit

Figure 2-52

Stator Criterion: Pick–Up Characteristic in Admittance Diagram

A further characteristic (1/xd CHAR.3 /α3 can be matched to the dynamic stability characteristic of the synchronous machine. Since stable operation is impossible if this characteristic is exceeded, immediate tripping is required in this case (T CHAR 3 time stage).

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107

Functions

Excitation Voltage Request

In case of a faulty voltage regulator or a failure of the excitation voltage, it is possible to switch up with a short delay (time stage T SHRT Uex<, e.g. 1.5 s). To do so, the device must either be informed via a binary input of the excitation voltage failure, or the excitation voltage must be fed in via measuring transducer TD3 and a voltage divider, provided that at address 3012 EXCIT. VOLT. the excitation voltage request via measuring transducer has been switched ON. As soon as the excitation voltage drops below a settable minimum 3013 Uexcit. <, short-time tripping is initiated. Instead of the excitation voltage detection, or even in addition to it, the signal of an external excitation voltage monitoring feature can be fed in via a binary input. Here again, high-speed tripping is initiated as soon as a failure of the excitation voltage is signalled.

Low-Pass Filter

As the excitation DC voltage may contain a large amount of superimposed harmonics (e.g. owing to thyristor control), an analog low pass is provided on the C-I/O-6 board in addition to the integrated digital filter. This low pass damps especially multiples of the sampling frequency, which cannot be suppressed sufficiently by the digital filter. The jumper settings for activating this filter are described in Section 3.1.3. When the 7UM62 is delivered from the factory, the filter is on. The jumper setting must match the setting of the parameter 0297 TRANSDUCER 3 (see Power System Data, Section 2.3.2). If they do not match, an alarm is output, the device is reported faulty and not operative.

Undervoltage Blocking

The admittance calculation requires a minimum measurement voltage. During a severe collapse (short-circuit) or failure of the stator voltages, the protection is therefore blocked by an integrated a.c. voltage monitor whose pickup threshold 3014A Umin is set on delivery to 25 V. Figure 2-53 illustrates the logic diagram of the underexcitation protection.

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7UM62 Manual C53000-G1176-C149-3


3002 1/xd CHAR. 1 3003 ANGLE 1

3004 T CHAR. 1

FNo. 05344

Exc<1 TRIP

& FNo. 05329

>Char. 1 BLK. 3005 1/xd CHAR. 2 3006 ANGLE 2

3007 T CHAR. 2

FNo. 05345

Tripping matrix

Exc<2 TRIP

& FNo. 05330

>Char. 2 BLK. 3008 1/xd CHAR. 3 3009 ANGLE 3

3010 T CHAR 3

FNo. 05343

Exc<3 TRIP

& FNo. 05327 FNo. 05337

>Char. 3 BLK.

OR

Exc< picked up 3011 T SHRT Uex<

3013 Uexcit. <

FNo.05336

TMin TRIP CMD

&

>Uexc fail.

FNo. 05346

Exc
OR FNo. 05328

>Uexc fail.

3014A Umin

OR FNo. 05323

FNo. 05334

>Exc. BLOCK

Exc. U< blk FNo. 05332

Excit.BLOCKED

Figure 2-53

Logic diagram of the Underexcitation Protection


The underexcitation protection is only effective and accessible if this function was set within the framework of the protective function configuration (section 2.2, address 0130, UNDEREXCIT. = Enabled). Set Disabled if the function is not required. At the address 3001 UNDEREXCIT. the user can switch the function ON or OFF, or only block the trip command (Block Relay). The correct power system data is required according to section 2.3. This is a prerequisite for the setting of the underexcitation protection.

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109

Functions

The trip characteristics of the underexcitation protection in the admittance value diagram are composed of straight lines which are respectively defined by their conductance section 1/xd (=coordinate distance) and their inclination angle α. The straight lines (1/xd CHAR.1)/α1 (characteristic 1) and (1/xd CHAR.2)/α2 (characteristic 2) form the static underexcitation limit (see figure 2-54). (1/xd CHAR.1) corresponds to the reciprocal value of the related synchronous direct reactance. UN 1 1 ----- = ------ ⋅ ---------------xd Xd 3 ⋅ I N If the voltage regulator of the synchronous machine has underexcitation limiting, the static characteristics are set in such a way that the underexcitation limiting of the voltage regulator will intervene before characteristic 1 is reached (see figure 2-56).

G [p.u.] 2

3

1

α1

B [p.u.]

α2

α3

1/xd CH.1

λ2 CH.2 1/xd

λλ2 3CH.3 1/xd

Figure 2-54

CharacteristicCurve Values

110

Underexcitation Protection Characteristics in the Admittance Plane

If the generator power diagram (Figure 2-55) in its preferred representation (abscissa = positive reactive power; ordinate = positive active power) is transformed to the admittance plane (division by U2), the tripping characteristic can be matched immediately to the stability characteristic of the machine. If the axis sizes are divided by the nominal apparent power, the generator diagram is indicated per unit (this diagram corresponds to a per unit representation of the admittance diagram).

7UM62 Manual C53000-G1176-C149-3


.

U = UN = 6300 V

P/SN

I = IN

1,4

SN = 5270 kVA fN = 50.0 Hz nN = 1500 RPM cos ϕ = 0.800 xd = 2.470 xq = 1.400

1,2 Limit of the stator 1,0 winding heating

Measuring point

0,8

0,6

0,4 Limit of the stator winding heating

Phase angle

”Response circle”

0,2 0

–0,8

–0,6

–0,4

–0,2

0

0,2

0,4

underexcited

Figure 2-55

0,6

0,8

Q/SN

overexcited

Power Diagram of a Salient-Pole Generator, Indicated per Unit

The primary setting values can be read out directly from the diagram. The related values must be converted for the protection setting. The same conversion formula can be used if the protection setting is calculated with the predefined synchronous direct reactance. I Nmach U N VT prim 1 1 ------------- = ----------------- ⋅ ------------------ ⋅ -------------------------x dsec x dmach U Nmach I N CT prim with

xdsec

Secondary per unit synchronous direct reactance,

xd mach

Per unit synchronous direct reactance of machine,

IN mach

Rated machine current

UN mach

Rated machine voltage

UN VT prim

Primary rated voltage of the voltage transformers

IN CT prim

Primary rated current of the current transformers

Instead of 1/xd mach the approximate value IK0/IN can be used (with IK0 = short-circuit current at no-load excitation).

Setting example: Machine:

Current transformers:

7UM62 Manual C53000-G1176-C149-3

UN mach

= 6.3 kV

IN mach

= SN/√3 UN = 5270 kVA/√3 ⋅ 6.3 kV = 483 A

xd mach

= 2.47 (= machine manufacturer’s indication in Fig. 2-55)

IN CT prim

= 500 A

111

Functions

Voltage transformer: UN VT prim

= 6.3 kV

1 1 483 A 6300 V ------------- = ----------- ⋅ ------------------- ⋅ ------------------- = 0.39 x dsec 2.47 6300 V 500 A Multiplied by a safety factor of about 1.05, the setting value 1/xd CHAR. 1 at address 3002 results. For α1, the angle of the underexcitation limiting of the voltage regulator is selected or the inclination angle of the machine stability characteristic is used. The setting value ANGLE 1 is typically situated between 60 ° and 80 °. In most cases, the machine manufacturer prescribes a minimum excitation value for small active powers. For this purpose, characteristic 1 is cut from characteristic 2 in case of a low active-power load. Consequently, 1/xd CHAR. 2 is set to about 0.9 ⋅ (1/xd CHAR. 1), the ANGLE 2 to 90 °. The kinked tripping limit according to figure 2-54 (CHAR. 1, CHAR. 2) results in this way, if the corresponding time delays T CHAR. 1 and T CHAR. 2 of both characteristics are set equally. Characteristic 3 serves to adapt the protection to the dynamic machine stability limits. If there are no precise indications, the user must select a value 1/xd CHAR. 3 situated approximately between the synchronous direct reactance xd and the transient reactance xd'. However, it should be greater than 1. A value between 80 ° and 110 ° is usually selected for the corresponding ANGLE 3, which ensures that only a dynamic instability can lead to a pickup with characteristic 3. The associated time delay is set at address 3010 T CHAR 3 to the value suggested in Table 2-6. Underexcitation limitation (controller)

G [p.u.] Simulated characteristic consists of characteristic 1 and char. 2

IE ------UN IN ------UN θΝ

B [p.u.] 1 1.05 ⋅ ------xd

Figure 2-56

Time Delays

ϕΝ

1-----xd

Admittance Diagram of a Turbo Generator

If the static limit curve consisting of the characteristics 1 and 2 is exceeded, the voltage regulator must first have the opportunity of enhancing the excitation. For this reason, a warning message due to this criterion is ”long-time” delayed (at least 10 s for 3004 T CHAR. 1 and 3007 T CHAR. 2). If the excitation voltage is missing or too low, the stator criterion picks up as well, provided that the excitation voltage request feature has been switched ON at address 3012 EXCIT. VOLT., and the voltage has dropped below the threshold Uexcit. < set at address 3013, or the absence of the excitation voltage has been signalled to the device by a binary input. In all these cases tripping is possible with a short delay.

112

7UM62 Manual C53000-G1176-C149-3


This feature is set at address 3011 T SHRT Uex<. The following messages and trip commands are typically assigned: Table 2-6

Setting the Underexcitation Protection

Characteristic 1 and 2 static not delayed stability

Annunciation: Err < PU

Characteristic 1 and 2 static long-time delayed Trip stability T CHAR. 1 = T CHAR. 2 Exc<1 TRIP / Exc<2 TRIP ≈ 10 s Characteristic 1 and 2 excitation voltage failure

short–time delayed T SHRT Uex< ≈ 1.5 s

Trip Exc< Uexc < TRIP

Characteristic 3 dynamic stability

short–time delayed T CHAR 3 ≈ 0.5 s

Trip Exc<3 TRIP

Note: If very short time delays are selected, dynamic balancing procedures may cause unwanted operations. For this reason, it is recommended to set time values of 0.05 s or higher. Excitation Voltage Request

The excitation voltage monitoring feature is set to approx. 50 % of the no-load excitation voltage. If the generator is used for phase-shifting, an even lower threshold must be chosen, depending on the application in had. It should also be noted that normally a voltage divider is connected between the device and the excitation voltage. U Exc 0 SettingxU Exc < ≈ 0.50 ⋅ ---------------- [ V ] kU where UExc kVD

No-load excitation voltage, Transformation ratio of voltage divider

Example: UExc N

= 110 V

UExc 0

= 40 V

kVD

= 10: 1

40 V Setting U Exc < ≈ 0.50 ⋅ -----------10

= 2.0 V (address 3013)

2.14.2.1 Settings of the Underexcitation (Loss-of-Field) Protection Addr.

Setting Title

Setting Options

Default Setting

Comments

3001

UNDEREXCIT.


OFF


3011

T SHRT Uex<

0.00..60.00 sec; ∞

0.50 sec

T-Short Time Delay (Char. & Uexc<)

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113

Functions

Addr.

Setting Title

Setting Options

Default Setting

Comments

3012

EXCIT. VOLT.

ON OFF

OFF

State of Excitation Volt. Supervision

3013

Uexcit. <

0.50..8.00 V

2.00 V

Excitation Voltage Superv. Pikkup

3014A

Umin

10.0..125.0 V

25.0 V

Undervoltage blocking Pickup

3002

1/xd CHAR. 1

0.25..3.00

0.41

Conductance Intersect Characteristic 1

3003

ANGLE 1

50..120 °

80 °

Inclination Angle of Characteristic 1

3004

T CHAR. 1

0.00..60.00 sec; ∞

10.00 sec

Characteristic 1 Time Delay

3005

1/xd CHAR. 2

0.25..3.00

0.36


3006

ANGLE 2

50..120 °

90 °


3007

T CHAR. 2

0.00..60.00 sec; ∞

10.00 sec


3008

1/xd CHAR. 3

0.25..3.00

1.10


3009

ANGLE 3

50..120 °

90 °


3010

T CHAR 3

0.00..60.00 sec; ∞

0.30 sec


2.14.2.2 Information for the Underexcitation (Loss-of-Field) Protection F.No.

Alarm

Comments

05323 >Exc. BLOCK

>BLOCK underexcitation protection

05329 >Char. 1 BLK.

>BLOCK underexc. prot. char. 1

05330 >Char. 2 BLK.


05327 >Char. 3 BLK.


05328 >Uexc fail.

>Exc. voltage failure recognized

05331 Excit. OFF

Underexc. prot. is switched OFF

05332 Excit.BLOCKED

Underexc. prot. is BLOCKED

05333 Excit.ACTIVE

Underexc. prot. is ACTIVE

05334 Exc. U< blk

Underexc. prot. blocked by U<

05336 Uexc failure

Exc. voltage failure recognized

05337 Exc< picked up

Underexc. prot. picked up

05344 Exc<1 TRIP

Underexc. prot. char. 1 TRIP

05345 Exc<2 TRIP


05343 Exc<3 TRIP


05346 Exc
Underexc. prot. char.+Uexc< TRIP

114

7UM62 Manual C53000-G1176-C149-3


2.15


General

Reverse power protection is used to protect a turbo-generator unit in case of failure of energy to the prime mover. In this case the synchronous generator runs as a motor and drives the turbine, taking the required motoring energy from the network. This condition leads to overheating of the turbine blades and must be interrupted within a short time by tripping the network circuit-breaker. For the generator, there is the additional risk that in case of a malfunctioning residual steam pass (defective stop valves) after the switching off of the circuit breakers, the turbine-generator-unit is speeded up, thus reaching an overspeed. For this reason, the system isolation should only be performed after the detection of active power input into the machine.

2.15.1 Functional Description Reverse Power Determination

The reverse power protection of the7UM62 precisely calculates the active power from the symmetrical components of the fundamental waves of the voltages and currents by averaging the values of the last 16 cycles. The evaluation of only the positive phase-sequence systems makes the reverse power determination independent of current and voltage asymmetries and corresponds to the actual load of the drive end. The calculated active power value corresponds to the overall active power. By taking the error angles of the instrument transformers into account, the active power component is calculated even with very high apparent powers and low power factor (cos ϕ). The correction is performed by a W0 constant correction angle (see section 2.3), determined during the commissioning of the protective relay in the system. The correction angle is set at Power System Data 1 (see Section 2.3).

Pickup Seal-In Time

To ensure that frequently occurring short pickups can cause tripping, it is possible to perform a selectable prolongation of these pickup pulses at parameter 3105A THOLD. Each positive edge of the pickup pulses triggers this time stage again. For a sufficient number of pulses, the pickup signals adds up and become longer than the time delay.

Trip Signal

For bridging a perhaps short power input during synchronization or during power swings caused by system faults, the trip command is delayed by a selectable time TSV-OPEN. In case of a closed emergency tripping valve, a short delay is, however, sufficient. By means of entering the emergency tripping valve position via a binary input, the short time delay T-SV-CLOSED becomes effective under an emergency tripping condition. The time T-SV-OPEN is still effective as back-up stage. It is also possible to block tripping via an external signal. Figure 2-57 illustrates the logic diagram of the reverse power protection.

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115

Functions

FNo. 05096

Pr picked up 3102 P> REVERSE

3105A T-HOLD

3103 T-SV-OPEN

&

FNo. 05097

Pr TRIP

Tripping matrix

3104 T-SV-CLOSED

& FNo. 05098

Pr+SV TRIP FNo.05083

FNo. 05092

>Pr BLOCK

Pr BLOCKED

TMin TRIP CMD

FNo.05086

>SV tripped

Figure 2-57

Logic Diagram of the Reverse Power Protection


The reverse power protection is only effective and accessible if this function was set within the framework of the protective function configuration (section 2.2, address 0131, REVERSE POWER = Enabled. Set Disabled if the function is not required. The address 3101 REVERSE POWER, serves to switch the function ON- or OFF or to block only the trip command (Block Relay). In case of a reverse power, the turbine set must be disconnected from the system as the turbine operation is not permissible without a certain minimum steam throughput (cooling) or, in case of a gas turbine set, the motor load would be too heavy for the network.

Pick-Up Values

The level of the active power input is determined by the friction losses to be overcome and are situated in the following range, depending on the individual system: • Steam turbines: PReverse/SN ≈ 1 % to 3 % • Gas turbines: PReverse/SN ≈ 1 % to 3 % • Diesel drives: PReverse/SN > 5 % The setting can be acquired through a primary test. The reverse power should be measured with the relay (Section 3.4.10.2). The user should select a setting of 0.5 times the value of the measured motoring energy. This value can be found at the per cent operational measured values. The feature to correct angle faults of the current and voltage transformers should be used especially for very large machines with a particularly low motoring energy (see sections 2.3 and 3.4.10.2). The pickup value 3102 P> REVERSE is to be set in percent of the secondary rated apparent power.

116

7UM62 Manual C53000-G1176-C149-3


SNsec = √3 ⋅ UNsec ⋅ INsec. If the primary motoring energy is known, it must be converted to secondary quantities using the following formula: P sec P mach U N mach I N mach Setting = --------------- = -------------------- ⋅ --------------------- ⋅ -----------------S Nsec S N mach U N prim I N prim

with

Psec

Secondary active power according to setting value

SNsec

Secondary rated power = √3 ⋅ UNsec ⋅ INsec

Pmach

Active power of machine according to setting value

SN mach Rated apparent power of machine UN mach Rated voltage of machine IN mach

Rated current of the machine

UN prim

Primary rated voltage of voltage transformers

IN prim

Primary rated current of current transformers

Pickup Seal-In Time

The 3105A T-HOLD pickup seal-in time serves to extend pulsed pickups to the parameterized minimum duration.

Time Delays

If reverse power without emergency tripping is used, a corresponding time delay must be considered to bridge short reverse power states after synchronization or power swings subsequent to system faults (e.g. 3-pole short circuit). Usually, a time delay 3103 T-SV-OPEN = approx. 10 s is set. Under emergency tripping conditions, the reverse power protection performs a shorttime delayed trip subsequent to the emergency tripping via an oil-pressure switch or a position switch at the emergency trip valve. Before tripping, it must be ensured that the reverse power is only caused by the missing drive power at the turbine side. A time delay is necessary to bridge the active power swing in case of sudden valve closing, until a stationary active-power value is set. A 3104 T-SV-CLOSED time delay of about 1 to 3 s is sufficient for this purpose, whereas a time delay of about 0.5 s is recommended for gas turbine sets. The set times are additional time delays not including the operating times (measuring time, drop-out time) of the protective function.

2.15.2.1 Settings of the Reverse Power Protection Addr.

Setting Title

Setting Options

Default Setting

Comments

3101

REVERSE POWER OFF ON Block relay for trip commands

OFF


3102

P> REVERSE

-30.00..-0.50 %

-1.93 %

P> Reverse Pickup

3103

T-SV-OPEN

0.00..60.00 sec; ∞

10.00 sec

Time Delay Long (without Stop Valve)

3104

T-SV-CLOSED

0.00..60.00 sec; ∞

1.00 sec

Time Delay Short (with Stop Valve)

3105A

T-HOLD

0.00..60.00 sec; ∞

0.00 sec

Pickup Holding Time

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117

Functions

2.15.2.2 Information for the Reverse Power Protection F.No.

Alarm

Comments

05083 >Pr BLOCK

>BLOCK reverse power protection

05086 >SV tripped

>Stop valve tripped

05091 Pr OFF

Reverse power prot. is switched OFF

05092 Pr BLOCKED

Reverse power protection is BLOCKED

05093 Pr ACTIVE

Reverse power protection is ACTIVE

05096 Pr picked up

Reverse power: picked up

05097 Pr TRIP

Reverse power: TRIP

05098 Pr+SV TRIP

Reverse power: TRIP with stop valve

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7UM62 Manual C53000-G1176-C149-3


2.16


General

The machine protection 7UM62 includes an active power supervision which monitors whether the active power falls below one set threshold, and whether a separate second set threshold is exceeded. Each of these functions can initiate different control functions. When, for example, with generators operating in parallel, the active power output of one machine becomes so small that other generators could take over this power, then it is often appropriate to shut down the lightly loaded machine. The criterion in this case is that the “forward” power supplied into the network falls below a certain value. In some applications it can be desirable to output a control signal if the active power output rises above a certain value. For example, an industrial network which has certain measures of its own generation is coupled via a coupling circuit breaker with a HV utility network and should be decoupled when a fault in the utility network is not cleared within a critical time. As a criterion for decoupling, underfrequency, undervoltage, overcurrent, power direction, or combinations of these can be used. As a result, the 7UM62 can also be used for network decoupling.

2.16.1 Functional Description Active Power Measuring

For power measurement, two measurement methods are available. Depending on the application either high-speed measurement or high-accuracy measurement (average about 16 cycles) may be selected. High-speed measurement is suitable e.g. for network decoupling. The device calculates the active power from the positive sequence systems of the generator currents and voltages. This value is compared with the set values. Each stage can be blocked individually, as can be the complete forward active power supervision, via binary inputs. Figure 2-58 shows the logic diagram of the forward active power supervision. FNo. 05126

Pf< picked up

3202 Pf<

3204 T-Pf<

&

FNo. 05128

FNo. 05116

Pf< TRIP

>Pf< BLOCK

Tripping matrix

FNo. 05127

Pf> picked up 3203 Pf>

3205 T-Pf>

& FNo. 05129

FNo. 05117

Pf> TRIP

>Pf> BLOCK FNo. 05113

FNo. 05122

>Pf BLOCK

Pf BLOCKED

Figure 2-58

7UM62 Manual C53000-G1176-C149-3

TMin TRIP CMD

Logic Diagram of the Forward Active Power Supervision

119

Functions


The forward active power protection is only effective and accessible if this function was set within the framework of the protective function configuration (section 2.2, address 0132, FORWARD POWER = Enabled. Set Disabled if the function is not required. The address 3201 FORWARD POWER, serves to switch the function ON or OFF or to block only the trip command (Block Relay).

Pick-up Values Time Delays

The setting of the forward power protection depends on the intended purpose. For this reason, general setting instructions are not possible. The pickup values are set in percent of the secondary apparent power rating SNsec = √3 ⋅ UNsec ⋅ INsec. Consequently, the machine power must be converted to secondary quantities: P sec P mach U N mach I N mach Setting = --------------- = -------------------- ⋅ --------------------- ⋅ -----------------S Nsec S N mach U N prim I N prim with

Psec

secondary active power according to setting value

SNsec

Secondary rated power = √3 ⋅ UNsec ⋅ INsec

Pmach

Active power of machine according to setting value

SN mach Rated apparent power of machine UN mach Rated voltage of machine IN mach

Rated current of the machine

UN prim

Primary rated voltage of voltage transformers

IN prim

Primary rated current of current transformers

Address 3202 serves to set the threshold of the forward power to an underrange (Pf<) and address 3203 (Pf>) serves to set it to overrange. Addresses 3204 T-Pf< and 3205 T-Pf> serve to set the associated time delays. In address 3206A MEAS. METHOD the user can select whether a fast or a precise measuring procedure must be used for the forward power calculation. In most cases, the precise measuring procedure is preferred in the power station sector (as a rule), whereas the fast procedure is applied for use as network decoupling. The set times are additional time delays not including the operating times (measuring time, drop-out time) of the protective function.

2.16.2.1 Settings of the Forward Active Power Supervision Addr.

Setting Title

Setting Options

Default Setting

Comments

3201

FORWARD POWER


OFF


3202

Pf<

0.5..120.0 %

9.7 %

P-forw.< Supervision Pickup

3204

T-Pf<

0.00..60.00 sec; ∞

10.00 sec

T-P-forw.< Time Delay

3203

Pf>

1.0..120.0 %

96.6 %

P-forw.> Supervision Pickup

3205

T-Pf>

0.00..60.00 sec; ∞

10.00 sec

T-P-forw.> Time Delay

3206A

MEAS. METHOD

Method accurate Method fast

Method accurate

Method of Operation

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7UM62 Manual C53000-G1176-C149-3


2.16.2.2 Information for the Forward Power Supervision F.No.

Alarm

Comments

05113 >Pf BLOCK

>BLOCK forward power supervision

05116 >Pf< BLOCK

>BLOCK forw. power superv. Pf< stage

05117 >Pf> BLOCK

>BLOCK forw. power superv. Pf> stage

05121 Pf OFF

Forward power supervis. is switched OFF

05122 Pf BLOCKED

Forward power supervision is BLOCKED

05123 Pf ACTIVE

Forward power supervision is ACTIVE

05126 Pf< picked up

Forward power: Pf< stage picked up

05127 Pf> picked up

Forward power: Pf> stage picked up

05128 Pf< TRIP

Forward power: Pf< stage TRIP

05129 Pf> TRIP

Forward power: Pf> stage TRIP

7UM62 Manual C53000-G1176-C149-3

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Functions

2.17


General

The machine impedance protection is used as a selective time graded protection to provide shortest possible tripping times for short-circuits in the synchronous machine, on the terminal leads as well as in the lower voltage winding of the unit transformer. It thus provides a fast back-up protection to the generator and transformer differential relays. The impedance protection feature of the 7UM62 always operates with the currents of side 2 (IL1, 2 ,3; S2).

2.17.1 Functional Description 2.17.1.1 Pickup General

Fault detection is required to detect a faulty condition in the power system and to initiate all the necessary procedures for selective clearance of the fault: − Start the time delays for the final stage t3, − Determination of the faulty phase − Release of impedance calculation, − Release of tripping command, − Indication/output of the faulty conductor(s). Overcurrent fault detection is used for the machine impedance protection, which can be supplemented by an undervoltage seal-in circuit. Following numeric filtering, the currents in each phase are monitored in comparison with a set threshold value. A pickup signal is generated for that (those) phase(s) in which the set threshold has been exceeded. These pickup signals are considered for choosing the measured values. The overcurrent fault detector is reset when 95% of the pick-up value is fallen below unless it is maintained by the undervoltage seal-in feature.

Undervoltage SealIn

In case of excitation systems deriving their power from the machine terminals or from the network, the excitation voltage can rapidly decay to almost zero. This results in decreasing short-circuit current, in spite of the short-circuit, and consequently drop-off of the overcurrent fault detectors. In such cases the impedance protection pick-up is maintained for a sufficiently long period by means of an undervoltage controlled sealin circuit using the positive sequence voltage. Fault detection will drop off only when the voltage has reappeared to a magnitude of 105% of the predetermined value, or when the holding time has expired. The seal-in logic operates separate for each phase. The first pickup of a phase overcurrent starts the timer T-SEAL-IN. Figure 2-59 shows the logic diagram of the fault detection module of the impedance protection.

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7UM62 Manual C53000-G1176-C149-3


2.17.1.2 Determination of the Short–Circuit Impedance For calculation of the fault impedance, the currents and voltages of the faulty loop are decisive. The phase selective fault detector determines the faulted loop and releases the corresponding measurement values for impedance calculation (see Table 2-7). Loop Selection

− The corresponding phase-earth loop is used for a 1-pole pickup. − With a 2-pole pickup, the phase-phase loop with the corresponding phase-to-phase voltage is used for impedance calculation. − With a 3-pole pickup, the phase-phase loop with the highest current value is used and with equal current amplitudes, the procedure described in the lowest line of Table 2-7 is applied.

Table 2-7

Measuring Loop Selection Pickup

Measuring Loop

1-pole

L1 L2 L3

2-pole

L1...L2 L2, L3 L3, L1

Phase-earth

L1–E L2–E L3–E

Phase-phase, Calculation of UI I and II I

L1– L2 L2– L3 L3– L1

3-pole, with different amplitudes

L1.2*L2,L3 L2,2*L3,L1 L3,2*L1,L2

Phase-earth, selection of L2–E loop with the highest current L3–E UI (Imax) and II (Imax) L1–E

3-pole, with same amplitude

L1, L2, L3

Phase-earth, any, maximum IIL1=IL2=IL3 => IL1 current amount) IL1=IL2 > IL3 => IL1 IL2=IL3 > IL1 => IL2 IL3=IL1 > IL2 => IL1

This loop selection type ensures that the fault impedance of system faults is measured correctly via the unit transformer. A measuring error occurs with a 1-pole system shortcircuit, as the zero phase-sequence system is not transmitted via the machine transformer (switching group e.g. Yd5). Table 2-8 describes the fault modeling and the measuring errors.

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123

Functions

Table 2-8

Fault Modeling and Measuring Errors on the Generator Side in Case of System Faults

G

Z System Fault

124

Fault Model on the Generator Side

Loop selection

Measuring Errors

3–pole short circuit


Phase-earth

Always correct measuring



Phase-earth loop with highest current

Always correct measuring



Phase-phase loop

Impedance measured too high by the zero impedance

7UM62 Manual C53000-G1176-C149-3


FNo. 03967

Imp. Fault L1 FNo. 03968

Pickup IL1>

OR

Imp. Fault L2

&

*)

FNo. 03969

Imp. Fault L3

Pickup IL2>

OR

&

OR

&

*)

Pickup IL3> *)

FNo. 03966

OR

Imp. picked up

FNo. 03953

FNo. 03962

>Imp. BLOCK

Imp. BLOCKED FNo. 03970

Imp. I> & U<

OR *) seal-in logic operates separately for each phase

3303 U< SEAL-IN

&

Pickup U1<

S

Fuse Failure

&

≥1

Q R

3305 T-SEAL-IN

FNo. 03958

>Useal-in BLK

Figure 2-59

Logic Diagram of the Pickup Stage of the Impedance Protection

2.17.1.3 Tripping Characteristic The tripping zones of the machine impedance protection relay have a polygonally shaped trip characteristic (see also Figure 2-60). It is a symmetrical characteristic, even though a fault in reverse direction (negative R and X values) is impossible provided the usual connection to the current transformers at the star-point side of the generator is used. The polygon is identified by one parameter: impedance Z. As long as a fault detector has picked up, the impedance calculation is effected continuously. This is carried out by complex division of the voltage and current phases derived from the loop selection. When the calculated fault impedance lies within the set trip characteristic, the protection issues a trip command which may be delayed according to the time setting.

7UM62 Manual C53000-G1176-C149-3

125

Functions

The protected zones can be chosen such that the first stage (ZONE Z1, T-Z1) covers faults in the generator and the lower voltage side of the unit transformer, whereas the second stage (ZONE Z2, ZONE2 T2) measures into the network. It should be noted that faults in the system cause impedance measurement errors due to the connection group (star-delta) of the unit transformer (see subsection 2.17.1.2). An unwanted operation of the stage can be excluded as the fault impedances of power system faults are modeled too high. Faults outside this range are switched off by the T END final time stage. Depending on the switching status of the system, it may be useful to extend the ZONE Z1, T-Z1. If, for example, the high-voltage side circuit breaker is open, the pickup can only be caused by a fault in the power unit. If a consideration of the circuit breaker auxiliary contact is possible, a so-called ZONE Z1B overreach zone can be switched effective (see Figure 2-62). X X2=Z2 X1b=Z1b

X1=Z1

R1b=Z1b R1=Z1

Figure 2-60

R2=Z2

R

Tripping Characteristics of the Impedance Protection

2.17.1.4 Tripping Logic The T END time delay is started subsequent to the protection pickup. The fault loop is determined now. The loop impedance components are compared with the limit values of the zones previously set. The tripping is executed if the impedance is within its zone during the expiration of the corresponding time stage. For the first Z1 zone and also for the Z1B overreach zone, the time delays will in most cases be zero or at least very short, i.e. the tripping is executed as soon as it is certain that the fault is within this zone. The Z1B overreach stage can be switched effective from outside, via a binary input. For the Z2 zone which may reach into the network, a time delay is selected overreaching the first stage of the power system protection.

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7UM62 Manual C53000-G1176-C149-3


A drop-out can only be caused by a drop-out of the overcurrent pickup and not by leaving the tripping polygon. Figure 2-61 illustrates the logic diagram of the impedance protection.

FNo. 03966

3312 T END

Imp. picked up

3310 ZONE Z2

3311 ZONE2 T2

&

S 3307 T-Z1

&

Z U

Q

R

3306 ZONE Z1

3308 ZONE Z1B

S 3309 T-Z1B

&

I

Q

R

S

Q

R

UL1,UL2,UL3 IL1,IL2,IL3

Loop selection

FNo. 3967 U1 IL1,IL2,IL3

Imp. Fault L1

FNo. 3977

FNo. 3968

Imp.Z1
Imp. Fault L2 FNo. 3969

FNo. 3979

Imp. Fault L3

Imp.Z2
FNo. 3970

Pickup

Tripping matrix

FNo. 3978

Imp I> & U< PU

Imp.Z1B
FNo. 3980

>Useal-in BLK

Imp.T3>TRIP TMin TRIP CMD

3315 BLOCKING OF

Z1 „1“ IL1, IL2, IL3 I2 Z1

Z1 and Z2

FNo. 3976

Power Swing

&

Power swing logic

see Section 2.17.3 FNo. 0361

>FAIL:Feeder V

see Figure 2-120 in Section 2.38.1.4

OR

FFM FNo. 3956

>Extens. Z1B FNo. 3953

FNo. 3962

>Imp. BLOCK

Imp. BLOCKED

Figure 2-61

7UM62 Manual C53000-G1176-C149-3

Logic Diagram of the Impedance Protection

127

Functions


The machine impedance detection is only effective and accessible if it was previously set within the framework of project configuration (Section 2.2) at address 0133, IMPEDANCE PROT. = Enabled. Set Disabled if the function is not required. Address 3301 IMPEDANCE PROT. is used to switch the function ON and OFF, or to block only the trip command (Block Relay).

Pickup

The maximum load current during operation is the most important criterion to be considered when setting the overcurrent pickup. A pickup by an overload must be excluded in any case! For this reason, the 3302 IMP I> pick-up value must be set above the maximum (over) load current to be expected. Recommended setting: 1.2 to 1.5 times the nominal machine current. The pickup logic corresponds to the logic of the UMZ I> definite time-overcurrent protection. If the pickup is derived from the generator terminals and if, for this reason, the short circuit can fall below the pickup value (address 3302) due to the collapsing voltage, the undervoltage seal-in feature is used, i.e. the address 3303 U< SEAL-IN is switched ON. The undervoltage seal-in feature U< (address 3304) is set to a value below the lowest phase-to-phase voltage occurring during operation, e.g. to U< = 75 % to 80 % of the nominal voltage. The seal-in time (address 3305 T-SEAL-IN) must exceed the maximum fault clearance time in a back-up case (recommended setting: address 3312 T END + 1 s).

Impedance Stages

As illustrated in figure 2-60, the protection has the following characteristics which may be set independently: − 1st zone (Z1 instantaneous zone) with the setting parameters ZONE Z1 T-Z1

Reactance = reach, = 0 or short delay, if required.

− Z1B overreach zone, externally controlled via binary input, with the setting parameters ZONE Z1B T-Z1B

Reactance = reach, T1B = 0 or short delay, if required.

− 2nd zone (Z2 zone) with the setting parameters ZONE Z2 ZONE2 T2

Reactance = reach, The user must select a value for T2 which is situated above the grading time of the network protection.

− Non-directional final stage with the setting parameter T END

The user must select a value for T END which ensures that the 2nd or 3rd stage of the series-connected power system distance protection is overreached.

As the user can proceed on the assumption that the impedance protection measuring influences the unit transformer, it must be ensured that the parameterization selection sufficiently considers the transformer control range. Therefore, ZONE Z1 is normally set to a reach of approx. 70 % of the protected zone (i.e. about 70 % of the transformer reactance), with no or only a small delay (i.e. T-Z1 = 0.00 s to 0.50 s). In this case, the protective relay will switch off faults on this distance

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7UM62 Manual C53000-G1176-C149-3


with its operating time or with a slight time delay (undelayed tripping). A 0.1 s time delay is preferred. For ZONE Z2 the reach could be set to about 100 % of the transformer reactance, or in addition to a network impedance. The corresponding ZONE2 T2 time stage is to be selected in a way that it overreaches the network protective relays of the following lines. The T END time is the last back-up time.

The following formula is generally valid for the primary impedance (with limiting to the unit transformer): 2

k R u sc U N Z prim = ---------- ⋅ ---------- ⋅ -------100 100 S N with

kR

Zone reach of zone Z1 in [%]

usc

Relative transformer short-circuit voltage [%]

SN

Rated transformer power [MVA]

UN

Machine-side rated transformer voltage [kV]

The values determined such must be converted for the secondary side of current and voltage transformers. In general:

CT transformation ratio Z secondary = ------------------------------------------------------------- ⋅ Z primary VT transformation ratio The nominal current of the protective relay (= secondary nominal current of the current transformer) is automatically considered by the relay. You have already communicated the transformation ratios of the current and voltage transformers to the relay by entering the nominal transformer quantities (see Section 2.3). Example: Transformer data: usc = 7 % SN = 5.3 MVA UN = 6.3 kV Transformation ratios: Current transformer transformation ratio = 500 A/1 A VT transformation ratio

6.3 kV 100 V = ----------------- ⁄ --------------3 3

This results to a 70 % reach for zone 1: 2

70 7 6.3 Z1 prim = ---------- ⋅ ---------- ⋅ ----------- = 0.3669 Ω 100 100 5.3

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129

Functions

Consequently, the secondary side setting value of zone 1 at address 3306 ZONE Z1 is: 500 A ⁄ 1 A Z1 secondary = ------------------------------------ ⋅ 0.3669 Ω = 2.91 Ω 6.3 kV ⁄ 100 V Note: The following ratio would result from the connection of a 5 A device to a 5 A transformer: 500 A ⁄ 5 A Z1 secondary = ------------------------------------ ⋅ 0.3669 Ω = 0.58 Ω 6.3 kV ⁄ 100 V The following primary reactance results for a 100 % reach for zone 2: 2

100 7 6.3 Z2 prim = ---------- ⋅ ---------- ⋅ ----------- = 0.5242 Ω 100 100 5.3 The following secondary side setting value of zone 2 results at address 3310 ZONE Z2: 500 A ⁄ 1 A Z2 secondary = ------------------------------------ ⋅ 0.5242 Ω = 4.16 Ω 6.3 kV ⁄ 100 V

t T3

T2 T1

X1=0.70*X1Transf

Z1 (X1, R1)

Z2 (X2, R2 )

Z1B (X1B, R1B)

Z

X1=X1Transf

G Internal consumption

Z< Figure 2-62

Z1B Overreach Zone

130

BI

Time Grading for Machine Impedance Protection – Example

The Z1B overreach zone (address 3308 ZONE Z1B) is an externally controlled stage which does not influence the Z1 normal stage. Consequently, there is no changeover, but the overreach zone is switched effective or ineffective, depending on the position of the high-voltage side circuit breaker.

7UM62 Manual C53000-G1176-C149-3


The Z1B zone is usually switched effective with an open high-voltage circuit breaker. In this case, every impedance protection pickup can only be due to a fault in the protection zone of the block, as the power system is disconnected from the block. Consequently, the undelayed tripping zone can be extended to 100 % to 120 % of the protection zone without any loss of selectivity. The Z1B zone is activated via a binary input controlled by the circuit breaker auxiliary contact (see figure 2-62). The overreach zone is assigned to an individual 3309 TZ1B time delay. Final Stage

In case of short circuits outside the Z1 and Z2 zones, the relay functions as a timedelayed overcurrent protection. Its nondirectional final time T END is selected in a way that its time value overreaches the second or third stage of the series-connected network distance protection.

2.17.3 Power Swing Blocking General

Dynamic occurrences such as sudden load changes, short-circuits, automatic reclosures or switching operations within the power system may cause power swings. Therefore, the impedance protection is complemented by a power swing blocking function to avoid spurious tripping. Power swings are three-phase symmetrical occurrences. The first prerequisite is therefore the symmetry of the phase currents, which is verified by evaluation of the negative sequence current. This means that asymmetrical (all single-phase and twophase) short-circuits cannot cause the power swing blocking to pick up. Even if a power swing has been detected, the asymmetrical short-circuits following it quickly deactivate the power swing blocking and make a trip by the impedance protection possible. Since a power swing happens much more slowly than a short-circuit, the rate of change of the impedance is a reliable criterion for its identification. Because of its symmetrical nature, the positive sequence impedance obtained from the positive sequence components of the currents and voltages is evaluated.

Logic

Figure 2-63 shows the logic diagram of the power swing blocking. In the upper section, the current symmetry monitoring can be seen. A release signal is given if there is a three-pole pickup with no negative sequence system current. For detection of power swings, a power swing polygon (P/SPOL) is used which is greater than the trip polygon (TPOL). The distance between the two polygons can be set (common setting for R and X direction). The user can choose for each setting parameter whether the trip polygon refers only to characteristic Z1 or to characteristics Z1 & Z2. In the latter case, the trip polygon is the maximum impedance value.

Measuring Principle

The criterion for power swing blocking is composed of the power swing polygon, its distance to the trip polygon, the trip polygon itself and the rate of change of the impedance. The protection compares the first impedance value after entering the power swing polygon (at a moment Tent) with the last impedance value outside the polygon (at a moment Tent-∆t). The time ∆t is determined by the measuring interval, which is one cycle. If the rate of change of the impedance vector thus determined is less than a set value ∆Z/∆t, a power swing is detected. The impedance stage is not blocked, however, until the impedance vector enters the trip polygon TPOL. If the first impedance value is both inside the P/SPOL and the TPOL, the protection detects immediately a short-circuit, because there must be at least one impedance value between the P/SPOL and the TPOL. The distance between the power swing

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131

Functions

polygon P/SPOL and the trip polygon TPOL, and the rate of change ∆Z/∆t are matched to one another in such a way that power swings are reliably detected and the desired impedance zone (Z1 or Z1 & Z2) of the impedance protection is blocked. The blocking remains effective until the measured impedance vector has left again the trip polygon / power swing polygon, the impedance changes faster than the change rate, or asymmetrical power conditions rule out the possibility of a power swing. The power swing blocking time is also limited by a parameter setting (T-ACTION P/S). Blocking of the Impedance Stages

Power swing blocking is mostly used for impedance stage Z1, because the delay time T1 for this stage is set low. Accordingly, a high delay time T2 must be set for zone Z2. In the overreach zone Z1B no power swings can occur by definition, since the network breaker is open and there is thus no second machine for power swings. Likewise, the power swing blocking does not block the non-directional overcurrent stage (T3).

3966 Imp. picked up 3-pole pickup OFF ON

&

"1"

Release of Power swing blocking

3313 POWER SWING

IL1 IL2 IL3

I2<0,1I/In, Gen

see Figure 2-61 Blocking

I2

3976 Power Swing 3315 dZ/dt

"Power swing presumed"

3314 P/SPOL-TPOL P/SPOL Within P/S polygon

Tent

S Q

&

&

< R

Z(Tent-∆t) Rate of ∆Z / ∆t change

P/SPOL Outside P/S polygon

P/SPOL

&

Z(Tent)

3317 T-ACTION P/S

>

OR Z(Tent)

First value within P/S polygon (at Tent) Z(Tent-∆t) Last value outside P/S polygon P/SPOL Power swing polygon TPOL Trip polygon ∆Z / ∆t Rate of change of the impedance vector

TPOL

Within Trip polygon

Figure 2-63 Logic Diagram for the Power Swing Blocking of the Impedance Protection

2.17.3.1 Setting Hints The power swing blocking is only effective if address 3313 POWER SWING has been set to ON. A sensible compromise has to be found for the distance between the power swing polygon and the trip polygon (parameter: P/SPOL-TPOL (address 3314) and for the rate of change (parameter: dZ/dt (address 3315)). It must be kept in mind that the rate of change is not constant and decreases with increasing proximity to the origin of the coordinate system.The rate of change is also determined by power system conditions, such as the impedance between the systems involved in the power swing, and by the power swing frequency (see also Section 2.18 Out-of-Step Protection).

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7UM62 Manual C53000-G1176-C149-3


The following relation allows to estimate the rate of change: Xπf p Xπf p dZ ( t ) dR ( t ) Ω -------------- ≈ -------------- = ---------------------------- in ---- = ---------------------2 dt dt s 2 δ 2sin ( πf p t ) 2sin æ ---ö è 2ø Meaning: X

Reactance between the sources of the power swing

fp

Power swing frequency

δ

Power swing angle

Figure 2-64 shows an example of how the rate of change evolves as a function of the power swing angle. The rate of change is smallest at an angle of 180°, but increases proportionally with the angle considered.

Ω/s

300 dZ(δ) 250

200

150

100

50

0

50

100

150

200

250

300

350 δ

400 Degrees

Figure 2-64 Evolution of the Rate of Change (fp = 1 Hz; X = 10 Ω)

For this reason, the setting value dZ/dt must also be coordinated with the impedance jump occurring at the start of a short-circuit. To do so, you determine the minimum operating impedance (ZL, min), form the difference to the setting of the impedance zone (e.g. Z1) and calculate the impedance gradient, taking into account the one-cycle measuring interval. Example: Umin = 0.9 UN, Imax = 1.1 IN, uK = 10 %, ∆t = 20 ms UN = 100 V, IN = 1 A 0, 7 ⋅ u K ⋅ U N Z1 = --------------------------------------- = 4, 04 Ω 100 % ⋅ 3 ⋅ I N

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Functions

0, 9 ⋅ U N Z L, min = ------------------------------- = 47, 24 Ω 3 ⋅ 1, 1 ⋅ I N dZ ------- = ( Z L, min – Z1 )∆/t = 43, 20 Ω/20 ms = 2160 Ω/s dt If safety factor 4 is chosen, dZ/dt should never be set higher than 500 Ω/s (or 100 Ω/s for 5 A transformers). The default setting for dZ/dt is 300 Ω/s, which should be adequate for most applications. This is also the basis for the minimum distance P/SPOL - TPOL, assuming that for detection of a power swing there must be one impedance value between P/SPOL and TPOL. P/SPOL – TPOL > dZ/dt ⋅ ∆t = 300 Ω/s ⋅ 0.02 s = 6 Ω (selected setting value: 8 Ω) All other settable parameters are advanced parameters which need not normally be modified. Table 2-9

Parameters

Address

Parameter

Remark

3316A

BLOCKING OF

Default setting is Z1, as there is little or no delay for this stage. The delay time of Z2 is determined by the power system protection, and greater (see also the hints below).

3317A

T-ACTION P/S

The default setting is 3 s. This time depends on the minimum possible power swing frequency.

Whether a power swing can cause an overfunctioning of the impedance protection depends mainly on the time the impedance vector remains inside the trip polygon. This time can only be reliably determined by „transient“ calculations. If the rate of change in the proximity of 180° is known, it can be the basis for a rough estimation of the time. T = 2 ⋅ Zcharacteristic /dZ/dt (180°) The above data yield the following value: Zcharacteristic= Z1 = 4 Ω dZ/dt (180°) = 20 Ω/s (from Figure 2-64) T = 2 ⋅ 4 Ω/20 Ω/s = 0.4 s This means that for delay times of more than 0.4 s no power swing blocking is needed.

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2.17.3.2 Settings of the Impedance Protection Addr.

Setting Title

Setting Options

Default Setting

Comments

3301

IMPEDANCE PROT.


OFF


3302

IMP I>

0.10..20.00 A

1.35 A

Fault Detection I> Pickup

3303

U< SEAL-IN

ON OFF

OFF

State of Undervoltage Seal-in

3304

U<

10.0..125.0 V

80.0 V

Undervoltage Seal-in Pickup

3305

T-SEAL-IN

0.10..60.00 sec

4.00 sec


3312

T END

0.00..60.00 sec; ∞

3.00 sec

T END: Final Time Delay

3306

ZONE Z1

0.05..130.00 Ohm

2.91 Ohm

Impedance Zone Z1

3307

T-Z1

0.00..60.00 sec; ∞

0.10 sec

Impedance Zone Z1 Time Delay

3308

ZONE Z1B

0.05..65.00 Ohm

4.99 Ohm

Impedance Zone Z1B

3309

T-Z1B

0.00..60.00 sec; ∞

0.10 sec

Impedance Zone Z1B Time Delay

3310

ZONE Z2

0.05..65.00 Ohm

4.16 Ohm

Impedanz Zone Z2

3311

ZONE2 T2

0.00..60.00 sec; ∞

0.50 sec


3313

POWER SWING

ON OFF

OFF

Power Swing Blocking

3314

P/SPOL-TPOL

0.10..30.00 Ohm

8.00 Ohm

Distance betw. Power Swing Trip-Pol.

3315

dZ/dt

1.0..600.0 Ohm/s

300.0 Ohm/s

Rate of Change of dZ/dt

3316A

BLOCKING OF

Zone Z1 Zone Z1 and Z2

Zone Z1

Power Swing Blocking locks out

3317A

T-ACTION P/S

0.00..60.00 sec; ∞

3.00 sec

Power Swing Action Time

2.17.3.3 Information from the Impedance Protection F.No.

Alarm

Comments

03953 >Imp. BLOCK

>BLOCK impedance protection

03956 >Extens. Z1B

>Zone 1B extension for impedance prot.

03958 >Useal-in BLK

>Imp. prot. : BLOCK undervoltage seal-in

03961 Imp. OFF

Impedance protection is switched OFF

03962 Imp. BLOCKED

Impedance protection is BLOCKED

03963 Imp. ACTIVE

Impedance protection is ACTIVE

03966 Imp. picked up

Impedance protection picked up

03970 Imp. I> & U<

Imp.: O/C with undervoltage seal in

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135

Functions

F.No.

Alarm

Comments

03967 Imp. Fault L1

Imp.: Fault detection , phase L1

03968 Imp. Fault L2


03969 Imp. Fault L3


03977 Imp.Z1< TRIP

Imp.: Z1< TRIP

03978 Imp.Z1B< TRIP

Imp.: Z1B< TRIP

03979 Imp. Z2< TRIP

Imp.: Z2< TRIP

03980 Imp.T3> TRIP

Imp.: T3> TRIP

03976 Power Swing

Power swing detection

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2.18


General

In extensive high-voltage networks, short-circuits which are not disconnected quickly enough, or disconnection of coupling links which may result in an increasing of the coupling reactance, may lead to system swings. These consist of power swings which endanger the stability of the power transmission. Stability problems result in particular from active power swings which can lead to pole-slipping and thus to overloading of the synchronous machines.

2.18.1 Functional Description 2.18.1.1 Measuring Principle General

The out-of-step protection detects these power swings by the well-proven impedance measurement. The trajectory of the complex impedance vector is evaluated. The impedance is calculated from the positive sequence components of the voltages and currents. Trip decision is made dependent of the rate of change of the impedance vector and on the location of the electrical centre of the power swing. The out-of-step condition is illustrated at a simplified equivalent circuit. Figure 2-65 shows the generator voltage UG and the network equivalent voltage UN. The generator, transformer, and network impedance is situated between these two voltages. The total of these impedances should be the impedance Ztot.

ZG

ZTr

IN

∼

∼

UG

UN Ztot = ZG + ZTr + ZN

m=0 UG

m=1 U(m)

U(m)

UG

UN

UN

δ

Figure 2-65

Equivalent of Power Swing

The measurement location divides the total impedance into the impedances m ⋅ Ztot and (1-m) ⋅ Ztot. The following applies for the impedance at m: U(m) Z(m) = ------------I(m)

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Functions

The current I is independent of the location of the measurement: UG – U N I(m) = I = ---------------------Z tot The voltage U at the location of measurement m is: U(m) = U G – ( m ⋅ Z tot ⋅ I ) Thus results with: UG = U G ⋅ e

j δG

UN = UN ⋅ e

j δN

δ = δ G – δN

1 Z(m) = ------------------------------------- – m ⋅ Z tot UN –j δ 1 – æ -------- ⋅ e ö è UG ø where δ is the displacement angle between the generator voltage and the network equivalent voltage. Under normal conditions, this angle depends on the load situation and is nearly constant. It fluctuates during power swings and can vary, in case of an out-of-step condition, between 0° and 360°. Figure 2-66 shows the trajectory of the impedance vector at the measurement location m according to the above formula. The origin of the coordinate system corresponds to the measurement location (voltage transformer set). When the ratio of the voltage magnitudes UN/UG is kept constant and the load angle δ varies, then circles result as a locus diagram. The centre and the radius of the circle are determined by the ratio UN/UG. The centre points are situated on a line which is determined by Ztot. Minimum and maximum of the magnitude of the measured impedance are at load angles δ = 0° and δ = 180°. If the measurement location is the electrical centre, the measured voltage, and thus the measured impedance, becomes zero when the load angle becomes δ = 180°. Power Swing Polygon

138

The measurement characteristic is a rectangle with adjustable widths and inclination angle ϕP. This ensures optimum matching to the conditions in the power station.

7UM62 Manual C53000-G1176-C149-3


Im(Z)

Z(m)

δ=0°

UN --------- = 0.8 UG UN --------- = 0.7 UG

(1–m)Ztot

δ=180°

(0.5–m)Ztot ϕP

δ=180°

–mZtot

Re(Z) UN -------- = 1.0 UG

UN --------- = 1.3 UG

δ=0°

Figure 2-66

UN --------- = 1.2 UG

Impedances at the Measurement Location m

2.18.1.2 Out-of-Step Logic Figure 2-67 shows, more detailed, the power swing detection characteristic. The inclination angle ϕP is assumed to be 90°. The setting parameters Za, Zb, Zc and (Zd– Zc) determine the rectangle. It is symmetrical as to its vertical axis. The limit or Zb reaches in reverse direction into the generator. The forward reaches are Zc) into the unit transformer, and the second stage Zd) into the network system. Two characteristics are available. The lower area, characteristic 1 (i.e. the non-hatched area in Figure 2-67), covers the electrical centre being in the generator block until the unit transformer, the hatched area, characteristic 2, discriminates the electrical centre being in the network system. The point of crossing of the symmetry axis is decisive for the assignment to the characteristic. Power swings are three-phase symmetrical occurrences. The first prerequisite is therefore the symmetry of the currents which is verified by evaluation of the negative sequence current. A condition for power swing detection is that the positive sequence component of the current exceeds an adjustable limit I1and the negative sequence current remains below an adjustable value I2.

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139

Functions

Im(Z)

Zd Zd–Zc

Characteristic 2

Z=R +jX

Zc

Characteristic 1

ϕP

Za

Re(Z)

Zb

Figure 2-67

Polygonal Out-of-Step Characteristic and Typical Power Swing Occurrences

An out-of-step condition requires, additionally, that the impedance vector enters a power swing characteristic at one side and leaves it at the other side (loss of synchronism, cases and in Figure 2-67). This is characterized in that the real component of the impedance (or its component rectangular to the symmetrical axis ϕP has changed its sign while passing through the characteristic. It is also possible for the impedance vector to enter and leave the power swing polygon at the same side. In this case, power swing tends to be stabilized (cases and in Figure 2-67). When an out-of-step condition is recognized, i.e. when the impedance vector has passed through a power swing characteristic, an annunciation is issued which also identifies the characteristic. Additionally, a counter n1 (for characteristic 1) or n2 (for characteristic 2) is incremented. Out-of-step protection pick-up is indicated when a counter is set to 1. Another out-ofstep indication is given, for an adjustable time period, each time a counter is incremented. After an adjustable holding time pick-up resets unless a new power swing condition has been recognized. The holding time is triggered each time a counter is incremented. Trip command is given when the number of out-of-step periods, i.e. one of the counters, has reached a selectable number. The trip command is held for at least the set time T-HOLDING. The minimum trip command duration TMin TRIP CMD does not start until the pickup has reset.

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Figure 2-68 shows the logic diagram of the out-of-step protection. The feature has two stages and can be blocked by a binary input.

3512 T-SIGNAL

FNo. 05067

O/S char. 1 3511 T-HOLDING

FNo. 05069

UL1

Release

O/S det. char.1

UL2 UL3

Reset

U1

U 1 -------- = Z 1 I

Increment

1

Characteristic 1

n=0

n ≥1

n=n+1 n ≥ n1

FNo. 05071

O/S TRIP char.1

&

3509 REP. CHAR. 1

IL1

Tripping matrix

IL2 IL3

I1 I2

3512 T-SIGNAL

FNo. 05068

O/S char. 2 3511 T-HOLDING

FNo. 0507 Release

O/S det. char.2

Reset Increment Characteristic 2

n=0

n ≥1

n=n+1

n

≥ n2

TMin TRIP CMD

FNo. 05072

O/S TRIP char.2

&

3510 REP. CHAR. 2

I1 >

& I2 <

FNo. 05053

FNo. 05062

>BLOCK O/S

O/S BLOCKED

O/S Ch. 1 Ch. 2 U1 I1 I2

Figure 2-68

7UM62 Manual C53000-G1176-C149-3

– – – – – –

Out-of-step signal for the duration of T-SIGNAL Characteristic 1 Characteristic 2 Complex positive sequence component of the voltages Complex positive sequence component of the currents Complex negative sequence component of the currents ^

Logic Diagram of the Out-of-Step Protection

141

Functions


The out-of-step protection is only effective and accessible if this function has been set during the configuration of the protective functions (Section 2.2, address 0135, OUTOF-STEP = Enabled. Set Disabled if the function is not required. Address 3501 OUT-OF-STEP is used to switch the function ON or OFF, or to block only the trip command (Block Relay).

Pickup

The out-of-step protection operates only when the positive sequence component of the currents has exceeded a minimum threshold 3502 I1> RELEASE (overvoltage pickup). As out-of-step conditions are symmetrical occurrences, a maximum value of negative sequence current 3503 I2< RELEASE must not be exceeded. The determining factor for overcurrent setting I1> RELEASE is the maximum possible operating current. Pickup under conditions of permissible overload should be excluded. The setting should therefore be set above the maximum anticipated (over-) load current (at least 120 % IN. Depending on network conditions, smaller pickup thresholds can be chosen, so that the measurement (see Figure 2-68) may be released all the time. As out-of-step conditions are symmetrical occurrences, the pickup threshold of the negative sequence component of the current I2< RELEASE should be set to approx. 20 % IN.

Impedance Settings

The measured impedances during power swing conditions are decisive for the settings. For the direction to the machine (as viewed from the location of the voltage transformers), the power swing reactance of the machine must be considered, which is approximately the transient reactance Xd' of the machine. Consequently, you will calculate the secondary transient reactance and set it for Zb ≈ Xd' (see Figure 2-69).

Im(Z)

Zd Locus diagram of power swing impedance

Zd–Zc

Characteristic 2

Zc ü Characteristic 1 ý ≈ (0.7 to 0.9) ZK Transf Za þ ϕP ü

Re(Z)

ý ≈ Xd’

Zb

Figure 2-69

142

þ

Power Swing Polygon

7UM62 Manual C53000-G1176-C149-3


Xd' can be calculated from the per unit reactance xd' as follows: U N, Gen ü ct X d' = ----------------------------- ⋅ x d' ⋅ ------ü vt 3 ⋅ I N, Gen where Xd' xd' UN, Gen IN, Gen üct üvt

– – – – – –

Transient reactance of the machine Transient per unit reactance Primary rated machine voltage Primary rated machine current Current transformer ratio Voltage transformer ratio

Dependent on the type of generator and on the secondary current, a secondary voltage UN = 100 V or 120 V leads to approximately the reactance ranges listed in Table 2-10. Table 2-10

Transient Machine Reactances (Referred to Secondary Side)

Generator Type

Xd

Xd Xd Xd Xd UN = 100 V/ IN = 1 A UN = 120 V/ IN = 1 A UN = 100 V/ IN = 5 A UN = 120 V/ IN = 5 A

Non-salient pole rotor

0.13..0.35

7.5 Ω...20.2 Ω

9.4 Ω..24.3 Ω

1.5 Ω...4.0 Ω

1.9 Ω...4.9 Ω

Salient-pole rotor 0.20..0.45

11.5 Ω...26.0 Ω

13.9 Ω...31.2 Ω

2.3 Ω...5.2 Ω

2.8 Ω...6.2 Ω

As it is presupposed that the generator is connected with the network via a unit transformer, the setting in the network direction is chosen such that the reactance reach of characteristic 1 is approximately 70 % to 90 % of the transformer impedance, and the reach of characteristic 2 is into the network. Thus, Zc at address 3506 is set to 70 % to 90 % of the transformer impedance XSC. For characteristic 2, the remaining portion of the transformer impedance is set at 3507 Zd - Zc, if necessary complemented by the impedance of the additional line section to be monitored. Table 2-11 shows typical values of the impedances of unit transformers XSC for secondary rated currents IN = 1 A and IN = 5 A, the relationship of the values is according to the following equation: 2

u SC ⋅ U N u SC ⋅ U N U SC X SC prim = ----------------- = ------------------------------- = -------------------------100 ⋅ S N 3 ⋅ IN 100 ⋅ 3 ⋅ I N ü ct X SC = X SC prim ⋅ ------ü vt

. Table 2-11

Per Unit Impedance Voltages and Impedances of Transformers XSC XSC XSC XSC UN = 100 V/ IN = 1 A UN = 120 V/ IN = 1 A UN = 100 V/ IN = 5 A UN = 120 V/ IN = 5 A

Transformer Type

uSC

Unit transformer

8 %...13 %

4.6 Ω...7.5 Ω

5.5 Ω...9.0 Ω

0.9 Ω...1.5 Ω

1.1 Ω...1.8 Ω

General

3 %...16 %

1.7 Ω...9.2 Ω

2.1 Ω...11.1 Ω

0.3 Ω...1.8 Ω

0.4 Ω...2.2 Ω

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143

Functions

The setting Za is decisive for the width of the power swing polygon. This setting value 3504 Za is determined by the total impedance Ztot and can be derived from the equation in Figure 2-70. Ztot can be calculated from the sum of Zb and Zd; then the power swing angle is valid between the machine e.m.f. and the network. Optionally, Ztot can be calculated from Zb + Zc; in this case the power swing angle is valid between the machine e.m.f. and the unit transformer. The default setting of address 3504 Za corresponds to the latter case. Usually, a power swing angle δ = 120° is chosen, since the generator voltage UG and the system voltage UN equal the voltage difference:

Im(Z) ì

Z tot ⁄ 2 Z a = -----------------------tan ( δ ⁄ 2 )

Zd

ì

Re(Z)

Za Zb+Zdí δ

Zb+Zc í

î

Figure 2-70

Maximum Power Swing Frequency

î

with δ = 120°

Z = R + jX

Zc

UN --------- = 1 UG

Z tot ⁄ 2 Z a = --------------------------------tan ( 120° ⁄ 2 ) Z a ≈ 0.289 ⋅ Z tot

Zb

with Ztot= Zb + Zc

Power swing angle between generator and unit transformer (as illustrated) or

with Ztot= Zb + Zc

Power swing angle between generator and network

Power Swing Polygon and Impedance Vectors with Power Swing Angle δ

The polygon width Za determines also the maximum detectable power swing frequency. The consideration that, at maximum power swing frequency, at least two impedance measurements must have been carried out within the power swing polygon, leads to the following approximative formula for the maximum detectable power swing frequency fP: 4 1 Za f P = --- ⋅ --- ⋅ --------π T Z tot

with T = a.c. period

For a rated frequency of 50 Hz (i.e. T = 20 ms), for example, the above formula delivers: Z a ≈ 0.289 ⋅ Z tot f P ≈ 18 Hz as the maximum detectable power swing frequency.

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7UM62 Manual C53000-G1176-C149-3


The inclination angle ϕ of the power swing polygon can be set at address 3508 PHI POLYGON and thus matched to the conditions.

Calculation Example: Generator data: xd' = 0.20 UN = 6.3 kV IN = 483 A Transformer data: uSC = 7 % SN = 5.3 MVA UN = 6.3 kV Transformation ratios: Current transformers üct = 500 A/1 A 6300 V ⁄ ( 3 ) ü vt = ----------------------------------100 V ⁄ ( 3 )

Voltage transformers

Thus, the secondary transient reactance of the generator: U N, Gen ü ct X d' = ----------------------------- ⋅ x d' ⋅ ------ü vt 3 ⋅ I N, Gen 3

500 ⁄ 1 6.3 ⋅ 10 X d' = ---------------------- ⋅ 0.20 ⋅ ----------------------------------------- = 12 Ω 3 3 ⋅ 483 ( 6.3 ⋅ 10 ) ⁄ 100 Zb ≈ Xd' thus determines the setting of address 3505 Zb. The secondary reactance of the unit transformer is derived from the primary reactance by considering the transformer ratios: 2

3 2 u SC ⋅ U N ü ct 7 ( 6.3 ⋅ 10 ) 500 ⁄ 1 X SC = -------------------------- ⋅ ------- = ---------- ⋅ ------------------------------ ⋅ ----------------------------------------- = 4.2 Ω 100 5.3 ⋅ 10 6 ( 6.3 ⋅ 10 3 ) ⁄ 100 100 ⋅ S N ü vt

Assuming that the characteristic should cover 85 % of the transformer reactance, the setting of Zc results in ≈ 0.85 ⋅ 4.2 Ω ≈ 3.6 Ω. Assuming that the remaining transformer reactance (0.15 ⋅ 4.2 Ω) and the covered system reactance should be 10 Ω, the setting of 3507 results in: Zd - Zc = 6.4 Ω. The width Za of the polygon is determined by the total impedance Ztot. In this calculation example, the total impedance Ztot is that of characteristic 1, i.e. the sum of generator reactance and one portion of the unit transformer reactance; that is the sum of the setting values for Zb and Zc = 12 Ω + 3.6 Ω = 15.6 Ω): Za ≈ 0.289 ⋅ 15.6 Ω ≈ 4.5 Ω.

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Functions

Number of Power Swings

Address 3509 REP. CHAR. 1 determines the number of out-of-step periods for characteristic 1 which will lead to trip, i.e.the number of times this characteristic must have been passed through. For characteristic 1, 1 or 2 passes are normally adequate as out-of-step conditions with the electrical centre within the power station unit should not be tolerated too long, and the power swing frequency tends to accelerate during an out-of-step condition, so that the electrical and dynamic stress of the machine increases. On the other hand, for out-of-step conditions with the electrical centre being in the network system a higher number of slip periods can be tolerated, so that address 3510 REP. CHAR. 2 can usually be set to 4. Each time characteristic 1 or 2 is passed through, a holding time set at address 3511 T-HOLDING) is started. A detected out-of-step condition is maintained for that time so that the counter is incremented with the next passing through. When no renewed pickup occurs within this time, the counters n1 or n2 respectively are reset, i.e. the outof-step condition is “forgotten”. This time should be set higher that the longest expected slip period (i.e. lowest slip frequency). Settings between 20 s and 30 s are good values. Each time one of the counters n1 or n2 is incremented, the holding time is restarted, and an annunciation “Out-of-step characteristic 1" or “Out-of-step characteristic 2" is issued. These annunciations disappear after the time which is set at address 3512 TSIGNAL. If this time is set higher that the time between two power swings, the annunciation “Out-of-step characteristic 1(2)” begins with the first out-of-step detection and ends after the last detected out-of-step detection, prolonged wit the set time T-SIGNAL.

2.18.2.1 Settings of the Out-of-Step Protection With a rated secondary current of IN = 5 A, the parameters with the addresses 3504 to 3507 must be divided by 5. Addr.

Setting Title

Setting Options

Default Setting

Comments

3501

OUT-OF-STEP


OFF


3502

I1> RELEASE

20.0..400.0 %

120.0 %

Pickup Current for Measuring Release I1>

3503

I2< RELEASE

5.0..100.0 %

20.0 %

Pickup Current for Measuring Release I2<

3504

Za

0.20..130.00 Ohm

4.50 Ohm

Resistance Za of the Polygon (width)

3505

Zb

0.10..130.00 Ohm

12.00 Ohm

Reactance Zb of the Polygon (reverse)

3506

Zc

0.10..130.00 Ohm

3.60 Ohm

Reactance Zc of Polygon (forward char.1)

3507

Zd - Zc

0.00..130.00 Ohm

6.40 Ohm

Reactance Dif. Char.1 - Char.2 (forward)

3508

PHI POLYGON

60.0..90.0 °

90.0 °

Angle of Inclination of the Polygon

3509

REP. CHAR. 1

1..4

1

Number of Power Swing: Characteristic 1

146

7UM62 Manual C53000-G1176-C149-3


Addr.

Setting Title

Setting Options

Default Setting

Comments

3510

REP. CHAR. 2

1..8

4


3511

T-HOLDING

0.20..60.00 sec

20.00 sec

Holding Time of Fault Detection

3512

T-SIGNAL

0.02..0.15 sec

0.05 sec

Min. Signal Time for Annun. Char. 1/2

2.18.2.2 Information for the Out-of-Step Protection F.No.

Alarm

Comments

05053 >BLOCK O/S

>BLOCK out-of-step protection

05061 O/S OFF

Out-of-step protection is switched OFF

05062 O/S BLOCKED

Out-of-step protection is BLOCKED

05063 O/S ACTIVE

Out-of-step protection is ACTIVE

05067 O/S char. 1

Out-of-step pulse of characteristic 1

05068 O/S char. 2

Out-of-step pulse of characteristic 2

05069 O/S det. char.1

Out-of-step characteristic 1 picked up

05070 O/S det. char.2

Out-of-step characteristic 2 picked up

05071 O/S TRIP char.1

Out-of-step TRIP characteristic 1

05072 O/S TRIP char.2

Out-of-step TRIP characteristic 2

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Functions

2.19 General

Undervoltage Protection (ANSI 27) Undervoltage protection detects and reports abnormally low voltage conditions, some of which could be related to system stability problems (voltage collapse, etc.). Two-pole short circuits or earth faults cause an asymmetrical voltage collapse. Compared with three monophase measuring systems, the detection of the positive phase-sequence system is not influenced by these procedures and is advantageous especially with regard to the judgement of stability problems.

2.19.1 Functional Description For this, the fundamental wave of the positive sequence system is paramount. The phase voltages are filtered by the protection (Fourier analysis) and only the fundamental waves are evaluated. Of these, the protection only detects the positive sequence system. Undervoltage protection consists of two definite time elements. A pickup is signalled as soon as the value falls below the selectable voltage thresholds. A trip signal is transmitted if a voltage pickup exists for a selectable time. In order to ensure that the protection does not accidentally pick up due to a secondary voltage failure, each stage can be blocked individually or both stages can be blocked in common via binary input(s), e.g. by a voltage transformer miniature circuit breaker (m.c.b.). In addition to this, the integrated Fuse–Failure–Monitor blocks both stages (see section 2.38.1.4). When the undervoltage protection has picked up while the relay changes to the operational condition 0 - i.e. no suitable measured quantities are present or the permissible frequency range has been left - pick-up will be sealed in. Thus, trip is ensured even after the voltages have completely collapsed. This seal-in can be cancelled only after the voltage has reverted to a value above the undervoltage dropoff value or by activating the blocking input for undervoltage protection. There is no pickup and trip if no pickup exists before the device is in operating status 0 (thus e.g. upon switchon of the device without present measuring quantities). An immediate tripping may be caused on transition into operating status 1 (i.e. by applying measuring quantities). For this reason, it is recommended to activate the blocking input of the undervoltage protection via the circuit breaker auxiliary contact and to block the protective function in this way, e.g. after a protection tripping.

Figure 2-71 shows the logic diagram of the undervoltage protection.

148

7UM62 Manual C53000-G1176-C149-3


FNo. 06533

U< picked up

4002 U<

4003 T U<

&

FNo. 06539

FNo. 06506

U< TRIP

>BLOCK U<

Tripping matrix

FNo. 06537

U<< picked up 4004 U<<

4005 T U<<

& FNo. 06540

FNo. 06508

TMin TRIP CMD

U<< TRIP

>BLOCK U<< FNo. 000361

>FAIL:Feeder VT

refer Fig. 2-120 in Subsection 2.38.1.4

OR

FFM FNo. 06503

FNo. 06531

>BLOCK U/V

Undervolt. BLK

Figure 2-71

Logic Diagram of the Undervoltage Protection


The undervoltage protection is only effective and accessible if it has been set during the configuration of the protection functions (Section 2.2) at address 0140, UNDERVOLTAGE = Enabled. Set Disabled if the function is not required. Address 4001 UNDERVOLTAGE is used to switch the function ON or OFF, or to block only the trip command (Block Relay).

Setting Values

It must be considered that the positive phase-sequence system of the voltages and thus also the pickup thresholds are evaluated as phase-to-phase quantities (terminal voltage ⋅ √3). The first undervoltage protection stage is typically set to about 75% of % the nominal machine voltage, i.e. address 4002 U< = 75 V. The user must select a value for the 4003 T U< time setting that ensures that voltage dips affecting the operating stability are disconnected. On the other hand, the time delay must be long enough to avoid disconnection in case of permissible short-time voltage dips. For the second stage, a lower pickup threshold 4004 U<< e.g. = 65 V should be combined with a shorter trip time 4005 T U<< e.g. = 0.5 s to perform an approximate adaptation to the stability behaviour of the consumers. All setting times are additional time delays which do not include the operating times (measuring time, drop-out time) of the protective function. The drop-out ratio can be adapted in small steps to the operating conditions at address 4006A U< DOUT RATIO.

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Functions

2.19.2.1 Settings of the Undervoltage Protection Addr.

Setting Title

Setting Options

Default Setting

Comments

4001

UNDERVOLTAGE


OFF


4002

U<

10.0..125.0 V

75.0 V

U< Pickup

4003

T U<

0.00..60.00 sec; ∞

3.00 sec

T U< Time Delay

4004

U<<

10.0..125.0 V

65.0 V

U<< Pickup

4005

T U<<

0.00..60.00 sec; ∞

0.50 sec

T U<< Time Delay

4006A

U< DOUT RATIO

1.01..1.20

1.05

U< Drop Out Ratio

2.19.2.2 Information for the Undervoltage Protection F.No.

Alarm

Comments

06503 >BLOCK U/V

>BLOCK undervoltage protection

06506 >BLOCK U<

>BLOCK undervoltage protection U<

06508 >BLOCK U<<

>BLOCK undervoltage protection U<<

06530 Undervolt. OFF

Undervoltage protection switched OFF

06531 Undervolt. BLK

Undervoltage protection is BLOCKED

06532 Undervolt. ACT

Undervoltage protection is ACTIVE

06533 U< picked up

Undervoltage U< picked up

06537 U<< picked up

Undervoltage U<< picked up

06539 U< TRIP

Undervoltage U< TRIP

06540 U<< TRIP

Undervoltage U<< TRIP

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2.20


General

Overvoltage protection serves to protect the electrical machine, and the associated electrical plant connected to it, from the effects of impermissible voltage increases. Overvoltages can be caused by incorrect manual operation of the excitation system, faulty operation of the automatic voltage regulator, (full) load shedding of a generator, separation of the generator from the system or during island operation.

2.20.1 Functional Description By means of the overvoltage protection feature, the user can select if he wants to monitor the phase-to-phase voltages or the phase-earth-voltages. In case of a high overvoltage, the switchoff is performed with a short-time delay, whereas in case of lower overvoltages, the switchoff is performed with a longer time delay. In this way, the voltage regulator can take the voltage back into the nominal range. The user can specify the voltage limit values and the time delays individually for both stages. Each stage can be blocked individually and/or both stages can be blocked in common via binary input(s). Figure 2-72 shows the logic diagram of the overvoltage protection.

FNo. 06571

U>> picked up 4105 T U>>

Pickup U>>

FNo. 06573

U>> TRIP

&

FNo. 06517

>BLOCK U>>

U> picked up 4103 T U>

Pickup U>

FNo. 06570

U> TRIP

& TMin TRIP CMD

FNo. 06516

>BLOCK U>

FNo. 06513

FNo. 06566

>BLOCK O/V

Overvolt. BLK

Figure 2-72

Tripping matrix

FNo. 06568

Logic Diagram of the Overvoltage Protection


7UM62 Manual C53000-G1176-C149-3

The overvoltage protection is only effective and accessible if it has been set during the configuration of the protective functions (Section 2.2) at address 0141, OVERVOLTAGE = Enabled. Set Disabled if the function is not required. Address 4101 OVERVOLTAGE is used to switch the function ON or OFF, or to block only the trip command (Block Relay).

151

Functions

Address 4107A VALUES U> serves to specify the measured quantities used by the protection feature. The default setting (normal case) is specified for phase-to-phase voltages (= U-ph-ph). The phase-earth-voltages should be selected for low-voltage machines with grounded neutral conductor (= U-ph-e). It should be noted that even if phase-earth voltages are selected as measured quantities, the setting values of the protection functions are referred to phase-to-phase voltages.

Setting Values

The setting of limit values and time delays of the overvoltage protection depends on the speed with which the voltage regulator can regulate voltage variations. The protection must not intervene into the regulation process of the fault-free functioning voltage regulator. For this reason, the two-stage characteristic must always be above the voltage time characteristic of the regulation procedure. The long-time stage 4102 U> and 4103 T U> must intervene in case of steady-state overvoltages. It is set to approximately 110 % to 115 % UN and, depending on the regulator speed, to a range between 1.5 s and 5 s. In case of a full-load rejection of the generator, the voltage increases first in relation to the transient voltage. Only by this time, the voltage regulator reduces it again to its nominal value. The U>>-stage is set as short-time stage in a way that the transient procedure in case of a full-load rejection does not lead to a tripping. For example, for 4104 U>> about 130 % UN with a 4105 T U>> delay of zero to 0.5 s are typical values. All setting times are additional time delays which do not include the operating times (measuring time, drop-out time) of the protective function. The drop-out ratio at the address 4106A U> DOUT RATIO can be adapted in small steps to the operating conditions and used for highly precise signalizations (e.g. network infeed of wind power stations).

2.20.2.1 Settings of the Overvoltage Protection Addr.

Setting Title

Setting Options

Default Setting

Comments

4101

OVERVOLTAGE


OFF


4102

U>

30.0..170.0 V

115.0 V

U> Pickup

4103

T U>

0.00..60.00 sec; ∞

3.00 sec

T U> Time Delay

4104

U>>

30.0..170.0 V

130.0 V

U>> Pickup

4105

T U>>

0.00..60.00 sec; ∞

0.50 sec

T U>> Time Delay

4106A

U> DOUT RATIO

0.90..0.99

0.95

U> Drop Out Ratio

4107A

VALUES U>

Voltage protection with UPhase-Phase Voltage protection with UPhase-earth

Voltage protection with U-PhasePhase

Measurement Values for U>

2.20.2.2 Information for the Overvoltage Protection F.No. 06513 >BLOCK O/V

152

Alarm

Comments >BLOCK overvoltage protection

7UM62 Manual C53000-G1176-C149-3


F.No.

Alarm

Comments

06516 >BLOCK U>

>BLOCK overvoltage protection U>

06517 >BLOCK U>>

>BLOCK overvoltage protection U>>

06565 Overvolt. OFF

Overvoltage protection switched OFF

06566 Overvolt. BLK

Overvoltage protection is BLOCKED

06567 Overvolt. ACT

Overvoltage protection is ACTIVE

06568 U> picked up

Overvoltage U> picked up

06571 U>> picked up

Overvoltage U>> picked up

06570 U> TRIP

Overvoltage U> TRIP

06573 U>> TRIP

Overvoltage U>> TRIP

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Functions

2.21


General

The frequency protection function detects abnormally high and low frequencies in the system. If the frequency lies outside the allowable range, appropriate actions are initiated, such as separating a generator from the system. A decrease in system frequency occurs when the system experiences an increase in the real power demand, or when a malfunction occurs with a generator governor or automatic generation control (AGC) system. The frequency decrease protection is also used for generators which (for a certain time) function on an island network. This is due to the fact that the reverse power protection cannot operate in case of a drive power failure. The generator can be disconnected from the power system by means of the frequency decrease protection. An increase in system frequency occurs when large blocks of load are removed from the system, or again when a malfunction occurs with a generator governor or AGC system. This means a risk of self-excitation for generators feeding long lines under noload conditions. Through the use of filters and repeated measurements, the frequency evaluation is free from harmonic influences and very accurate.

2.21.1 Functional Description Underfrequency and Overfrequency Protection

Frequency protection consists of four frequency elements (f1 to f4). Any given frequency element can be set to pickup for either overfrequency or underfrequency conditions. Each element can be independently set, and utilized to perform different functions within the system. The parameterization determines the individual application purpose of the corresponding stage. For the f4 frequency stage, the user can specify independently of the parameterized limit value if this stage shall function as decrease or increase stage. For this reason, it can also be used for special applications, if, for example, the user desires a signalization in case of a frequency overrange below the nominal frequency.

Operating Ranges

The frequency can be determined as long as the positive sequence voltages are present and of sufficient magnitude. If the measurement voltage drops below a settable value Umin, then frequency protection is blocked, as precise frequency values can no longer be calculated from the signal under these conditions. With the overfrequency protection, there is a seal-in of the overfrequency pickup during the transition to the 0 mode, if the last measured frequency amounted to >66 Hz. The switch-off command drops out by a function blocking or by the transition into operational condition 1. The pickup drops out if the frequency measured last before the transition into operational condition 0 is <66 Hz. With the underfrequency protection, there is no precise frequency calculation during the transition into the 0 mode due to a too low frequency. Consequently, the pickup or tripping drop out.

Timers/Logic

Each frequency element has an associated settable time delay. When a frequency element picks up and the time delay elapses, a trip signal is generated. When a frequency elements drops out, the control signal (tripping or alarm signal) is immediately terminated, but not before the minimum command duration has elapsed. Each of the four frequency elements can be blocked individually by binary inputs.

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Figure 2-73 shows the logic diagram for the frequency protection function.

f1 picked up FNo. 05232...

>BLOCK f1 FNo. 05206...

4202 f1 PICKUP

&

4204 T f1

f

f1 TRIP FNo. 05236...

4215 Umin

U123

U>Umin

Measurement/ Logic

4201 O/U FREQUENCY

FNo. 05214

Freq UnderV Blk

OR

ON

”1”

FNo. 05211

OFF

Freq. OFF FNo. 05213

OR

OR

Freq. ACTIVE

FNo. 05203

FNo. 05212

>BLOCK Freq.

Freq. BLOCKED

Figure 2-73

Logic Diagram of the Frequency Protection


The frequency protection will only be effective and accessible if address 0142 FREQUENCY Prot. has been set to Enabled during the configuration of the protective functions. Set Disabled if the function is not required. Address 4201 O/U FREQUENCY is used to switch the function ON or OFF, or to block only the trip command (Block Relay).

Pick-Up Values

The nominal system frequency is programmed in Power System Data 1, and the pickup settings for each of the frequency elements f1 PICKUP to f4 PICKUP determines whether the function will be used for overfrequency or underfrequency protection. Set the pickup threshold lower than nominal frequency if the element is to be used for underfrequency protection, and higher than nominal frequency if it is to be used for overfrequency protection. Note: If the element is not required, the frequency setting should be set equal to the nominal frequency, in which case the element becomes inactive. For the f4 frequency stage, the previously explained circumstances are only relevant if the 4214 THRESHOLD f4 parameter is set to Automatic (default setting). If desired, this parameter can also be set to f> or f<, in which case the evaluation direction (increase or decrease detection) can be specified independent of the parameterized f4 PICKUP threshold.

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Functions

If underfrequency protection is used for load shedding purposes, then the frequency settings relative to other feeder relays are generally based on the priority of the customers served by the protective relay. Normally a graded load shedding is required that takes into account the importance of the consumers or consumer groups. Further application examples exist in the field of power stations. The frequency values to be set mainly depend, also in these cases, on the specifications of the power system/power station operator. In this context, the frequency decrease protection ensures the power station’s own demand by disconnecting it from the power system on time. The turbo regulator regulates the machine set to the nominal speed. Consequently, the station’s own demands can be continuously supplied at nominal frequency. Under the assumption that the apparent power is reduced to the same degree, turbine-driven generators can, as a rule, be continuously operated down to 95 % of the nominal frequency. However, for inductive consumers, the frequency reduction does not only mean an enhanced current input but also endangers stable operation. For this reason, only a short-time frequency reduction down to about 48 Hz (for fN = 50 Hz) or 58 Hz (for fN = 60 Hz) is permissible. A frequency increase can, for example, occur due to a load shedding or malfunction of the speed regulation (e.g. in an island network). In this way, the frequency increase protection can, for example, be used as overspeed protection. Setting example: Stage

Cause for fN = 50 Hz

Setting Values for fN = 60 Hz

Delays

f1

Disconnection from the network

48.00 Hz

58.00 Hz

1.00 s

f2

Shutdown

47.00 Hz

57.00 Hz

6.00 s

f3

Alarm

49.50 Hz

59.50 Hz

20.00 s

f4

Alarm or tripping

52.00 Hz

62.00 Hz

10.00 s

Delays

The time delays (definite time) T f1 to T f4 entered at addresses 4204, 4207, 4210 and 4213) allow the device to prioritize or sort corrective actions based on the degree to which the actual system frequency departs (upward or downward) from the nominal system frequency. The set times are additional time delays not including the operating times (measuring time, drop-out time) of the protective function.

Minimum Voltage

Address 4215 Umin is used to set the minimum voltage. If the positive sequence voltage is less than this value, the frequency protection is blocked. The recommended value is approx. 65 % UN. The minimum voltage limiting can be deactivated by means of the”0” setting.

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2.21.2.1 Settings for the Frequency Protection

Addr.

Setting Title

Setting Options

Default Setting

Comments

4201

O/U FREQUENCY


OFF

Over / Under Frequency Protection

4202

f1 PICKUP

40.00..65.00 Hz

48.00 Hz

f1 Pickup

4203

f1 PICKUP

40.00..65.00 Hz

58.00 Hz

f1 Pickup

4204

T f1

0.00..600.00 sec

1.00 sec

T f1 Time Delay

4205

f2 PICKUP

40.00..65.00 Hz

47.00 Hz

f2 Pickup

4206

f2 PICKUP

40.00..65.00 Hz

57.00 Hz

f2 Pickup

4207

T f2

0.00..100.00 sec

6.00 sec

T f2 Time Delay

4208

f3 PICKUP

40.00..65.00 Hz

49.50 Hz

f3 Pickup

4209

f3 PICKUP

40.00..65.00 Hz

59.50 Hz

f3 Pickup

4210

T f3

0.00..100.00 sec

20.00 sec

T f3 Time Delay

4211

f4 PICKUP

40.00..65.00 Hz

52.00 Hz

f4 Pickup

4212

f4 PICKUP

40.00..65.00 Hz

62.00 Hz

f4 Pickup

4213

T f4

0.00..100.00 sec

10.00 sec

T f4 Time Delay

4214

THRESHOLD f4

Freq. prot. stage automatic Freq. prot. stage overfreqency Freq. prot. stage underfreqency

Freq. prot. stage automatic

Handling of Threshold Stage f4

4215

Umin

10.0..125.0 V; 0

65.0 V

Minimum Required Voltage for Operation

2.21.2.2 Information for Frequency Protection F.No.

Alarm

Comments

05203 >BLOCK Freq.

>BLOCK frequency protection

05206 >BLOCK f1

>BLOCK stage f1

05207 >BLOCK f2

>BLOCK stage f2

05208 >BLOCK f3

>BLOCK stage f3

05209 >BLOCK f4

>BLOCK stage f4

05211 Freq. OFF

Frequency protection is OFF

05212 Freq. BLOCKED

Frequency protection is BLOCKED

05213 Freq. ACTIVE

Frequency protection is ACTIVE

05214 Freq UnderV Blk

Frequency protection undervoltage Blk

05232 f1 picked up

f1 picked up

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Functions

F.No.

Alarm

Comments

05233 f2 picked up

f2 picked up

05234 f3 picked up

f3 picked up

05235 f4 picked up

f4 picked up

05236 f1 TRIP

f1 TRIP

05237 f2 TRIP

f2 TRIP

05238 f3 TRIP

f3 TRIP

05239 f4 TRIP

f4 TRIP

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2.22


General

The overexcitation protection is used to detect impermissible overexcitation conditions which can endanger generators and transformers. The overexcitation protection must pick up when the induction admissible for the protected object (e.g. power station unit transformer) is exceeded. The transformer is endangered, for example, if the power station block is disconnected from the system from full-load, and if the voltage regulator either does not operate or does not operate sufficiently fast to control the associated voltage rise. Similarly, decrease in frequency (speed), e.g. in island systems, can endanger the transformer because of increased induction. An increase in induction above the rated values leads very quickly to saturation of the iron core and to large eddy current losses.

2.22.1 Functional Description Measuring Procedure

The overexcitation protection feature servers to measure the voltage/frequency ratio which is proportional to the B induction and puts it in relation to the BN nominal induction. In this context, both voltage and frequency are related to nominal values of the object to be protected (generator, transformer). U B ∼ ---f U --------------------U B U N Mach -------------------- = -------------------- = ---B N Mach f f ----fN

(simplified notation)

The calculation is based on the maximum voltage of the three phase-to-phase voltages. The frequency range from 10 Hz to 70 Hz can be monitored in this way. Transformer Adaptation

A perhaps existing deviation between the primary nominal voltage of the voltage transformers and the object to be protected is compensated by means of the internal correction factor (UN prim/UN mach). For this reason, pick-up values and characteristics do not need to be converted to secondary values. As a prerequisite, however, the system quantities ’primary nominal transformer voltage’ and ’nominal voltage of the object to be protected’ must be entered correctly (see Sections 2.3 and 2.5).

Characteristics

The overexcitation protection feature includes two staged characteristics and one thermal characteristic for an approximate modeling of the heating which the overexcitation may cause to the object to be protected. As soon as a first pickup threshold (warning stage 4302 U/f >) has been exceeded, a 4303 T U/f > time stage starts. A warning message is transmitted subsequent to the expiration of this time stage. A counter switching is activated when the pickup threshold is exceeded. This weighted counter is incremented according to the present U/f value. Consequently, the trip time results from the parameterized characteristic. A trip signal is transmitted as soon as the trip counter state has been reached. The trip signal is canceled as soon as the value falls below the pickup threshold and the counter is decremented according to a parameterizeable cool-down time selection.

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Functions

The thermal characteristic is prespecified by 8 value pairs concerning the U/f overexcitation (related to nominal values) and the t trip time. In most cases, the specified characteristic related to standard transformers provides for sufficient protection. If this characteristic does not correspond to the actual thermal behavior of the object to be protected, each desired characteristic can be implemented by entering customer-specific trip times for the specified U/f overexcitation values. Intermediate values are determined by a linear interpolation within the device. The characteristic resulting from the device default settings is shown in Figure 4-13 in the Technical Data, Section 4.18. Figure 2-74 illustrates the behaviour of the protection on the assumption that within the framework of configuration the setting for the pickup threshold (parameter 4302 U/f >) was chosen higher or lower than the first setting value of the thermal characteristic.

T t 1.05

a) Pickup threshold U/f > is less than the 1st setting value of the thermal characteristic

Pickup threshold U/f > (parameter 4302) 1. Setting value of thermal characteristic

Tripping area Thermal trip stage Overexcitation trip stage U/f >>

T U/f >>

1.0 1.05 1.10

1.20

1.30

1.40

F#

U/f >> (Setting of stepped characteristic)

t t 1.05

b) Pickup threshold U/f > is greater than the 1st setting value of the thermal characteristic

Pickup threshold U/f > (parameter 4302) 1. Setting value of thermal characteristic

Tripping area Thermal trip stage Overexcitation trip stage U/f >>

T U/f >>

1.0 1.05 1.10

1.20

1.30

1.40

U/f

U/f >> (Setting of stepped characteristic)

Figure 2-74

160

Tripping Time Characteristic of the Overexcitation Protection

7UM62 Manual C53000-G1176-C149-3


Figure 2-75 illustrates the logic diagram of the overexcitation protection. The counter can be reset to zero by means of a blocking input or a reset input.

FNo. 05370

U/f> picked up 4302 U/f >

4303 T U/f >

FNo. 05367

&

U/f> warn Tripping matrix

U f

U/f

U/f heating

1

U/f cool down

2

t(U/f) Reset counter=0

& FNo. 05372

U/f> th.TRIP

OR 4304 U/f >>

4305 T U/f >>

FNo. 05371

U/f>> TRIP

& FNo. 05357

FNo. 05373

>RM th.rep. U/f

U/f>> pick.up

TMin TRIP CMD

FNo. 05369

RM th.rep. U/f FNo. 05353

FNo. 05362

>U/f BLOCK

U/f> BLOCKED

Figure 2-75

Logic Diagram of the Overexcitation Protection


The overexcitation protection is only effective and accessible if it has been set during the configuration of the protective functions at 0143 OVEREXC. PROT. = Enabled. Set Disabled if the function is not required. Address 4301 OVEREXC. PROT. is used to switch the function ON or OFF, or to block only the trip command (Block Relay). The overexcitation feature serves to measure the voltage/frequency quotient proportional to the B induction. The overexcitation protection must pick up when the induction admissible for the protected object (e.g. power station unit transformer) is exceeded. The transformer is endangered, if, for example, the power station block is switched off at full-load operation and the voltage regulator does not respond at all or does not respond fast enough to avoid the related voltage increase. Similarly, a decrease in frequency (speed), e.g. in island systems, can endanger the transformer because of increased induction. In this way, the U/f protection monitors the correct function both of the voltage regulators and of the speed regulation in all operating states.

Independent Stages

The limit-value setting at address 4302 U/f > is based on the induction limit value relation to the nominal induction (B/BN) specified by the manufacturer of the object to be protected. A pickup message is transmitted as soon as the induction limit value U/f set at address 4302 is exceeded. A warning message is transmitted subsequent to the corresponding 4303 T U/f > time delay.

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Functions

The 4304 U/f >>, 4305 T U/f >> trip stage characteristic serves to switch off particularly strong overexcitations within a short time. The time set for this purpose is an additional time delay which does not include the operating time (measuring time, drop-out time). Thermal Characteristic

A thermal characteristic is superimposed to the trip stage characteristic. For this purpose, the overtemperature created by the overexcitation is approximately modeled. Not only the already mentioned pickup signalization is generated on exceeding the protection U/f induction limit value set at address 4302 but a counter is tripped additionally. Depending on the set characteristic, this counter provokes the tripping after the specified time. t [s]

U⁄f ----------------UN ⁄ fN Figure 2-76

Tripping Time Characteristic of the Overexcitation Protection – Presettings

The characteristic of a Siemens standard transformer was selected as a presetting for the parameters 4306 to 4313. If the manufacturer of the object to be protected did not include any instructions on this subject, the preset standard characteristic should be used. Otherwise, any trip characteristic can be specified by point-wise entering of parameters by maximally 7 straight lengths. To do this, the trip times of the overexcitation values U/f = 1.05; 1.10; 1.15; 1.20; 1.25; 1.30; 1.35 and 1.40 are read out from the predefined characteristic and entered at the addresses 4306 t(U/ f=1.05) to 4313 t(U/f=1.40). The protective relay executes a linear interpolation between the points. Limitation

The model of the heating of the object to be protected is limited to a 150 % trip temperature overrange.

Time for Cool Down

The tripping by the thermal image drops out by the time of the pickup threshold dropout. However, the counter content is reset to zero with the cool-down time parameterized at address 4314 T COOL DOWN. In this context, this parameter is defined as the time required by the thermal image to cool down from 100 % to 0 %.

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Voltage Transformer Adaptation

A perhaps existing deviation between the primary nominal voltage of the voltage transformers and the object to be protected is compensated by means of the internal correction factor (UN prim/UN mach). As a prerequisite, however, the incoming power system parameters 0221 Unom PRIMARY and 0251 UN GEN/MOTOR must have been entered correctly according to the Section 2.3.

2.22.2.1 Settings of the Overexcitation Protection Addr.

Setting Title

Setting Options

Default Setting

Comments

4301

OVEREXC. PROT.


OFF


4302

U/f >

1.00..1.20

1.10

U/f > Pickup

4303

T U/f >

0.00..60.00 sec; ∞

10.00 sec

T U/f > Time Delay

4304

U/f >>

1.00..1.40

1.40

U/f >> Pickup

4305

T U/f >>

0.00..60.00 sec; ∞

1.00 sec

T U/f >> Time Delay

4306

t(U/f=1.05)

0..20000 sec

20000 sec

U/f = 1.05 Time Delay

4307

t(U/f=1.10)

0..20000 sec

6000 sec


4308

t(U/f=1.15)

0..20000 sec

240 sec


4309

t(U/f=1.20)

0..20000 sec

60 sec


4310

t(U/f=1.25)

0..20000 sec

30 sec


4311

t(U/f=1.30)

0..20000 sec

19 sec


4312

t(U/f=1.35)

0..20000 sec

13 sec


4313

t(U/f=1.40)

0..20000 sec

10 sec


4314

T COOL DOWN

0..20000 sec

3600 sec


2.22.2.2 Information from the Overexcitation Protection F.No.

Alarm

Comments

05353 >U/f BLOCK

>BLOCK overexcitation protection

05357 >RM th.rep. U/f

>Reset memory of thermal replica U/f

05361 U/f> OFF

Overexcitation prot. is swiched OFF

05362 U/f> BLOCKED

Overexcitation prot. is BLOCKED

05363 U/f> ACTIVE

Overexcitation prot. is ACTIVE

05369 RM th.rep. U/f

Reset memory of thermal replica U/f

05367 U/f> warn

Overexc. prot.: U/f warning stage

05370 U/f> picked up

Overexc. prot.: U/f> picked up

05373 U/f>> pick.up

Overexc. prot.: U/f>> picked up

05371 U/f>> TRIP

Overexc. prot.: TRIP of U/f>> stage

05372 U/f> th.TRIP

Overexc. prot.: TRIP of th. stage

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Functions

2.23


General

The inverse-time undervoltage protection mainly protects consumers (induction machines) from the consequences of dangerous voltage drops in island networks and prevents impermissible operating conditions and possible loss of stability. It can also be used as a criterion for load shedding in interconnected networks. Two-pole short circuits or earth faults cause an asymmetrical voltage collapse. Compared with three monophase measuring systems, the detection of the positive phase-sequence system is not influenced by these procedures and is advantageous especially with regard to the judgement of stability problems.

2.23.1 Functional Description Measured Quantity

For the above reasons, the positive sequence system is calculated from the fundamental waves of the three phase-earth voltages, and fed to the protection. The measured voltages are filtered by numerical filter algorithms; the fundamental wave is paramount. Where voltage transformers in broken delta (V) connection are available on the plant side, the protection is applied to the phase-to-phase voltages; the internal starpoint is left empty. By this a virtual starpoint is formed, so that the (virtual) phase-to-earth voltages can still be detected (see connection example in Figure A-34 in the Appendix A.4).


The protection can be matched exactly to the stability characteristic by means of a voltage-time integral-action characteristic. If a motor falls into the unstable area below the curve, it will stall or run at substantially reduced speed, even if full voltage is restored after a short time. Only squirrel-cage machines for which the torque characteristic of the driven machine lies below the motor characteristic at all speeds will regain their rated speed. All other machines will be thermally and perhaps mechanically overstressed during an attempt to return to full speed after return of voltage. Undervoltage protection consists of an inverse time element. In order to avoid malfunction of the protection in the event of secondary voltage failure, it can be blocked via a binary input, e.g. by the auxiliary contact of a voltage transformer miniature circuit breaker or from the position of the main circuit breaker when the machine is at stand-still. In addition to this, the integrated fuse failure monitor (FFM) blocks both stages (see Section 2.38.1.4). If no measured values are available at the device (operation condition 0), no trip signal is given if there was no pickup. This ensures that the undervoltage protection does not pick up at once when it is switched on with no measured value available. Once the protection has been activated, it can only be deactivated by triggering the blocking input. If a pickup signal is present when the device enters operating condition 0 (i.e. no measured values, or frequency outside the permissible range), it is sealed in. The delay time until tripping is calculated in the same way as for a drop to 0 V. The sealedin pickup or tripping signal is only reset if the voltage is restored, or if the blocking input is triggered.

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The pickup/dropout ratio is 101 % or 0.5 V absolute of the threshold set at address 4402 Up< PICKUP. The integral action of the tripping time determination is “frozen“ between the pickup and the dropout value. Figure 2-77 shows the logic diagram of the inverse undervoltage protection.

FNo. 06525

Up< picked up FNo. 06526 4403 T MUL

Up< ch. pick.up

U

Tripping matrix

4404 T Up<

4402 Up< PICKUP

U1

T

& FNo. 06520

FNo. 06523

>BLOCK Up<

Up< BLOCK

FNo. 06527

Up< TRIP TMin TRIP CMD


Figure 2-77

Logic Diagram of the Inverse-Time Undervoltage Protection


The inverse overvoltage protection is only effective and accessible if it has been set during the configuration of the protective functions (Section 2.2, address 0144, INV.UNDERVOLT. = Enabled). Set Disabled if the function is not required. Address 4401 INV. UNDERVOLT. is used to switch the function ON or OFF, or to block only the trip command (Block Relay).

Setting Values

It must be considered that the positive phase-sequence system of the voltages and thus also the pickup thresholds are evaluated as phase-to-phase quantities (terminal voltage ⋅ √3). For the pickup values no hard and fast rules can be laid down. But since the protection is used mainly to protect consumers (induction machines) from the consequences of voltage drops, and to prevent loss of stability, the pickup value is normally set to approx. 75 % of the nominal machine voltage, i.e. address 4402 Up< PICKUP is set to 75 V. In exceptional cases, where the voltage drop during startup is too big, it may be necessary to set lower values. The time multiplier 4403 T MUL must be selected such that voltage drops that would lead to unstable operation are reliably disconnected. On the other hand, the time delay must be big enough to avoid disconnections in case of permissible short-time voltage dips. If required, the tripping time can also be extended by an additional time stage 4404 T Up<. All setting times are additional time delays which do not include the operating times (measuring time, drop-out time) of the protective function.

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Functions

2.23.2.1 Settings of the Inverse Undervoltage Protection Addr.

Setting Title

Setting Options

Default Setting

Comments

4401

INV. UNDERVOLT.


OFF


4402

Up< PICKUP

10.0..125.0 V

75.0 V

Up< Pickup

4403

T MUL

0.10..5.00 sec; 0

1.00 sec

Time Multiplier for Characteristic

4404

T Up<

0.00..60.00 sec; ∞

0.00 sec

T Up< Time Delay

2.23.2.2 Information for the Inverse Undervoltage Protection F.No.

Alarm

Comments

06520 >BLOCK Up<

>BLOCK inverse undervoltage protection

06522 Up< OFF

Inv. Undervoltage prot. is switched OFF

06523 Up< BLOCK

Inv. Undervoltage protection is BLOCKED

06524 Up< ACTIVE

Inv. Undervoltage protection is ACTIVE

06525 Up< picked up

Inverse Undervoltage Up< picked up

06526 Up< ch. pick.up

Inv. Undervoltage Up<-char. picked up

06527 Up< AUS

Inverse Undervoltage Up< TRIP

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2.24


General

With the rate-of-frequency-change protection, frequency changes can be quickly detected. This allows a prompt response to frequency dips or frequency rises. A trip command can be issued even before the pickup threshold of the frequency protection (see Section 2.21) is reached. Frequency changes occur, for instance, when there is an unbalance between the produced and the necessary active power. They call for control measures on one hand and for switching actions on the other hand. These can be relief measures, such as network decoupling, or disconnection of loads (load shedding). The sooner these measures are taken after a malfunction appears, the more effective they are. The two main applications for this protection function is thus network decoupling and load shedding.


From the positive-sequence voltage, the frequency is determined once per cycle over a measuring window of 3 cycles, and a mean value of two successive frequency measurements is formed. The frequency difference is then determined over a settable time interval (default setting 5 cycles). The ratio between frequency difference and time difference is equivalent to the frequency change; it can be positive or negative. The measurement is performed continuously (per cycle). Monitoring functions such as undervoltage monitoring, checks for phase angle jumps etc. help to avoid overfunctioning.

Frequency Increase/ Decrease

The rate-of-frequency-change protection has four stages, from df1/dt to df4/dt. This allows to adapt the function variably to all power system conditions. The stages can be set to detect either frequency decreases (-df/dt<) or frequency increases (+df/dt>). The -df/dt stage is only active for frequencies below the rated frequency, or less if the underfrequency release is activated. Likewise, the df/dt> stage is active for frequencies above the rated frequency, or higher, if the overfrequency release is activated. The parameter setting decides where a stage will be used. To avoid a proliferation of setting parameters, the settable measuring window for the frequency difference formation and the dropout difference are each valid for two stages.

Operating Ranges

The frequency can be determined as long as there is a sufficiently strong positive sequence system of voltages. If the measuring voltage drops below a settable value Umin, the frequency protection is blocked because the signal allows under such conditions no precise calculation of the frequency values.

Time Delays/Logic

Tripping can be delayed by a set time delay associated with each frequency element. This is recommended for monitoring of small gradients. A trip command is generated as soon as a time delay has expired. After the pickup has reset, the trip command is immediately reset as well, but the trip signal is maintained for at least the minimum command duration. Each of the four frequency change stages can be blocked individually by binary input. The undervoltage blocking acts on all stages simultaneously. Figure 2-78 shows the logic diagram.

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Functions

f4 f3 f2 5516 df1/dt pickup

f1

5517 df2/dt pickup OFF

5518 df3/dt pickup

ON

OR

&

"1"

5519 df4/dt pickup

4505 df1/dt & f1 5520 df1/dt TRIP

5232 f1 picked up

5521 df2/dt TRIP

-df/dt<

5522 df3/dt TRIP

+df/dt> "1" 4504 T df1/dt

4502 df1/dt >/< & OR

4503 STAGE df1/dt df/dt

&

df/dt≤

Tripping matrix Tmin TRIP CMD

f≤fn df/dt

5523 df4/dt TRIP

df/dt≥ &

f≥fn 5504 >df1/dt block

5503 >df/dt block

5512 df/dt BLOCKED

OR 4518 U MIN U1

5514 df/dt U< block

U1≤

Figure 2-78 Logic Diagram of the Rate-of-Frequency-Change Protection


The rate-of-frequency-change protection is only effective and accessible if during the configuration address 145 df/dt Protect. has been set accordingly. 2 or 4 stages can be selected. The default setting is 2 df/dt stages. Address 4501 df/dt Protect. allows to switch the function ON or OFF, or to block only the trip command (Block relay).

Pickup Values

The setting procedure is the same for all stages. In a first step, it must be determined whether the stage is to monitor a frequency rise at f>fN or a frequency drop at f< fN. For stage 1, for instance, this setting is made at address 4502 df1/dt >/<. The pickup value is set as an absolute value at address 4503 STAGE df1/dt. The setting of address 4502 informs the protection function of the applicable sign. The pickup value depends on the application and is determined by power system conditions. In most cases, a network analysis will be necessary. A sudden disconnection of loads leads to a surplus of active power. The frequency rises and causes a positive frequency change. A failure of generators, on the other hand, leads to a deficit of active power. The frequency drops and leads to a negative frequency change.

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The following relations can be used as an example for estimation of the pickup value. They apply for the change rate at the beginning of a frequency change (approx. 1 second). f N ∆P df ----- = – --------- ⋅ -------dt 2 H SN Meaning: fN

Rated frequency

∆P Active power change ∆P = PConsumption – PGeneration SN Rated apparent machine power H

Inertia constant

Typical values for H are: – for hydro-electric generators (salient-pole machines) – for turbine-driven generators (cylindrical-rotor machines) – for industrial turbine-generators

H = 1.5 s to 6 s H = 2 s to 10 s H = 3 s to 4 s

Example: fN = 50 Hz H=3s Case 1: ∆P/SN = 0.12 Case 2: ∆P/SN = 0.48 Case 1: df/dt = –1 Hz/s Case 2: df/dt = –4 Hz/s The default settings are based on the above example. The four stages have been set symmetrically. Delay Times

The delay time should be set to zero wherever the protection function is supposed to respond very quickly. This will be the case with high setting values. For the monitoring of small changes (< 1Hz/s), on the other hand, a small delay time can be useful to avoid overfunctioning. The delay time is set at address 4504 T df1/dt, and the time set there is added to the protection operating time.

Release by the Frequency Protection

The parameter df1/dt & f1 (address 4505) is used to set the release of the stage from a certain frequency threshold on. For this the pertinent frequency stage of the frequency protection (Section 2.21) is queried. In the setting example this is stage f1. To exclude coupling of the two functions, the parameter can be set to OFF (default setting).

Advanced Parameters

The advanced parameters allow to set for two stages each (e.g. df1/dt and df2/dt) the dropout difference and the measuring window. These parameters can only be set with the DIGSI communication software. Setting changes are necessary e.g. to obtain a great dropout difference. For the detection of very small frequency changes (<0.5 Hz/s), the default setting of the measuring window should be extended to improve the measuring accuracy.

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Functions

Table 2-12

Minimum Voltage

Setting Value stage dfn/dt

df/dt HYSTERESIS (Addr. 4519A, 4521A)

dfx/dt M WINDOW (Addr. 4520A, 4522A)

0.1...0.5 Hz/s

≈ 0,05

25...10

0.5...1 Hz/s

≈ 0,1

10...5

1...5 Hz/s

≈ 0,2

10...5

5...20 Hz/s

≈ 0,5

5...1

Address 4518 U MIN is used to set the minimum voltage below which the frequency change protection will be blocked. A value of approx. 65 % UN is recommended. The minimum voltage threshold can be deactivated by setting this address to „0“.

2.24.2.1 Settings of the Rate-of-Frequency-Change Protection Addr.

Setting Title

Setting Options

Default Setting

Comments

4501

df/dt Protect.


OFF


4518

U MIN

10.0..125.0 V; 0

65.0 V

Minimum Operating Voltage Umin

4519A

df1/2 HYSTERES.

0.02..0.99 Hz/s

0.10 Hz/s

Reset Hysteresis for df1/dt & df2/dt

4520A

df1/2 M-WINDOW

1..25 Cycle

5 Cycle

Measuring Window for df1/dt & df2/dt

4521A

df3/4 HYSTERES.

0.02..0.99 Hz/s

0.40 Hz/s


4522A

df3/4 M-WINDOW

1..25 Cycle

5 Cycle

Measuring Window for df3/dt & df4/dt

4502

df1/dt >/<

-df/dt< negative rate of freq. change +df/dt> positive rate of freq. change

-df/dt< negative rate of freq. change

Mode of Threshold (df1/dt >/<)

4503

STAGE df1/dt

0.1..10.0 Hz/s; ∞

1.0 Hz/s

Pickup Value of df1/dt Stage

4504

T df1/dt

0.00..60.00 sec; ∞

0.50 sec

Time Delay of df1/dt Stage

4505

df1/dt & f1

OFF ON

OFF

AND logic with pickup of stage f1

4506

df2/dt >/<




4507

STAGE df2/dt

0.1..10.0 Hz/s; ∞

1.0 Hz/s


4508

T df2/dt

0.00..60.00 sec; ∞

0.50 sec


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7UM62 Manual C53000-G1176-C149-3


Addr.

Setting Title

Setting Options

Default Setting

Comments

4509

df2/dt & f2

OFF ON

OFF


4510

df3/dt >/<




4511

STAGE df3/dt

0.1..10.0 Hz/s; ∞

4.0 Hz/s


4512

T df3/dt

0.00..60.00 sec; ∞

0.00 sec


4513

df3/dt & f3

OFF ON

OFF


4514

df4/dt >/<




4515

STAGE df4/dt

0.1..10.0 Hz/s; ∞

4.0 Hz/s


4516

T df4/dt

0.00..60.00 sec; ∞

0.00 sec


4517

df4/dt & f4

OFF ON

OFF


2.24.2.2 Information for the Rate-of-Frequency-Change Protection F.No.

Alarm

Comments

05503 >df/dt block

>BLOCK Rate-of-frequency-change prot.

05504 >df1/dt block

>BLOCK df1/dt stage

05505 >df2/dt block

>BLOCK df2/dt stage

05506 >df3/dt block

>BLOCK df3/dt stage

05507 >df4/dt block

>BLOCK df4/dt stage

05511 df/dt OFF

df/dt is switched OFF

05512 df/dt BLOCKED

df/dt is BLOCKED

05513 df/dt ACTIVE

df/dt is ACTIVE

05514 df/dt U< block

df/dt is blocked by undervoltage

05516 df1/dt pickup

Stage df1/dt picked up

05517 df2/dt pickup


05518 df3/dt pickup


05519 df4/dt pickup


05520 df1/dt TRIP

Stage df1/dt TRIP

05521 df2/dt TRIP

Stage df2/dt TRIP

05522 df3/dt TRIP

Stage df3/dt TRIP

05523 df4/dt TRIP

Stage df4/dt TRIP

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Functions

2.25


General

It is not uncommon that consumers with their own generating plant feed power directly into a network. The incoming feeder is usually the ownership boundary between the utility and these consumers/producers. A failure of the input line, e.g. because of a three-pole automatic reclosure, can cause a deviation of the voltage or frequency at the feeding generator which is a function of the overall output. When the incoming feeder line is switched on again after the dead time, it may meet with asynchronous conditions which cause damage to the generator or the gear train between generator and drive. One criterion for identifying an interruption of the incoming feeder is the monitoring of the phase angle in the voltage. In case of a failure of the incoming feeder, the abrupt current interruption causes a phase angle jump in the voltage. This jump is detected by means of a delta process. As soon as a preset threshold is exceeded, an opening command for the generator or bustie coupler circuit-breaker is issued. This means that the vector jump function is mainly used for network decoupling. Figure 2-79 shows the evolution of the frequency when a load is disconnected from a generator. Opening of the generator circuit breaker causes a phase angle jump that can be observed in the frequency measurement as a frequency jump. The generator is accelerated in accordance with the power system conditions (see also Section 2.24 Rate-of-Frequency-Change Protection).

Hz 7

f-fn 6

5

4

3

2

1

0 -1.00

-0.75

-0.50

-0.25

0.00

0.25

0.50

0.75

1.00

1.25

1.50

1.75

2.00

t

s

Figure 2-79 Evolution of the Frequency after Disconnection of a Load (Fault recording with 7UM6 - the figure shows the deviation from the rated frequency)

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7UM62 Manual C53000-G1176-C149-3



The vector of the positive sequence system voltage is calculated from the phase-toearth voltages, and the phase angle change of the voltage vector is determined over a delta interval of 2 cycles. The presence of a phase angle jump is an indicator for an abrupt change of the current flow. The basic principle is shown in Figure 2-80. The diagram on the left shows a steady state, and the diagram on the right the vector change following a load shedding. The vector jump is clearly visible.

∆U

∆U I1

I2

I1'

Z Gen

~

Z Gen U

Z

Network

Z

NET

Up

~

U

U

Z

U

∆U

Z

NET

U'

∆U

Up

Up Network/Load

Generator

Network

φ

Network/Load Generator

∆φ

Figure 2-80 Voltage Vector Following a Load Shedding

The function features a number of additional measures to avoid spurious tripping, such as: − Correction of steady-state deviations from rated frequency − Frequency operating range limited to fN ± 3 Hz − Detection of internal sampling frequency changeover − Minimum voltage for release − Blocking on voltage connection or disconnection Logic

Figure 2-81 shows the logic diagram. The phase angle comparison determines the angle difference, and compares it with the set value. If this value is exceeded, the vector jump is stored in an RS flip-flop. Tripping can be delayed by the associated time delay. The stored pickup can be reset via a binary input, or automatically by a timer (address 4604 T RESET).

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Functions

The vector jump function becomes ineffective on leaving the permissible frequency band. The same is true for the voltage, for which the limiting parameters are U MIN and U MAX. On violation of the frequency or voltage band, the logic generates a logical “1”, and the reset input is continuously active. The result of the vector jump measurement is suppressed. If, for instance, the voltage is connected, and the frequency band is correct, the logical “1” changes to “0”. The timer T BLOCK with reset delay keeps the reset input active for a certain time, and thus prevents a pickup caused by the vector jump function. If a short-circuit causes the voltage to drop abruptly to a low value, the reset input is immediately activated to block the function. The vector jump function is thus prevented from causing a trip.

5586 VEC JUMP pickup

5587 VEC JUMP TRIP

4602 DELTA PHI 4603 T DELTA PHI Angle comparison with three measuring points n-2, n-1, n

∆φn

S

Q Tmin TRIP CMD

R

5581 >VEC JUMP block

OR

Tripping matrix

4604 T RESET

5583 VEC JMP BLOCKED frated

3 Hz f<(frated-3 Hz)

f +

frated

3 Hz

4607 T BLOCK

f>(frated+3 Hz)

f

OR

0

T

5585 VEC JUMP Range

4605 U MIN U1
U1

4606 U MAX

U1

Figure 2-81

U1>U MAX

Logic Diagram of the Vector Jump Detection


The vector jump function is only effective and accessible if address 0146 VECTOR JUMP has been set to Enabled during configuration. Address 4601 VECTOR JUMP is used to switch the function ON or OFF, or to block only the trip command (Block relay).

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7UM62 Manual C53000-G1176-C149-3


Pickup Values

The value to be set for the vector jump (address 4602 DELTA PHI) depends on the feeding and load conditions. Abrupt load changes in the active power cause a jump of the voltage vector. The value to be set must be specifically determined for the power system considered. This can be done on the basis of the equivalent circuit diagram in Figure 2-80, or by means of a network calculation software. If the setting is too sensitive, the protection function is likely to perform a network decoupling every time loads are connected or disconnected. Therefore, the default setting is 10°. The permissible voltage operating range can be set in the addresses 4605A for U MIN and 4606A for U MAX. The limit values of the setting range are to some extent a matter of the utility’s philosophy. The value for U MIN should be less than the permissible level of short voltage dips for which network decoupling is required. The default setting is 80 % of the rated voltage. U MAX should be the maximum permissible voltage. This will be in most cases 130 % of the rated voltage. The time delay T DELTA PHI (address 4603) should be left at zero, except if you wish to transmit the trip indication with a delay to a logic (CFC), or to leave enough time for an external blocking to take effect.

Time Delays

After expiry of the timer T RESET (address 4604), the protection function is automatically reset. The reset time depends on the decoupling philosophy. It must have expired before the circuit breaker is reclosed. Where the automatic reset function is not used, the timer is set to ∞. The reset signal must come in that case from the binary input (circuit breaker auxiliary contact). The timer T BLOCK with reset delay (address 4607A) helps to avoid overfunctioning when voltages are connected or disconnected. Normally, the default setting need not be changed. If changes are necessary, they can be performed with the DIGSI communication software (advanced parameters). It must be kept in mind that T BLOCK should always be set to more than the measuring window for vector jump measurement (2 cycles).

2.25.2.1 Settings of the Vector Jump Detection Addr.

Setting Title

Setting Options

Default Setting

Comments

4601

VECTOR JUMP


OFF


4602

DELTA PHI

2..30 °

10 °

Jump of Phasor DELTA PHI

4603

T DELTA PHI

0.00..60.00 sec; ∞

0.00 sec

T DELTA PHI Time Delay

4604

T RESET

0.10..60.00 sec; ∞

5.00 sec

Reset Time after Trip

4605A

U MIN

10.0..125.0 V

80.0 V

Minimal Operation Voltage U MIN

4606A

U MAX

10.0..170.0 V

130.0 V

Maximal Operation Voltage U MAX

4607A

T BLOCK

0.00..60.00 sec; ∞

0.10 sec

Time Delay of Blocking

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Functions

2.25.2.2 Information for the Vector Jump Detection F.No.

Alarm

Comments

05581 >VEC JUMP block

>BLOCK Vector Jump

05582 VEC JUMP OFF

Vector Jump is switched OFF

05583 VEC JMP BLOCKED

Vector Jump is BLOCKED

05584 VEC JUMP ACTIVE

Vector Jump is ACTIVE

05585 VEC JUMP Range

Vector Jump not in measurement range

05586 VEC JUMP pickup

Vector Jump picked up

05587 VEC JUMP TRIP

Vector Jump TRIP

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2.26


General

The stator earth fault protection detects earth faults in the stator windings of threephase machines. The machine can be operated in busbar connection (directly connected to the network) or in unit connection (via unit transformer). The criterion for the occurrence of an earth fault is mainly the occurrence of a neutral displacement voltage. This principle results in a protected zone of 90 % to 95 % of the stator winding.

2.26.1 Functional Description Displacement Voltage

The displacement voltage UE can be measured either at the machine starpoint via voltage transformers or neutral earthing transformers (Figure 2-82) or via the e-n winding (broken delta winding) of a voltage transformer set or the measurement winding of a line connected earthing transformer (Figure 2-83). Since the neutral earthing transformer or the line connected earthing transformer usually supply a displacement voltage of 500 V (with full displacement), a voltage divider 500 V/100 V is to be connected in such cases. If the displacement voltage can not be directly applied to the device, the device calculates the displacement voltage from the phase-to-ground voltages. Address 0223 UE CONNECTION serves for specifying the way the displacement voltage is to be measured or calculated. In all kinds of displacement voltage formation, the components of the third harmonic in each phase are summed since they are in phase in the three-phase system. In order to obtain reliable measured quantities, only the fundamental of the displacement voltage is evaluated in the stator earth fault protection. Harmonics are filtered out by numerical filter algorithms. For machines in unit connection the evaluation of the displacement voltage is sufficient. The achieved sensitivity of the protection is only limited by power frequency interference voltages during an earth fault in the network. These interference voltages are transferred to the machine side via the coupling capacitances of the unit transformer. If necessary, a loading resistor can be provided to reduce these interference voltages. The protection initiates disconnection of the machine when an earth fault in the machine zone has been present for a set time.

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Functions

CK

CG

CL

CTr

RB RT UE

7UM62

RB – Loading resistor RT – Voltage divider UE – Displacement voltage

Figure 2-82

CG – CL – CTr – CK –

Generator earth capacitance Line earth capacitance Unit transformer earth capacitance Coupling capacitance of unit transformer

Unit Connected Generator with Neutral Earthing Transformer

CK

CG

RB RT UE CG CL CTr CK

– – – – – – –

Loading resistor Voltage divider Displacement voltage Generator earth capacitance Line earth capacitance Unit transformer earth capacitance Coupling capacitance of unit

Figure 2-83

Earth Current Direction Detection

CL

CTr

RB RT UE

7UM62

Unit Connected Generator with Earthing Transformer

For machines in busbar connection, it is not possible to differentiate between a network earth fault or a machine earth fault by the displacement voltage alone. In this case the earth fault current is used as a further criterion, and the displacement voltage as a necessary release condition. To achieve the necessary sensitivity, the earth fault current is measured using a toroidal current transformer or a set of CTs in Holmgreen connection. During a network earth fault, the machine supplies only a negligible earth fault current across the measurement location, which must be situated between the machine and the network. During a machine earth fault, the earth fault current of the network is available. However, since the network conditions generally vary according to the switching status of the network, a loading resistor, which supplies an increased earth fault current on the occurrence of a displacement voltage, is used in order to obtain definite measurement conditions independent of the switching status of the network. The earth fault current produced by the loading resistor must always flow across the measurement location.

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G

RL L3 L2 L1 IEE2

UE

7UM62 Figure 2-84

Earth Fault Direction Detection with Busbar Connection

Consequently, the loading resistor must be situated on the other side of the measurement location (current transformer, toroidal current transformer) when viewed from the machine. The earthing transformer is usually connected to the busbar. Apart from the magnitude of the earth fault current, the direction of this current in relation to the displacement voltage can be used for the safe recognition of a machine earth fault in the case of bus-bar connection. The directional border between “machine direction” and “network direction” can be altered in the 7UM62 (refer to Figure 2-85). The protection feature detects a machine earth fault if all three of the following two criteria met: − Displacement voltage larger than set value U0>, − Earth fault current across the measurement location larger than set value 3I0>, − Earth fault current is flowing in the direction of the protected machine.

IE ohmic ohmsch IE

Uen E (= U0)

Generator Richtung direction Generator

IE (= 3I0) IE

Settable pickup parametrierbare An threshold 3I0> sprechschwelle I3I0 ERD> >

ϕE öE

Settable directional angle einstellbarer Richtungswinkel IE capacitive IE kapazitiv

Figure 2-85

7UM62 Manual C53000-G1176-C149-3

Network Richtung direction Netz

IE IE induktiv inductive

Characteristic of Directional Stator Earth Fault Protection for Busbar Connection

179

Functions

On the occurrence of earth fault in the machine zone, the disconnection of the machine is initiated after a set delay time. When the earth current is not decisive to detect an earth fault, e.g. because the circuit breaker is open, the earth current detection can be switched off by a control signal via a binary input of the relay. During this time, the displacement voltage stage is fully operative as the only earth fault protection (e.g. during run-up of the machine). Figure 2-87 shows the logic diagram of the stator earth fault protection. If the stator earth fault protection is used as directional busbar connection protection, this feature is assigned to the sensitive current measuring input of the 7UM62 device. The user must be aware that the sensitive earth fault detection can use the same measuring input (if IEE2 has been configured) and thus the same measuring quantity. For this reason, two additional, independent pickup thresholds Iee> and Iee>> could be formed for this measuring quantity by means of the sensitive earth fault detection (see section 2.27). If the user does not desire this, he should remove the sensitive earth fault configuration at address 0151, or use it with IEE1. If the rotor earth fault protection (see Section 2.30) is used, it occupies the additional voltage input; the displacement voltage U0 for the stator earth fault protection is therefore calculated from the phase-earth voltages in that case. Earth Fault Detection (Earth Differential Protection with Tripping via Displacement Voltage)

In the industrial sector, busbar systems are implemented with high- or low-resistance, switchable starpoint resistances. For earth-fault detection, the starpoint current and the total current are detected via toroidal current transformers and transmitted to the protective relay as current difference. In this way, both the earth current portion derived from the starpoint resistance and the earth current portion derived from the power system contribute to the total earth current. In order to exclude an unwanted operation due to transformer faults, the displacement voltage is used for tripping (see figure 2-86). The protection feature detects a machine earth fault if the following two criteria are fulfilled: − Displacement voltage larger than set value U0>, − Earth fault current difference ∆IE higher than setting value 3I0>,

G ∆IE

IEE

7UM62

UE

&

Figure 2-86

Earth Current Differential Protection with Busbar Connection

Appendix A.4 (Figure A-27) illustrates a connection example with a low-resistance starpoint (earth current limiting to about 100 A). In this example as well, 3I0> and U0> are the tripping criteria.

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7UM62 Manual C53000-G1176-C149-3


Determination of the Faulty Phase

In addition to this, a supplementary function serves to determine the faulty phase. As the phase-earth-voltage in the faulty phase is less than in the two remaining phases and as the voltage even increases in the latter ones, the faulty phase can be determined by determining the smallest phase-earth voltage in order to generate a corresponding result as fault message. FNo. 05193

S/E/F TRIP 5002 U0>

FNo. 05187 FNo. 05186

&

FNo. 05188

&

5003 3I0>

U0> TRIP

U0> picked up 3I0> picked up 5005 T S/E/F

&

OR

&

&

Tripping matrix

5004 DIR. ANGLE 5005 T S/E/F

&

OR

FNo. 05173

FNo. 05182

>S/E/F BLOCK

S/E/F BLOCKED

&

TMin TRIP CMD

FNo. 05176

>S/E/F Iee off

”1”

non-direct. only U0 directional non-dir. with U0 & I0

OR &

FNo. 05194

SEF Dir Forward

0150 S/E/F PROT.

Figure 2-87

Logic Diagram of the 90%–Stator Earth Fault Protection


The 90% stator earth fault protection is only effective and accessible if it has been set during the configuration of the protection functions at address 0150 S/E/F PROT. = directional; non-dir. U0 or non-dir. U0&I0. If non–dir. U0 was selected, the parameters concerning the earth current are ineffective. If one of the options directional or non–dir. U0&I0 was selected, the parameters concerning the earth current are accessible. For machines in busbar connection, one of the latter options must set as a differentiation between the power system earth fault and the machine earth fault is only possible by way of the earth current. If the 90% stator earth fault protection is used as ”earth differential protection”, address 0150 S/E/F PROT. = non-dir. U0&I0 is selected. Set Disabled if the function is not required. Address 5001 S/E/F PROT. is used to switch the function ON or OFF, or to block only the trip command (Block Relay).

Displacement Voltage

The criterion for the inception of an earth fault in the stator circuit is the occurrence of a neutral displacement voltage. Exceeding the setting value 5002 U0> therefore represents the pickup for this protection. The setting must be chosen such that the protection does not pick up during operational asymmetries. This is particularly important for machines in busbar connection since all voltage asymmetries of the network affect the voltage system of the machine. The pickup value should be at least twice the value of the operational asymmetry. A value of 5% to 10% of the full displacement value is normal.

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Functions

For machines in unit connection, the pickup value has to be chosen such that displacements during network earth faults which are transferred via the coupling capacitances of the unit transformer to the stator circuit, do not lead to pickup. The damping effect of the loading resistor must also be considered in this case. Instructions for the dimensioning of the earth current transformer and the loading resistor are contained in the pamphlet “Planning Machine Protection Systems”, Order No. E50400-U0089-U412-A1-7600. The setting value is twice the displacement value which is coupled in at full network displacement. The setting value is finally determined during commissioning with primary values according to section 3.4.6.1. Delays

The stator earth fault trip is delayed by the time set under address 5005 T S/E/F. When setting the delay time, the overload capability of the loading equipment must be considered. All set times are additional delay times and do not include operating times (measurement times, reset times) of the protection function itself.

Earth Current

Addresses 5003 and 5004 are only of importance for machines in busbar connection, 0150 S/E/F PROT. = directional or non–dir. U0&I0 has been set. The following considerations are not applicable for machines in unit connection. The pickup value 5003 3I0> is set such that for an earth fault in the protected zone, the earth current safely exceeds the setting. Since the residual earth current in a compensated network is very small, an earthing transformer with an ohmic loading resistor is normally provided to increase the residual wattmetric current in the event of an earth fault. This arrangement also makes the protection independent of network conditions. Instructions for the dimensioning of the earth current transformer and the loading resistor are contained in the pamphlet “Planning Machine Protection Systems”, Order No. E50400-U0089-U412-A1-7600. Since the magnitude of earth fault current in this case is determined mainly by the loading resistor, a small angle is set for 5004 DIR. ANGLE, e.g. 15°. If the network capacitances in an isolated network are also to be considered, then a larger angle (approx. 45°) can be set which corresponds to the superimposition of the capacitance network current onto the loading current. The directional angle 5004 DIR. ANGLE indicates the phase displacement between the neutral displacement voltage and the perpendicular to the directional characteristic (Figure 2-85), i.e. it is equal to the inclination of the directional characteristic to the reactive axis. If, in an isolated network, the capacitances to earth of the network are mainly decisive for the earth fault protection, it is also possible to work without earthing transformer. In this case, the angle is set to approximately 90° (corresponding to sin ϕ switching). Example busbar connection: Earthing transformer

6.3 kV 500 V ----------------- ⁄ --------------3 3

(limb transformation)

27 kVA Loading resistor

182

10 Ω 10 A

continuous

50 A

for 20 s

7UM62 Manual C53000-G1176-C149-3


Voltage divider

500 V / 100 V

Toroidal c.t.

60 A/1 A

Protected zone

90 %

With full neutral displacement voltage, the load resistor supplies: 500 V --------------- = 50 A 10 Ω Referred to the 6.3 kV side, this results in: 500 ⁄ 3 I EE prim = 50 A ⋅ ----------------------------------- ⋅ 3 = 6.87 A 6300 V ⁄ ( 3 ) The secondary current of the toroidal transformer supplies to the input of the device: I EE prim 6.87 A I EE sec = ------------------------- = ----------------- = 115 mA 60 A ⁄ 1 A 60 For a protected zone of 90 %, the protection should already operate at 1/10 of the full displacement voltage, whereby only 1/10 of the earth fault current is generated 115 mA Setting 3I0> = -------------------- = 11.5 mA 10 In this example 3I0> is set to 11 mA. For the displacement voltage setting, 1/10 of the full displacement voltage is used (because of the 90% protected zone). Considering a voltage divider of 500 V/100 V, this results in: Setting value U0> = 10 V The time delay must lie below the 50 A capability time of the loading resistor, i.e. below 20 s. The overload capability of the earthing transformer must also be considered if it lies below that of the loading resistor.

2.26.2.1 Settings of the 90% Stator Earth Fault Protection Addr.

Setting Title

Setting Options

Default Setting

Comments

5001

S/E/F PROT.


OFF


5002

U0>

2.0..125.0 V

10.0 V

U0> Pickup

5003

3I0>

2..1000 mA

5 mA

3I0> Pickup

5004

DIR. ANGLE

0..360 °

15 °

Angle for Direction Determination

5005

T S/E/F

0.00..60.00 sec; ∞

0.30 sec

T S/E/F Time Delay

7UM62 Manual C53000-G1176-C149-3

183

Functions

2.26.2.2 Information for the 90% Stator Earth Fault Protection F.No.

Alarm

Comments

05173 >S/E/F BLOCK

>BLOCK stator earth fault protection

05176 >S/E/F Iee off

>Switch off earth current detec.(S/E/F)

05181 S/E/F OFF

Stator earth fault prot. is switch OFF

05182 S/E/F BLOCKED

Stator earth fault protection is BLOCK.

05183 S/E/F ACTIVE

Stator earth fault protection is ACTIVE

05189 Uearth L1

Earth fault in phase L1

05190 Uearth L2


05191 Uearth L3


05186 U0> picked up

Stator earth fault: U0 picked up

05188 3I0> picked up

Stator earth fault: I0 picked up

05187 U0> TRIP

Stator earth fault: U0 stage TRIP

05193 S/E/F TRIP

Stator earth fault protection TRIP

05194 SEF Dir Forward

Stator earth fault: direction forward

184

7UM62 Manual C53000-G1176-C149-3


2.27


2.27.1 Functional Description General

The highly sensitive earth fault protection has the task to detect earth fault in systems with isolated or high-impedance earthed star-point. The pick-up criterion is the magnitude of the (residual) earth current. The magnitude of the residual current allows earth fault detection, for example, on electrical machines which are directly connected to the busbar of an isolated power system, when in case of a network earth fault the machine supplies only a negligible earth fault current across the measurement location, which must be situated between the machine terminals and the network, whereas in case of a machine earth fault the higher earth fault current produced by the total network is available. The measured current may be derived from toroidal CTs or CTs in Holmgreen connection. In the 7UM62, the sensitive earth fault detection feature can be allocated to either input IEE1 or IEE2. This choice is made during configuration (see Section 2.2). This protection is not suited for detection of high earth currents which may arise in case of earthed system starpoints (higher than approx. 1 A at the relay terminals for highly sensitive earth current protection). If this protection feature nevertheless shall be used as short-circuit to earth protection, an additional, external current transformer is required as intermediate transformer. Note: The sensitive earth current protection as well as for the directional or non– directional stator earth fault protection of busbar-connected machines may use the same current measuring input (IEE2). That means that both protection functions use identical input currents if address 0150 S/E/F PROT. is set to directional or non-dir. U0&I0.

Application as Rotor Earth Fault Protection

Alternatively, this protection can be used as rotor earth fault protection when a system frequency bias voltage is applied to the rotor circuit (refer to Figure 2-88). In this case, the measured current is determined by the magnitude of the bias voltage UV and the capacitance of the coupling capacitors of the rotor circuit. A measured value supervision is provided for the application as rotor earth fault protection: The measurement circuit is assumed to be closed as long as a small earth current IEE< is flowing which is determined by the rotor-earth capacitance. If not, an alarm is issued after a short delay time of 2 s.

Measuring Procedure

Initially, the residual current is numerically filtered so that only the fundamental wave of the current is used for the measurement. This makes the measurement insensitive to transient conditions at the inception of a short-circuit and to harmonics content in the current. The protection consists of two stages. A pickup is detected as soon as the first parameterized threshold value IEE> is exceeded. The trip command is transmitted subsequent to the T IEE> delay time. A pickup is detected as soon as the second parameterized threshold value IEE>> is exceeded. The trip command is transmitted subsequent to the T IEE>> delay time. Both stages can be blocked via a binary input.

7UM62 Manual C53000-G1176-C149-3

185

Functions

Figure 2-89 shows the logic diagram of sensitive earth fault detection.

UE

UE

3PP13

7UM62

IEE

7XR61

UV

Figure 2-88

Application Example as Rotor Short Circuit to Earth Protection (7XR61 – series device for the rotor short circuit to earth protection; 3PP13 – from UPU > 150 V, resistors in the 7XR61 must be shorted!)

5102 IEE>

FNo. 01224

FNo. 01226

IEE> picked up

IEE> TRIP

5103 T IEE>

&

Iee

5104 IEE>>

Tripping matrix

FNo. 01221

FNo. 01223

IEE>> picked up

IEE>> TRIP

5105 T IEE>>

& TMin TRIP CMD

FNo. 01203

>BLOCK IEE> FNo. 01202

>BLOCK IEE>> FNo. 01231

FNo. 01233

IEE BLOCKED

>BLOCK Sens. E 5106 IEE<

& Figure 2-89

186

2s

FNo. 05396

Fail.

REF

Logic Diagram of the Sensitive Earth Fault Protection

7UM62 Manual C53000-G1176-C149-3



The sensitive earth fault detection is only effective and accessible if it has been set during the configuration of the protective functions at address 0151 O/C PROT. Iee> = with Iee1 or with Iee2. If one of the options with current evaluation was selected during the configuration of the 90–%–stator earth fault protection (0150 S/ E/F PROT., see Section 2.2) the sensitive current measuring input of the 7UM62 is assigned to this feature. The user must be aware that the sensitive earth fault detection possibly uses the same measuring input (IEE2) and thus the same measuring quantity. If the sensitive earth fault detection is not required, this parameter is set to Disabled. Address 5101 O/C PROT. Iee> is used to switch the function ON or OFF, or to block only the trip command (Block Relay).

Use as Rotor Earth Fault Protection

The highly sensitive earth current protection can be used to detects earth fault either in the stator or in the rotor winding of the machine. A precondition is that the magnitude of the measured current is a sufficient criterion. When the protected winding is isolated or high-resistance earthed, sufficient magnitude of the earth current must be produced. When, for example, used as rotor earth fault protection, a system frequency bias voltage (UV ≈ 42 V must be applied to the rotor circuit by means of the 7XR61 series device in Figure 2-88). In this case, the measured current is determined by the magnitude of the bias voltage and the capacitance of the coupling capacitors of the rotor circuit, which can be measured in order to ensure a closed measuring circuit (address 5106 IEE<). Approximately 2 mA is a typical pickup value. The monitoring stage is ineffective is this value is set to 0. This can become necessary if the earth capacitances are too small. The earth current pick-up value 5102 IEE> is chosen such that an earth resistance RE between 3 kΩ and 5 kΩ is covered: Warning stage setting value e.g.:

U V 42 V IEE> ≈ ------- ≈ ------------ ≈ 10 mA R E 4 kΩ

On the other hand, the setting value should correspond to at least twice the interference current caused by the earth capacitances of the rotor circuit. The 5104 IEE>> trip stage should be dimensioned for a fault resistance of about 1.5 kΩ.

Trip stage setting value e.g.:

UV 42 V IEE>> ≈ ----------------------------- ≈ ------------------------------------------ ≈ 23 mA R E + Z coup 1.5 kΩ + 0.4 kΩ

with Zcoup- Impedance amount of the series device with nominal frequency The 5103 T IEE> and 5105 T IEE>> tripping time delays do not include the operating times. Use as Stator Earth Fault Protection

7UM62 Manual C53000-G1176-C149-3

Please also refer to section 2.26. For use as stator earth fault protection, a sufficient current must be produced by an earthing transformer, if necessary. Instructions for the dimensioning of the earth current transformer and the loading resistor are contained in the pamphlet “Planning Machine Protection Systems”, Order No. E50400-U0089U412-A1-7600.

187

Functions

Use as Earth ShortCircuit Protection

For low-voltage machines with neutral conductor incorporated in cables or machines with low-impedance earthed starpoint, the time-overcurrent protection of the phase branches already is a short-circuit to earth protection, as the short-circuit to earth current also flows through the faulty phase. If the sensitive earth current detection nevertheless shall be used as short-circuit to earth protection, an external intermediate transformer must be used to ensure that the short-circuit current does not exceed the thermal limit values (15 A continuous, 100 A for < 10 s, 300 A for < 1 s) of this measuring input.

2.27.2.1 Settings of the Sensitive Earth Fault Protection Addr.

Setting Title

Setting Options

Default Setting

Comments

5101

O/C PROT. Iee>


OFF


5102

IEE>

2..1000 mA

10 mA

Iee> Pickup

5103

T IEE>

0.00..60.00 sec; ∞

5.00 sec

T Iee> Time delay

5104

IEE>>

2..1000 mA

23 mA

Iee>> Pickup

5105

T IEE>>

0.00..60.00 sec; ∞

1.00 sec

T Iee>> Time Delay

5106

IEE<

1.5..50.0 mA; 0

0.0 mA

Iee< Pickup (Interrupted Circuit)

2.27.2.2 Information for the Sensitive Earth Current Detection F.No.

Alarm

Comments

01231 >BLOCK Sens. E

>BLOCK sensitiv earth current prot.

01203 >BLOCK IEE>

>BLOCK IEE>

01202 >BLOCK IEE>>

>BLOCK IEE>>

01232 IEE OFF

Earth current prot. is swiched OFF

01233 IEE BLOCKED

Earth current prot. is BLOCKED

01234 IEE ACTIVE

Earth current prot. is ACTIVE

01224 IEE> picked up

IEE> picked up

01221 IEE>> picked up

IEE>> picked up

01226 IEE> TRIP

IEE> TRIP

01223 IEE>> TRIP

IEE>> TRIP

05396 Fail. REF Iee<

Failure R/E/F protection Iee<

188

7UM62 Manual C53000-G1176-C149-3

100–%–Stator Earth Fault Protection with 3rd Harmonics (ANSI 27/59TN 3rd Harm.)

2.28



As described in section 2.26, the measuring procedure based on the fundamental wave of the displacement voltage serves to protect maximally 90 % to 95 % of the stator winding. A non-line-frequent voltage must be used to implement a 100 % protection range. With the 7UM62 device, the 3rd harmonic is used for this purpose. The 3rd harmonic is created in each machine in a more or less significant way. It is provoked by the shape of the poles. If an earth fault occurs in the generator stator winding, the division ratio of the parasitic capacitances changes, as one of the capacitances was short-circuited by the earth fault. During this procedure, the 3rd harmonic measured in the starpoint decreases, whereas the 3rd harmonic measured at the generator terminals increases (see figure 2-90). The 3rd harmonic forms a zero phase-sequence system and can thus also be determined by means of the voltage transformer switched in star/delta or by calculating the zero phase-sequence system from the phase-earth-voltages.

L1 L2 L3 3. Harmonics

Earth fault close to starpoint Normal operation Terminals

Starpoint

Figure 2-90

Profile of the 3rd Harmonic along the Stator Winding

Moreover, the level of the 3rd harmonic depends on the operating point of the generator, i.e. a function of the P active power and the Q reactive power. For this reason, the working area of the stator earth fault protection is restricted in order to enhance security. In case of a busbar connection, all machines contribute to the 3rd harmonic, which impedes the separation of the individual machines. Measuring Principle

The level of the 3rd harmonic in the measuring quantity is the pickup criterion. The 3rd harmonic is determined from the displacement voltage measured during two cycles by means of digital filtering. Different measuring procedures are applied, depending on whether the displacement voltage is detected or not (project configuration parameter 0223 UE CONNECTION):

7UM62 Manual C53000-G1176-C149-3

189

Functions

1. Ue connected to neutral transformer: Connection of the UE input to the voltage transformer in the machine starpoint 2. Ue connected to broken delta winding: Connection of the UE input to the broken delta winding 3. Not connected: Calculation of the displacement voltage by means of the three phase-earth-voltages, if the UE input is not connected 4. Ue connected to any VT: measuring of any other voltage; the function 100– %–stator earth fault protection is blocked. 5. Ue connected to Rotor: measuring of any other voltage; the function 100– %–stator earth fault protection is blocked. 6. Ue connected to loading Resistor: The UE-input is used by the 100– %–stator earth fault protection with 20–Hz–injection. The function 100–%–stator earth fault protection with 3rd harmonics is blocked. Ue Connected to Neutral Transformer

As an earth fault in the starpoint causes a reduction of the measured 3rd harmonic compared with the faulty case, the protective function is implemented as undervoltage stage (5202 U0 3.HARM<). This arrangement is the preferred application.

Ue Connected to Broken Delta Winding

If no neutral transformer exists, the protective function is based on the zero component of the 3rd harmonic of the terminal voltages. This voltage increases in case of a fault. In this case, the protective function is an overvoltage stage (5203 U0 3.HARM>).

Not Connected; Calculation of U0

Like for the connection to the broken delta winding, an increase of the 3rd harmonic in case of a fault also results for the calculated voltage. The 5203 U0 3.HARM> parameter is also relevant for this application.

Ue Connected to any VT Ue Connected to Rotor

With these connection types the function 100–%–stator earth fault protection is blocked.

Figure 2-91 illustrates the logic diagram of the 100– %–stator earth fault protection.

190

7UM62 Manual C53000-G1176-C149-3


U(3.H.)

FNo. 05567

5202 U0 3.HARM<

SEF 3H pick.up

neutral transformer

5204 T SEF 3. HARM.

& 5203 U0 3.HARM>

FNo. 05568

SEF 3H TRIP

not connected or broken delta winding

5205 P min >

5206 U1 min >

Tripping matrix

TMin TRIP CMD

&

0223 UE CONNECTION Neutral transformer broken delta winding not connected Load Resistor connected to Rotor

”1”

connected to any VT

FNo. 05553

FNo. 05562

>SEF 3H BLOCK

SEF 3H BLOCK

Figure 2-91

Logic Diagram of the 100–%–Stator Earth Fault Protection


The 100 % stator earth fault protective function is only effective and available if 0152 SEF 3rd HARM.has been set during the configuration of the protective functions to Enabled. Set Disabled if the function is not required. Address 5201 SEF 3rd HARM. is used to switch the function ON or OFF, or to block only the trip command (Block Relay).

Connection Type

Depending on the system conditions, the user specified at address 0223 UE CONNECTION during the project configuration if the displacement voltage Uen is tapped via a neutral transformer (Ue connected to neutral transformer) or via the broken delta winding of an earthing transformer (Ue connected to broken delta winding) and fed to the protective relay. If it is possible to make the displacement voltage available to the protective relay as a measured quantity, calculated quantities are used and the parameter must be set to not connected. The option UE connected to any VT is selected if the 7UM62 voltage input shall be used for measuring any other voltage instead of using it for earth fault protection. In this case the function 100–%–stator earth fault protection is blocked. The option Ue connected to Rotor is selected if the bias voltage for rotor earth fault connection shall be fed in at this input. In this case the function 100–%–stator earth fault protection is blocked. The option Ue connected to loading resistor is for the 100–%–stator earth fault protection with 20–Hz–injection. At this setting the 100–%–stator earth fault protection with 3rd harmonics is blocked.

7UM62 Manual C53000-G1176-C149-3

191

Functions

Pickup Value for 3rd Harmonics

Depending on the selection of the connection type, only one of the two setting parameters 5202 or 5203 is accessible. The setting values can only be determined within the framework of a primary test. The following principle is generally valid: − The 5202 U0 3.HARM< undervoltage stage is relevant for a connection to a transformer in the starpoint. The pickup value should be chosen as low as possible. − The 5203 U0 3.HARM> overvoltage stage is relevant for a connection via the broken delta winding of an earthing transformer and for a not connected, but internally calculated displacement voltage.

Working Area

Due to the strong dependency of the measurable 3rd harmonic from the corresponding working point of the generator, the working area of the 100–%–stator earth fault protection is only tripped above the active-power threshold set via 5205 P min > and on exceeding a minimum positive phase-sequence voltage 5206 U1 min >. Recommended setting:

Pmin > 40 % P/SN U1 min > 80 % UN

The tripping in case of an earth fault is delayed by the time set at address 5204 T SEF 3. HARM.. The set time is an additional time delay not including the operating time of the protective function.

Delay Time

2.28.2.1 Settings of the 100–%–Stator Earth Fault Protection with 3rd Harmonics Addr.

Setting Title

Setting Options

Default Setting

Comments

5201

SEF 3rd HARM.


OFF

Stator Earth Fault Protection 3rdHarm.

5202

U0 3.HARM<

0.2..40.0 V

1.0 V

U0 3rd Harmonic< Pickup

5203

U0 3.HARM>

0.2..40.0 V

2.0 V

U0 3rd Harmonic> Pickup

5204

T SEF 3. HARM.

0.00..60.00 sec; ∞

0.50 sec

T SEF 3rd Harmonic Time Delay

5205

P min >

10..100 %; 0

40 %

Release Threshold Pmin>

5206

U1 min >

50.0..125.0 V; 0

80.0 V

Release Threshold U1min>

192

7UM62 Manual C53000-G1176-C149-3


2.28.2.2 Information for the 100–% Stator Earth Fault Protection with 3rd Harmonics F.No.

Alarm

Comments

05553 >SEF 3H BLOCK

>BLOCK SEF with 3.Harmonic

05561 SEF 3H OFF

SEF with 3.Harm. is switched OFF

05562 SEF 3H BLOCK

SEF with 3.Harm. is BLOCKED

05563 SEF 3H ACTIVE

SEF with 3.Harm. is ACTIVE

05567 SEF 3H pick.up

SEF with 3.Harm.: picked up

05568 SEF 3H TRIP

SEF with 3.Harm.: TRIP

7UM62 Manual C53000-G1176-C149-3

193

Functions

2.29

100–% Stator Earth Fault Protection with 20 Hz Voltage Injection (ANSI 64G - 100%)

General

The 100-% stator earth fault protection detects earth faults in the stator windings of generators which are connected with the network via a unit transformer. This protection function, which works with an injected 20 Hz voltage, is independent of the system-frequency displacement voltage appearing in earth faults, and detects earth faults in all windings including the machine starpoint. The measuring principle used is not influenced at all by the generator operating mode and allows to perform measurements even with the generator standing still. The two measuring principles used – measurement of the displacement voltage (see Section 2.26) and evaluation of the measured quantities at an injected 20 Hz voltage – allow to implement reliable protection concepts that complement one another. If an earth fault in the generator starpoint or close to the starpoint is not detected, the generator is running with an “earthing”. A subsequent fault (e.g. a second earth fault) causes a single-pole short-circuit that may have an extremely high fault current because the generator zero impedance is very small. A 100 % stator earth fault protection is therefore a basic function for large generators.

2.29.1 Functional Description Basic Principle

Figure 2-92 shows the basic protection principle. An external low-frequency alternating voltage source (20 Hz) injects into the generator starpoint a voltage of max. 1 % of the rated generator voltage. If an earth fault occurs in the generator starpoint, the 20 Hz voltage drives a current through the fault resistance. From the driving voltage and the fault current, the protective relay determines the fault resistance. The protection principle described here also detects earth faults at the generator terminals, including connected components such as voltage transformers.

max. 200 V

20 Hz

RF

I

Figure 2-92

Circuit Design

194

Basic Principle of Voltage Injection into the Generator Starpoint

To implement the above concept, some additional equipment is required. Figure 2-93 shows that a 20 Hz generator generates a square-wave voltage with an amplitude of approx. 25 V. This square-wave voltage is fed via a band pass into the loading resistor of the earthing or neutral transformer. The band pass serves for rounding the squarewave voltage and for storing energy. The 20 Hz resistance of the band pass is approx. 8 Ω. The band pass has also a protection function. If the load resistor carries the full displacement voltage in case of a terminal-to-earth fault, the higher series resistance of the band pass protects the 20 Hz generator from high feedback currents.

7UM62 Manual C53000-G1176-C149-3


The driving 20 Hz voltage is picked up directly at the loading resistor via a voltage divider. In addition, the 20 Hz current flow is measured via a miniature CT. Both quantities (USEF and ISEF) are fed to the protection device. The voltage to be injected into the generator starpoint depends on the driving 20 Hz voltage (voltage divider: load resistor and band pass), and on the transformation ratio of the neutral or earthing transformer. To prevent the secondary load resistance from becoming too small (it should be > 0.5 Ω, where possible), a high secondary rated voltage should be chosen for the earthing or neutral transformer. 500 V has proven to be a good value.

20 Hz generator

~ ~ ~

Band pass

Earthing transformer U Nom 500 V

500 V

a

USEF

200 V R L K

b

l k

ISEF

3

3

Supply voltage (DC or AC)

G 20 Hz

7UM62 Prot. Relais

Min. CT (400 A / 5 A)

GS 3~ a

b Neutral transformer

R USEF ISEF

Figure 2-93

Loading resistor Displacement voltage at protective relay Measuring current at protective relay

Circuit Design of the 100-% Stator Earth Fault Protection with Earthing Transformer or Neutral Transformer (see also Figure A-43 in the Appendix).

The same measuring principle can also be used with a primary loading resistor. The 20 Hz voltage is connected in this case via a voltage transformer, and the starpoint current is directly measured. The connection scheme, and hints on circuit design, can be found in the Appendix A.5 (Figure A-43). Measuring Procedure

From the two measured quantities USEF and ISEF in Figure 2-93, the 20 Hz current and voltage vectors are calculated, and from the resulting complex impedance the ohmic fault resistance is determined. This method eliminates disturbances caused by the stator earth capacitance, and ensures a high sensitivity. The measuring accuracy is further increased by using mean current and voltage values obtained over several cycles for calculating the resistance. The model takes into account a transfer resistance RPS that may be present at the neutral, earthing or voltage transformer. Other error factors are taken into account in the angle error.

7UM62 Manual C53000-G1176-C149-3

195

Functions

In addition to the determination of the earth resistance, the protection function features an earth current stage which processes the current r.m.s. value and thus takes into account all frequencies. It is used as a backup stage and covers approx. 80 to 90 % of the protection zone. A monitoring circuit checks the coupled external 20 Hz voltage and the 20 Hz current and detects by evaluating them a failure of the 20 Hz generator or of the 20 Hz connection. In case of a failure, the resistance determination is blocked. The earth current stage remains active. Logic

Figure 2-94 shows the logic diagram. It comprises: − Monitoring of the 20 Hz connection − Resistance calculation and threshold value decision − Independent current measurement stage The protection function has an alarm stage and a trip stage. Both stages can be delayed with a timer. The earth current detection acts only on the trip stage. The evaluation of the earth resistance measurement is blocked between 10 Hz and 40 Hz, because in this frequency range a zero voltage can also be generated by generators starting up or slowing down. Such a zero voltage would then superimpose the connected 20 Hz voltage, causing measurement errors and overfunctioning. The resistance measurement function is active with frequencies below 10 Hz (i.e. at standstill) and above 40 Hz. The earth current measurement is active over the entire range.

5476 >U20 failure 5307 U20 MIN

5308 I20 MIN

&

0,5 s

OR

5486 Failure SEF

&

5302 R< SEF ALARM 5304 T SEF ALARM & USEF ISEF

Num. filter

5487 SEF100 Alarm

&

U20 I20

U20 I20

R

5488 SEF100 PICKUP

5303 R<< SEF TRIP

5305 T SEF TRIP &

5306 SEF I>>

f > 10 Hz and f ≤ 40 Hz

&

5489 SEF100 TRIP

OR

OR

Tripping matrix &

5173 >S/E/F BLOCK

Figure 2-94

196

Tmin TRIP CMD 5482 SEF100 BLOCKED

Logic Diagram of the 100-% Stator Earth Fault Protection

7UM62 Manual C53000-G1176-C149-3



The 100-% stator earth fault protection is only effective and accessible if it has been set to Enabled at address 0153 100% SEF-PROT. during the configuration of the protection functions. In addition, the function requires the following settings to be made in Power System Data 1: − Address 0275: FACTOR R SEF; Sets the resistance transformation ratio (see side title “Fault Resistances”) − Address 223: UE CONNECTION should be set to Load. resistor for this application. The 20 Hz voltage is in this case picked up at the UE input, and the displacement voltage for the 90-% stator earth fault protection (SEF) is calculated from the phaseto-earth voltages. If the measured voltage (input UE is to be used for the 90-% SEF as well, the address should be set to neutr. transf. or broken delta. Address 5301 100% SEF-PROT. is used to switch the function ON or OFF, or to block only the trip command (Block relay).

Fault Resistances

The final setting values are determined in the primary test as described in Section 3.3. Please note that the protection calculates the earth resistance from the secondary values USEF and ISEF which are present at the device terminals. The association between this calculated value and the actual (primary) stator earth resistance is determined by the transformation ratio of the earthing and the neutral transformer. For the overall transformation, the following formula applies: ü MinCT 1 R Esec = ------------------- ⋅ -------------------- ⋅ R Eprim 2 ü Transf ü Divider Meaning: REsec

Earth resistance, converted for the device side

REprim

Primary earth resistance of the stator winding (= fault resistance)

üTransf

Transformation ratio of the earthing or neutral transformer Earthing transformer (leg transformation divided by 3): U Nprim U Nprim ---------------------------------1 1 3 3 ü Transf = ü EarthTransf = --- ⋅ ------------------- = --- ⋅ ------------------3 500V 3 U Nsec ----------------------------3 3

Neutral transformer: U Nprim -----------------3 ü Transf = ü NeutralTransf = ------------------U Nsec üMinCT

Transformation ratio of the miniature CT

üDivider Transformation ratio of the voltage divider

7UM62 Manual C53000-G1176-C149-3

197

Functions

The conversion factor of the earth resistance is set as FACTOR R SEF at address 0275 in Power System Data 1. The general formula for calculation (REprim / REsec) is: ü Divider 2 FACTOR R SEF = ü Transf ⋅ -------------------ü MinCT This formula is true only for nearly ideal earthing or neutral transformers. If necessary, the measuring result from the primary tests must be set as FACTOR R SEF. For this the fed fault resistance (trip stage) is put into relation with the secondary fault resistance. The primary fault resistance should be set to 1 to 2 kΩ for the trip stage and to approx. 3 to 8 kΩ for the alarm stage. The default times have proven to be good values. Example: üTransf

10kV -------------- ⁄ 500V -------------3 3

Loading resistor

RL

10 Ω (10 A continuously, 50 A for 20 s)

Miniature CT

üMinCT

200 A / 5 A


The transformation ratio of the miniature CT 400 A:5 A has been reduced to 200 A:5 A by the primary conductor passing twice through the transformer window. This yields for FACTOR R SEF a value of: 2 000 V 3 æ 10 ------------------------ ⋅ ----------------ö è ø 500 V 3 500 ⁄ 200 FACTOR R SEF = ----------------------------------------------------- ⋅ ------------------------ = 8.33 9 200 ⁄ 5

If for the trip stage R<< a generator-side fault resistance of 1000 Ω is chosen, a resistance of R<< SEF TRIP = 1000 Ω/8.33 = 120 Ω is set at address 5303. For the warning stage, a primary resistance of 3 kΩ yields a setting value of R< SEF ALARM = 360 Ω. Earth Current Stage

The earth current stage has a backup protection function. It is set to a protected zone of approx. 80 %. Referenced to the maximum secondary fault current, the pickup threshold is at approx. 20 %, and the setting value is calculated as follows: U Nsec 1 500 V 5 A SEF100 I>> = 0.2 ⋅ ---------------- ⋅ ------------------- = 0.2 ⋅ ---------------- ⋅ ---------------- = 0.25 A ü MinCT 10 Ω 200 A RL The delay time T SEF TRIP (address 5305), which is also relevant for the earth current stage, must be less than the 50 A capability time of the loading resistor (in this example 50 A for 20 s). The overload capability of the earthing or neutral transformer must also be considered if it lies below that of the loading resistor.

Monitoring

198

At the addresses 5307, 5308 the monitoring thresholds are set with U20 MIN and I20 MIN. If the 20 Hz voltage drops below the pickup value without the 20 Hz current rising, there must be a problem of the 20 Hz connection. The default settings will be adequate for most applications. Where the loading resistor is less than 1 Ω, the voltage threshold U20 MIN must be reduced to 0.5 V. The current threshold I20 MIN can be left at 10 mA.

7UM62 Manual C53000-G1176-C149-3


Correction Angle, Contact Resistance

The parameter PHI I SEF (default setting 0°) of address 5309 is used to compensate the angle error of the CTs and angle distortions caused by a less than ideal earthing or neutral transformer. The correct setting for this parameter can only be determined with a primary test. The adjustment should be made for the tripping value. The same is true for the transfer resistance of the earthing or neutral transformer. This advanced parameter can be set with the DIGSI communication software (not possible in local operation). As this resistance is normally negligible, a default setting SEF Rps = 0 Ω has been chosen for address 5310A. However, the transfer resistance of the voltage transformer is no longer negligible if the 20 Hz voltage is fed to a primary-side loading resistor via a voltage transformer. In large power units with generator circuit breaker, applications can be found where there is some additional loading equipment on the low-voltage side of the unit transformer to reduce the influence by the zero voltage when the generator circuit breaker is open. The 20 Hz source is connected via the neutral transformer in the generator starpoint. With the generator circuit breaker closed, the protection measures the loading resistance on the unit transformer side, which can be mistaken for an earth resistance. The advanced parameter address 5311A allows to set this additional loading resistance. The default setting for Rl-PARALLEL is ∞. No additional loading resistance is assumed.

2.29.2.1 Settings of the 100-% Stator Earth Fault Protection Addr.

Setting Title

Setting Options

Default Setting

Comments

5301

100% SEF-PROT.


OFF


5302

R< SEF ALARM

20..700 Ohm

100 Ohm

Pickup Value of Alarm Stage Rsef<

5303

R<< SEF TRIP

20..700 Ohm

20 Ohm

Pickup Value of Tripping Stage Rsef<<

5304

T SEF ALARM

0.00..60.00 sec; ∞

10.00 sec

Time Delay of Alarm Stage Rsef<

5305

T SEF TRIP

0.00..60.00 sec; ∞

1.00 sec

Time Delay of Tripping Stage Rsef<<

5306

SEF I>>

0.02..1.50 A

0.40 A

Pickup Value of I SEF>> Stage

5307

U20 MIN

0.3..15.0 V

1.0 V

Supervision Threshold of 20Hz Voltage

5308

I20 MIN

5..40 mA

10 mA

Supervision Threshold of 20Hz Current

5309

PHI I SEF

-60..60 °

0°

Correction Angle for I SEF 100%

5310A

SEF Rps

0.0..700.0 Ohm

0.0 Ohm

Resistance Rps

5311A

Rl-PARALLEL

20..700 Ohm; ∞

∞ Ohm

Parallel Load Resistance

7UM62 Manual C53000-G1176-C149-3

199

Functions

2.29.2.2 Information for the 100-% Stator Earth Fault Protection F.No.

Alarm

Comments

05473 >SEF100 BLOCK

>BLOCK Stator earth fault protection

05476 >U20 failure

>Failure 20Hz bias voltage (S/E/F)

05481 SEF100 OFF

S/E/F 100% protection is switched OFF

05482 SEF100 BLOCKED

Stator earth flt. prot. 100% is BLOCKED

05483 SEF100 ACTIVE

Stator earth flt. prot. 100% is ACTIVE

05486 Failure SEF

Failure stator earth flt. prot. 100%

05487 SEF100 Alarm

Stator earth flt. prot.100% Alarm stage

05488 SEF100 PICKUP

Stator earth flt. prot.100%: picked up

05489 SEF100 TRIP

Stator earth flt. prot.100%: TRIP

200

7UM62 Manual C53000-G1176-C149-3


2.30


General

Rotor earth fault protection is used to detect earth faults in the excitation circuit of synchronous machines. One earth fault in the rotor winding does not cause immediate damage; however, if a second earth fault occurs, then this represents a winding shortcircuit of the excitation circuit. Magnetic unbalances can occur resulting in extreme mechanical forces which can lead to the destruction of the machine.

2.30.1 Functional Description Measuring Procedure

The rotor earth fault protection in the 7UM62 uses an external auxiliary voltage of approximately 36 to 45 V AC, which can be taken from the voltage transformers via a coupling unit 7XR6100-0*A00. This voltage is symmetrically coupled to the excitation circuit via the capacitors of the coupling unit and simultaneously connected to the measurement input of the 7UM62. The capacitors CK of the 7XR6100 coupling unit are protected by series resistors Rseries and - in case high harmonics content is expected in the excitation circuit (e.g. excitation by thyristor circuits) - by an additional filter choke (for a connection example with terminal assignment see Figure A-31 in Appendix A.4). The auxiliary AC voltage drives a small charging current through the coupling unit, brush resistance and capacitance to earth of the excitation circuit. This current IRE amounts to only a few mA during normal operation and is measured by the device (Figure 2-95).

RE

CE

Rseries Rseries

CK

Rotor earth fault protection

Figure 2-95

7UM62 Manual C53000-G1176-C149-3

Rseries 7UM62

IRE

IEE1

URE

UE

3PP13

CK

Rseries

7XR61

Determination of the Rotor Earth Resistance RE (7XR61 – series device for the rotor short circuit to earth protection; 3PP13 – from UPU > 150 V, resistors in the 7XR61 must be shorted!)

201

Functions

The rotor earth fault calculation calculates the complex earth impedance from the auxiliary AC voltage URE and the current IRE. The earth resistance RE of the excitation circuit is then calculated from the earth impedance. The device also considers the coupling capacitance of the coupling unit CK, the series (e.g. brush) resistance Rseries and the capacitance to the earth excitation circuit CE. This method ensures that even relatively high-ohmic earth faults (up to 30 kΩ under ideal conditions) can be detected. In order to eliminate the influence of harmonics - such as occur in static excitation equipment (thyristors or rotating rectifiers) - the measured quantities are filtered prior to their evaluation. The earth resistance supervision has two stages. Usually an alarm is initiated if the earth resistance falls below an initial high-resistance stage (e.g. 5 kΩ to 10 kΩ). If the value falls below the second low-resistance stage (e.g. 2 kΩ to 5 kΩ), tripping will be initiated after a short time delay. The dropout threshold is defined for both stages as 125 % of the set value. Note: The rotor earth fault protection uses for the detection of the voltage URE the UE voltage input of the device. Therefore, the displacement voltage U0 for the 90–% stator earth fault protection (see Section 2.26) is in that case calculated from the phase-toearth voltages. Measuring Circuit Supervision

Since a current flows even during healthy operation, namely the capacitive charging current of CE, the protection can recognize and alarm an interruption in the measurement circuit, provided the capacitance to earth is at least 0.15 µF.

Stabilization of the Resistance Measurement

If the measuring current IRE exceed an internal predetermined value (100 mA), a lowohmic earth fault (RE ≈ 0) is detected regardless of the calculated resistance. If this current drops below the internal predetermined value of 0.3 mA, RE → ∞ is detected regardless of the calculated resistance.

Figure 2-96 shows the logic diagram of the rotor earth fault protection.

6008 I RE< 10.00s

& 6002 RE< WARN

FNr. 05400

Failure R/E/F Tripping matrix

6004 T-WARN-RE<

FNr. 05397

R/E/F warning

IRE URE

RE

&

FNr. 05398

R/E/F picked up 6003 RE<< TRIP

6005 T-TRIP-RE<<

FNr. 05399

20V/25V (fixed)

FNr.05394

TMin TRIP CMD

R/E/F TRIP

R/E/F U< block

OR FNr. 05383

FNr. 05392

>BLOCK R/E/F

R/E/F BLOCKED

Figure 2-96

202

Logic Diagram of the Rotor Earth Fault Protection

7UM62 Manual C53000-G1176-C149-3



The rotor earth fault protection is only effective and accessible if it has been set during the configuration of the protective functions at address 0160 ROTOR E/F = Enabled. Set Disabled if the function is not required. Address 6001 ROTOR E/F is used to switch the function ON or OFF, or to block only the trip command (Block relay for trip commands). Also, configuration parameter 0223 UE CONNECTION must be set to UE connected to Rotor. If it is not, a voltage URE = 0 is displayed and evaluated, so that the protection remains blocked.

Pick-Up Values

Since the protection calculates the ohmic rotor-earth resistance from the values caused by the applied bias voltage, the thresholds for the warning stage (6002 RE< WARN) and for the trip stage (6003 RE<< TRIP) can be set directly as resistance values. The default settings are sufficient for the majority of cases. These values can be changed depending on the insulation resistance and the coolant. Care must be taken to allow a sufficient margin between the setting value and the actual insulation resistance.

Delays

The time delay for the warning stage 6004 T-WARN-RE< is usually set to approximately 10 s, and the delay for the trip stage 6005 T-TRIP-RE<< to approximately 0.5 s. The set times are additional time delays not including the operating times (measuring time, drop-out time) of the protective function.

Data for the Coupling to the Rotor Circuit

The setting of the coupling reactance 6006 X COUPLING and the series resistance 6007 R SERIES enable the protection to calculate the earth resistance RE from the complex equivalent diagram of the coupling capacitance of the coupling unit, the series (e.g. measuring brush) resistance, the capacitance to earth of the excitation circuit, and the earth resistance of the excitation circuit; please refer to Figure 2-95. The equivalent circuit according to Figure 2-97 applies.

.

IRE

∼

XCOUPLING RV = Rseries + Rpre + Rz

URE

CE

RE

where URE

Bias voltage of the rotor circuit

IRE

Earth current

XCOUPLING

Total series reactance of the coupling circuit, consisting of coupling capacitance and inductance (if applicable)

Rv

Total resistance of the coupling circuit, consisting of brush resistance, protection resistance (if applicable) and damping resistance (if applicable)

CE

Rotor earth capacitance

RE

Rotor earth resistance

Figure 2-97

7UM62 Manual C53000-G1176-C149-3

Equivalent Measuring Circuit for Rotor Earth Fault Protection

203

Functions

The series resistors Rpre for the protection of the coupling capacitors can be considered with the total series resistance (address 6007) since the brush resistance and the series resistance are connected in series in the measurement circuit. The resultant resistance applies for R SERIES, i.e. the parallel connection in each case of the series resistors Rpre and for the resistance of the two brushes. Similarly, the coupling reactance is calculated from the parallel connection of the two coupling capacitors CK. In some cases, the inductor integrated in the 7XR6100 is included in the coupling circuit to reduce very high harmonics content of the excitation voltage. This forms, together with the coupling capacitance, a band pass for the system frequency. In these cases, it must be considered that the reactance must not become less than –100 Ω (lower threshold of setting 6006 X COUPLING). Angle Error Correction

Coupling reactance and series resistance can be measured by the protection itself during commissioning (see Section 3.3.7). It may be advantageous to compensate for the angle error of the input CTs of the relay in order to increase accuracy. This can be done at address 6009 PHI I RE. Thus, if the warning stage in particular does not pick up during testing at the expected insulation resistance level, you should check and correct the correction angle and the coupling reactance (see also Section 3.3.7). The values calculated and displayed by the relay may become negative due to CT angle errors, wrong settings of the coupling impedance or malfunctions of the excitation equipment. In that case, a check is performed whether the current IRE > is more than 7 mA, in which case a tripping decision is made. If the current is < 7 mA, the measurement is marked as invalid, and the rotor earth resistance RRotor ∞ is displayed. This additional consistency check ensures that even if the setting of the correction angle or the coupling impedance is wrong, tripping in case of low-resistance earth faults is ensured although the warning stage may not pick up correctly.

Measuring Circuit Monitoring

If a sufficiently high rotor capacitance (CE ≥ 0.15 µF) is available, an interruption in the measurement circuit can also be recognized. A measurement circuit interruption is assumed when the voltage drops below the threshold set at address 6008 I RE<, and the voltage UV is at the same time above 25 V. The alarm is reset when the current is 0.5 mA or 20 % above the setting value, or when the voltage falls below 20 V. If I RE< is set to 0.0 mA, there is no current monitoring and no alarm.

2.30.2.1 Settings of the Rotor Earth Fault Protection Addr.

Setting Title

Setting Options

Default Setting

Comments

6001

ROTOR E/F


OFF


6002

RE< WARN

3.0..30.0 kOhm

10.0 kOhm

Pickup Value of Warning Stage Re<

6003

RE<< TRIP

1.0..5.0 kOhm

2.0 kOhm

Pickup Value of Tripping Stage Re<<

6004

T-WARN-RE<

0.00..60.00 sec; ∞

10.00 sec

Time Delay of Warning Stage Re<

6005

T-TRIP-RE<<

0.00..60.00 sec; ∞

0.50 sec

Time Delay of Tripping Stage Re<<

204

7UM62 Manual C53000-G1176-C149-3


Addr.

Setting Title

Setting Options

Default Setting

Comments

6006

X COUPLING

-100..800 Ohm

398 Ohm

Coupling Reactance

6007

R SERIES

0..999 Ohm

50 Ohm

Series Resistance (e.g. Meas. Brushes)

6008

I RE<

1.0..50.0 mA; 0

2.0 mA

Pickup Value of Failure Detection Ire<

6009

PHI I RE

-15.0..15.0 °

0.0 °

Correction Angle for Ire

2.30.2.2 Information for the Rotor Earth Fault Protection F.No.

Alarm

Comments

05383 >BLOCK R/E/F

>BLOCK rotor earth fault prot. (R,fn)

05391 R/E/F OFF

Rotor earth fault prot. (R,fn) swit. OFF

05392 R/E/F BLOCKED

Rotor earth fault prot. (R,fn) BLOCKED

05393 R/E/F AKTIVE

Rotor earth fault prot. (R,fn) is ACTIVE

05394 R/E/F U< block

Rot. earth flt. prot. (R,fn) block by U<

05397 R/E/F warning

Rot. earth flt.prot. (R,fn) Re< warning

05400 Failure R/E/F

Failure rotor earth fault prot. (R,fn)

05398 R/E/F picked up

Rot. earth flt.prot. (R,fn) Re<< pick.up

05399 R/E/F TRIP

Rotor earth fault prot. (R,fn) Re<< TRIP

7UM62 Manual C53000-G1176-C149-3

205

Functions

2.31

Sensitive Rotor Earth Fault Protection with 1 to 3 Hz Square Wave Voltage Injection (ANSI 64R - 1 to 3 Hz)

General

The rotor earth fault protection has the task to detect high- or low-resistance earth faults in the excitation circuit of synchronous generators. Although an earth fault in the excitation winding does not cause immediate damage, a second earth fault will lead to a turn-to-turn fault in the excitation winding. The resulting magnetic unbalances can develop extreme mechanical forces, which may destroy the machine. The protection function described here differs from the function described in Section 2.30 in that it is far more sensitive; it is used for large generators.

2.31.1 Functional Description Basic Principle

As Figure 2-98 shows, the rotor earth fault protection works with a direct voltage of approx. 50 V, the polarity of which is reversed between 1 and 4 times per second, depending on the setting. This voltage Ug injected into the rotor circuit is generated in the 7XT71 controller unit. The voltage passes through a resistor unit 7XR6004 (or 7XR6003) and is symmetrically coupled to the excitation circuit via high-resistance resistors, and at the same time connected to the earthing brush (potential to earth) via a low-resistance measuring shunt RM (see also Appendix, Figure A-36). The voltage picked up at the measuring shunt and the control voltage are fed into the protection device via measuring transducers. The control voltage is proportional to the injected 50 V voltage Ug in terms of amplitude and frequency. The earth current flowing in the rotor is modeled by the measurement voltage. Every time the polarity of the direct voltage Ug is reversed, a charging current Ig is driven across the resistor unit into the rotor-earth capacitors of the excitation circuit. This current causes a proportional voltage drop UMeas. Once the rotor earth capacitors are charged, the charging current drops to zero. In the presence of a rotor earth fault, a continuous earth current flows whose intensity is determined by the fault resistance. The use of a low-frequency square-wave voltage as displacement voltage eliminates the influence of the rotor-earth capacitors and ensures at the same time a sufficient margin against interference signals from the interference frequencies of the excitation system.

206

7UM62 Manual C53000-G1176-C149-3


7XR6003 or 7XR6004

7XT71

7UM62x

fg : 0.5 Hz to 4.0 Hz RS 40 kΩ RS CE/2 Fault resistance

CE/2

Galvanic isolation

lg (t) Ug (t) +/-50 V

40 kΩ

UControl/Ug = 1/6

UControl (MU1)

UMeas/lg = 375 Ω

UMeas (MU2)

lg (t)

CE: Rotor-earth capacitance RS : Series resistor

Ug: Square-wave voltage from 7XT71 Ig: Current flow from 7XT71 via rotor to earth fg: Square-wave frequency of the 7XT71

Figure 2-98

Connection Scheme of Voltage Injection into the Rotor Winding

Measuring Procedure

From the control voltage UControl, the function determines the timing for the polarity reversals and triggers the measurement. At the same time it calculates the voltage amplitude and converts it to the voltage Ug. The actual fault resistance is determined from the voltage UMeas, which is proportional to the current Ig. Every time the polarity of the control voltage is reversed, the DC component of the measurement voltage is determined by means of a mean value filter. The frequency of the series device must be set low enough to ensure that during the mean-value generation the rotor-earth capacitors are charged, so that only the steady-state portion is evaluated. This allows to detect high-resistance faults (max. approx. 80 kΩ) without being influenced by the earth capacitance. However, the measurement is falsified by two sources of interference. One of them is a DC voltage component in the measurement circuit which depends on the intensity of the excitation voltage and on the location of the earth fault in the excitation winding, and the other are considerable high-frequency voltage peaks that may superimpose the DC excitation voltage. These peaks are damped by a numerical filter. To eliminate the interference from the superimposed DC voltage component, the polarity of the voltage Ug is reversed (square-wave voltage). The measurement voltage calculation described above is performed for both polarities. On formation of the difference between two subsequent measurement results for Ig, namely Ig1 and Ig2 (see Figure 2-99), the DC component originating from the excitation circuit (Ioffset) is eliminated, whereas the DC components originating from the injected voltage Ug accumulate. With the measured quantity thus obtained, and the calculated amount of the displacement voltage Ug, the earth resistance can be calculated, taking into account the series resistors Rs (see Figure 2-99).

7UM62 Manual C53000-G1176-C149-3

207

Functions

ug (t) Ug 50 V

2 ⋅ Ug t

Displacement voltage Ug

50 V

u Meas (t)

ig (t) RE

5 mA t

5 mA

u Meas (t)

ig (t)

∞

Ig1 = Ig2 = 0

RE = 5 k Ω 2 ⋅ Ug

2 ⋅ Ig

2 ⋅ Ig Ig2

Ig1

=

Rs 2

+ RE , with R M << Rs

Ig2 - Ig1 = 2 ⋅ Ig

Ioffset

Ioffset = Interference t

Figure 2-99


Curves of the Displacement Voltage Ug, the Shunt Voltage UMeas and the Measurement Current Ig

On each polarity reversal, the charging current of the rotor earth capacitor is determined. A drop of this current allows to detect defects in the measurement circuit such as wire breaks, poor brush contact etc. This is only possible, however, if the rotor-earth capacitance is high enough (> 0.15 µF) and the interference from the excitation system is low. As an alternative, the protection function offers an external test option using a test resistor (included in the 7XR6004 and 7XR6003). The test mode is activated via a binary input, and the fault resistor is connected to a slip ring with an external relay. The protection function must be informed of the pertinent test resistance. The protection function issues appropriate indications showing the test results. It is also able to detect one-sided interruptions (such as wire breaks or loose terminals in a coupling (see Figure 2-98)). The evaluation logic is shown in Figure 2-100.

208

7UM62 Manual C53000-G1176-C149-3


Test mode 100 kΩ

20 kΩ (Series resistor = RS /2) 6107 TEST RESISTOR

+ 0.7

X X

1.3

X X

5411 2 Cir. open

&

RE>

&

RE>

&

& 5408 Test REF PASSED

&

RE<

RE

5410 1 Cir. open

&

RE<

RE>

&

&

OR

5409 Test REF Fail.

Figure 2-100 Logic Diagram of the Rotor Earth Fault Protection in Test Mode

In addition, the control voltage is monitored. If the control voltage is found to be missing or too low, a failure of the control unit is assumed (see also logic diagram in Figure 2-100). Logic

Figure 2-100 shows the logic diagram. It comprises the following elements: − Monitoring of the control unit 7XT71 − Supervision of the measurement circuit − Two-stage protection function − Effects of the rotor earth fault protection test If the earth resistance drops below the high-resistance stage RE<, a warning message will normally be issued. If it drops below the second, low-resistance stage RE<<, a trip signal is issued after a short time.

7UM62 Manual C53000-G1176-C149-3

209

Functions

10 V 4-20 mA 20 mA

"1" 295

TRANSDUCER 1 &

10 V 4-20 mA 20 mA

"1" 296

TRANSDUCER 2

Edge detector T Edge 5s

&

5401 Fail REF 1-3Hz

OR

6106 Qc < òdt Qc

5395 REF 1-3Hz open

T Interference 10 s

&

6102 RE< WARN 6104 T-WARN-RE< 5403 REF 1-3Hz Warn

UMeas(~Ig) UControl(~Ug)

RE

&

&

6103 RE<< TRIP 6105 T-TRIP-RE<<

5406 REF 1-3Hz Fault &

5381 >REF 1-3Hz BLK

&

5407 REF 1-3Hz Trip

Tripping matrix Tmin TRIP CMD

Test mode

5388 REF 1-3Hz BLK

5386 >Test REF 1-3Hz

Figure 2-101 Logic Diagram of the Sensitive Rotor Earth Fault Protection

210

7UM62 Manual C53000-G1176-C149-3



The sensitive rotor earth fault protection is only effective and accessible if it has been set to Enabled at address 0161 REF 1-3Hz during the configuration of the protection functions. It must also be ensured that the measuring transducer inputs TD1 and TD2 are not used for any other function. Address 6101 REF 1-3Hz is used to switch the function ON or OFF, or to block only the trip command (Block relay).

Pickup Values

Since the protection calculates the ohmic rotor-earth resistance from the values supplied by the injected voltage, the series resistance and the flowing earth current, the thresholds for the warning stage 6102 RE< WARN) and for the trip stage (6103 RE<< TRIP) can be set directly as resistance values. The default settings (RE< WARN = 40 kΩ and RE<< TRIP = 5 kΩ) are sufficient for the majority of cases. These values can be changed depending on the insulation resistance and the coolant. Care must be taken to allow a sufficient margin between the setting value and the actual insulation resistance. As interference from the excitation system cannot be excluded, the setting for the warning stage is not finally determined until the primary tests.

Time Delays

The time delay for the warning stage (6102 T-WARN-RE<) is usually set to approximately 10 s, and the delay for the trip stage (6103 T-TRIP-RE<<) to approximately 1 s. The set times are additional time delays not including the operating times (measuring time, drop-out time) of the protection function.


The setting value of the measuring circuit monitoring (6106 Qc <) is defined during the primary tests. For this purpose, the operational measured value (Qc) is read out, and half of the value is set. If the charge measured is too low, the monitoring cannot be effective. The parameter Qc < should in that case be set to 0 mAs. No fault indication will be issued. No settings are required if you want to perform the external test using the test resistor included in the 7XR6004 (3.3 kΩ). If a different resistor is to be used, its resistance must be set in the advanced parameter TEST RESISTOR (can only be changed with the DIGSI communication software) at address 6107A.

7UM62 Manual C53000-G1176-C149-3

211

Functions

2.31.2.1 Settings of the Sensitive Rotor Earth Fault Protection Addr.

Setting Title

Setting Options

Default Setting

Comments

6101

REF 1-3Hz


OFF


6102

RE< WARN

5.0..80.0 kOhm

40.0 kOhm


6103

RE<< TRIP

1.0..10.0 kOhm

5.0 kOhm


6104

T-WARN-RE<

0.00..60.00 sec; ∞

10.00 sec


6105

T-TRIP-RE<<

0.00..60.00 sec; ∞

1.00 sec


6106

Qc <

0.00..1.00 mAs

0.02 mAs

Pickup Value of open Rotor Circuit (Qc)

6107A

TEST RESISTOR

1.0..10.0 kOhm

3.3 kOhm

Testing Resistor

2.31.2.2 Information for the Sensitive Earth Fault Protection F.No.

Alarm

Comments

05381 >REF 1-3Hz BLK

>BLOCK rotor earth fault prot. (1-3Hz)

05386 >Test REF 1-3Hz

>Test rotor earth fault prot. (1-3Hz)

05387 REF 1-3Hz OFF

REF protection (1-3Hz) is switched OFF

05388 REF 1-3Hz BLK

REF protection (1-3Hz) is BLOCKED

05389 REF 1-3Hz ACT

REF protection (1-3Hz) is ACTIVE

05395 REF 1-3Hz open

REF protection (1-3Hz) open circuit

05401 Fail REF 1-3Hz

Failure REF protection (1-3Hz)

05403 REF 1-3Hz Warn

REF prot. (1-3Hz): warning stage (Re<)

05406 REF 1-3Hz Fault

REF prot. (1-3Hz) Re<< picked up

05407 REF 1-3Hz Trip

REF prot. (1-3Hz) Re<< TRIP

05408 Test REF PASSED

REF prot. (1-3Hz) test passed

05409 Test REF Fail.

REF prot. (1-3Hz) test NOT passed

05410 1 Cir. open

REF (1-3Hz) 1 Measuring circuit open

05411 2 Cir. open

REF (1-3Hz) 2 Measuring circuits open

212

7UM62 Manual C53000-G1176-C149-3


2.32


General

When the 7UM62 relay is used to protect a motor, the starting time monitoring feature supplements the overload protection described in Section 2.9 by protecting the motor against the potential damage that might result from frequent starting or extended starting durations. In particular, rotor-critical high-voltage motors can quickly be heated above their thermal limits when multiple starting attempts occur in a short period of time. If the durations of these starting attempts are lengthened by excessive voltage surges during motor starting, by excessive load moments, or by locked rotor conditions a tripping signal will be initiated by the device.

2.32.1 Functional Description The motor starting time monitoring is initiated by the motor starting recognition setting entered at address 6505 I MOTOR START. This current releases the calculation of the tripping characteristic. One characteristic is definite time while the other one is inverse time. Inverse TimeOvercurrent Tripping Characteristic

The inverse time-overcurrent characteristic is designed to operate only when the rotor is not blocked. The inverse time characteristic allows motor starting time monitoring to adjust for those situations where high starting voltages result in decreased starting currents. The tripping time is calculated based on the following formula: I StartCurrent 2 where I > IMotor Start t TRIP = æ --------------------------------ö ⋅ tStartmax è ø I where

tTRIP

– Actual tripping time for flowing current I

tStartmax

– Tripping time for nominal start-up current IA (set at address 6503, STARTING TIME) – Current actually flowing (measured value) – Nominal starting current of the motor (set at address 6502, START. CURRENT) – Pickup value for recognition of motor starting (set at address 6505, I MOTOR START)

I IStartCurr. IMotorStart

tTRIP [s]

tStartmax

IMotorStart

IStartCurr.

I

Figure 2-102 Inverse Time Characteristic Tripping Curve for Motor Starting Current

7UM62 Manual C53000-G1176-C149-3

213

Functions

Therefore, if the starting current I actually measured is smaller (or larger) than the nominal starting current IA entered at address START. CURRENT), the actual tripping time ttrip is lengthened (or shortened) accordingly (see also Figure 2-102). Definite-Time Overcurrent Tripping Characteristic (Locked Rotor Time)

During motor starting, the definite time characteristic is designed to initiate a trip if the motor starting time exceeds the maximum allowable blocked rotor time tE. The device can detect a locked rotor condition via a binary input (”>Rotor locked”) from an external rpm-counter. If the current in any of the phases exceeds the motor starting recognition setting entered at address I MOTOR START, and if a locked rotor condition is detected via a binary input, a motor starting condition is assumed, and time delayed tripping via the definite time characteristic will be initiated (based on the maximum allowable locked rotor time). It should be noted that this happens every time the motor is started and is a normal operating condition that is neither entered in the operational annunciations buffer, nor output to the control center, nor causes the creation of a fault record. The locked rotor delay time (LOCK ROTOR TIME) is ANDed with the binary input”>Rotor locked”. If the binary input is still high after the locked rotor time has elapsed, tripping is performed immediately, regardless of whether the binary input was activated before or during the delay, or after the delay had elapsed.

Logic

The motor starting time supervision may be switched on or off by parameters. In addition, motor starting protection may be blocked via a binary input, at which time pickup messages and time delays will be reset. Figure 2-103 illustrates the logic for motor starting protection. A pickup does not create a fault record. Fault recording is not started until a trip command has been issued.

Fault condition FNo. 06821

6505 I MOTOR START

OR

IL1

START-SUP TRIP

FNo. 06823

START-SUP PU

6502 START. CURRENT 6503 STARTING TIME

OR 6504 LOCK ROTOR TIME T

L1

0

Tripping matrix

OR R

OR

&

S

Q

FNo. 06822 Rotor locked TMin TRIP CMD

FNo. 06805 >Rotor locked FNo. 06801 >BLK START-SUP

FNo. 06812 START-SUP BLK

Figure 2-103 Logic Diagram of the Motor Starting Time Supervision

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The motor starting time supervision is only effective and accessible if address 0165 STARTUP MOTOR has been set to Enabled during the configuration of the protective functions. Set Disabled if the function is not required. Address 6501 STARTUP MOTOR is used to switch the function ON or OFF, or to block only the trip command (Block Relay).

Pickup Values

The device is informed of the startup current values under normal conditions at address 6502 START. CURRENT, and of the startup time at address 6503 STARTING TIME. This ensures timely tripping if the value of I2 t calculated by the relay is exceeded. If the starting time exceeds the permissible locked rotor time, the definite-time tripping characteristic can be started by an external r.p.m. counter via a binary input (“>Rotor locked”). A locked rotor leads to a loss of ventilation and therefore to a reduced thermal load capacity of the machine. Therefore, the starting time supervision must issue a trip command before the thermal characteristic for normal operation is reached. A current above the threshold I MOTOR START (address 6505) is interpreted as a motor startup. Consequently, this value must be chosen such that it is reliably attained by the actual starting current under any load or voltage conditions during motor startup, but not during a permissible short-time overload. Example: Motor with the following data: Nominal voltage

UN = 6600 V

Nominal current

IMot.nom = 126 A

Startup current

IStartCurr. = 624 A

Permissible continuous stator current: Starting time at IStartCurr.

Imax = 135 A TStartmax = 8.5 s

CT ratio IN CT prim/IN CT sec

200 A/1 A

The setting for address START. CURRENT is calculated as follows: Start-up current 624 A IStartCurr, sec = ---------------------------------------------------- ⋅ IN CT sec = --------------- ⋅ I N CT sec = 3.12 A Nominal CT current 200 A For reduced voltage, the start-up current is also reduced almost linearly. At 80 % nominal voltage, the start-up current in this example is reduced 0.8 ⋅ ISTARTUP = 2.5 ⋅ IN CT sec. The threshold for detection of a motor startup must lie above the maximum load current and below the minimum start-up current. If no other influencing factors are present (peak loads), the value (I MOTOR START set at address 6505) may be a median value: Based on the long-term current rating:

135 A --------------- = 0.68 ⋅ I N CT sec 200 A

2.5 I N + 0.68 I N I MotorStart = ----------------------------------------- ≈ 1.6 ⋅ IN CT sec 2

= 1.6 A

The tripping time of the starting time monitoring is calculated as follows:

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215

Functions

I StartCurr. 2 T Trip = æ ----------------------ö ⋅ T Startmax è ø I Under nominal conditions, the tripping time is the maximum starting time TStartmax. For ratios deviating from nominal conditions, the motor tripping time changes. At 80 % of nominal voltage (which corresponds to 80% of nominal starting current), the tripping time can be: 2 624 A T Trip = æ ----------------------------ö ⋅ 8.5 s = 13.3 s è 0.8 ⋅ 624 Aø

After the delay time LOCK ROTOR TIME has elapsed, the locked rotor binary input becomes effective and initiates a tripping signal. If the locked rotor time is set just long enough that during normal startup the binary input ”>Rotor locked” (FNo. 06805) is reliably reset during the delay time LOCK ROTOR TIME, faster tripping will be available during motor starting under locked rotor conditions.

2.32.2.1 Settings of the Motor Starting Time Supervision The following list indicates the setting ranges and the default settings of a IN = 1 A secondary nominal current. For a secondary nominal current of IN = 5 A, these values must be multiplied by 5. Consider the current transformer ratios when setting the device with primary values. Addr.

Setting Title

Setting Options

Default Setting

Comments

6501

STARTUP MOTOR


OFF


6502

START. CURRENT

0.10..16.00 A

3.12 A

Starting Current of Motor

6503

STARTING TIME

1.0..180.0 sec

8.5 sec

Starting Time of Motor

6504

LOCK ROTOR TIME

0.5..120.0 sec; ∞

6.0 sec

Permissible Locked Rotor Time

6505

I MOTOR START

0.60..10.00 A

1.60 A

Current Pickup Value of Motor Starting

2.32.2.2 Information for the Motor Starting Time Supervision F.No.

Alarm

Comments

06801 >BLK START-SUP

>BLOCK Motor Starting Supervision

06805 >Rotor locked

>Rotor is locked

06811 START-SUP OFF

Starting time supervision switched OFF

06812 START-SUP BLK

Starting time supervision is BLOCKED

06813 START-SUP ACT

Starting time supervision is ACTIVE

06822 Rotor locked

Rotor is LOCKED after Locked Rotor Time

06823 START-SUP PU

Starting time supervision picked up

06821 START-SUP TRIP

Starting time supervision TRIP

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2.33


General

The rotor temperature of a motor generally remains well below its maximum allowable temperature during normal operation and even during severe loading conditions. However, during motor starting, the rotor can heat up quickly. If multiple starting attempts are made in a short duration of time, the rotor could suffer thermal damage. Therefore, the 7UM62 motor start blocking feature is available. A motor restart inhibit signal is initiated when the relay projects rotor temperature exceeds the maximum allowable temperature, and blocking continues until the calculated rotor temperature decreases below the reset level. To block starting, the restart inhibit signal must be masked to an output relay whose contact is inserted in the motor starting circuit.

2.33.1 Functional Description Determining the Rotor Overtemperature

Because the rotor current cannot be measured directly, the stator current must be used to generate a thermal profile of the rotor. The r.m.s. values of the currents are generated for this. The excessive rotor temperature ΘR is calculated using the highest of the three phase currents. The thermal limit values for the rotor winding are based on manufacturer’s data regarding the nominal starting current, maximum permissible starting time, and the number of starts permitted from cold (ncold) and warm (nwarm) conditions. From this data, the device performs the necessary calculations to establish the thermal rotor profile and issues a blocking signal until the thermal rotor profile decreases below the restarting limit.

Cool down at τ·kτ at running

ΘL Maximum permissible rotor temperature Temperature curve: Rotor cage bar upper side limit

Threshold of restart inhibit (ΘReInhib)

Rotor cage bar lower side limit

Cool down at τ·kτ at stop

Thermal profile 1. Startup Motor started Current

2. Startup Rotor temper. equilibr. time

Motor started

Rotor temper. equilibr. time

3. Startup Motor started

t Rotor temper. equilibr. time

CB I > t

Figure 2-104Temperature Curve at the Rotor and the Thermal Profile during Repeated StartUp Attempts

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217

Functions

Although the heat distribution at the rotor cage bars can range widely during motor starting, the different maximum temperatures in the rotor do not necessarily affect the motor restart inhibit (see Figure 2-104). It is much more important to establish a thermal profile, after a complete motor start, that is appropriate for the protection of the motor’s thermal condition. Figure 2-104 shows, as an example, the heating processes during repeated motor starts (three starts from cold operating condition), as well as the thermal reproduction by the protective relay. Restarting Limit

If the rotor temperature has exceeded the restarting limit, the motor cannot be restarted. When the rotor temperature goes below the restarting limit, that is, when exactly one start becomes possible without exceeding the excessive rotor temperature limit, the blocking signal is terminated. Therefore the restarting temperatureΘRe.Inhib, related to the maximum permissible rotor overtemperature is expressed as:

n cold – 1 Θ ReInhib [ % ] = --------------------- ⋅ 100 % n cold

Restarting Times

ncold

2

3

4

ΘRe.Inhib [%]

50 %

66.7 %

75 %

The motor manufacturer allows a maximum number of starting attempts under cold (ncold) and warm (nwarm) conditions. Afterwards the motor cannot be restarted but must be allowed some time — the restarting time — for the rotor to cool down. This temperature behaviour is provided for in the protection as follows: After each motor shutdown, a temperature equilibrium time (address 6604 T EQUAL) is started which takes into account the different temperatures of different motor parts at the moment of shutdown. During the rotor temperature equilibrium time, the thermal profile is not updated but kept constant to model the equilibrium taking place in the rotor. After that, the thermal profile cools down with a rotor time constant multiplied by extension factor). During the equilibrium time the motor cannot be restarted. As soon as temperature sinks below the restarting threshold, the next restart attempt can be made. The entire time that must elapse before motor starting can resume is equal to the equilibrium time and the amount of time, calculated via the thermal model, that it takes for the rotor temperature to decrease to the reset temperature level: Θ pre ⋅ n cold T ReInhib time = T Equilibrium + k τ ⋅ τ LR ⋅ ln ----------------------------n cold – 1 where TEquilibrium – Rotor temperature equilibrium time address 6604 kτ

τR Θpre

– Extension factor for the time constant = Kt at RUNNING address 6609 or Kt at STOP address 6608 – Rotor time constant, internally calculated: τR = tStart ⋅ (ncold – nwarm) ⋅ Ιstart2 where tStart = Starting time in s ΙStart = Starting current in pu – Thermal profile at the moment of motor shutdown (depends on the operating state)

The operational measured value TReInhib time (to be found in the overload measured values) shows the time remaining until the next restart is permissible.

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7UM62 Manual C53000-G1176-C149-3


Extending the Cooling Time Constant

In order to properly account for the reduced heat exchange when a self-ventilated motor is stopped, the cooling time constants can be increased relative to the time constants for a running machine by the factor Kt at STOP (address 6608). A stopped motor is defined by current below an adjustable current flow monitoring threshold BkrClosed I MIN, assuming that the motor idle current is greater than this threshold. The pickup threshold BkrClosed I MIN affects also the thermal overload protection function (see Section 2.9). While the motor is running, the heating of the thermal profile is modeled with the time constantτL calculated from the motor ratings, and the cooldown calculated with the time constant τL ⋅ Kt at RUNNING (address 6609). In this way, the protection caters to the requirements in case of a slow cooldown (slow temperature equilibrium).

Minimum Inhibit Time

Regardless of thermal profiles, some motor manufacturers require a minimum inhibit time after the maximum number of permissible starting attempts has been exceeded. The duration of the inhibit signal depends on which of the times, T MIN. INHIBIT or TReInhib time, is longer.

Behaviour in Case of a Power Supply Failure

Depending on the setting of parameter 0274A ATEX100, the value of the thermal profile is either reset on a failure of the power supply voltage, or cyclically buffered in a”non-volatile” memory until the power supply voltage returns. In the second case, the thermal replica uses the last buffered value for calculation and matches it to the operating conditions.

Emergency Starting

If, under emergency conditions, motor starting in excess of the maximum allowable rotor temperature must take place, the motor start blocking signal can be terminated via a binary input (”>Emer. Start QR”), thus allowing a new starting attempt. The thermal rotor profile continues to function, however, and the maximum allowable rotor temperature will be exceeded. No motor shutdown will be initiated by the motor restart inhibit, but the calculated excessive temperature of the rotor can be observed for risk assessment.

Blocking

If the motor start blocking function is blocked or switched off, the thermal profile of the excessive rotor temperature and the equilibrium time T EQUAL as well as the minimum inhibit time T MIN. INHIBIT are reset, and any existing motor start inhibit signal is terminated.

Logic

The thermal profile can also be reset via a binary input. This may be useful for testing and commissioning, and after a power supply voltage failure. Figure 2-105 shows the logic diagram for the restart inhibit function.

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219

Functions

I IL2 L3 IL1

6609 Kt at RUNNING

Imax

kτat Running x τ 6602 IStart/IMOTnom 6608 Kt at STOP

6603 T START MAX

kτat Stop x τ

6606 MAX.WARM STARTS 6607

0281

BkrClosed I MIN

6604 T EQUAL T

I>

0

S

#COLD-#WARM

ΘL(t) Calculator

Q

ΘL = 0

R

&

ΘL(t) > ΘRe.Inhib

OR

FNo. 04830

Re. Inhib.ALARM 6610 T MIN. INHIBIT

FNo. 04828

>RM th.rep. QR S

&

Q

T

0

R

OR FNo. 04827

OR

FNo. 04823

Re. Inhib. TRIP

& &

>Emer. Start QR

Tripping matrix

TMin TRIP CMD

FNo. 04829

OR

WES RS.th.Abb.

FNo. 04822

FNo. 04825 Re. Inhibit BLK

>BLK Re. Inhib.

FNo. 04826

OR

OR

Re. Inhibit ACT

6601 RESTART INHIBIT

”1”

OFF ON Block relay

FNo. 04824

Re. Inhibit OFF

Figure 2-105 Logic Diagram of the Restart Inhibit


220

The motor start blocking function is only effective and accessible if address 0166 RESTART INHIBIT was set to Enabled during configuration of the protective functions. Set Disabled if the function is not required. Address 6601

7UM62 Manual C53000-G1176-C149-3


RESTART INHIBIT is used to switch the function ON or OFF, or to block only the trip command (Block Relay). Necessary Characteristic Values

The user communicates to the protective relay the characteristic motor values supplied by the manufacturer, which are necessary for calculation of the rotor temperature. These values include the starting current IStart, the nominal motor current IMot.nom, the maximum permissible startup time T START MAX (address 6603), the number of permissible restart attempts under cold (ncold) and (nwarm) conditions. The starting current is entered at address 6602, expressed as a multiple of the nominal motor current (IStart/IMOTnom). For a correct interpretation of this parameter, it is important that in Power System Data 1 the apparent power (address 252 SN GEN/ MOTOR) and the rated voltage (address 251 UN GEN/MOTOR) of the motor are correctly set. The number of warm starts allowed is entered at address 6606 (MAX.WARM STARTS), and the difference between the number of allowable cold and warm starts (#COLD-#WARM) is entered at address 6607. For motors without separate ventilation, the reduced cooling at motor stop can be accounted for by entering at address 6608 the reduced ventilation, expressed by the factor Kt at STOP. As soon as the current no longer exceeds the current flow monitoring setting entered at address 0281 BkrClosed I MIN, a motor standstill is assumed and the time constant is increased by the set factor. If no difference between the time constants is to be used (e.g. externally-ventilated motors), then the factor should be set to Kt at STOP = 1. The cooling with the motor running is influenced by the extension Kt at RUNNING. This factor considers that motor running under load and a stopped motor do not cool down at the same speed. It becomes effective as soon as the current exceeds the value set at address 0281 BkrClosed I MIN. With Kt at RUNNING = 1 the heating and the cooling time constant are the same at operating conditions (I > BkrClosed I MIN).

Setting Example:

Motor with the following data: Nominal voltage

UN = 6600 V

Nominal current

IMot.nom = 126 A

Starting current

IStart = 624 A

Starting time at ISTART

TSTART max = 8.5 s

Permissible number of startups with cold motor Permissible number of startups with warm motor CT transformation ratio

ncold = 3 nwarm = 2 200 A/1 A

The ratio between the starting current and the motor nominal current is: 624 A I Start ⁄ I Mot.nom = --------------- = 4.95 ≈ 4.9 126 A Settings

7UM62 Manual C53000-G1176-C149-3

IStart/IMOTnom T START MAX MAX.WARM STARTS #COLD-#WARM

= 4.9 = 8.5 s =2 =1

221

Functions

For the rotor temperature equilibrium time, a setting of. T EQUAL = 1 min has proven to be a good value. The value for the minimum inhibit time T MIN. INHIBIT depends of the requirements made by the motor manufacturer, or by the system conditions. It must in any case be higher than T EQUAL. In this example, a value has been chosen that reflects the thermal profile (T MIN. INHIBIT = 6.0 min). The motor manufacturer's, or system requirements determine also the extension factor for the time constant during cooldown, especially with the motor stopped. Where no other specifications are made, the following settings are recommended: Kt at STOP = 5 and Kt at RUNNING = 2. For a proper functioning, it is also important that the CT values for side 2 (addresses 0211 and 0212), the power system data (addresses 0251, 0252) and the threshold current for distinction between stopped and running motor (address 0281 BkrClosed I MIN, recommended setting ≈ 0.1 ⋅ I/IN Motor) have been set correctly. An overview of the parameters and their default settings is given in the tables at the end of this section and in the Appendix. Temperature Behaviour during Changing Operating States

For better understanding of the above considerations, two of the many possible operating states will be discussed in the following paragraph. The examples use the settings indicated above. 3 cold and 2 warm startup attempts have resulted in a restart limit of 66.7 %. Figure 2-106 illustrates the temperature behaviour during 2 warm startup attempts. The motor is always operated at nominal current. After the first shutdown, T EQUAL takes effect. 30 s later the motor is restarted and immediately shut down again. After another pause, the 2nd restart attempt is made. The motor is shut down once again. During this 2nd startup attempt, the restarting limit is exceeded, so that after shutdown the restart inhibit takes effect. After the temperature equilibrium time (1 min), the thermal profile cools down with the time constant τL ⋅ Kt at STOP ≈ 5 ⋅ 204 s = 1020 s. The restart inhibit is effective for about 7 min.

1st startup

2nd startup

p.u. 1.0

0.8 Inhibit time

0.6

0.4

Temperature in p.u. Restarting limit

0.2

Motor current in I/IN

0 100

200

300

400

500

600

700

t/s

Figure 2-106 Temperature Behaviour during Two Successive Warm Starts

222

7UM62 Manual C53000-G1176-C149-3


In Figure 2-107, the motor is also restarted twice in warm condition, but the pause between the restart attempts is longer than in the first example. After the second restart attempt, the motor is operated at 90 % nominal current. After the shutdown following the first starting attempt, the thermal profile is “frozen”. After the temperature equilibrium time (1 min) the rotor cools down with the time constant τL ⋅ Kt at STOP ≈ 5 ⋅ 204 s = 1020 s. During the second restart, the starting current causes a temperature rise, whereas the subsequently flowing on-load current of 0.9 ⋅ I/IN Motor reduces the temperature. This time, the time constant τL ⋅ Kt at RUNNING = 2 ⋅ 204 s = 408 s is effective. The fact that the restarting limit is exceeded for a short time does not mean a thermal overload. It rather signals that a thermal overload of the rotor would arise if the motor were shut down immediately and restarted.

p.u.

1st startup

2nd startup

1.0

0.8

0.6

0.4 Temperature in p.u. Restarting limit

0.2

Motor current in I/IN 0 200

600

400

800

1000

t/s

Figure 2-107 Two Warm Restart Followed by Continuous Running

2.33.2.1 Settings of the Restart Inhibit for Motors Addr.

Setting Title

Setting Options

Default Setting

Comments

6601

RESTART INHIBIT


OFF


6602

IStart/IMOTnom

1.5..10.0

4.9

I Start / I Motor nominal

6603

T START MAX

3.0..320.0 sec

8.5 sec


6604

T EQUAL

0.0..320.0 min

1.0 min

Temperature Equalization Time

6606

MAX.WARM STARTS

1..4

2

Permissible Number of Warm Starts

6607

#COLD-#WARM

1..2

1

Number of Cold Starts - Warm Starts

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223

Functions

Addr.

Setting Title

Setting Options

Default Setting

Comments

6608

Kτ at STOP

1.0..100.0

5.0

Extension of Time Constant at Stop

6609

Kτ at RUNNING

1.0..100.0

2.0

Extension of Time Constant at Running

6610

T MIN. INHIBIT

0.2..120.0 min

6.0 min

Minimum Restart Inhibit Time

2.33.2.2 Information for the Motor Restart Inhibit F.No.

Alarm

Comments

04822 >BLK Re. Inhib.

>BLOCK Restart inhibit motor

04828 >RM th.rep. ΘR

>Reset thermal memory rotor

04823 >Emer. Start ΘR

>Emergency start rotor

04824 Re. Inhibit OFF

Restart inhibit motor is switched OFF

04825 Re. Inhibit BLK

Restart inhibit motor is BLOCKED

04826 Re. Inhibit ACT

Restart inhibit motor is ACTIVE

04829 RM th.rep. ΘR

Reset thermal memory rotor

04827 Re. Inhib. TRIP

Restart inhibit motor TRIP

04830 Re. Inhib.ALARM

Alarm restart inhibit motor

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2.34



The breaker failure protection can be assigned to the current inputs of side 1 or side 2 during the configuration of the protective functions (see Section 2.2). The breaker failure protection function monitors the reaction of a circuit breaker to a trip signal. In machine protections, it is typically referred to the mains breaker. To determine if the circuit breaker has properly opened in response to a trip signal, one of the following methods is used to ascertain the status of the circuit breaker: • Checking whether the current in all three phases drops below a set threshold following a trip command, • Evaluating the position of a circuit breaker auxiliary contact for protective functions, with which the current criterion is perhaps not expressive, e.g. frequency protection, voltage protection, rotor earth fault protection. If the circuit breaker has not opened after a programmable time delay (breaker failure), a higher-level circuit breaker can initiate the disconnection (refer to Figure 2-108 as an example).

Breaker Failure Protection B/F I>

Protective Elements

&

B/F–Ttrip 0 TRIP B/F”

G Figure 2-108 Functional Principle of the Breaker Failure Protection Function

Initiation

The breaker failure protection function can be initiated by two different sources: • Internal protective function of the 7UM62, e.g. trip commands of protective functions or via CFC (internal logic functions), • External trip signals via binary input.

Criteria

7UM62 Manual C53000-G1176-C149-3

The two pickup criteria (current criterion, circuit breaker auxiliary contact) are OR logics. In case of a tripping without short circuit current, e.g. by the voltage protection in case of light load, the current is no safe criterion of the circuit breaker response. For this reason, the pickup is also possible by means of the auxiliary contact criterion.

225

Functions

The current criterion is fulfilled if at least one of the three phase currents exceeds a parameterized threshold value (CIRC. BR. I>). The dropout is performed if all three phase currents fall below 95 % of the pickup threshold value. If the binary input of the circuit breaker auxiliary contact is inactive, only the current criterion is effective and the breaker failure protection cannot become active with a tripping signal if the current is below the CIRC. BR. I> threshold. Two-Channel Feature

To protect against nuisance tripping due to excessive contact bounce, a stabilization of the binary inputs for external trip signals takes place. This external signal must be present during the entire period of the delay time. Otherwise, the timer is reset and no tripping signal is issued. A redundant binary input “>ext.start2 B/F” is linked to further enhance the security against unwanted operation. This means that no initiation is possible unless both binary inputs are activated. The two-channel feature is also effective for an”internal” initiation.

Logic

If the breaker failure protection has picked up, a corresponding message is transmitted and a parameterized time delay starts. If the pickup criteria are still fulfilled on expiration of this time, a redundant source evaluation before fault clearing is initiated via a further AND link by means of a superior circuit breaker. A pickup drops off and no trip command is produced by the breaker failure protection if − an internal start condition (Output relay BO12 or via CFC) or “>ext.start1 B/F” or “>ext.start2 B/F” causing the pickup drop off. − a tripping signal of the protective functions still exists, whereas the current criterion and the auxiliary contact criterion drop out. Figure 2-109 illustrates the logic diagram of the breaker failure protection. The overall breaker failure protection can be switched on or off via parameters and also blocked dynamically via binary inputs.

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7UM62 Manual C53000-G1176-C149-3


Device-internal protective functions I>TRIP

U>>TRIP

Masking

HW model of relays

BO 12 binary output (Relay R12), potential-free

f
>int. start B/F FNo. 01441

>ext.start2 B/F

7002 TRIP INTERN

OFF

”0”

CFC Bin.Outp.12

OR int. start B/F

FNo. 01423

>ext.start1 B/F

FNo. 01471

BrkFailure TRIP

FNo. 01443

OR

FNo. 01455

B/F picked up Tripping matrix

7004 TRIP-Timer

&

& FNo. 01422

>Break. Contact

OR

7003 CIRC. BR. I>

FNo. 01444

B/F I> FNo. 01403

FNo. 01452

>BLOCK BkrFail

BkrFail BLOCK

TMin TRIP CMD

Figure 2-109 Logic Diagram for the Breaker Failure Protection


The breaker failure protection function is only effective and available if it has been assigned at address 0170 BREAKER FAILURE to Side 1 or Side 2 during configuration of the protective functions. Set Disabled if the function is not required. Address 7001 BREAKER FAILURE is used to switch the function ON or OFF, or to block only the trip command (Block Relay). The current measurement for the circuit breaker failure protection can be performed either at side 1 (inputs IL, S1) or at side 2 (inputs IL, S2). It is recommended to use the terminal-side set of CTs, i.e. side 1.

Criteria

The parameter 7002 TRIP INTERN serves to select the OFF criterion of the internal pickup. It can be implemented by reading the switching statuses of the corresponding output relays BO12 (7002 TRIP INTERN = BO12) or by a logic link created in CFC (= CFC) (annunciation 1442 ”>int. start B/F”). The internal source can be completely deactivated (7002 TRIP INTERN = OFF). In this case the breaker failure protection can only be initiated by external sources via binary input. Note: Be aware that only the potential-free binary output BO12 (Relay R12) can be used for the breaker failure protection. This means that trippings for the network breaker must be configured to this binary output.

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227

Functions

The pickup threshold 7003 CIRC. BR. I> setting of the current criterion refers to all three phases. The user must select a value ensuring that the function still picks up even for the lowest operating current to be expected. For this reason, the value should be set at least 10% below the minimum operating current. However, the pick-up value should not be selected lower than necessary, as a too sensitive setting risks prolongations of the drop-out time due to balancing procedures in the current transformer secondary circuit during the switchoff of too high currents. The breaker failure time delay setting is entered at 7004 TRIP-Timer. This setting should be based on the circuit breaker interrupting time plus the dropout time of the current flow monitoring element plus a safety margin. Figure 2-110 illustrates the timing of a typical breaker failure scenario.

Time Delay

Fault occurs Normal fault clearing time Trip. time

Breaker disconnecting time

Dropout CIRC. BR. I>

Safety time

Breaker failure pickup Breaker disconnecting time (adjacent)

Delay time TRIP-Timer Breaker failure monitoring

Total fault clearing time for breaker failure condition

Figure 2-110 Timing for a Typical Breaker Failure Scenario

2.34.2.1 Settings for Breaker Failure Protection The following list indicates the setting ranges and the default settings of a IN = 1 A secondary nominal current. For a secondary nominal current of IN = 5 A, these values must be multiplied by 5. Consider the current transformer ratios when setting the device with primary values. Addr.

Setting Title

Setting Options

Default Setting

Comments

7001

BREAKER FAILURE


OFF


7002

TRIP INTERN

OFF Start Breaker Failure with Bin.Outp.12 Start Breaker Failure with CFC

OFF

Start with Internal TRIP Command

7003

CIRC. BR. I>

0.04..2.00 A

0.20 A

Supervision Current Pickup

7004

TRIP-Timer

0.06..60.00 sec; ∞

0.25 sec

TRIP-Timer

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7UM62 Manual C53000-G1176-C149-3


2.34.2.2 Information for the Breaker Failure Protection F.No.

Alarm

Comments

01403 >BLOCK BkrFail

>BLOCK breaker failure

01422 >Break. Contact

>Breaker contacts

01423 >ext.start1 B/F

>ext. start 1 breaker failure prot.

01441 >ext.start2 B/F

>ext. start 2 breaker failure prot.

01442 >int. start B/F

>int. start breaker failure prot.

01451 BkrFail OFF

Breaker failure is switched OFF

01452 BkrFail BLOCK

Breaker failure is BLOCKED

01453 BkrFail ACTIVE

Breaker failure is ACTIVE

01443 int. start B/F

Breaker fail. started intern

01444 B/F I>

Breaker failure I>

01455 B/F picked up

Breaker failure protection: picked up

01471 BrkFailure TRIP

Breaker failure TRIP

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229

Functions

2.35 General

Inadvertent Energization (ANSI 50, 27) The inadvertent energizing protection serves to limit damages by accidental connection of the standing or already started, but not yet synchronized generator by a fast actuation of the mains breaker. A connection to a standing machine corresponds to the connection to an inductivity. Due to the nominal voltage impressed by the power system, the generator starts with a high slip as asynchronous machine. In this context, impermissibly high currents are induced inside the rotor which may finally destroy it.

2.35.1 Functional Description Criteria

The inadvertent energizing protection only intervenes if measured quantities do not yet exist in the valid frequency working area (operational condition 0 in case of the standing machine) or if an undervoltage below the nominal frequency is present (machine already started, but not yet synchronized). The inadvertent energizing protection is blocked by a voltage criterion on exceeding a minimum voltage, in order to avoid that it picks up during normal operation. This blocking is delayed to avoid that the protection is blocked immediately by the time of an unwanted connection. Another pickup delay is necessary to avoid an unwanted operation in case of high-current faults with a heavy voltage dip. A dropout time delay allows for a measuring limited in time. As the inadvertent energizing protection must intervene very quickly, the instantaneous current values are monitored over a large frequency range already in operational condition 0. If valid measured quantities exist (operational condition 1), the positive phase-sequence voltage, the frequency for blocking the inadvertent energizing protection as well as the instantaneous current values are evaluated as tripping criterion. Figure 2-111 illustrates the logic diagram of the inadvertent energizing protection. This function can be blocked via a binary input. For example, the existence of an excitation voltage can be used as addition criterion. As the voltage is a necessary criterion for tripping the inadvertent energizing protection, the voltage transformers must be monitored by the Fuse–Failure–Monitor (FFM). If it detects a voltage transformer fault, the voltage criterion of the inadvertent energizing protection is deactivated.

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7104 PICK UP T U1<

no meas. quant.

7105 DROP OUT T U1<

(operational condition 0)

FNo. 05546

OR

I.En. release

7103 RELEASE U1<

U1

& FNo. 05547

I.En. picked up Fuse Failure

Tripping matrix

& 7102 I STAGE

FNo. 05548

I.En. TRIP IL1 7102 I STAGE

OR

IL2

TMin TRIP CMD

7102 I STAGE

IL3

FNo. 05533

FNo. 05542

>BLOCK I.En.

I.En. BLOCKED

Figure 2-111 Logic Diagram of the Inadvertent Energizing Protection (Dead Machine Protection)


The inadvertent energizing protection is only effective and accessible it is was set at address 0171 INADVERT. EN. = Enabled during the configuration of the protection functions. Set Disabled if the function is not required. Address 7101 INADVERT. EN. is used to switch the function ON or OFF, or to block only the trip command (Block Relay).

Criteria

Parameter 7102 I STAGE serves to specify the current pickup threshold of the inadvertent energization protection function. As a rule, this threshold value is set more sensitively than the threshold value of the time-overcurrent protection. In this case, the inadvertent energizing protection may only be effective if the device is either in operational condition 0 or if no nominal conditions have been reached yet. The parameter 7103 RELEASE U1< serves to define these nominal conditions. The typical setting is about 50 % to 70 % of the nominal voltage. A 0 V setting deactivates the voltage tripping. However, this should only be used if 7102 I STAGE shall be used as 3rd time-overcurrent protection stage, at a very high setting. The parameter 7104 PICK UP T U1< parameter represents the time delay for the release of the tripping condition in case of an undervoltage. The user should select a higher value for this time delay than the for the tripping time delay of the timeovercurrent protection. The delay time to block the tripping conditions when the voltage is above the undervoltage threshold is set at 7105 DROP OUT T U1<. The inadvertent energizing protection is blocked only after this time in order to enable a tripping subsequent to connection.

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Figure 2-112 illustrates the course of events during an unwanted connection in case of a machine standstill and, contrary to this, during a voltage collapse in case of a short circuit close to generator terminals.

Start T U1 Pickup

U1< Release of INADV. EN.

T U1< Dropout

T U1< Pickup

IL> Trip Machine

Machine

”stopped”

”running” Trip Short circ. short-circuit close to gen. protection

Inadvertent energization

b) Unit connection

a) Trip after inadvertent energization

Figure 2-112 Course of Events of the Inadvertent Energizing Protection

2.35.2.1 Settings of the Inadvertent Energizing Protection The following list indicates the setting ranges and the default settings of a IN = 1 A secondary nominal current. For a secondary nominal current of IN = 5 A, these values must be multiplied by 5. Addr.

Setting Title

Setting Options

Default Setting

Comments

7101

INADVERT. EN.


OFF


7102

I STAGE

0.1..20.0 A; ∞

0.3 A

I Stage Pickup

7103

RELEASE U1<

10.0..125.0 V; 0

50.0 V

Release Threshold U1<

7104

PICK UP T U1<

0.00..60.00 sec; ∞

5.00 sec

Pickup Time Delay T U1<

7105

DROP OUT T U1<

0.00..60.00 sec; ∞

1.00 sec

Drop Out Time Delay T U1<

2.35.2.2 Information for the Inadvertent Energizing Function F.No.

Alarm

Comments

05533 >BLOCK I.En.

>BLOCK inadvertent energ. prot.

05541 I.En. OFF

Inadvert. Energ. prot. is swiched OFF

05542 I.En. BLOCKED

Inadvert. Energ. prot. is BLOCKED

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F.No.

Alarm

Comments

05543 I.En. ACTIVE

Inadvert. Energ. prot. is ACTIVE

05546 I.En. release

Release of the current stage

05547 I.En. picked up

Inadvert. Energ. prot.: picked up

05548 I.En. TRIP

Inadvert. Energ. prot.: TRIP

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2.36


General

To detect DC voltages, DC currents and small AC quantities, the 7UM62 is equipped with a measuring transducer input (TD1) that can be used either for voltages (± 10 V) or currents (± 20 mA). Higher DC voltages are connected via an external voltage divider. The DC voltage/DC current protection can be used, for example, for the monitoring of the excitation voltage of synchronous machines (see Figure 2-113), or for the detection of earth faults in the DC section of the start-up converter of a gas turbine set (see Figure 2-114).

2.36.1 Functional Description A measuring transducer performs the analog/digital conversion of the measured quantity. The measuring transducer provides for galvanic isolation, a digital filter integrates the measurement voltage over two cycles and suppresses high ripple content or non-periodic peaks. A mean value of 32 samples is generated. Since the absolute values are sampled, the result is always positive. Thus, the polarity of the voltage is of no concern. When no suitable measured AC quantities are present ("operating condition 0 "), the DC voltage protection is still operative. The mean value is then calculated over 4 x 32 measured value samples. If, in special cases, an AC voltage should be measured via this analog input, the RMS value should be set on the protection. The factor 1.11 between r.m.s. and mean value is recognized within the protection function. Optionally, this function can also be used for the monitoring of small currents, provided that the TD input has been configured as current input and the settings of the associated jumpers on the C–I/O–6 have been changed. If the jumper settings do not match the configuration parameters, an error message is output. The protection can be set to operate for overvoltage or undervoltage. Pickup can be blocked via a binary input, and the output signal can be time delayed. Typical applications are shown in the Figures 2-113 and 2-114. Excitation Voltage Monitoring

Figure 2-113 illustrates the excitation voltage monitoring. The excitation voltage is stepped down to a processable level by a voltage divider, and fed to the measuring transducer.

G

Rotor

7UM62 Excitation system

10:1

TD1 Measuring transducer

Input filter

20:1 U=

∼ ∼

0 – 8,5 V

3PP1326–0BZ–V718 160

Figure 2-113 DC Voltage Protection Used for Excitation Voltage Monitoring

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Earth Fault Detection in the Startup Converter

If an earth fault occurs in the startup converter circuit, a current flows through all earthed parts of the system because of the DC voltage. As earthing and neutral transformers have a lower ohmic resistance than voltage transformers, the thermal load is the highest on them. As shown in Figure 2-114, the DC current is converted into a voltage in a shunt, and fed via a shunt converter to the measuring transducer of the device. Shunt converters can be measuring transducers such as the 7KG6131. For short distances between the shunt converter and the protective device, a voltage input may be used. For longer distances, use the version with current input (-20 to 20 mA or 4 to 20 mA).


7UM62 L1 L2 L3

Startup converter

=

∼ =

∼

TD1 Measuring transducer

Input filter

–20...20 mA 10 A/ 150 mV

Shunt Fuse

Shunt converter 10 V/–20..20 mA

Figure 2-114 DC Voltage Protection Used to Detect an Earth Fault in the Startup Converter

Figure 2-115 shows the logic diagram of the overvoltage protection.

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Functions

7204 U DC >< 7205 I DC >< 7202

MEAS.METHOD

FNo. 05306

DC Prot.pick.up

7203 DC >/<

FNo. 05307

DC Prot. TRIP

Mean

U= or. U∼

I= I∼

R.M.S.

mean value formation

absolute value

Rectification

mean value formation

7206 T DC

mean

Tripping matrix

& r.m.s. factor 1.11

2 mA

& 0172

TMin TRIP CMD

FNo. 05308

&

Failure DC Prot

DC PROTECTION 10V 4-20 mA 20 mA

”1”

FNo. 05293

FNo. 05302

>BLOCK DC Prot.

DC Prot.BLOCKED

Figure 2-115 Logic Diagram of the DC Voltage Protection


The DC voltage protection is only effective and accessible if it was set at address 0172 DC PROTECTION = Enabled during the configuration of the protection functions. Set Disabled if the function is not required. For the associated measuring transducer 1, either 10 V, 4–20 mA oder 20 mA has been selected during configuration at address 0295 TRANSDUCER 1 (see Section 2.3). Jumpers X94, X95 and X67 on the C–I/O–6 module are used to set in the hardware whether the measuring transducer input will be a voltage or a current input (see Section 3.1.3). Their setting must correspond to the setting at address 0295. If it does not, the device is blocked and issues an annunciation to that effect. When the relay is delivered from the factory, the jumpers and configuration parameters are set to voltage measurement. Address 7201 DC PROTECTION is used to switch the function ON or OFF, or to block only the trip command (Block Relay).

Measuring Procedure

Normally an integrated average value filter is switched on. A high ripple content or non-periodic peaks in the measurement voltage are averaged in this manner. The polarity of the measured voltages is of no concern since the absolute value is taken. Alternatively, a sinusoidal AC voltage can be measured (address 7202 MEAS.METHOD = RMS). The protection then multiplies the rectified average value with 1.11. The frequency of the AC voltage must match the frequency of other AC quantities, because the latter determine the sampling rate. The maximum AC amplitude must not exceed 10 V, so that for r.m.s. value measurement a maximum setting of 7.0 Vrms is reasonable. The resulting higher secondary voltage can be reduced by means of a voltage divider.

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The DC voltage/DC current protection can be set to operate for overvoltage or undervoltage (address 7203 DC >/<). Pickup Thresholds

Depending on the whether current or voltage input has been set at address 0295 TRANSDUCER 1, one of the following parameters is available, whereas the other is masked out: − Voltage measurement threshold: 7204 U DC >< − Current measurement threshold: 7205 I DC >< When setting the pickup values (address 7204), the ratio of a voltage divider – if fitted – has to be considered.

Application Examples

When used for excitation voltage monitoring, the DC current protection is configured to operate for undervoltage; the pickup threshold is set to approx. 60 % to 70 % of the no-load excitation voltage. Users should be aware that normally a voltage divider is connected between the protection and the excitation voltage (see Figure 2-113). Another typical application is the earth fault protection for the startup converter of a gas turbine set. In the case of an earth fault in the DC circuit, half of the DC voltage is present between the transformer starpoint and the earth if the transformer starpoint is not earthed. This voltage can be considered as the voltage feeding the earth current. As the transformer starpoints are earthed, the current flowing is determined by the feeding voltage and the ohmic resistance of all transformers that are galvanically connected to the converter set and earthed. This DC current is normally between about 3 and 4 A. For a startup converter having a startup transformer with UN, AT ≈ 1.4 kV and a 6-pulse bridge circuit, there will be a DC voltage of UDC ≈ 1.35 ⋅ UN, AT = 1.89 kV. In case of an earth fault in the intermediate circuit, the „displacement voltage“will be half of the DC voltage (UDC, fault = 0.5 ⋅ UDC = 945 V). If we assume that the earthing transformer has an ohmic winding resistance of R ≈ 150 Ω, a DC current of I0 = 945 V/150 Ω = 6,3 A will flow through its starpoint. Note: The ohmic winding resistances of earthing and neutral transformers can differ widely depending on the type. For a concrete application, they should be obtained from the manufacturer, or determined by measurements. If not tripped, the earth fault current would cause a temperature overload that would destroy the wye-connected voltage transformers and the earthing transformer. To ensure that the protection will pick up reliably, it is set to a value of less than half the fault current, in this example to 2 A. With the shunt and shunt converter used in the example, this current causes a secondary current of 4 mA (see Figure 2-114) (fault current ≈ 6 A, selected pickup value = 2 A, setting value = 4 mA).

Delays

The tripping delay can be set at address 7206 T DC. The set time is an additional time delay not including the operating time of the protective function. For the startup earth fault current protection, T DC is determined by the permissible temperature load of the earthing and/or neutral transformer. A value of 2 s or less is quite common.

Note: It should be noted that in operating condition 0, the operating times for pickup and dropout are 4 times longer due to the more complex filter procedure needed to eliminate disturbances.

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2.36.2.1 Settings of the DC Voltage Protection Addr.

Setting Title

Setting Options

Default Setting

Comments

7201

DC PROTECTION


OFF


7202

MEAS.METHOD

Mean Value Root Mean Square

Mean Value

Measurement Method (MEAN/ RMS Values)

7203

DC >/<

DC Voltage/Current Stage DC > DC Voltage/Current Stage DC <

DC Voltage/Current Stage DC >

Method of Operation (DC >/<)

7204

U DC ><

0.1..8.5 V

2.0 V

DC Voltage Pickup

7205

I DC ><

0.2..17.0 mA

4.0 mA

DC Current Pickup

7206

T DC

0.00..60.00 sec; ∞

2.00 sec

Time Delay for Trip of DC Protection

2.36.2.2 Information from the DC Voltage Protection F.No.

Alarm

Comments

05293 >BLOCK DC Prot.

>BLOCK DC protection

05301 DC Prot. OFF

DC protection is switched OFF

05302 DC Prot.BLOCKED

DC protection is BLOCKED

05303 DC Prot. ACTIVE

DC protection is ACTIVE

05307 DC Prot. TRIP

DC protection TRIP

05306 DC Prot.pick.up

DC protection picked up

05308 Failure DC Prot

Failure DC protection

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Analog Outputs

2.37

Analog Outputs

2.37.1 Functional Description Depending on the variant ordered, the 7UM62 machine protection can have up to four analog outputs (plug-in modules on ports B and D). The values to be transmitted via these interfaces have been specified during the configuration of the scope of protection functions (see Section 2.2). A maximum of four of the following analog outputs are available. • Measured positive sequence current I1 in percent of the rated operational current; • Measured negative sequence current I2 in percent of the rated operational current; • Measured positive sequence voltage U1 in percent of the rated voltage; • Measured value |P| (absolute value of active power) in percent of the rated operational apparent power √3·UN ·IN, • Measured value |Q| (absolute value of reactive power) in percent of the rated operating apparent power √3·UN ·IN, • Measured value frequency f in percent of the nominal frequency, • Measured value |cosϕ| (absolute value of power factor) in percent, referred to 1.00, • Measured value rotor temperature ΘR/ΘR max in percent of the maximum permissible rotor temperature, • Measured value stator temperature ΘS/ΘS TRIP in percent of the tripping temperature. Operating nominal quantities are the nominal values set at addresses 0251 UN GEN/ MOTOR and 0252 SN GEN/MOTOR (see also Section 2.3). For measured values that can be negative (power, power factor), absolute values are formed and output. Analog values are output as load-independent currents. The analog outputs have a nominal range between 0 mA and 20 mA, their operating range can be up to 22.5 mA. The conversion factor and the scope of validity are set.


You have specified during the configuration of the analog outputs (Section 2.2, addresses 0173 through 0176) which of the analog inputs available will be used for what measured values. Set Disabled if a function is not needed. The other parameters associated to that analog output are masked out in that case.

Measured Values

If you have selected measured values for the analog outputs (Section 2.2, addresses 0173 through 0176), you specify for the available outputs the conversion factor and the range of validity; these are

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Functions

For analog output B1 at location”B” (port B1): At address 7301 20 mA (B1) = the percent value to be displayed at 20 mA, At address 7302 MIN VALUE (B1) the smallest valid value. For analog output B2 at location”B” (port B2): At address 7303 20 mA (B2) = the percent value to be displayed at 20 mA, At address 7304 MIN VALUE (B2) the smallest valid value. For analog output D1 at location”D” (port D1): At address 7305 20 mA (D1) = the percent value to be displayed at 20 mA, At address 7306 MIN VALUE (D1) the smallest valid value. For analog output D2 at location”D” (port D2): At address 7307 20 mA (D2) = the percent value to be displayed at 20 mA, At address 7308 MIN VALUE (D2) the smallest valid value. The maximum possible value is 22.0 mA; in case of an overflow (value outside the maximum permissible range) 22.5 mA is output. Example: You want to output the positive sequence currents at analog output B1, location”B”. 10 mA are the value at nominal operational current, consequently 20 mA mean 200 %. Values below 1 mA are invalid. Settings Address 7301 20 mA (B1) = 200.0 %, Address 7302 MIN VALUE (B1) = 1.0 mA.

2.37.3 Settings of the Analog Outputs Addr.

Setting Title

Setting Options

Default Setting

Comments

7301

20 mA (B1) =

10.0..1000.0 %

200.0 %

20 mA (B1) correspond to

7302

MIN VALUE (B1)

0.0..5.0 mA

1.0 mA

Output value (B1) valid from

7303

20 mA (B2) =

10.0..1000.0 %

200.0 %


7304

MIN VALUE (B2)

0.0..5.0 mA

1.0 mA


7305

20 mA (D1) =

10.0..1000.0 %

200.0 %

20 mA (D1) correspond to

7306

MIN VALUE (D1)

0.0..5.0 mA

1.0 mA

Output value (D1) valid from

7307

20 mA (D2) =

10.0..1000.0 %

200.0 %


7308

MIN VALUE (D2)

0.0..5.0 mA

1.0 mA


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2.38

Measured Value Monitoring Functions The device is equipped with extensive monitoring capabilities - both for hardware and software. In addition, the measured values are also constantly monitored for plausibility, therefore, the current transformer and voltage transformer circuits are largely integrated into the monitoring.

2.38.1 Functional Description 2.38.1.1 Hardware Monitoring The device is monitored from the measurement inputs to the output relays. Monitoring circuits and processor check the hardware for malfunctions and disallowed conditions (see Table 2-13 in Section 2.38.1.5). Auxiliary and Reference Voltages

The processor voltage of 5 V DC is monitored, and if the voltage decreases below the minimum value, the device is removed from operation. When the cross-polarized voltage returns, the processor system is restarted. Removal of or switching off the supply voltage removes the device from operation and a message is immediately generated by a dead contact. Brief voltage interruptions of less than 50 ms do not disturb the readiness of the device (for nominal auxiliary voltage ≥110 V DC). The processor monitors the offset and reference voltage of the AD (analog-digital) converter. The protection is suspended if the voltages deviate outside an allowable range, and lengthy deviations are reported (”Error A/D-conv.”).

Buffer Battery

The buffer battery, which ensures the operation of the internal clock and the storage of counters and messages if the auxiliary voltage fails, is periodically checked for charge status. If it is less than an allowed minimum voltage, then the ”Fail Battery” message is issued. If the power supply voltage is cut off for 1 or 2 days, the internal buffer battery is automatically switched off, i.e. the internal clock will stop, whereas the buffered annunciations and fault event data will be preserved.

Memory Components

The working memory (RAM) is tested when the system is started up. If a malfunction occurs then, the starting sequence is interrupted and an LED blinks. During operation, the memory is checked using its checksum. For the program memory, the cross sum is formed periodically and compared to the stored program cross sum. For the settings memory, the cross sum is formed periodically and compared to the cross sum that is freshly generated each time the setting process takes place. If a malfunction occurs, the processor system is restarted.

Sampling

7UM62 Manual C53000-G1176-C149-3

Sampling and the synchronization between the internal buffer components are constantly monitored. If any deviations cannot be removed by renewed synchronization, then the processor system is restarted.

241

Functions

Measured Value Acquisition Currents

In the current path, there are three input transformers each on side 1 and side 2; the digitized sum of the outputs of these on one side must be almost zero for generators with isolated starpoint and earth-fault-free operation. A current circuit fault is detected if IF = |IL1 + IL2 + IL3 | >

ΣI THRESHOLD · IN + ΣI FACTOR · Imax

ΣI THRESHOLD and ΣI FACTOR are settings that are available individually for side 1 and side 2. The component SUM.Fact.I · Imax takes into account permissible current proportional transformation errors in the input converters, which can be especially large when high fault current levels are present (Figure 2-116). The dropout ratio is about 95%. This error is reported separately for side 1 and side 2 by ”Fail ΣI”. The current sum monitoring is only effective for the side for which the starpoint has been configured as Isolated in the power system data (addresses 0242 / 0244). IF IN Slope:

ΣI FACTOR

ΣI THRESHOLD

Imax IN Figure 2-116 Current Sum Monitoring

Measured Value Acquisition Voltages

In the voltage path, there are four input transformers: If three of them are used for phase-earth voltages, and one input for the displacement voltage (e–n voltage from the broken delta winding or neutral transformer) of the same system, a fault in the phase-earth voltage sum is detected if |UL1 + UL2 + UL3 + kU · UE |

>

SUM.thres. U + SUM.Fact. U x Umax

SUM.thres. U and SUM.Fact. U are parameter settings, and Umax is the highest of the phase-earth voltages. The factor kU considers the transformation ratio differences between the displacement voltage input and the phase voltage inputs (parameter kU = Uph / Udelta address 0225A). The SUM.Fact. U x Umax component considers permissible voltage-proportional transformation errors, which can be especially large in the presence of high voltages (Figure 2-117). This malfunction is reported as ”Fail S U Ph-E”.

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Note: Voltage sum (phase-earth) monitoring is only operative if an externally formed displacement voltage s connected to the residual voltage input of the relay and if this was communicated to the device via the parameter 0223 UE CONNECTION. Voltage sum (phase-earth) monitoring can operate properly only if the matching factor Uph / Udelta at address 0225A has been correctly configured (see Section 2.3.2).

UF UN Slope:

SUM.Fact.U

SUM.thres.U

Umax UN Figure 2-117 Voltage Sum Monitoring

2.38.1.2 Software Monitoring Software Monitoring

For continuous monitoring of the program sequences, a time monitor is provided in the hardware (hardware watchdog) that runs upon failure of the processor or an internal program, and causes a complete restart of the processor system. An additional software watchdog ensures that malfunctions during the processing of programs are discovered. This also initiates a restart of the processor system. To the extent such a malfunction is not cleared by the restart, an additional restart attempt is begun. After three unsuccessful restarts within a 30 second window of time, the device automatically removes itself from service and the red ”Error” LED lights up. The readiness relay opens and indicates ”device malfunction” with its normal contact.

2.38.1.3 Monitoring of External Current Transformer Circuits Interruptions or short circuits in the secondary circuits of the current transformers or voltage transformers, as well as faults in the connections (important for start-up!), are detected and reported by the device. The measured quantities are periodically checked in the background for this purpose, as long as no system fault is present.

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Functions

Current Symmetry

The currents fed in at the current inputs of side 1 and side 2 are monitored for symmetry. During normal system operation (i.e. the absence of a short-circuit fault), symmetry among the input currents is expected. This symmetry is checked by the device, using a quantity monitor. The smallest phase current is compared to the largest phase current, and asymmetry is recognized if: |Imin | / |Imax | < BAL. FACTOR I provided that Imax / IN > BALANCE I LIMIT / IN where Imax is the largest of the three phase currents and Imin is the smallest. The symmetry factor BAL. FACTOR I is the measure for the asymmetry of the phase currents; the limit value BALANCE I LIMIT is the lower limit of the operating range of this monitoring (see Figure 2-118). Both settings are adjustable individually for side 1 and side 2. The dropout ratio is about 95 %. This malfunction is reported as ”Fail. Isym” individually for side 1 and side 2. Imin IN

Slope:

BAL. FACTOR I

BALANCE I LIMIT

Imax IN

Figure 2-118 Current Symmetry Monitoring

Voltage Symmetry

During normal system operation (i.e. the absence of a short-circuit fault), symmetry among the input voltages is expected. From the phase-to-ground voltages, the protection generates the rectified average values and checks the symmetry of their absolute values. The smallest phase voltage is related to the highest. Asymmetry is recognized if: |Umin | / |Umax | <

BAL. FACTOR U provided that |Umax|

>

BALANCE U-LIMIT

where Umax is the highest of the three voltages and Umin the smallest. The symmetry factor BAL. FACTOR U is the measure for the asymmetry of the conductor voltages; the limit BALANCE U-LIMIT is the lower limit of the operating range of this monitoring (see Figure 2-119). Both settings are adjustable. The dropout ratio is about 95%. This malfunction is reported as ”Fail U balance”. In the case of unsymmetrical conditions a zero sequence voltage is possible. If the 90–%–stator earth fault protection is switched on and has picked up, it blocks the voltage symmetry supervision. The voltage symmetry supervision is active as long as no protection function has picked up.

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Umin V

Slope:

BAL. FACTOR U

BALANCE I LIMIT

Umax V

Figure 2-119 Voltage Symmetry Monitoring

Current and Voltage Phase Sequence

To detect swapped phase connections in the voltage and current input circuits, the phase sequence of the phase-to-phase measured voltages and the phase currents are checked by the monitoring. Direction measurement with cross-polarized voltages, path selection for impedance protection, and unbalance load detection all assume a clockwise phase sequence. The current rotation is checked and reported individually for side 1 and side 2. The phase sequence of the phase-to-ground voltages is verified by ensuring the following UL1 leads UL2 leads UL3 Likewise, the phase sequence of the phase currents is verified by ensuring the following: IL1 leads IL2 leads IL3 Verification of the voltage rotation occurs when each measured voltage is at least |UL1|, |UL2|, |UL3| > 40 V/√3 Verification of the current rotation occurs when each measured current is at least |IL1|, |IL2|, |IL3| > 0.5 IN. For counter-clockwise phase sequence, the annunciations ”Fail Ph. Seq. U”, (FNo. 176) or ”FailPh.Seq I S1”, (FNo. 00265) are output for side 1, or ”FailPh.Seq I S2”, (FNo. 00266) for side 2, as well as an OR link for these annunciations ”Fail Ph. Seq.”, (FN. 00171). For applications where the phase rotation of the measured quantities is counterclockwise phase in normal operation, this must be set in the device with the parameter 0271 PHASE SEQ. or an appropriately masked binary input. If the phase sequence is changed in the relay, phases ‘L2’ and ‘L3’ internal to the relay are reversed, and the positive and negative sequence currents are thereby exchanged (see also Section 2.43). The phase- related messages, malfunction values, and measured values are not affected by this.

2.38.1.4 Fuse Failure Monitoring In case of a measuring voltage failure caused by a short circuit or a phase failure in the voltage transformer secondary system, a zero voltage can be simulated to individual measuring loops. The measuring results of the undervoltage protection, the impedance protection and other voltage-dependent protective functions may be falsified in this way, which may cause an unwanted operation.

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Functions

If fuses are used instead of a secondary miniature circuit breaker with connected auxiliary contacts, then the fuse failure monitoring can detect problems in the voltage transformer secondary circuit. Of course, supervision of the miniature circuit breaker and the fuse failure monitor can be used at the same time. This function uses the current of side 2. Measuring Principle for 1–Pole and 2–Pole Fuse Failures

The measuring voltage failure detection is based on the fact a significant negativephase sequence system is formed with regard to the voltage during a 1- or 2-pole voltage failure, without influencing the current. This enables a clear distinction from asymmetries impressed by the power system. If the negative-phase sequence system is related to the current positive-phase sequence system, the following rules apply for the fault-free case: U ------2- = 0 U1

and

I ---2- = 0 I1

If a fault of the voltage transformers occurs, the following rules apply for a single-pole failure: U 0.33 ------2- = ----------- = 0.5 U1 0.66

and

I ---2- = 0 I1

U I æ ------2- > ---2-ö è U 1 I 1ø

If a fault of the voltage transformers occurs, the following rules apply for a two-pole failure: U2 0.33 ------- = ----------- = 1 U1 0.33

and

I ---2- = 0 I1

U I æ ------2- > ---2-ö è U 1 I 1ø

In case of an outage of one or two phases, the current also shows a negative-phase sequence system of 0.5 or 1. Consequently, the voltage monitoring does not respond as no the voltage transformer fault can be present. In order to avoid - in case of a too small positive-sequence system - an unwanted operation by inaccuracies of the measuring voltages failure detection, the function is blocked below a minimum threshold of the positive-sequence systems of (U1 < 10 V) and current (I1 < 0.1 IN). 3–Pole Fuse Failure

A 3-pole voltage transformer failure cannot be detected via the positive- and negative phase sequence system, but requires a monitoring of the current and voltage time course. A voltage dip to approximately zero (or if the voltage is zero) although the current remains unchanged by the same time, this is probably due to a 3-pole voltage transformer failure. The deviation of the actual current value from the nominal current value is evaluated for this purpose. The measuring voltage failure monitoring is blocked if the deviation amount is greater than a threshold value. Moreover, this function is blocked if a pickup of an (overcurrent) protective function is already present.

Additional Criteria

In addition to this, the function can either be blocked via a binary input or deactivated by an undervoltage protection at a separate voltage transformer set. If an undervoltage is also detected at a separate transformer set, this is most probably not due to a transformer error and the monitoring switching can be blocked. The separate undervoltage protection must be set non-delayed and should also evaluate the positive-phase sequence system of the voltages (e.g. 7RW600).

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7UM62 Manual C53000-G1176-C149-3


Figure 2-120 illustrates the logic diagram of the measuring voltage failure detection feature. Voltage at UE Input

Depending on how UE is connected, it may be necessary to block the voltage measurement of this input. A blocking can be generated with the CFC tool and linked by the annunciation “Fuse Failure“. 1- and 2-pole fuse failure U2/U1 > 0,4

& FNo.06575

I2/I1 < 0.2

OR

VT Fuse Failure

3-pole fuse failure UL1 < 10 V & UL2 < 10 V & UL3 < 10 V

&

Undervolt. U <

FNo. 05011

>FFM U< extern

see Figure 2-71 in Section 2.19.1

see Figure 2-77 in Section 2.23.1

OR

Inv. Underv.Up < |I1 - IN| > 0.5 IN


Gen. trip

Imp. I>+U<


Blocked if generator running without load

Imp. Z < I1 < 0.1

& U1 < 0.1

OR

see Figures 2-18 and 2-19 in Section 2.8.1 O/C f(U)

FNo. 05010

>FFM BLOCK

see Figure 2-10 in Section 2.6.1 O/C I > + U <

Figure 2-120 Logic Diagram of the Measuring Voltages – Fuse Failure Monitor)

2.38.1.5 Malfunction Responses of the Monitoring Functions Depending on the type of malfunction discovered, an annunciation is sent, a restart of the processor system is initiated, or the device is taken out of service. After three unsuccessful restart attempts, the device is taken out of service as well. The live status contact operates to indicate the device is malfunctioning. Also, the red LED ”ERROR” lights up on the front cover, if the internal auxiliary voltage is present, and the green ”RUN” LED goes out. If the internal power supply fails, then all LEDs are dark. Table 2-13 shows a summary of the monitoring functions and the malfunction responses of the relay.

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Functions

Table 2-13

Overview of Error Reactions by the Protection Relay

Monitoring

Possible Cause

Reaction

Annunciation

Output DOK2) drops out

Supply voltage failure

External (power supply) internal (converter)

Relay goes out of service all LEDs go dark

Internal supplyvoltages

Internal (converter) or Reference voltage

Relay goes out of service ”ERROR” LED DOK2) drops ”Error A/D-conv.” out (FNo. 000181)

Battery

Internal (battery)

Annunciation

”Fail Battery” (FNo. 000177)

Relay goes out of service1)

”ERROR” LED

DOK2) drops out

”ERROR” LED

DOK2) drops out

Hardware Monitoring

Internal (processor failure)

Software Monitoring

Internal (program execution) Relay attempts restart 1)

ROM

Internal (hardware)

Relay aborts restart LED flashes Relay goes out of service

RAM

Internal (hardware)

During startup

LED flashes

During operation: Relay attempts restart 1)

”ERROR” LED

DOK2) drops out

DOK2) drops out

Parameter memory

Intern (hardware)

Relay attempts restart 1)

”ERROR” LED

DOK2) drops out

Sampling frequency

Internal (hardware)

Relay goes out of service ”ERROR” LED

DOK2) drops out

1 A/5 A changeover Side 1

Jumper for 1 A/5 A for side 1 Relay goes out of service ”ERROR” LED misconnected Annunciation ”Err1A/ 5AwrongS1”

DOK2) drops out

(FNo. 000210

1 A/5 A changeover Side 2

DOK2) drops out

Jumper for 1 A/5 A for side 2 Relay goes out of service ”ERROR” LED misconnected Annunciation ”Err1A/ 5AwrongS2” (FNo. 000211)

Jumper setting for measuring transducer 1 does not match parameter 0295

DOK2) drops Relay goes out of service ”ERROR” LED Annunciation ”Err. TD1 jumper” out





Current sum Side 1

Internal (measured value acquisition)

Annunciation

Current sum Side 2


Annunciation

Current symmetry Side 1

External (power system or current transformer)

Annunciation

Voltage/current changeover at TD1 Voltage/current changeover at TD2 Filter on/off changeover at TD3

1) 2)

(FNo. 0212)

(FNo. 0213)

(FNo. 0214)

”Fail. S I Side1”

as masked

(FNo. 000230),

”Fail. S I Side2”

as masked

(FNo. 000231)

”Fail. Isym 1”

as masked

(FNo. 000571)

After three unsuccessful restart attempts, the device will go out of service DOK = ”Device Okay” = Ready for service relay drops off, protection and control function are blocked, HMI might be still accessible

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Table 2-13

Overview of Error Reactions by the Protection Relay

Monitoring

Possible Cause

Reaction

Current symmetry Side 2

External (power system or current transformer)

Annunciation

Voltage sum


Annunciation

External (power system or voltage transformer)

Annunciation

Voltage phase sequence

External (power system or connection)

Annunciation

Current phase sequence Side 1


Annunciation

Current phase sequence Side 2


Annunciation

Voltage symmetry

as masked

”Fail S U Ph-E”

as masked

”Fail U balance”

as masked

(FNo. 0167)

”Fail Ph. Seq. U” as masked (FNo. 00176)

”FailPh.Seq I S1” as masked (FNo. 000265)

”FailPh.Seq I S2” as masked (FNo. 000266)

Trip circuit monitoring

Annunciation

2)

”Fail. Isym 2”

(FNo. 0165)

Annunciation

1)

Output

(FNo. 000572)

Fuse failure monitoring External (voltage transformers) External (trip circuit or control voltage)

Annunciation

”VT Fuse Failure” as masked (FNo. 06575)

”FAIL: Trip cir.” as masked (FNo. 6865)

After three unsuccessful restart attempts, the device will go out of service DOK = ”Device Okay” = Ready for service relay drops off, protection and control function are blocked, HMI might be still accessible

2.38.2 Setting Hints Measured Value Monitoring

The measured value monitoring can be set at address 8101 MEASURE. SUPERV to ON or OFF. In addition, the sensitivity of measured value monitor can be modified. Default values are set at the factory, which are sufficient in most cases. If especially high operating asymmetry in the currents and/or voltages is to be expected for the application, or if it becomes apparent during operation that certain monitoring Functions activate sporadically, then the setting should be less sensitive. Address 8102 BALANCE U-LIMIT determines the voltage threshold (phase–phase) above which the voltage symmetry monitoring is effective (see also Figure 2-119). Address 8103 BAL. FACTOR U is the associated symmetry factor, i.e. the slope of the symmetry characteristic (Figure 2-119). Address 8104 BAL. I LIMIT S1 determines for side 1, and address 8106 BAL. I LIMIT S2 for side 2, the current threshold above which the current symmetry monitoring is active (see also Figure 2-118). Address 8105 BAL. FACT. I S1 is the associated symmetry factor for side 1, address 8107 BAL. FACT. I S2 is the associated symmetry factor for side 2, i.e. the slope of the symmetry characteristic (Figure 2-118). Address 8110 SI THRESHOLD S1 determines for side 1 the current threshold above which the summation current monitoring picks up (see Figure 2-116) (absolute component, only referred to IN). Consequently, address 8112 SI THRESHOLD S2 is valid for side 2. The relative component (referred to the maximum phase current) for the pickup of the summation current monitoring (Figure 2-116) is set for side 1 at address 8111 SI FACTOR S1, and for side 2 at 8113 SI FACTOR S2.

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Functions

Address 8108 SUM.thres. U determines the voltage threshold above which the summation voltage monitoring picks (see Figure 2-117) (absolute component, referred only to UN). The relative component for pickup of the summation voltage monitoring (Figure 2-117) is set at address 8109 SUM.Fact. U.

Note: In the power system data 1, the voltage earth path and its matching factor Uph / Udelta have been specified. The measured value monitoring will only function properly if the settings there are correct.

Measuring Voltage Failure Detection

The measuring voltage failure monitoring is only effective and accessible if it has been set during configuration of the protection functions at address 0180 FUSE FAIL MON. = Enabled. Set Disabled if the function is not required. Address 8001 FUSE FAIL MON. is used to switch the function ON or OFF. The thresholds U2/U1 ≥ 40 % and I2/I1 ≤ 20 % for detecting 1-pole and 2-pole voltage failures are fixed. The thresholds for detecting a 3-pole voltage failure (undervoltage threshold = 10 V, below which the failure detection feature responds unless the current changes significantly, and the differential current monitoring = 0.5 IN) are likewise fixed and need not be set.

2.38.2.1 Settings Addr. 8001

Setting Title FUSE FAIL MON.

Setting Options OFF ON

Default Setting OFF

Comments Fuse Failure Monitor

The following list indicates the setting ranges and the default settings of a IN = 1 A secondary nominal current. For a secondary nominal current of IN = 5 A, these values must be multiplied by 5. Consider the current transformer ratios when setting the device with primary values. Addr.

Setting Title

Setting Options

Default Setting

Comments

8101

MEASURE. SUPERV

OFF ON

OFF

Measurement Supervision

8102

BALANCE U-LIMIT

10..100 V

50 V

Voltage Threshold for Balance Monitoring

8103

BAL. FACTOR U

0.58..0.90

0.75

Balance Factor for Voltage Monitor

8104

BAL. I LIMIT S1

0.10..1.00 A

0.50 A

Current Balance Monitor Side 1

8105

BAL. FACT. I S1

0.10..0.90

0.50

Balance Factor for Current Monitor S1

8106

BAL. I LIMIT S2

0.10..1.00 A

0.50 A


8107

BAL. FACT. I S2

0.10..0.90

0.50


8108

SUM.thres. U

10..200 V

10 V

Summation Thres. for Volt. Monitoring

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7UM62 Manual C53000-G1176-C149-3


Addr.

Setting Title

8109

SUM.Fact. U

8110

Setting Options 0.60..0.95; 0

Default Setting

Comments

0.75

Factor for Volt. Sum. Monitoring

ΣI THRESHOLD S1 0.05..2.00 A

0.10 A

Summated Cur. Mon. Threshold on Side 1

8111

ΣI FACTOR S1

0.10

Summated Current Mon. Factor on Side 1

8112

ΣI THRESHOLD S2 0.05..2.00 A

0.10 A


8113

ΣI FACTOR S2

0.10


0.00..0.95

0.00..0.95

2.38.2.2 Information of the Monitoring Functions F.No.

Alarm

Comments

00161 Fail I Superv.

Failure: General Current Supervision

00230 Fail. Σ I Side1

Failure: Current Summation on Side 1

00231 Fail. Σ I Side2

Failure: Current Summation on Side 2

00571 Fail. Isym 1

Fail.: Current symm. supervision side 1

00572 Fail. Isym 2

Fail.: Current symm. supervision side 2

00164 Fail U Superv.

Failure: General Voltage Supervision

00165 Fail Σ U Ph-E

Failure: Voltage Summation Phase-Earth

00167 Fail U balance

Failure: Voltage Balance

00171 Fail Ph. Seq.

Failure: Phase Sequence

00265 FailPh.Seq I S1

Failure: Phase Sequence I side 1

00266 FailPh.Seq I S2

Failure: Phase Sequence I side 2

00176 Fail Ph. Seq. U

Failure: Phase Sequence Voltage

00197 MeasSup OFF

Measurement Supervision is switched OFF

F.No.

Alarm

Comments

00110 Event Lost

Event lost

00113 Flag Lost

Flag Lost

05010 >FFM BLOCK

>BLOCK fuse failure monitor

05011 >FFM U< extern

>FFM extern undervoltage

06575 VT Fuse Failure

Voltage Transformer Fuse Failure

00140 Error Sum Alarm

Error with a summary alarm

00181 Error A/D-conv.

Error: A/D converter

00210 Err1A/5AwrongS1

Err:1A/5Ajumper different from settingS1

00211 Err1A/5AwrongS2

Err:1A/5Ajumper different from settingS2

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251

Functions

F.No.

Alarm

Comments

00194 Error neutralCT

Error: Neutral CT different from MLFB

00212 Err. TD1 jumper

Err: TD1 jumper different from setting





00191 Error Offset

Error: Offset

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

00147 Error PwrSupply

Error Power Supply

00177 Fail Battery

Failure: Battery empty

00068 Clock SyncError

Clock Synchronization Error

2.38.2.3 Sum Events of the Monitoring Functions For certain conditions, the monitoring functions output sum events. Table 2-14 shows the sum events and their content. Table 2-14

FNo

Sum Events

Designation

0160 Error sum event (minor malfunction or configuration error; does not affect the protective functions)

252

Sum events FNo

Designation

FNo

Content Meaning

0161 Measured value monitoring I

0230 0231 0571 0572

Error ΣI S1 Error ΣI S2 Error Isymm S1 Error Isymm S2

0164 Measured value monitoring U

0165 0167

Error ΣUphe Error Usymm

0171 Phase sequence error

0265 0266 0176

Fail Ph. Seq. I S1 Fail Ph. Seq. I S2 Fail Ph. Seq. U

0147 6575 0193 0177

Fail. power supply Fuse Failure Fail. calendar Fail. battery Failure clock

7UM62 Manual C53000-G1176-C149-3


Table 2-14

FNo

Sum Events

Designation

0140 Alarm sum event (some/all protective functions are blocked)

7UM62 Manual C53000-G1176-C149-3

Sum events FNo

Designation

0181 Failure measured val. (Live status contace drops out/ Error LED lights up/all protective functions blocked)

FNo

Content Meaning

0210 0211 0194 0212 0213 0214 0190 0185 0187 0188

Err1A/ 5AwrongS1 Err1A/ 5AwrongS2 Error neutralCT Err. TD1 Jumper Err. TD2 Jumper Err. TD3 Jumper Error BG0 = C–CPU–2 Error BG3 = C–I/O–2 Error BG5 = C–I/O–6 Error BG6 = C–I/O–1

0191

Error: Offset

0264

Error Thermobox 1

0267

Error Thermobox 2

253

Functions

2.39


2.39.1 Functional Description The Multifunctional Protection 7UM62 is equipped with an integrated trip circuit monitor. Depending on the number of available binary inputs, monitoring with one or two binary inputs can be selected. If the configuration of the binary inputs needed for this does not match the selected monitoring type, then a message to this effect (”TripC ProgFail”) is sent. When using two binary inputs, malfunctions in the trip circuit can be detected under all circuit breaker conditions. When only one binary input is used, malfunctions in the circuit breaker itself cannot be detected. Monitoring with Two Binary Inputs (not Connected to Common Potential)

When using two binary inputs, these are connected according to Figure 2-121, parallel to the associated trip contact on one side, and parallel to the circuit breaker auxiliary contacts on the other. A condition for the use of trip circuit monitoring is that the control voltage for the circuit breaker is greater than the sum of the minimum voltage drops of both binary (USt > 2·UBImin). Since at least 19 V are needed for each binary input, the monitor can only be used with a system control voltage of over 38 V. USt

L+

7UM62 FNo. 06852 >TripC trip rel

UBI1

RTC

7UM62 FNo. 06853 >TripC brk rel.

Legend:

UBI2

CB

AuxCont2

TC Aux Cont1

L–

RTC CB TC AuxCont1 AuxCont2

— — — — —

Relay trip contact Circuit breaker Circuit breaker trip coil Circuit breaker auxiliary contact (NO contact) Circuit breaker auxiliary contact (NC contact)

UCtrl UBI1 UBI2

— Control voltage (trip voltage) — Input voltage for 1st binary input — Input voltage for 2nd binary input

Note: In the figure the circuit breaker is shown closed.

Figure 2-121 Principle of Trip Circuit Monitor with Two Binary Inputs (not Connected to Common Potential)

Monitoring with binary inputs not only detects interruptions in the trip circuit and loss of control voltage, it also monitors the response of the circuit breaker using the position of the circuit breaker auxiliary contacts. Depending on the conditions of the trip contact and the circuit breaker, the binary inputs are activated (logical condition ”H” in Table 2-15), or not activated (logical condition ”L”). Even for healthy trip circuits the condition that both binary inputs are not actuated (”L”) is possible during a short transition period (trip contact is closed, but the circuit breaker has not yet opened.) A continuous state of this condition is only possible when the trip circuit has been interrupted, a short-circuit exists in the trip circuit, a loss of battery voltage occurs, or malfunctions occur with the circuit breaker mechanism.

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7UM62 Manual C53000-G1176-C149-3


Table 2-15

Condition Table for Binary Inputs, depending on RTC and CB Position

No.

Trip Contact

Circuit Breaker

AuxCont 1

AuxCont 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

The conditions of the two binary inputs are checked periodically. A check takes place about every 600 ms. If three consecutive conditional checks detect an abnormality (after 1.8 s), an annunciation is reported (see Figure 2-122). This is used to avoid the annunciation for brief transition periods. When the fault in the trip circuit has been cleared, the annunciation is automatically reset.

FNo. 06852

>TripC trip rel FNo. 06853

“L” & “L”

“H”

FNo. 06865

> n

FAIL: Trip cir.

>TripC brk rel. n . ..... Number of condition checks (= 3) (measurement repeated every 600 ms)

Figure 2-122 Logic Diagram for Trip Circuit Monitoring with Two Binary Inputs

Monitoring with Two Binary Inputs (Connected to Common Potential)

If two binary inputs connected to common potential are used, they are connected according to 2-121, i.e. to L+ or once in parallel to the corresponding protection command relay contact and to the CB auxiliary contact 1.

USt

L+


UBI1 7UM62

FNo. 06853 >TripC brk rel.

RTC

Legend:

UBI2

CB

TC

L–

Aux AuxCont 2 Cont 1

RTC CB TC AuxCont1 AuxCont2 UCtrl UBI1 UBI2

— — — — — — — —

Relay trip contact Circuit breaker Circuit breaker trip coil Circuit breaker aux. contact (NO contact) Circuit breaker aux. contact (NC contact) Control voltage (trip voltage) Input voltage for 1st binary input Input voltage for 2nd binary input


Figure 2-123 Principle of Trip Circuit Monitor with two Binary Inputs (Connected to Common Potential)

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Functions

Depending on the conditions of the trip contact and the circuit breaker, the binary inputs are activated (logical condition ”H” in Table 2-16), or not activated (logical condition ”L”). . Table 2-16

Condition Table for Binary Inputs, Depending on RTC and CB Position

No.

Trip Contact

Circuit Breaker

AuxCont 1

AuxCont 2

BI 1

BI 2

1

Open

CLOSED

Closed

Open

H

L

Normal operation with closed CB

2

Open or closed

OPEN

Open

Closed

L

H

Normal operation with open CB or RTC has tripped with success

3

Closed

CLOSED

Open

L

L

Transition/fault

4

Open

CLOSED or OPEN

Closed

H

H

Theoretical status: Aux. contact defective, BI defective, wrong connection

Closed Closed

Dyn. Status

Stat. Status

Fault

With this solution, it is impossible to distinguish between status 2 (”normal operation with open CB LS” and ”KR triggered with success”. However, these two statuses are normal statues and thus not critical. Status 4 is only theoretical and indicates a hardware error. Even for healthy trip circuits the condition that both binary inputs are not actuated (”L”) is possible during a short transition period (trip contact is closed, but the circuit breaker has not yet opened.) A continuous state of this condition is only possible when the trip circuit has been interrupted, a short-circuit exists in the trip circuit, a loss of battery voltage occurs, or malfunctions occur with the circuit breaker mechanism. The conditions of the two binary inputs are checked periodically. A check takes place about every 600 ms. If three consecutive conditional checks detect an abnormality (after 1.8 s), an annunciation is reported (see Figure 2-122). The repeated measurements help to determine the delay of the alarm message and to avoid that an alarm is output during short-time transition phases. When the fault in the trip circuit has been cleared, the annunciation is automatically reset.

Monitoring with One Binary Input

The binary input is connected according to Figure 2-124 in parallel with the associated trip contact. The circuit breaker auxiliary contact AuxCont2 is connected in series with a high-ohm resistor R. The control voltage for the circuit breaker should be about two times the value of the minimum voltage drop at the binary (USt > 2·UBImin). Since the minimum voltage to activate a binary input is 19 V, a DC voltage supply of 38 V or higher is required.

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7UM62 Manual C53000-G1176-C149-3


USt

L+


UBI 7UM62

RTC Legend:

R CB

TC

Aux AuxCont 2 Cont 1

RTC CB TC AuxCont1 AuxCont2 R

— — — — — —

Relay trip contact Circuit breaker Circuit breaker trip coil Circuit breaker auxiliary contact (NO contact) Circuit breaker auxiliary contact (NC contact) Equivalent resistor

UCtrl UBI

— Control voltage (trip voltage) — Control voltage for binary input


L– Figure 2-124 Principle of Trip Circuit Monitoring with One Binary Input

During normal operation, the binary input is activated (logical condition “H”) when the trip contact is open and the trip circuit is intact, because the monitoring circuit is closed by either the circuit breaker auxiliary contact (if the circuit breaker is closed) or through the equivalent resistor R. Only as long as the trip contact is closed, the binary input is short circuited and thereby de-activated (logical condition ”L”). If the binary input is continuously de-activated during operation, this leads to the conclusion, there is an interruption in the trip circuit or loss of control voltage. The trip circuit monitor does not operate during system faults. A momentary closed tripping contact does not lead to a failure message. If, however, tripping contacts from other devices operate in parallel with the trip circuit, then the failure annunciation must be delayed (see also Figure 2-125). The conditions of the binary input are, therefore, checked 500 times before an annunciation is sent. A condition check takes place about every 600 ms, so trip circuit monitoring is only activated during an actual malfunction of the trip circuit (after 300 s). When the fault in the trip circuit has been cleared, the annunciation is automatically reset. Note: If the lock-out function is used, the trip circuit monitoring with only one binary input must not be used as the relay remains permanently picked up after a trip command (more than 300 s).

FNo. 06852 >TripC trip rel

Fault cond.

FNo. 06865

&

> n

FAIL: Trip cir.

n.. .... Number of condition checks (= 500) (measurement repeated every 600 ms)

Figure 2-125 Logic Diagram for Trip Circuit Monitoring with One Binary Input

Figure 2-126 shows the logic diagram for the message that can be generated by the trip circuit monitor, depending on the control settings and binary inputs.

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257

Functions

0182

Trip Cir. Sup.

Disabled ”1”

with 2 Bin. Inp.

OR

with 1 Bin. Inp.

& FNo. 06864 FNo. 06852

>TripC trip rel FNo. 06853 >TripC brk rel.

&

TripC ProgFail

Configured

& Configured FNo. 06861

TripC OFF

8201 TRIP Cir. SUP. ”1”

FNo. 06865

OFF

S

ON

R

Q

&

Function

FAIL: Trip cir. FNo. 06863

TripC ACTIVE FNo. 06851 >BLOCK TripC

FNo. 06862 TripC BLOCKED

Figure 2-126 Message Logic for the Trip Circuit Monitor

2.39.2 Setting Hints The function is only effective and accessible if it has been enabled during the configuration of the protective functions at address 0182 Trip Cir. Sup. (Section 2.2) by setting one of the alternatives with 2 Binary Inputs or with 1 Binary Input and provided that the required number of binary inputs is allocated to it and that the function has been set at address 8201 TRIP Cir. SUP. = ON. If the configuration of the binary inputs needed for this does not match the selected monitoring type, then a message to this effect (”TripC ProgFail”) is sent. If the trip circuit monitor is not to be used at all, address 0182 should be set to Disabled. Further settings are not needed. The message of a trip circuit interruption is delayed by a fixed amount of time. For two binary inputs, the delay is about 2 seconds, and for one binary input, the delay is about 300 ms. This ensures that the trip circuit monitor waits until the longest possible duration of a trip signal has elapsed, and generates an alarm only if there is a real malfunction in the trip circuit. Monitoring with One Binary Input

Note: When using only one binary input (BI) for the trip circuit monitor, some malfunctions, such as interruption of the trip circuit or loss of battery voltage, can indeed be detected, but malfunctions with closed trip contacts cannot. Therefore, the measurement must take place over a period of time that bridges the longest possible duration of a closed trip contact. This is ensured by the fixed number of measurement repetitions and the time between the condition checks. When using only one binary input, a resistor R is inserted into the circuit on the system side, instead of the missing second binary input. Through appropriate sizing of the resistor and depending on the system relationship, a lower control voltage can often be sufficient. The resistor R is inserted into the circuit of the circuit breaker auxiliary

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7UM62 Manual C53000-G1176-C149-3


contact (AuxCont2), to facilitate the detection of a malfunction when the circuit breaker auxiliary contact (AuxCont1) open and the trip contact has dropped out (see Figure 2124). This resistor must be sized such that the circuit breaker trip coil is no longer energized when the circuit breaker is open (which means AuxCont1 is open and AuxCont2 is closed). The binary input should still be picked up when the trip contact is simultaneously opened. 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: R max + R min R = --------------------------------2 In order that the minimum voltage for controlling the binary input is ensured, Rmax is derived as: U St – U BI min R max = æ ---------------------------------ö – R TC è I BI (High) ø So the circuit breaker trip coil does not remain energized in the above case, Rmin is derived as: U Ctrl – U TC (LOW) R min = R TC ⋅ æ ---------------------------------------------ö è ø U TC (LOW) IBI (HIGH)

Constant current with BI on (= 1.8 mA)

UBI min

UCtrl

Minimum Control Voltage for BI (= 19 V for delivery setting for nominal voltage of 24/48/60 V; = 88 V for delivery setting for nominal voltage of 110/125/220/250 V) Control voltage for trip circuit

RTC

DC Resistance of circuit breaker trip coil

UTC (LOW)

Maximum voltage on the circuit breaker trip coil that does not lead to tripping

If the result of the calculation is Rmax < Rmin the calculation must be repeated, with the next lowest pickup threshold UBI min; for this threshold one or more jumpers must be set in the device (see Section 3.1.3). For the power consumption of the resistance: U Ctrl 2 2 P R = I ⋅ R = æ ---------------------ö ⋅ R è R + R TCø

Example: IBI (HIGH)

UCtrl

1.8 mA (from SIPROTEC® 7UM62) 19 V for delivery setting for nominal voltage of 24/48/60 V (from the 7UM62) 88 V for delivery setting for nominal voltage of 110/125/220/250 V) (from the 7UM62) 110 V (from system / trip circuit)

RTC

500 Ω (from system / trip circuit)

UBI min

UTC (LOW) 2 V (from system / trip circuit)

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Functions

110 V – 19 V R max = æ ----------------------------------ö – 500 Ω = 50.1 kΩ è 1.8 mA ø

110 V – 2 V R min = 500 Ω ⋅ æ ------------------------------ö = 27 kΩ è ø 2V

R max + R min R = -------------------------------- = 38.6 kΩ 2 The closest standard value of 39 kΩ is selected; the power is: 2 110 V P R = æ ----------------------------------------ö ⋅ 39 kΩ è 39 kΩ + 0.5 kΩø

P R ≥ 0.3 W

2.39.2.1 Settings for the Trip Circuit Supervision Addr. 8201

Setting Title TRIP Cir. SUP.

Setting Options OFF ON

Default Setting OFF

Comments TRIP Circuit Supervision

2.39.2.2 Information F.No.

Alarm

Comments

06851 >BLOCK TripC

>BLOCK Trip circuit supervision

06853 >TripC brk rel.

>Trip circuit supervision: breaker relay

06852 >TripC trip rel

>Trip circuit supervision: trip 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

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2.40


General

This function monitors the thresholds of selected measured values, checking whether the values exceed or drop below these thresholds. The processing speed of this function is so high that it can be used for protection applications. The necessary logical can be implemented by means of CFC. The principal field of application of threshold supervision are high-speed supervision and automatic functions as well as application-specific protection functions (e.g. power plant decoupling) which are not included in the scope of protection functions.

2.40.1 Functional Description There are 6 threshold supervision blocks, 3 each for responding to values in excess of and below the threshold. They output as result a logical indication that can be further processed by the CFC. A total of 9 processable measured values are available, all of which can be evaluated as percentages. Each threshold block can be allocated one of these 9 measured values. As in all other protection functions, the measured values are referred to secondary quantities. Table 2-17 below show the useable measured values. The threshold values are queried once per cycle. Table 2-17

7UM62 Manual C53000-G1176-C149-3

Measured Values

Measured Value

Scaling

Comments

P (Active power)

P/SN,sec ⋅ 100 % (normalized with addr. 252)

The positive sequence system quantities for U and I are formed once per cycle from the sampled values. From the result, P is calculated. The measuring result is subject to the angle correction (address 204 CT ANGLE W0) in the current path.

Q (Reactive power)

Q/SN,sec ⋅ 100 % (normalized with addr. 252)

The positive sequence system quantities for U and I are formed once per cycle from the sampled values. From the result, Q is calculated. The measuring result is subject to the angle correction (address 204 CT ANGLE W0) in the current path.

∆P (Change of active power)

∆P/SN,sec ⋅ 100 % (normalized with addr 252)

The active power difference is calculated from the active power over a measuring window of 3 cycles.

U1 (Positive sequence voltage)

U1/UN,sec ⋅ 100 % (normalized with addr. 251)

The positive sequence voltage is determined from the phase-to-earth voltages on the basis of the definition equation for symmetrical components. The calculation is perfomed once per cycle.

U2 (Negative sequence voltage)

U2/UN,sec ⋅ 100 % (normalized with addr. 251)

The negative sequence voltage is determined from the phase-to-earth voltages on the basis of the definition equation for symmetrical components. The calculation is perfomed once per cycle.

261

Functions

Table 2-17

Measured Values

Measured Value

Scaling

Comments

I0 (Zero sequence current system side 2)

I0/IN,S2,sec ⋅ 100 % (normalized with addr. 212)

The zero sequence current is determined from the phase currents on the basis of the definition equation for symmetrical components. The calculation is perfomed once per cycle.

I1 (Positive sequence current system side 2)

I1/IN,S2,sec ⋅ 100 %

The positive sequence current is determined from the phase currents on the basis of the definition equation for symmetrical components. The calculation is perfomed once per cycle.

I2 (Negative sequence current system side 2)

I2/IN,S2,sec ⋅ 100 %

The negative sequence current is determined from the phase currents on the basis of the definition equation for symmetrical components. The calculation is perfomed once per cycle.

ϕ

ϕ/180° ⋅ 100 %

The power angle is calculated from the positive sequence voltage and the positive sequence current. The following definition applies: ϕ = ϕU - ϕI (A positive angle will appear if the current lags behind the voltage)

(Power angle)

The following figure shows an overview of the logic.

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7UM62 Manual C53000-G1176-C149-3


Disabled Pa Pr Delta Pa

8502 THRESHOLD MV1>

U1 U2

7960 Meas. Value1>

I0 I1 I2 PHI

8501 MEAS. VALUE 1>

Disabled Pa Pr Delta Pa

8512 THRESHOLD MV6<

U1 U2

7965 Meas. Value6<

I0 I1 I2 PHI

8511 MEAS. VALUE 6<

Figure 2-127 Logic Diagram of the Threshold Supervision

The figure shows that the measured values can be freely allocated to the threshold supervision blocks. The dropout ratio for the MVx> stage is 0.95 or 1 %. Accordingly, it is 1.05 or 1 % for the MVx< stage.


The threshold supervision function is only effective and accessible if address 185 THRESHOLD has been set to Enabled during the configuration of the protection functions.

Pickup Values

The pickup values are set as percentages. Please note the scaling factors listed in Table 2-17.

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Functions

The measured values for power P, Q and ∆P, as well as the phase angle, can be either positive or negative. Where the monitoring is for a negative threshold value, the number line definition applies (–10 is smaller than –5). Example: The measured quantity P (active power) is allocated to MV1> and set to –5 %. If the actual measured value is higher than –5 % (e.g. –4 % or even +100 %), the indication “Meas. Value1>” is output as a logical “1”, which means a pickup in terms of protection engineering. A dropout signal (indication “Meas. Value1>” logical “0”) is output if the measured value drops to less than –5 % ⋅ 1.05 = –5.25 %. With the measured quantity P allocated to MV2<, the monitoring checks whether the value drops below the threshold. A pickup signal is output in that case if the measured value becomes less than –5 % (e.g. –8 %). The dropout value is at –5 % ⋅ 0.95 = –4.75 %. Note: The measured values U1, U2, I0, I1 and I2 are always greater than 0. Care should be taken here to use only positive threshold values which allow the indication to drop out. When defining the power angle ϕ, it should be kept in mind that this angle is only defined for ± 100 % (equivalent to ± 180°) or less. The threshold value should be chosen accordingly, taking into account the dropout ratio.

Further Processing of Indications

The indications of the 6 measured value monitoring blocks (see list of information) are available in the configuration matrix for further logical processing by the CFC (see System Manual, Chapter 5).

2.40.2.1 Settings of the Threshold Supervision Addr.

Setting Title

Setting Options

8501

MEAS. VALUE 1>

8502

THRESHOLD MV1> -200..200 %

264

Disabled Active Power P Reactive Power Q Change of Active Power Delta P Positive Sequence Voltage U1 Negative Sequence Voltage U2 Zero Sequence Current I0 Positive Sequence Current I1 Negative Sequence Current I2 Power Angle PHI

Default Setting

Comments

Disabled

Measured Value for Threshold MV1>

100 %

Pickup Value of Measured Value MV1>

7UM62 Manual C53000-G1176-C149-3


Addr.

Setting Title

8503

MEAS. VALUE 2<

8504

Setting Options Disabled Active Power P Reactive Power Q Change of Active Power Delta P Positive Sequence Voltage U1 Negative Sequence Voltage U2 Zero Sequence Current I0 Positive Sequence Current I1 Negative Sequence Current I2 Power Angle PHI

Default Setting

Comments

Disabled

Measured Value for Threshold MV2<

THRESHOLD MV2< -200..200 %

100 %

Pickup Value of Measured Value MV2<

8505

MEAS. VALUE 3>

Disabled


8506


100 %


8507

MEAS. VALUE 4<

Disabled


8508


100 %


7UM62 Manual C53000-G1176-C149-3



265

Functions

Addr.

Setting Title

8509

MEAS. VALUE 5>

8510

Setting Options Disabled Active Power P Reactive Power Q Change of Active Power Delta P Positive Sequence Voltage U1 Negative Sequence Voltage U2 Zero Sequence Current I0 Positive Sequence Current I1 Negative Sequence Current I2 Power Angle PHI

Default Setting

Comments

Disabled



100 %


8511

MEAS. VALUE 6<

Disabled


8512


100 %



2.40.2.2 Information for the Threshold Supervision F.No.

Alarm

Comments

07960 Meas. Value1>

Measured Value MV1> picked up

07961 Meas. Value2<

Measured Value MV2< picked up

07962 Meas. Value3>


07963 Meas. Value4<


07964 Meas. Value5>


07965 Meas. Value6<


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2.41


2.41.1 Functional Description Up to four desired signal from external protection or supervision units can be incorporated into the processing of 7UM62. The signals are coupled as ”External signal” via binary inputs. Like the internal protection and supervision signals, they can be annunciated, time delayed, transmitted to the trip matrix, and blocked. By means of these signals it is possible to include external protection commands, e.g. from Buchholz protection or shaft current supervision, into the processing of annunciations and trip commands of 7UM61. Furthermore, an interaction of protection functions of different numerical machine protection relays of the series 7UM6 can be performed. The status of the assigned inputs is checked in cyclic intervals. Alteration of the input status is considered only after two subsequent status checks with equal result. An additional time delay 8602 T DELAY is available for each of the external trip command channels. The logic diagram of one external trip command channel is illustrated in Figure 2-128. In total, the relay incorporates four such channels, i.e. four times this logic. The illustrated function numbers are valid for the first external trip command channel.

FNo. 04536 etc.

Ext 1 picked up FNo. 04537 etc.

Ext 1 Gen.TRP 8602 T DELAY

FNo. 04526

>Ext trip 1

Tripping matrix

& TMin TRIP CMD

FNo. 04523

FNo. 04532 etc.

>BLOCK Ext 1

Ext 1 BLOCKED

Figure 2-128 Logic Diagram of One External Trip Command Channel


External trip commands via binary inputs are only effective and accessible if during the configuration of the protective functions the addresses 0186 EXT. TRIP 1 through 0189 EXT. TRIP 4 have been set to Enabled. Set Disabled if the functions are not required. Addresses 8601 EXTERN TRIP 1 through 8901 EXTERN TRIP 4 are used to switch the functions individually ON or OFF, or to block only the trip command (Block Relay). Like the internal protection and supervision signals, they can be annunciated as ”External trip”, time delayed and transmitted to the trip matrix. The delay times are set at addresses 8602 T DELAY through 8902 T DELAY. Like for the protective functions, the dropout of the direct input trippings is extended by TMin TRIP CMD parameterized minimum duration.

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Functions

2.41.2.1 Settings Addr.

Setting Title

Setting Options

Default Setting

Comments

8601

EXTERN TRIP 1


OFF


8602

T DELAY

0.00..60.00 sec; ∞

1.00 sec

Ext. Trip 1 Time Delay

8701

EXTERN TRIP 2


OFF


8702

T DELAY

0.00..60.00 sec; ∞

1.00 sec


8801

EXTERN TRIP 3


OFF


8802

T DELAY

0.00..60.00 sec; ∞

1.00 sec


8901

EXTERN TRIP 4


OFF


8902

T DELAY

0.00..60.00 sec; ∞

1.00 sec


2.41.2.2 Information for the Function Control 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.TRP

External trip 1: General TRIP

04543 >BLOCK Ext 2

>BLOCK external trip 2

04546 >Ext trip 2


04551 Ext 2 OFF


04552 Ext 2 BLOCKED


04553 Ext 2 ACTIVE




04557 Ext 2 Gen.TRP


04563 >BLOCK Ext 3


04566 >Ext trip 3


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F.No.

Alarm

Comments

04571 Ext 3 OFF


04572 Ext 3 BLOCKED


04573 Ext 3 ACTIVE




04577 Ext 3 Gen.TRP


04583 >BLOCK Ext 4


04586 >Ext trip 4


04591 Ext 4 OFF


04592 Ext 4 BLOCKED


04593 Ext 4 ACTIVE




04597 Ext 4 Gen.TRP


7UM62 Manual C53000-G1176-C149-3

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Functions

2.42

Temperature Detection by Thermoboxes Up to 2 thermoboxes with a total of 12 measuring points can be used for temperature detection and evaluated by the protection device. They are particularly useful for monitoring the thermal condition of motors, generators and transformers. In rotating machines, they also check the bearing temperatures for violation of limit values. The temperatures are measured at various points of the protected object by temperature sensors (RTD = Resistance Temperature Detector), and fed to the device via one or two thermoboxes 7XV566.

Interaction with the Overload Protection

The ambient or coolant temperature can be fed via the thermobox to the overload protection function of the 7UM62. For this purpose, the required temperature sensor must be connected to sensor input 1 of the 1st thermobox (corresponds to RTD 1).

2.42.1 Functional Description Thermobox 7XV56

The thermobox 7XV566 is an external device mounted on a standard mounting rail. It has 6 temperature inputs and an RS485 interface to communicate with the protection device. The thermobox takes the coolant temperature of each measuring point from the resistance value of the temperature detectors connected with a two- or three-wire line (Pt100, Ni100 or Ni120) and converts it to a digital value. The digital values are output at a serial interface.

Communication with the Protection Device

The protection device can communicate with up to 2 thermoboxes via its service port (port C or D).

Temperature Evaluation

The non-linearized temperature values are converted into a temperature; the user can choose between °C and °F. The conversion factor depends on the temperature detector used.

Up to 12 temperature measuring points are in this way available. For long distances between the thermobox and the protection device, communication via fiber-optic cable is recommended. Section A.4.1 of the Appendix shows possible communication architectures.

For each measuring point, two pickup thresholds can be defined, the signals of which are then available for any kind of further processing. The user can allocate the pickup signals in the configuration matrix as required. To each temperature detector is assigned an alarm which is issued in case of a shortcircuit or an interruption of the sensor circuit. Figure 2-129 shows the logic diagram of the temperature evaluation. A connection diagram and a dimensional drawing can be found in the operating instructions supplied with the thermobox.

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7UM62 Manual C53000-G1176-C149-3


9011A RTD 1 TYPE

Non-linearized values

9013 RTD 1 STAGE 1

Temperature calculation

RTD 1 St.1 p.up FNo. 14112

9015 RTD 1 STAGE 2

RTD 1 St.2 p.up FNo. 14113

Monitoring

Fail: RTD 1 FNo. 14111

≥1

Fail: RTD FNo. 14101

Fail: RTD-Box 1 FNo. 00264

Figure 2-129 Logic Diagram of the Temperature Evaluation


The temperature detection function is only effective and accessible if it has been assigned to an interface during the configuration of the protection functions (Section 2.2.1). Address 0190 RTD-BOX INPUT is used to allocate the thermobox(es) to the interface (e.g. interface C) through which it will be operated. The number of detector inputs and the communication mode are selected with address 0191 RTD CONNECTION. The temperature unit (°C or °F) has been set in Power System Data 1 at address 0276 TEMP. UNIT.

Settings on the Protection Device

The settings to be made on the protection device are the same for each input; they are described here as an example for measuring input 1. For RTD1 (temperature detector for measuring 1), the type of temperature detector is set at address 9011A RTD 1 TYPE. Setting options are Pt 100 W, Ni 120 W and Ni 100 W. Where no measuring point is provided for RTD1, RTD 1 TYPE = Not connected is set. This setting is only possible with DIGSI® 4 under „Advanced Parameters“.

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271

Functions

The location RTD1 is communicated to the device at address 9012A RTD 1 LOCATION. Setting options are Oil, Ambient, Winding, Bearing and Other. This setting is only possible with DIGSI® 4 under “Advanced Parameters”. You can also set an alarm temperature and a tripping temperature. Depending on the temperature unit selected in the power system data (Section 2.3 at address 0276 TEMP. UNIT), you can select the alarm temperature at address 9013 RTD 1 STAGE 1 in degree Celsius (°C) or at address 9014 RTD 1 STAGE 1 in degree Fahrenheit (°F). The tripping temperature is set at address 9015 RTD 1 STAGE 2 in degree Celsius (°C) or at address 9016 RTD 1 STAGE 2 in degree Fahrenheit (°F). In the same way, you can make the settings for all connected temperature detectors (see the settings table in 2.42.2.1). Settings on the Thermobox

Where temperature detectors with a 2-wire line are used, the line resistance must be measured and set (with the temperature detector shorted). To do so, select mode 6 in the thermobox and enter the resistance value for the desired detector (range 0 to 50.6 Ω). For temperature detectors with a 3-wire line, no extra settings are required. The information is exchanged with a baud rate of 9600 bits/s. The parity is even. The bus number is set to 0 in the factory. Changes can be made in mode 7 on the thermobox. The following convention applies: Table 2-18

Setting the Bus Address on the Thermobox

Operation

Number of Thermoboxes

Address

Simplex

1

0

Half-duplex

1

1

Half-duplex

2

1st thermobox: 1 2nd thermobox: 2

More information can be found in the operating instructions supplied with the thermobox. Further Processing of Measured Values and Indications

The thermobox is seen in DIGSI® 4 as part of the 7UM62 protection device, i.e. indications and measured values appear in the configuration matrix just like those of internal functions, and can be masked and processed in the same way. This means that indications and measured values can also be transmitted to the integrated user-definabled logic (CFC) and linked in any desired way. If you want an indication to appear in the operational indication buffer, mark the matrix cell at the appropriate column/line intersection with a cross.

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7UM62 Manual C53000-G1176-C149-3


2.42.2.1 Settings of the Temperature Detection Function 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

Winding

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


9015

RTD 1 STAGE 2

-50..250 °C; ∞

120 °C


9016

RTD 1 STAGE 2

-58..482 °F; ∞

248 °F


9021A

RTD 2 TYPE


not connected

RTD 2: Type

9022A

RTD 2 LOCATION


Other

RTD 2: Location

9023

RTD 2 STAGE 1

-50..250 °C; ∞

100 °C


9024

RTD 2 STAGE 1

-58..482 °F; ∞

212 °F


9025

RTD 2 STAGE 2

-50..250 °C; ∞

120 °C


9026

RTD 2 STAGE 2

-58..482 °F; ∞

248 °F


9031A

RTD 3 TYPE


not connected

RTD 3: Type

9032A

RTD 3 LOCATION


Other

RTD 3: Location

9033

RTD 3 STAGE 1

-50..250 °C; ∞

100 °C


9034

RTD 3 STAGE 1

-58..482 °F; ∞

212 °F


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273

Functions

Addr.

Setting Title

Setting Options

Default Setting

Comments

9035

RTD 3 STAGE 2

-50..250 °C; ∞

120 °C


9036

RTD 3 STAGE 2

-58..482 °F; ∞

248 °F


9041A

RTD 4 TYPE


not connected

RTD 4: Type

9042A

RTD 4 LOCATION


Other

RTD 4: Location

9043

RTD 4 STAGE 1

-50..250 °C; ∞

100 °C


9044

RTD 4 STAGE 1

-58..482 °F; ∞

212 °F


9045

RTD 4 STAGE 2

-50..250 °C; ∞

120 °C


9046

RTD 4 STAGE 2

-58..482 °F; ∞

248 °F


9051A

RTD 5 TYPE


not connected

RTD 5: Type

9052A

RTD 5 LOCATION


Other

RTD 5: Location

9053

RTD 5 STAGE 1

-50..250 °C; ∞

100 °C


9054

RTD 5 STAGE 1

-58..482 °F; ∞

212 °F


9055

RTD 5 STAGE 2

-50..250 °C; ∞

120 °C


9056

RTD 5 STAGE 2

-58..482 °F; ∞

248 °F


9061A

RTD 6 TYPE


not connected

RTD 6: Type

9062A

RTD 6 LOCATION


Other

RTD 6: Location

274

7UM62 Manual C53000-G1176-C149-3


Addr.

Setting Title

Setting Options

Default Setting

Comments

9063

RTD 6 STAGE 1

-50..250 °C; ∞

100 °C


9064

RTD 6 STAGE 1

-58..482 °F; ∞

212 °F


9065

RTD 6 STAGE 2

-50..250 °C; ∞

120 °C


9066

RTD 6 STAGE 2

-58..482 °F; ∞

248 °F


9071A

RTD 7 TYPE


not connected

RTD 7: Type

9072A

RTD 7 LOCATION


Other

RTD 7: Location

9073

RTD 7 STAGE 1

-50..250 °C; ∞

100 °C


9074

RTD 7 STAGE 1

-58..482 °F; ∞

212 °F


9075

RTD 7 STAGE 2

-50..250 °C; ∞

120 °C


9076

RTD 7 STAGE 2

-58..482 °F; ∞

248 °F


9081A

RTD 8 TYPE


not connected

RTD 8: Type

9082A

RTD 8 LOCATION


Other

RTD 8: Location

9083

RTD 8 STAGE 1

-50..250 °C; ∞

100 °C


9084

RTD 8 STAGE 1

-58..482 °F; ∞

212 °F


9085

RTD 8 STAGE 2

-50..250 °C; ∞

120 °C


9086

RTD 8 STAGE 2

-58..482 °F; ∞

248 °F


9091A

RTD 9 TYPE


not connected

RTD 9: Type

7UM62 Manual C53000-G1176-C149-3

275

Functions

Addr.

Setting Title

Setting Options

Default Setting

Comments

9092A

RTD 9 LOCATION


Other

RTD 9: Location

9093

RTD 9 STAGE 1

-50..250 °C; ∞

100 °C


9094

RTD 9 STAGE 1

-58..482 °F; ∞

212 °F


9095

RTD 9 STAGE 2

-50..250 °C; ∞

120 °C


9096

RTD 9 STAGE 2

-58..482 °F; ∞

248 °F


9101A

RTD10 TYPE


not connected

RTD10: Type

9102A

RTD10 LOCATION


Other

RTD10: Location

9103

RTD10 STAGE 1

-50..250 °C; ∞

100 °C

RTD10: Temperature Stage 1 Pickup

9104

RTD10 STAGE 1

-58..482 °F; ∞

212 °F


9105

RTD10 STAGE 2

-50..250 °C; ∞

120 °C


9106

RTD10 STAGE 2

-58..482 °F; ∞

248 °F


9111A

RTD11 TYPE


not connected

RTD11: Type

9112A

RTD11 LOCATION


Other

RTD11: Location

9113

RTD11 STAGE 1

-50..250 °C; ∞

100 °C


9114

RTD11 STAGE 1

-58..482 °F; ∞

212 °F


9115

RTD11 STAGE 2

-50..250 °C; ∞

120 °C


9116

RTD11 STAGE 2

-58..482 °F; ∞

248 °F


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7UM62 Manual C53000-G1176-C149-3


Addr.

Setting Title

Setting Options

Default Setting

Comments

9121A

RTD12 TYPE


not connected

RTD12: Type

9122A

RTD12 LOCATION


Other

RTD12: Location

9123

RTD12 STAGE 1

-50..250 °C; ∞

100 °C


9124

RTD12 STAGE 1

-58..482 °F; ∞

212 °F


9125

RTD12 STAGE 2

-50..250 °C; ∞

120 °C


9126

RTD12 STAGE 2

-58..482 °F; ∞

248 °F


2.42.2.2 Information for the Temperature Detection Function 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


14121 Fail: RTD 2


14122 RTD 2 St.1 p.up


14123 RTD 2 St.2 p.up


14131 Fail: RTD 3


14132 RTD 3 St.1 p.up


14133 RTD 3 St.2 p.up


14141 Fail: RTD 4


14142 RTD 4 St.1 p.up


14143 RTD 4 St.2 p.up


14151 Fail: RTD 5


14152 RTD 5 St.1 p.up


14153 RTD 5 St.2 p.up


14161 Fail: RTD 6


14162 RTD 6 St.1 p.up


14163 RTD 6 St.2 p.up


14171 Fail: RTD 7


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Functions

F.No.

Alarm

Comments

14172 RTD 7 St.1 p.up


14173 RTD 7 St.2 p.up


14181 Fail: RTD 8


14182 RTD 8 St.1 p.up


14183 RTD 8 St.2 p.up


14191 Fail: RTD 9


14192 RTD 9 St.1 p.up


14193 RTD 9 St.2 p.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


14211 Fail: RTD11


14212 RTD11 St.1 p.up


14213 RTD11 St.2 p.up


14221 Fail: RTD12


14222 RTD12 St.1 p.up


14223 RTD12 St.2 p.up


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2.43



A phase rotation feature via binary input and parameter is implemented in the 7UM62, thus ensuring that all protective and monitoring functions operate correctly when the phase rotation is reversed. If an anti-clockwise rotating phase sequence permanently exists, the appropriate setting should be entered in the power system data (see Section 2.3). If the phase rotation reverses during operation (e.g. in a pumping power station, the transition from the generator operation to the pumping operation is realized by changing the phase rotation), then a reversal signal at the input masked for this purpose is sufficient to inform the protective relay of the phase-sequence reversal.

Logic

The phase rotation is permanently set in a parameter of the power system data at address 0271 PHASE SEQ.. The binary input ”>Reverse Rot.” sets the phase rotation for the opposite of the setting (see figure 2-130).

FNo. 05145

>Reverse Rot. FNo. 05002

Operat. Cond.

> OR >

&

200 ms

&

FNo. 05148

OR

Rotation L1L3L2

0271 PHASE SEQ.

”1”

L1 L2 L3

&

FNo. 05147

OR

Rotation L1L2L3

L1 L3 L2

& & Figure 2-130 Message Logic of the Phase-Sequence Reversal

For safety reasons, the device accepts the phase rotation reversal only by a time when no usable measured quantities exist. The binary input is only inquired if operational condition 1 is not present. If a reverse command is present for a period of at least 200 ms, the measured quantities of phases L2 and L3 exchanged. If operational condition 1 is reached before the minimum control time of 200 ms has expired, the phase rotation reversal does not become effective. As no phase rotation reversal is possible in operational condition 1, the control signal could be cancelled in operational condition 1 without a phase rotation. For safety reasons, the control signal should be permanently present in order to avoid malfunctions also in case of a device reset (e.g. due to configuration change).

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Functions

Influence on Protective Functions

The swapping of phases directly impacts the calculation of positive and negative sequence quantities, as well as phase-to-phase voltages via the subtraction of one phase-to-ground voltage from another. Therefore, this function is vital so that phase detection messages, fault values, and operating measurement values are not falsified. As stated before, this function influences the unbalance load protection function, directional overcurrent protection function, and some of the monitoring functions (see Subsection 2.38.1.3), that issue messages if the required and calculated phase rotations do not match.

2.43.2 Setting Hint The normal phase sequence has been set at the address 0271 (see Section 2.3). If, on the system side, phase rotation reversal is performed temporarily, then this is communicated to the protective device via the binary input ”>Reverse Rot.” (FNo. 05145).

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2.44

Protection Function Logic The function logic is the heart of the device. It coordinates the sequence of both the protective and auxiliary functions, processes functional decisions, and processes data received from the system. In particular, the function logic is responsible for the following: • Processing Measurement and Detection Logic • Processing Tripping Logic

2.44.1 Functional Description 2.44.1.1 Processing Tripping Logic General Device Pickup

The pickup signals for all protective functions in the device are connected via an OR function, and lead to the general device pickup. General device pickup is initiated by the first function to pickup, and general device drop out occurs when the last function drops out. A corresponding message ”Dev. Pickup” indicating that general device pickup has occurred is reported. General device pickup is a precondition for a series of internal and external functions that occur subsequently. The following are among the internal functions controlled by general device pickup: • Start of Trip Log: From general device pickup to general device drop out, all fault messages are entered in the trip log. • Initialization of Oscillographic Records: The storage and maintenance of oscillographic values can also be made dependent on the general device pickup. • Generation of Spontaneous Messages: Certain fault messages are displayed in the device display as so-called spontaneous messages (see below ”Spontaneous Messages”). These display messages can also be made dependent on the general device trip.

Spontaneous Messages

Spontaneous messages are fault messages that appear in the display automatically when general device pickup has occurred. For the 7UM62, these messages include: • “Relay PICKUP”: protective function that last picked up • ”Relay TRIP”:

protection function that last initiated a trip signal

• “PU Time”:

running time from general device pickup to general device dropout, with time indicated in ms;

• “TRIP Time”:

running time from general device pickup to initiation of the first trip signal by the device, with time indicated in ms;

Please note that the overload protection does not have a pickup comparable to the other protective functions. The general relay pickup time PU Time is first started with the trip signal, and an abnormal occurrence is opened. The dropout of the thermal image of the overload protection ends the fault message and, thereby, the running time from general relay pickup to general device dropout PU Time.

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2.44.2 Processing Tripping Logic 2.44.2.1 Functional Description General trip

The tripping signals for all protective functions are connected by ”OR” and generate a message ”General TRIP” indicating that the device has initiated a trip signal. This annunciation, like individual trip indications, can be allocated to an LED or an output relay. It can also be used as a sum event.

Terminating the Tripping Signal

• If a protective function is set to Block Relay, it is blocked for the activation of the output relay. The other protective functions are not affected by this. • A trip command once transmitted is stored (see Figure 2-131). At the same time, the minimum trip command duration TMin TRIP CMD is started. This trip signal duration timer ensures the trip signal is transmitted to the circuit breaker for a sufficient amount of time, even if the function which issued the trip signal drops out quickly. The trip signal is only terminated after all protection Functions drop out AND the minimum trip signal duration expires. • Finally, it is possible to latch the trip signal until it is manually reset (lockout function). This allows to lock the circuit breaker against reclosing until the cause of the malfunction has been clarified and the lockout has been manually reset. The reset takes place either by pressing the LED reset key or by activating an appropriately masked binary input (”>Reset LED”). A precondition, of course, is that the circuit breaker trip coil – as usual – remains energized at the circuit breaker as long as the trip signal is present, and that the trip coil current is interrupted by the auxiliary contacts of the circuit breaker.

Block.Relais, e.g. I>

&

S

Tripping, e.g. I>

Q

R

Relay triggering

0280 TMin TRIP CMD

& T

Lockout function (Output relay stored)

S

Lockout reset (using LED–Reset)

R

Q

Figure 2-131 Terminating the Trip Signal, Example of a Protective Function

2.44.2.2 Settings for the Tripping Logic Trip and Close Command Duration

282

The setting of the minimum trip signal duration at address 0280 TMin TRIP CMD was already discussed in Subsection 2.3. This time is valid for all protective functions

7UM62 Manual C53000-G1176-C149-3


that can initiate trip signals, as well as for trip signals that are initiated using the device function controller. Addr. 0280

Parameter

Setting

TMin TRIP CMD.

0.01 .. 32.00 s

Default Settings 0.15 s

Comment Minimum duration of the trip command

2.44.3 Fault Display on the LEDs/LCD 2.44.3.1 Principle of Function The storage of messages masked to local LEDs, and the maintenance of spontaneous messages, can be made dependent on whether the device has issued a trip signal. In this situation, these messages are not issued, if one or more protective functions have only picked up on a fault, but a trip signal has not been issued yet by the 7UM62 because the fault was cleared by another device (for instance outside of the own protection range). These messages are then limited to faults in the own protection range. Figure 2-132 illustrates the creation of the reset command for stored messages. By the moment of the device dropout, the stationary conditions (fault indication with excitation/with trip signal; tripping/no tripping) decide whether the new fault remains stored or is reset. 7110 FltDisp.LED/LCD

Targets on every pickup ”1”

Targets on TRIP only

&

Relay TRIP

Reset LED and LCD messages

Trip Signal drop out

Figure 2-132 Creation of the reset command for the memory of the LED and LCD messages

2.44.3.2 Settings Pickup of a new protective function generally turns off any previously set light displays, so that only the latest fault is displayed at any time. It can be selected whether the stored LED displays and the spontaneous messages on the display appear upon renewed pickup, or only after a renewed trip signal is issued. In order to enter the desired type of display, select in the SETTINGS menu the sub-menu Device. Address 7110 FltDisp.LED/LCD offers the two alternatives Display Targets on every Pickup and Display Target on TRIP only. Addr. 7110

Parameter FltDisp.LED/LCD

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Setting

Default Settings

Display Targets on every Pickup Display Targets on TRIP only

Display Targets on every Pickup

Comment Fault display on the LEDs/LCD

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Functions

2.44.4 Statistical Counters 2.44.4.1 Functional Description Number of Trips

The number of trips initiated by the 7UM62 is counted, as long as the position of the circuit breaker is monitored via breaker auxiliary contacts and binary inputs. To use this function, the internal pulse counter ”Trip Count” is masked in the matrix to a binary input that is controlled by the circuit breaker OPEN position. The pulse count value ”Trip Count” can be found in the submenu ”Statistic” if ”Measured and Metered Values Only” has been selected in the matrix.

Switch-Off Values (at Trip)

Additionally, the following switch-off values are indicated in the fault messages for each trip signal: − the primary currents in all three phases in kA, individually for side 1 and side 2 − if tripping has been initiated by the differential protection, the differential and restraint currents of all three phases are indicated. − the three phase-earth-voltages in kV − primary active power P in kW, MW or GW (precisely averaged power) − primary reactive power Q in kVA, MVA or GVA (precisely averaged power) − frequency in Hz

Operating Hours

The operating hours under load (= the current value in at least one phase is larger than the limit value BkrClosed I MIN) set at address 0281) are also stored.

Accumulated Shutdown Currents

The shutdown currents for each phase, which are indicated at every trip command individually for side 1 and side 2, are accumulated and stored. The counter and memory levels are secured against loss of auxiliary voltage.

2.44.4.2 Setting/Resetting The above listed statistical counters are set and reset in the menu ANNUNCIATIONS → STATISTIC by overwriting the displayed counter values.

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2.44.4.3 Information for the Statistical Counter 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

UnlockDT

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 1)

00056 Initial Start

Initial Start of Device 2)

00067 Resume

Resume 3)

00069 DayLightSavTime

Daylight Saving Time

SynchClock

Clock Synchronization

00070 Settings Calc.

Setting calculation is running

00071 Settings Check

Settings Check

00072 Level-2 change

Level-2 change

00125 Chatter ON

Chatter ON

HWTestMod

Hardware Test Mode

1)

Device is reset on each Power ON ) Initial start of device after initialization using DIGSI® 4 3 ) Restart after loading a parameter set or after reset 2

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2.45

Auxiliary Functions The auxiliary functions of the 7UM62 relay include: • processing of messages, • processing of operational measured values, • storage of fault record data. • Commissioning aids.

2.45.1 Processing of Messages After the occurrence of a system fault, data regarding the response of the protective relay and the measured quantities should be saved for future analysis. For this reason message processing is done in three ways: LEDs and Binary Outputs (Output Relays)

Important events and conditions are displayed, using LEDs on the front panel of the relay. The relay also contains output relays for remote signaling. All LEDs and binary outputs indicating specific messages can be freely configured. The relay is usually delivered with a default setting. The SIPROTEC® 4 System Manual describes in detail how to proceed for the configuration. The default settings on delivery are listed in the Appendix of this manual, Section . The output relays and the LEDs can be operated in a latched or unlatched mode (individually settable for each one). The latched conditions are protected against loss of the auxiliary voltage. Please observe the following: − If necessary, clear stored indications by pressing the ”LED-Reset” key. − Remotely using a binary input, − Using one of the serial interfaces, − Automatically at the beginning of a new pickup. Condition messages should not be stored. Also, they cannot be reset until the criterion to be reported is cleared. This applies to messages from monitoring functions, or similar. A green LED displays operational readiness of the relay, and cannot be reset. It goes out if the self-check feature of the microprocessor recognizes an abnormal occurrence, or if the auxiliary voltage is lost. When auxiliary voltage is present, but the relay has an internal malfunction, then the red LED (ERROR) lights up and the processor blocks the relay.

Fault Information Display or Personal Computer

Events and conditions can be read out on the display on the front cover of the relay. Using the front operator interface or the rear service interface, for instance, a personal computer can be connected, to which the information can be sent. In the idle condition, as long as no system fault is present, the display field can display selected operating information (overview of operating measurement values). In the case of a system fault, information about the system fault appears instead (spontaneous display messages, see also Section 2.44.1.1). After the fault related

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Auxiliary Functions

annunciations have been acknowledged, the initial display is shown again. Acknowledgement can be performed by pressing the LED button on the front panel. The relay is also equipped with several event buffers, for operational messages, circuit breaker statistics, etc., which are protected against loss of the auxiliary voltage by a buffer battery. These messages can be retrieved, at any time, using the operating keypad in the display field, or transferred to a personal computer, using the serial operator interface. Readout of messages during operation is described in detail in the SIPROTEC® 4 System Manual. Types of Annunciations

Annunciations can be of one of the following types: • Operational annunciations; these are generated while the device is operating: Information regarding the status of device functions, measured data, power system data, control command logs etc. • Alarms; these are annunciations of the last 8 network faults processed by the device. • Switching statistics annunciations; these are counters for trip commands initiated by the device, in some cases reclosure commands, values of shutdown currents and accumulated short-circuit currents. A complete list of all message and output functions that can be generated by the device, 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 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 “Disabled” in device configuration, then the associated messages cannot appear.

2.45.1.1 Operational Annunciations 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.

2.45.1.2 Fault Annunciations After a short-circuit fault on the system, for example, important information about the progression of the fault can be retrieved, such as the pickup of a protective element or the initiation of a trip signal. The time the initial occurrence of the short-circuit fault occurred is accurately provided via the system clock. Time progression of the shortcircuit fault is reported based on the moment of pickup, so that the duration, until the trip signal is issued and interrupted, is available. The time resolution used for reporting is 1 ms. Spontaneous Annunciations on the Device Front

7UM62 Manual C53000-G1176-C149-3

After a fault, the device displays automatically and without any operator action on its LCD display the most important fault data from the general device pickup in the sequence shown in Figure 2-133.

287

Functions

U0> picked up S/E/F TRIP PU Time 440ms TRIP Time 301ms

Protective Function that picked up first; Protective Function that dropped out last; Running time from general pickup to dropout; Running time from general pickup to the first trip command

Figure 2-133 Display of Spontaneous Messages on the Device Front

Retrieved Messages

The messages for the last eight network faults can be retrieved. Where a generator fault causes several protective functions to pick up, the fault is considered to include all that occurred between pickup of the first protective function and dropout of the last protective function. In total 600 messages can be recorded. Oldest data are erased for newest data when the buffer is full.

2.45.1.3 General Interrogation The present condition of a SIPROTEC® device can be retrieved by a general interrogation using DIGSI® 4. All messages included in a general interrogation are displayed with their present value.

2.45.1.4 Spontaneous Annunciations The spontaneous annunciations displayed using DIGSI® 4 reflect the present status of incoming information. New annunciations are displayed immediately, no triggered or cyclic refreshment is required.

2.45.1.5 Statistical Counters The messages in switching statistics are counters for the accumulation of interrupted currents by each of the breaker poles, the number of trips issued by the device to the breaker, and the operating hours of the breaker and protected equipment. 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. A password is not required to read switching statistics; however, a password is required to change or delete the statistics. Information to a Control Center

288

Stored information can also be transferred to a central control system (SCADA), using the system interface. The transfer can take place using various transfer protocols.

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Auxiliary Functions

2.45.2 Measurements Display of Measured Values

A series of measured values and the values derived from them are constantly available for call up on site, or for data transfer (See Table 2-19, as well as the following list). The operational measured values listed in Table 2-19 can be read out as secondary, primary or percent values. A precondition for correctly displaying the primary and percentage values is complete and correct entry of the nominal values for the current transformers, and protected equipment, in accordance with Subsections 2.3 and 2.5. Table 2-19 lists the formulae for the conversion of secondary into primary or percentage values. Depending on the version ordered, the type of device connection and the configured protective functions, only a part of the operational measured values listed in Table 219 may be available. The displacement voltage 3U0 is calculated from the phase-earth voltages: 3U0 = |UL1 + UL2 + UL3|. All three voltage inputs must be phase-ground connected for this.

Table 2-19

Conversion Formulae between Secondary Values and Primary/Percentage Values

Measured Val. Secondary IL1 S2, IL2 S2, IL3 S2, I1 S2, I2 S 3I0 S2

Isec S2

IL1 S1, IL2 S1, IL3 S1,

Isec S1

Primary

IN–PRI I–CT S2 --------------------------------------------- ⋅ I sec S2 IN–SEC I–CT S2

% I prim. S2 ------------------------------------------------------------------------------------------------------------------- ⋅ 100 SN GEN/MOTOR ⁄ ( 3 ⋅ UN GEN/MOTOR )

Diff. protect. for generators/motors: IN–PRI I–CT S1-------------------------------------------⋅I IN–SEC I–CT S1 sec S1

I prim. S1 ------------------------------------------------------------------------------------------------------------------- ⋅ 100 SN GEN/MOTOR ⁄ ( 3 ⋅ UN GEN/MOTOR )

Diff. protect. for 3-phase transformer: I prim. S1 ------------------------------------------------------------------------------------------ ⋅ 100 SN TRANSF ⁄ ( 3 ⋅ UN WIND.S1 )

IEE 1

IEE S2

IEE1 sec

FACTOR IEE1 ⋅ I EE1 sec

I EE1 prim . ------------------------------------------------------------------------------------------------------------------- ⋅ 100 SN GEN/MOTOR ⁄ ( 3 ⋅ UN GEN/MOTOR )

FACTOR IEE2 ⋅ I EE2 sec

I EE2 prim. ------------------------------------------------------------------------------------------------------------------- ⋅ 100 SN GEN/MOTOR ⁄ ( 3 ⋅ UN GEN/MOTOR )

IEE2 sec

UL1E, UL2E, UL3E, U0 U1, U2

UL-E sec.

UL1-L2, UL2-L3, UL3-L1

ULL sec.

UN–VT PRIMARY ----------------------------------------------------------- ⋅ U L-E sec UN–VT SECONDARY

7UM62 Manual C53000-G1176-C149-3

UN–VT PRIMARY = ----------------------------------------------------------- ⋅ U LL sec UN–VT SECONDARY

U prim. -------------------------------------------------------------- ⋅ 100 UN GEN/MOTOR ⁄ ( 3 ) U prim. ---------------------------------------------- ⋅ 100 UN GEN/MOTOR

289

Functions

Table 2-19

Conversion Formulae between Secondary Values and Primary/Percentage Values

Measured Val. Secondary UE

UE sec.

Primary UE measured:

%

U E prim. --------------------------------------------------------------------- ⋅ 100 UN–GEN PRIMARY ⁄ ( 3 )

FACTOR UE ⋅ UE sec UE calculated: :

UN – VT PRIMARY -------------------------------------------------------------- ⋅ U E sec UN – VT SECONDARY P, Q, S

Psec Qsec Ssec

PRIM. IN– PRI I–CT S2 -------------------------------------- ⋅ ----------------------------------------------- ⋅ P P prim = UN–VT sec

Powerprim. ⋅ 100 ---------------------------------------------SN GEN/MOTOR

Angle PHI

ϕ in °el

ϕ in °el

ϕ in °el

Power factoR

cos ϕ

cos ϕ

cos ϕ · 100 in %

Frequency (f)

f in Hz

f in Hz

UN–VT SEC,

IN– SEC I–CT S2

f in Hz ----------------- ⋅ 100 in % f nom U/f

U ---f UN–VT PRIMARY -------- ⋅ -------------------------------------U N UN–GEN/MOTOR -------fN

R, X

UE3.H

UDC/IDC (measuring transducer 1)

Rsec S2 Xsec S2

UE3.H,sec in V

UDC in V-

UN–CT PRIMARY ---------------------------------------------UN–VT SECONDARY ---------------------------------------------IN–PRI I–CT S2 ----------------------------------IN–SEC I–CT S2

290

Uerr

no display of percentage measured values ⋅ R sec S2

FACTOR UE ⋅ U E3.H,sec no primary values

IDC in mA-

Uerr (measuring transducer 3)

U ---f UN–VT PRIMARY -------- ⋅ -------------------------------------- ⋅ 100 in % U N UN–GEN/MOTOR -------fN

U E3.H.prim -------------------------------------------------------------- ⋅ 100 UN GEN/MOTOR ⁄ ( 3 ) U DC ⁄ V ------------------ ⋅ 100 10 V I DC ⁄ mA -------------------- ⋅ 100 20 mA

in %

in %

no primary value

Uerr ⁄ V ------------------- ⋅ 100 10 V

in %

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Auxiliary Functions

where Parameter

Address

Parameter

Address

Unom PRIMARY

0221

FACTOR IEE1

0205

Unom SECONDARY

0222

FACTOR IEE2

0213

IN-PRI I-SIDE1

0202

FACTOR UE

0224

IN-SEC I-SIDE1

0203

UN GEN/MOTOR

0251

IN-PRI I-SIDE2

0211

SN GEN/MOTOR

0252

IN-SEC I-SIDE2

0212

Uph / Udelta

0225A

UN-PRI SIDE 1

0241

SN TRANSFORMER 0249

In addition, the protection functions calculate and provide the following measured values: Measured Values of Rotor Earth Fault Protection (Rn, fn)

The following secondary values are available: System-frequency displacement voltage URE (= UE), earth fault current IRE (= IEE1) and rotor earth resistance Rearth, total resistance Rtot, total reactance Xtot and phase angle ϕZtot of the total resistance of the rotor earth fault protection.

Measured Values of the Rotor Earth Fault Protection (1–3 Hz)

Frequency and amplitude of the 1–3 Hz generator (7XT71) fgen, Ugen, current in the rotor circuit Igen, charge at polarity reversal QC and rotor earth resistance Rearth.

Measured Values of the Stator Earth Fault Protection (20 Hz)

Voltage and current in the stator earth circuit USEF and ISEF, the specific stator earth resistances Rsef and Rsefp (primary) and the phase angle ϕ SES between the current and the voltage at 20 Hz.

Values of the Differential Protection

− Differential and restraint currents (stabilized currents) IDiff L1, IDiff L2, IDiff L3, IStab L1, IStab L2, IStab L3, I–0Diff, I–0Stab, 3I0–1, 3I0–2 in percent of the nominal values of the protected object. The phase angle of the three currents on both sides of the protected object is φIL1S1, φIL2S1, φIL3S1, φIL1S2, φIL2S2, φIL3S2.

Thermal Measured Values

− ΘS/ΘSTrip

Overload protection measured values of the stator winding depending on the phase, in % of the tripping overtemperature,

− ΘS/ΘSTripL1

Normalized overload protection measured values of the stator winding for phase L1

− ΘS/ΘSTripL2


− ΘS/ΘSTripL3


− ΘR/ΘRmax

Normalized rotor temperature in % of the tripping temperature

− TRe.Inhib. time

Time until the next permissible restart

− I2 thermal,

Rotor overtemperature due to the negative phase-sequence component of the current, % of the tripping overtemperature,

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Functions

− U/f th.

Overtemperature caused by an overexcitation, in % of the tripping overtemperature,

− Coolant temperature (or ambient temperature) In addition, the following may be available: Min/Max Values1)

− Minimum and maximum values for the positive-sequence components I1 and U1, the active power P, reactive power Q, in primary values, of the frequency and of the 3rd harmonic content in the displacement voltage, in secondary values U3.H. Included are the date and time they were last updated. The minimum/maximum values can be reset via binary inputs or, in the delivery status of the device, also via the F4 function key.

Energy, Metered Values1)

− Wp, Wq, metered values of the active and reactive energy in kilowatt, megawatt or gigawatt hours primary or in kVARh, MVARh or GVARh primary, separately according to the input (+) and output (–), or capacitive and inductive. The calculation of the operational measured values is also executed in case of an existing fault. The values are updated in intervals of ≥ 0.3 s and ≤1 s.

Transfer of Measured Values

Measured values can be transferred via the interfaces to a central control and storage unit.

Setpoint Monitoring

SIPROTEC® 7UM62 allows to set warning levels for important measured and counter values. When a programmed limit value is exceeded (or fallen below), a message is generated that is output as an operational annunciation and can — like all operational annunciations — be masked to both output relays and LEDs and transmitted through the interfaces. In contrast to the actual protective functions, such as time-overcurrent protection or overload protection, this monitoring program executes in the background and may not respond promptly in case of a fault if the measured values change rapidly and protective functions pick up. Moreover, since a message is not generated until the set limit value has been exceeded several times, these monitoring functions cannot respond immediately before a device trip. In the7UM62, only the limit value of the undercurrent protection IL< is configured when the device is delivered from the factory. More limit values can be configured if their measured and metered values have been set accordingly in CFC) see SIPROTEC® 4 System Manual).

2.45.3 Oscillographic Fault Recording (Waveform Capture) Terminology

Please be aware of the fact that we use different terms for the above-mentioned function: (Oscillographic) Fault Recording, Oscillographic Recording, Wave Form Capture. However, all terms have the same meaning. The corresponding fault buffer in DIGSI® 4 is called Trip Log.

General

The Multifunctional Protection 7UM62 is equipped with a fault memory sampling either the instantaneous values or the r.m.s. values of various measured quantities to store them in a circulating buffer. The instantaneous values of measured values

1.) only in the 7UM62**–*****–3***

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iL1 S1; iL2 S1; iL3 S1; iEE1; iL1 S2; iL2 S2; iL3 S2; iEE2 and uL1, uL2, uL3, uE and u= or i= of the three measuring transducers are sampled at intervals of 1.25 ms (for 50 Hz) or 1.04 ms (for 60 Hz), and stored in a circulating buffer (16 samples per cycle). For a fault, the data are stored for an adjustable period of time, but not more than 5 seconds. The r.m.s. values of the measured quantities I1, I2, IEE2, IEE1; U1, UE, P, Q, ϕ, f–fN, R and X can be stored in a circulating buffer, in a grid of 1 measured value per cycle. R and X are the positive sequence impedances. For a fault, the data are stored for an adjustable period of time, but not more than 80 seconds. Up to 8 fault records can be recorded in this buffer. The memory is automatically updated with every new fault, so no acknowledgment for previously recorded faults is required. Waveform capture can also be started with protection pickup, via binary input, via operator interface, or SCADA. 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 such as the impedance or RMS values from the measured values. A selection may be made as to whether the currents and voltages are represented as primary 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 applicable programs in the central device. Currents and voltages are referred to their maximum values, scaled to their rated values and prepared for graphic representation. Binary signal traces (marks) of particular events e.g. ”fault detection”, ”tripping” are also represented. In the event of transfer to a central device, the request for data transfer can be executed automatically and can be selected to take place after each fault detection by the protection, or only after a trip.

2.45.4 Date and Time Stamping Integrated date and time stamping allows for the exact evaluation of sequence of events (e.g. operations or error messages, or limit violations). The clock may be influenced by: • the internal RTC clock (Real Time Clock), • external synchronization sources (DCF, IRIG B, SyncBox, IEC 60870–5–103, PROFIBUS), • external minute impulses via a binary input. Note: The device is delivered from the factory with the internal RTC clock selected as the time source, independent of whether the device is equipped with a system interface or not. If external synchronization is desired, it must be configured accordingly.

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Functions

Here you may select the time standard for internal time stamping by selecting from the following modes: Operating Mode

Explanations

Internal

Internal synchronization using RTC (pre-set)

IEC 60870–5–103

External synchronization using the system interface and the IEC 60870–5–103 protocol

PROFIBUS DP

External synchronization using PROFIBUS interface

IRIG B Time signal External synchronization using IRIG B DCF77 Time signal

External synchronization using DCF 77

SIMEAS Time signal Sync. Box

External synchronization using SIMEAS Sync. Box

Pulse via binary input

External synchronization with pulse via binary input

Fieldbus

External synchronization using Modbus interface

The time display may be set using either the European format (DD.MM.YYYY) or the US format (MM/DD/YYYY). If the power supply voltage is cut off for 1 or 2 days, the internal buffer battery is automatically switched off.

2.45.5 Commissioning Aids 2.45.5.1 Influencing Information on the System Interface During Test Operation If the device is connected to a central control or storage system, you can influence the information that will be transferred to the control center. The IEC 60870–5–103 protocol allows to identify all messages and measured values transferred to the central control system with an added message “test operation”- bit while the device is being tested on-site (test mode). This identification prevents the messages from being incorrectly interpreted as resulting from an actual power system disturbance or event. As another option, all messages and measured values normally transferred via the system interface can be blocked during the testing (block data transmission). Data transmission block can be accomplished by controlling binary inputs, by using the operating panel on the device, or with a PC and DIGSI® 4 via the operator interface. The CFC link for changeover to binary input is predefined in the device (see Figure A-48 in the Appendix A.9.7). The SIPROTEC® 4 System Manual describes in detail how to activate and deactivate test mode and blocked data transmission.

2.45.5.2 Testing the System Interface If the device has a SCADA interface that is used for communication with a control centre, you can test in the DIGSI® 4 Dialog Mode whether annunciations are correctly transmitted.

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A dialog box displays the texts of all annunciations that have been masked to the system interface in the matrix. In another column of the dialog box you can specify a value for the annunciations that you want to test (e.g. coming/ going) to generate an annunciation as soon as you have entered password no. 6 (for hardware test menus). The annunciation is output and can now be read both in the operational annunciations of the SIPROTEC® device and in the station control center. This test can be performed in annunciation direction as well as in command direction. The procedure is described in detail in Section 3.3.2.

2.45.5.3 Testing the States of the Binary Inputs/Outputs With DIGSI® 4 you can test selectively individual binary inputs, output relays and LEDs of the SIPROTEC®4 device. This allows you, for instance, to check during commissioning whether your station connections are correct. A dialog box displays all binary inputs and outputs existing in the device, and the LEDs with their current state. It also shows which commands or annunciations are masked to which hardware component. In anther column of the dialog box you can switch each item to the opposite state after entering password no. 6 (for hardware test menus). In this way you can, for instance, cause each output relay to pick up, and thus test the wiring between the 7UM62 and the station, without having to create the indications masked to it. This procedure is described in detail in Section 3.3.3.

2.45.5.4 Creating a Test Oscillographic Recording At the end of commissioning, an investigation of the stability of the protection during closing operations. For this, closing test should be carried out. Oscillographic event recordings obtain the maximum information about the behaviour of the protection. The 7UM62 also has the capability of capturing waveforms when commands are given to the device via the service program DIGSI® 4, the serial interface, or a binary input. For the latter, the binary input must be masked with event 4 ”>Trig.Wave.Cap.”. The oscillographic recording is then triggered when the input is energized. An auxiliary contact of the circuit breaker or primary switch may be used to control the binary input for triggering. An oscillographic recording that is externally triggered (that is, without a protective element pickup or device trip) is processed by the device as a normal oscillographic recording, and has a number for establishing a sequence. However, these recordings are not displayed in the Trip Log as they are not a fault event. The procedure for this is described in detail in Section 3.4.11.

2.45.6 Setting Hints Thresholds

The settings are entered under MEASUREMENT in the sub-menu SET POINTS (MV) by overwriting the existing values.

Waveform Capture

Waveform capture of faults is executed only when address 0104 FAULT VALUE has been set to Instantaneous values or RMS values. Other settings pertaining to waveform capture are found under the OSC. FAULT REC. submenu of the

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SETTINGS menu. Waveform capture makes a distinction between the trigger for an oscillographic record and the criterion to save the record (address 0401 WAVEFORMTRIGGER). Normally the trigger is the pickup of a protective element, i.e. when a protective element picks up the time is 0. The criterion for saving can be the pickup as well (Save w. Pickup), or the device trip (Save w. TRIP). Another option is to set (Start with TRIP). A trip command issued by the device is both the trigger and the criterion to save the record with this setting. A waveform capture includes in machine protection always the complete course of a fault. An oscillographic fault record includes data recorded prior to the time of trigger, and data after the dropout of the recording criterion. Therefore address 0402 WAVEFORM DATA is preset to Fault event. The user determines the length of pre-trigger time and post-dropout time to be included in the fault record with the settings in address 0404 PRE. TRIG. TIME and address 0405 POST REC. TIME. The maximum length of time of a record MAX. LENGTH is entered at address 0403. The setting depends on the criterion for storage, the delay time of the protective functions and the desired number of stored fault events. The largest value here is 5 s for fault recording of instantaneous values, 80 s for recording of r.m.s. values (see address 0104). A total of 8 records can be saved. Note: These times apply for 50 Hz. They will be different with another frequency. If RMS values are stored, the times stated for parameters 0403 to 0406 will be 16 times longer. An oscillographic record can be triggered and saved by a change in status of a binary input or via the operator interface connected to a PC. The trigger is dynamic. The length of a record for these special triggers is set at address 0406 BinIn CAPT.TIME (upper bound is MAX. LENGTH, address 0403). Pre-trigger and postdropout times are not included. If the binary input time is set to ∞, then the length of the record equals the time that the binary input is activated (static), or the MAX. LENGTH (address 0403), whichever is shorter.

2.45.6.1 Settings for Oscillographic Fault Recording Addr.

Setting Title

401

WAVEFORMTRIGGER

402

Setting Options Save with Pickup Save with TRIP Start with TRIP

Default Setting

Comments

Save with Pickup

Waveform Capture

WAVEFORM DATA Fault event Power System fault

Fault event

Scope of Waveform Data

403

MAX. LENGTH

0.30..5.00 sec

1.00 sec

Max. length of a Waveform Capture Record

404

PRE. TRIG. TIME

0.05..4.00 sec

0.20 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

Capture Time via Binary Input

2.45.6.2 Information for the Oscillographic Fault Recording F.No.

Alarm

00004 >Trig.Wave.Cap.

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Comments >Trigger Waveform Capture

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F.No.

Alarm

00203 Wave. deleted

Comments Waveform data deleted

FltRecSta

Fault Recording Start

2.45.6.3 Information for Minimum and Maximum Values F.No.

Alarm

Comments

00396 >I1 MiMaReset

>I1 MIN/MAX Buffer Reset

00399 >U1 MiMa Reset

>U1 MIN/MAX Buffer Reset

00400 >P MiMa Reset

>P MIN/MAX Buffer Reset

00402 >Q MiMa Reset

>Q MIN/MAX Buffer Reset

00407 >Frq MiMa Reset

>Frq. MIN/MAX Buffer Reset

00394 >UE3h MiMa Res.

>UE 3rd Harm. MIN/MAX Buffer Reset

00857 I1 Min=

Positive Sequence Minimum

00858 I1 Max=

Positive Sequence Maximum

00874 U1 Min =

U1 (positive sequence) Voltage Minimum

00875 U1 Max =

U1 (positive sequence) Voltage Maximum

00876 PMin=

Active Power Minimum

00877 PMax=

Active Power Maximum

00878 QMin=

Reactive Power Minimum

00879 QMax=

Reactive Power Maximum

00882 fMin=

Frequency Minimum

00883 fMax=

Frequency Maximum

00639 UE3h min=

UE 3rd Harmonic Voltage Minimum

00640 UE3h max=

UE 3rd Harmonic Voltage Maximum

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2.46

Breaker Control

General

In addition to the protective functions described thus far, a control command process is integrated in the SIPROTEC® 7UM62 to coordinate the operation of circuit breakers 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 − Operation using DIGSI® 4 − Remote operation using a substation automation and control system (e.g. SICAM) − Automatic functions (e.g., using a binary input) Single and double busbar systems are supported. The number of switchgear devices to be controlled is, basically, limited by the number of binary inputs and outputs present. Therefore, 7UM622 should be the preferred version. High security against inadvertent device operations can be ensured if interlocking checks are enabled. A standard set of optional interlocking checks is provided for each command issued to circuit breakers/switchgear.

Logical Links Using CFC

The 7UM62 can also execute user-defined logic functions. These logic functions can be edited with the CFC (=Continuous Function Chart) tool. Interlocking and command processing, as well as monitoring functions or processing of measured values, can be programmed by simple drawing; no programming knowledge is required. The desired functions can be put together from predefined function blocks which are grouped in a library. Detailed information on CFC is contained in the SIPROTEC® 4 System Manual, Order No. E50417–H1176–C151, and in particular in the CFC Manual, Order No. E50417–H1176–C098. A logic circuit is created with a PC using the DIGSI® 4 software; the serial or service port is used for this. When the device is delivered from the factory, it contains two standard CFC charts (see Appendix A.9.7). One chart is used to allow switching of an annunciation/ measured value blocking by binary input (blocking of annunciations in test mode) (see 2.45.5.1). The other chart (see Figure A-49) provides for undercurrent monitoring of three phase currents.

Operation Using the Keypad on the Local User Interface

Control commands can be initiated using the keypad on the local user interface of the relay (see also SIPROTEC® 4 System Manual, Control of Switchgear). Using the navigation keys , , , , the control menu can be accessed and the circuit breaker/switchgear to be operated can be selected. After entering a password, a new window is displayed in which multiple control actions (close, open, cancel) are available and can be selected using the and keys. Next a security check takes place. After the security check is completed, the ENTER key must be pressed again to carry out the command. If the ENTER key is not pressed within one minute, the selection is cancelled. Cancellation via the ESC key is possible at any time before the control command is issued. ESC If the attempted command fails, because an interlocking condition is not met, then an error message appears in the display. The message indicates why the control command was not accepted (see also SIPROTEC® 4 System Manual). This message must be acknowledged with ENTER before any further control commands can be issued.

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Operation using DIGSI® 4

Control commands for switchgear can also be entered in DIGSI® 4 with a PC that is connected to the operator interface. The procedure to do so is described in the SIPROTEC® 4 System Manual (Control of Switchgear).

Operation using the SCADA Interface

Control commands for switchgear can also be entered through the serial SCADA interface communicating with the substation control and protection system. A prerequisite for this is that the required peripherals physically exist in the device and the substation. Also, a few settings for the serial interface in the device are required (see SIPROTEC® 4 System Manual).

2.46.1 Types of Commands Two types of commands can be processed within the device: Control Commands

These are all commands that are directly output to the switchgear to change their process state: − Commands for the operation of circuit breakers (unsynchronized), disconnectors, earthing switches − Step commands (e.g. raising and lowering transformer LTCs) − Set-point commands with configurable time settings (Petersen coils)

Internal / Pseudo Commands

These commands do not directly operate binary outputs. They serve to initiate internal functions, simulate changes of state, or to acknowledge changes of state. − Manual overwriting commands to manually update information on processdependent objects such as annunciations and switching states, e.g. if the communication with the process is interrupted. Manually overwritten objects are marked as such in the information status and can be displayed accordingly. − Additionally, Tagging commands are issued to establish internal settings, such as switching authority (remote vs. local), parameter set changeover, data transmission block to the SCADA interface, and measured value set-points. − Acknowledgment and resetting commands for setting and resetting internal buffers. − Information status command to set/reset the additional „Information status“ item of a process object, such as: − Controlling activation of binary input status − Binary Output Blocking

2.46.2 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 programmed separately for each command. The actual execution of the command is also monitored afterwards. The entire sequence of a command is described briefly in the following:

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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 Recognition • User configurable Interlocking checks − Switching Authority − Device Position (scheduled vs. actual comparison) − Zone Controlled/Field Interlocking/ (logic using CFC) − System Interlocking (centrally, using SCADA system or substation controller) − Double Operation (interlocking against parallel switching operation) − Protection Blocking (blocking of switching operations by protective functions) • Fixed Command Checks − Internal process time (software watch dog which checks the time for processing the control action between initiation of the control and final close of the relay contact. − Setting Modification in Process (if setting modification is in process, commands are denied or delayed) − Equipment Present at Output (If a circuit breaker or other operable equipment is not configured 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 one circuit breaker or switch) − 1-of-n-check (for schemes with multiple assignments, such as common ground, whether a command has already been initiated for the affected output relay is checked). − Interruption of a Command because of a Cancel Command

Monitoring the Command Execution

− Running Time Monitor (feedback message monitoring time)

2.46.3 Interlocking Interlocking checks in a SICAM®/SIPROTEC® system are divided into: • System Interlocking (checked by a central control system such as SCADA or substation controller) • Zone Controlled/Bay Interlocking (checked in the device) Zone Controlled/Bay Interlocking System interlocking relies on the system data base in the substation or central control system.

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The extent of the interlocking checks is determined by the configuration of the relay. Circuit breakers (or other equipment) that require system interlocking in a central control system (Substation Controller) must be configured in their specific commands object properties box for the specific control device. For all commands, operation with interlocking (normal mode) or without interlocking (test mode) can be selected: − for local commands, by reprogramming the settings (using the local user interface) with password check, − for automatic commands, via command processing by CFC.

2.46.3.1 Interlocked / Non-Interlocked Switching The command checks that can be selected for the SIPROTEC® relays are also referred to as ”standard interlocking”. These checks can be activated (interlocked) or deactivated (non interlocked) using DIGSI® 4. Deactivated interlock switching means the configured interlocking conditions are not checked in the relay. Interlocked switching means that all configured interlocking conditions are checked within the command processing. If a condition is not fulfilled, the command is rejected, marked with a minus sign (e.g. ”CO–”), and a message to that effect is output. Table 2-20 shows the types of possible commands to switchgear, and the associated annunciations. Table 2-20

Types of Commands and Messages

Command Type

Command

Cause

Message

Control Issued

Switching

CO

CO+/–

Manual Tagging (positive / negative)

Manual overwriting

MT

MT+/–

Input Blocking

Controlling activation of binary input status

ST

ST+/– *)

Output Blocking

Binary output blocking

ST

ST+/– *)

Control Abortion

Abort

CA

CA+/–

*)appear in this form only on the device as operational indications, in DIGSI® 4 as spontaneous messages.

A + sign in the annunciation means a confirmation of the command. The command output has a positive result, as expected. A – means a negative, i.e. an unexpected result; the command was rejected. Possible command feedbacks and their causes are dealt with in the SIPROTEC® 4 System Manual. Figure 2-134 shows an example of operational annunciations (command and feedback) for successful switching of a circuit breaker. Interlocking checks can be configured individually for all switching devices and markings. Other internal control actions, such as manual overwriting or abort, are always executed regardless of any interlocking.

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EVENT LOG --------------------19.06.01 11:52:05,625 Q0 CO+ close 19.06.01 11:52:06,134 Q0 FB+ close Figure 2-134 Example of an Operational Annunciation for Switching Circuit Breaker Q0

Standard Interlocking Defaults

The following is a list of Standard Interlocking Conditions that can be selected for each controllable device. All of these are enabled as a default. • Device Position (scheduled vs. actual comparison) the switching command is rejected, and an error message is displayed, if the circuit breaker is already in the scheduled (desired) position. (If this check is enabled, then it works whether interlocking, e.g. zone controlled, is activated or deactivated.) • Substation Controller (System Interlocking) The system interlocking is checked by transmitting a local command to the central controller with the switching authority set to = Local. Switchgear that is subject to system interlocking cannot be switched by DIGSI® 4. • Bay Interlocking: All devices controlled by this relay can be interlocked by the CFC logic. • Blocked by protection: A CLOSE-command is rejected as soon as one of the protective elements in the relay picks up. The OPEN-command, in contrast, can always be executed. Please be aware, activation of thermal overload protection elements can create and maintain a fault condition status, and can therefore block CLOSE commands Double Operation Block: If you cancel the blocking, please be aware that in this case the motor restart inhibit feature will not automatically reject a restart command given to the motor. Therefore, a restart inhibit must be provided by other means, e.g. by a bay interlocking using. • Double Operation: Parallel switching operations are interlocked against one another; while one command is processed, a second cannot be carried out. • Switching Authority LOCAL: When this interlocking check is enabled in the Object Properties dialog box, the status of Switching authority is checked prior to issuing a control command. If this particular setting is selected, a control command from the user interface of the device is only allowed if switching authority is set to LOCAL. • Switching Authority DIGSI: Switching commands can be issued locally or remotely via DIGSI. As part of the safety features, the device will check the DIGSI configuration file in regard to the virtual device number to ensure that the correct configuration file is used. DIGSI must have the same virtual device number. It is important that one file can not be reused with multiple relays. But it is possible to copy the file and use the new file with another relay. • Switching Authority REMOTE: When this interlocking check is enabled in the Object Properties dialog box, the status of Switching authority is checked prior to issuing a control command. If this particular setting is selected a control command from a remote DIGSI connection or via the system interface is only allowed if switching authority is set to REMOTE. An overview for processing the interlocking conditions in the relay is shown by Figure 2-135.

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Breaker Control

.

Switching Authority

Device with source of command = LOCAL

Switching Mode

ON/OFF

&

REMOTE1), DIGSI

Local

&

Local

AUTO

&

Switching Authority (LOCAL/REMOTE)

Rem.

Switch Authority DIGSI:

DIGSI

&

& DIGSI

OR &

Rem.

Switch mode LOCAL: (interlocked/non-interl.)

Non-interlocked

OR

SCHED. = ACT. y/n

& Switching mode REMOTE (interlocked/non-interl.)

Interlocked switching

&

Feedback ON/OFF Blocked by protection: 52 Close

OR

SCHED. = ACT y/n System interlock. y/n Bay interlock. y/n Protection blockingy/n Double oper. block.y/n Sw. Auth. LOCAL y/n Sw. Auth. REMOTEy/n

OR

Command output ro relay

52 Open

Event Condition

1)

Source REMOTE also includes SAS. (LOCAL Command using substation controller REMOTE Command using remote source such as SCADA through controller to device).

Figure 2-135 Standard Interlocking Arrangements

Figure 2-136 shows the settings for the interlocking conditions when using DIGSI® 4.

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Figure 2-136 DIGSI® 4 Dialog Box for Setting the Interlocking Conditions

The display shows the configured interlocking reasons. The are marked by letters explained in the following Table 2-21: Table 2-21

Interlocking Commands

Interlocking Commands

Abbreviation Message

Switching Authority

L

L

System Interlock

S

S

Zone Controlled

Z

Z

Target State = Present State (check switch position)

P

P

Block by Protection

B

B

Figure 2-137 shows all interlocking conditions (which usually appear in the display of the device) for three switchgear items with the relevant abbreviations explained in Table 2-21. All parametrized interlocking conditions are indicated (see Figure 2-137). . Interlocking 01/03 -------------------Q0 Close/Open S – Z P B Q1 Close/Open S – Z P B Q8 Close/Open S – Z P B Figure 2-137 Example of Configured Interlocking Conditions

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Control Logic using CFC

For Zone Controlled (field interlocking), control logic can be developed, using the CFC. Via specific release conditions the information “released” or “zone controlled” is available.

Switching Authority

Switching authority configures the relay to perform Local/Remote Supervisory functions. The command source having switching authority can be set in the interlocking condition “Switching authority”. The following switching authority ranges are defined in the following priority sequence: − LOCAL (commands are issued from the relay keyboard) − DIGSI® 4 − REMOTE (commands are issued from SCADA) The switching authority condition LOCAL allows commands from the user interface of the relay, but not remote or DIGSI commands. In the 7UM62, the options “Local” and “Remote” are available in the display after entering a password. The switching authority condition DIGSI allows commands to be initiated using DIGSI® 4. Commands are allowed for both a remote and a local DIGSI® 4 connection. When a (local or remote) DIGSI PC logs on to the device, it enters its Virtual Device Number (VD). The device only accepts commands having that VD (with switching authority = OFF or REMOTE). When the DIGSI PC logs off, the VD is cancelled. Commands are checked for their source and the device settings, and compared to the information set in the objects “Switching authority” and “Switching authority DIGSI”. Configuration Programming: 1) Switching authority: y/n

(create appropriate object)

2) Switching authority DIGSI® 4: y/n

(create appropriate object)

3) Specific object (e.g., switching device): Switching authority LOCAL (check for commands initiated locally via keypad): y/n 4) Specific object (e.g., switching device): Switching authority REMOTE (check for SAS, REMOTE, or DIGSI commands): y/n

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In detail, the following interlocking logic is derived when using default configuration settings: Current Switching Authority Status

Switching Authority DIGSI

Command Issued Locally

Command Issued from SAS or SCADA

Command Issued from DIGSI

LOCAL

Not checked

Allowed

Interlocked *2) - switching authority LOCAL

Interlocked ”DIGSI not checked”

LOCAL

Checked

Allowed



REMOTE

Not checked

Interlocked *1) Allowed - switching authority REMOTE

Interlocked ”DIGSI not checked”

REMOTE

Checked

Interlocked *1) Interlocked *2) - switching authority - switching authority DIGSI DIGSI

Allowed

*1) By-passes Interlock if Configuration for ”switching authority LOCAL (check for Local status): n” *2) By-passes Interlock if Configuration for ”switch authority REMOTE (check for CLOSE, REMOTE, or DIGSI status): “n” SC = Source of command

SC=AUTO: Commands that are initiated internally (command processing in the CFC) are not subject to switching authority and are therefore always allowed. Switching Mode

The switching mode determines whether selected interlocking conditions will be activated or deactivated at the time of the switching operation. The following switching modes are defined: − Local commands (SC=LOCAL) − interlocked, or − non-interlocked switching. The selection between local and remote is made in the 7UM62 using the local user interface. A password is required to make this selection. − Remote or DIGSI® 4 (SC=LOCAL, REMOTE or DIGSI) −interlocked, or − non-interlocked switching. Here, deactivation of interlocking is accomplished via a separate command. The position of the key switch is irrelevant. − Auto: For commands from CFC (SC = AUTO), the notes in the CFC handbook should be referred to (e.g. component: BOOL to command).

Zone Controlled/ Field Interlocking

306

Zone Controlled (field interlocking) includes the verification that predetermined switchgear position conditions are satisfied to prevent switching errors as well as verification of the state of other mechanical interlocking such as High Voltage compartment doors etc.

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Breaker Control

Interlocking conditions can be programmed separately, for each switching device, for device control CLOSE and/or OPEN. Processing of the status of the release condition for an operation switching device can be based on information acquired: − directly, using a single point or double point indication (binary inputs), key-switch, or internal indication (marking), or − with logic using CFC. When a switching command is initiated, the actual status of all relevant switching devices is scanned cyclically. Substation Controller (System Interlocking)

Substation Controller (System interlocking) involves switchgear conditions of other bays evaluated by a central control system.

Double Operation

Parallel switching operations are interlocked. When a control command is received, all objects that are subject to double operation inhibit are checked for control commands in progress. While the command is being executed, the inhibit is in turn active for all other commands.

Blocked by Protection

With this function, switching operations are blocked by the pickup of protective elements. Blocking is configurable separately for both closing and tripping commands. When configured, “Block CLOSE commands” blocks CLOSE commands, whereas „Block TRIP commands” blocks TRIP signals. Operations in progress will also be aborted by the pickup of a protective element.

Device Position (Scheduled = Actual)

For switching commands, a check takes place whether the selected switching device is already in the scheduled/desired position (Open/Closed; scheduled/actual comparison). This means, if a circuit breaker is already in the CLOSED position and an attempt is made to issue a closing command, the command will be refused, with the operating message ”scheduled condition equals actual condition”. If the circuit breaker/switchgear device is in the intermediate position, then this check is not performed.

Bypassing Interlocks

Interlocks can be bypassed to perform switching operations. This is either done internally by adding a bypass code to the command, or globally by so-called switching modes. G

SC=LOCAL

− The 7UM62 offers the options “interlocked“ or “non-interlocked“ (bypassed) in the display after entry of a password. G

REMOTE and DIGSI® 4

− Interlocks for commands issued by SICAM® or DIGSI® 4 are bypassed by a global switching mode REMOTE. A separate bypass command has to be issued for this. Each bypass is valid for only one switching operation, and only for commands originating from the same source. − Control: command to object “Switching mode REMOTE”, CLOSE − Control: switching command to “switching device” G

Derived commands from CFC (automatic command, SC=AUTO):

− Behaviour configured in the CFC block (“BOOL to command”).

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2.46.4 Recording and Acknowledgement of Commands During the processing of the commands, independent of the further message routing and processing, command and process feedback information are sent to the message processing centre. These messages contain message cause indication. The messages are entered in the event list. Acknowledgement of Commands to the Device Front

All messages which relate to commands that were issued from the device front “Command Issued = Local” are transformed into a corresponding response and shown in the display of the device. A list of possible responses and their meanings is given in the SIPROTEC® 4 System Manual.

Acknowledgement of commands to Local/Remote/Digsi

The messages which relate to commands with the origin “Command Issued = Local/ Remote/DIGSI” must be send independent of the routing (configuration on the serial digital interface) to the initiating point. The acknowledgement of commands is therefore not executed by a response indication as it is done with the local command but by ordinary command and feedback information recording.

Monitoring of Feedback Information

The processing of commands monitors the command execution and timing of feedback information for all commands. At the same time the command is sent, the monitoring time is started (monitoring of the command execution). This time controls whether the device achieves the required final result within the monitoring time. The monitoring time is stopped as soon as the feedback information arrives. If no feedback information arrives, a response “Timeout command monitoring time” appears and the process is terminated. 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 information, the command output resets. The “plus” appearing in a feedback information confirms that the command was successful, the command was as expected, in other words positive. The “minus” is a negative confirmation and means that the command was not fulfilled 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 chapter on configuration in the SIPROTEC® 4 System Manual. n

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Installation and Commissioning

3

This section 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 a power system. Installation of the 7UM62 is described in this section. Connections for the device are discussed. Hardware modifications that might be needed in certain cases are explained. Connection verifications required before the device is put in service are also given. Commissioning tests are provided. For primary testing, the protected object (generator, motor, transformer) must be started up and in put into service.

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Installation and Connections

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3.2

Checking Connections and System (Plant) Integration

336

3.3

Commissioning

346

3.4

Primary Commissioning Tests with the Generator

360

3.5

Final Preparation of the Device

391

309

3 Installation and Commissioning

3.1

Installation and Connections

Warning! Trouble free and safe use of this SIPROTEC® 4 device depends on proper transport, storage, installation, and application of the device according to the warnings in this instruction manual. Of particular importance are the general installation and safety regulations for work in a high-voltage environment (for example, ANSI, IEC, EN, DIN, or other national and international regulations.) These regulations must be observed. Failure to observe these precautions can result in death, personal injury, or severe damage of property.

Requirements

3.1.1

Installation

Panel Flush Mounting

310

Verification of the 7UM62 according to the SIPROTEC® 4–System Manual and the connected external equipment must have been carried out.

The device housing can be 1/2 or 1/1 full size depending on the version. For the 1/2 size housing, there are four covers and four holes, as shown in Figure 3-1. There are six covers and six holes for the full size housing, as indicated in Figure 3-2. G

Remove the four covers on the corners of the front cover, for the 1/1 size housing also the 2 covers in the top and bottom center. Four or six elongated holes in the mounting angle strips become accessible.

G

Insert the device into the panel cutout and fasten with four or six screws. Refer to Figure 4-14 or 4-15 in Section 4.28 for dimensions.

G

Replace the four or six covers.

G

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-sectional area of the ground wire must be at least AWG 13.

G

Connect the plug terminals and/or the threaded terminals on the rear side of the device according to the elementary diagram for the panel. When using spade lugs or directly connecting wires to threaded 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 centered in the connection chamber so that the screw thread fits in the hole of the lug. SIPROTEC® 4 System Manual has pertinent information regarding wire size, lugs, bending radii (optical cables), etc.

7UM62 Manual C53000-G1176-C149-3

3.1 Installation and Connections

Elongated Holes

SIPROTEC

SIEMENS RUN

ERROR

MAIN MENU

7UM621

01/04

Annunciations Measured values

1 2

MENU

AnnunciationsF1

7

8

9

Measured values F2

4

5

6

1

2

3

0

+/-

Alarm

F3 F4

Figure 3-1

Elongated Holes

ENTER

ESC

LED

Panel Mounting of a 7UM621 with 1/2 Size Housing

SIPROTEC

SIEMENS RUN

ERROR

MAIN MENU

7UM622

01/04


1 2

MENU

AnnunciationsF1

7

8

9

Masured values F2

4

5

6

1

2

3

0

+/-

Alarm

F3 F4

Figure 3-2

7UM62 Manual C53000-G1176-C149-3

ENTER

ESC

LED

Panel Mounting of a 7UM622 with Full Size Housing

311


Rack Mounting

For the 1/2 size housing shown in Figure 3-3, four covers and four fastening holes are provided. On a device in full size housing there are six covers and six fastening holes, as shown in Figure 3-4. Two mounting brackets are necessary to install the 7UM62 in a rack. The order number for the brackets is given in the Appendix, Sub-section A.1. G

Loosely screw the two mounting brackets in the rack or cubicle with four screws.

G

Remove the four covers on the corners of the front cover of the device, on the 1/1 size housing also the 2 covers in the top and bottom center. Four or six elongated holes in the mounting angle strips become accessible.

G

Fasten the device to the mounting brackets with four or six screws.

G

Replace the four or six covers.

G

Tighten the mounting brackets to the rack using eight screws.

G

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-sectional area of the ground wire must be at least AWG 13.

Mounting Bracket

SIPROTEC

SIEMENS RUN

ERROR

7UM621

TRIP PICKUP PICKUP L1 PICKUP L2 PICKUP L3 PICKUP GND

MAIN MENU

01/04

Annunciation Measurement

1 2

Device faulty MENU

ENTER

ESC

LED

Event Log

F1

7

8

9

Operation. F2 Pr

4

5

6

1

2

3

0

+/-

Trip Log Reset Min/Max

F3 F4

Mounting Bracket

Figure 3-3

312

Installing a 7UM621 (1/2 Size Housing) in a Rack or Cubicle

7UM62 Manual C53000-G1176-C149-3


SIPROTEC

SIEMENS RUN

ERROR

MAIN MENU

7UM622

01/04


1 2

MENU

AnnunciationsF1

7

8

9

Masured values F2

4

5

6

1

2

3

0

+/-

Alarm

F3 F4

Figure 3-4

ENTER

ESC

LED

Installing a 7UM621 (1/1 Size Housing) in a Rack or Cubicle

Panel Surface Mounting

7UM62 Manual C53000-G1176-C149-3

G

Connect the plug terminals and/or the threaded terminals on the rear side of the device according to the elementary diagram for the rack. When using spade lugs or directly connecting wires to threaded 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 centered in the connection chamber so that the screw thread fits in the hole of the lug. SIPROTEC® 4 System Manual has pertinent information regarding wire size, lugs, bending radius (fiber cables), etc.

G

Secure the device to the panel with four screws. Refer to Figure 4-16 and 4-17 in Section 4.35 for dimensions.

G

Connect the ground of the device to the protective ground of the panel. The crosssectional area of the ground wire must be greater than or equal to the crosssectional area of any other control conductor connected to the device. Furthermore, the cross-sectional area of the ground wire must be at least AWG 13.

G

Solid, low impedance operational grounding (cross-sectional area ≥ AWG 13) must be connected to the grounding surface on the side. Use at least one M4 screw for the device ground.

G

Connect the threaded terminals on the top and bottom of the device according to the elementary diagram for the panel. SIPROTEC® 4 System Manual has pertinent information regarding wire size, lugs, bending radius (fiber cable), etc.

313


3.1.2

Connections Overview diagrams are shown in Appendix A.2. CT and VT connections for a 7UM62 are shown in the Appendix, Section A.4. Make sure that the settings of the Power System Data 1 (Section 2.3) match the connections.

Currents/Voltages

Overview diagrams are shown in the Appendix. Figures and A-27 show examples of current transformer circuit connections with busbar connection (address 0272 SCHEME = Busbar), Figures A-28 and A-29 with unit connection (address 0272 = Unit transf.). In all examples the CT starpoints point towards the machine; therefore, address 0201 STRPNT->OBJ S1 and 0210 STRPNT->OBJ S2 must be set to Yes. In Figures to A-28, the UE input of the device is connected to the open delta winding of a voltage transformer set. Consequently, address 0223 must be set to UE CONNECTION = delta winding. Figure is the standard connection where one busbar is fed by several generators. As the earth fault current can be increased by an earthing transformer connected to the busbar (approx. 10 A max.), a protection range of up to 90 % can be achieved. To achieve the necessary sensitivity, the earth fault current is measured using a toroidal current transformer. During startup of the machine, the displacement voltage can be used as a criterion for detecting an earth fault until synchronization is completed. Factor 0213 FACTOR IEE2 considers the transformation ratio between the primary and the secondary side of the summation current transformer when the sensitive current input of side 2 in Figure is used. Likewise, factor 0205 FACTOR IEE1 applies when the input of side 1 is used. Example: Summation current transformer 60 A/1 A Matching factor for sensitive earth fault current detection: FACTOR IEE2 = 60 (if the input on side 2 is used) If the sensitive current input of side 1 is used for rotor earth fault current detection (as suggested in ), FACTOR IEE1 = 1 is chosen. In Figure A-27 the generator starpoint has a low-resistance earthing. To avoid circulating currents (3rd harmonics) in multi-generator connections, the resistor should be connected to only one generator. For selective earth fault detection, the sensitive earth fault current input IEE2 is looped into the common return line of the two sets of CTs (current differential measurement). The current transformers are earthed in one place only. FACTOR IEE2 is set to = 1. It is recommended to use for this type of circuit current transformers that are balanced to one another (turns correction). In Figure A-28 the earth fault is detected by means of the displacement voltage. A loading resistor is provided on the broken delta winding to avoid spurious tripping in case of earth faults occurring in the power system. The UE input of the device is connected via a voltage divider to the broken delta winding of an earthing transformer (address 0223 UE CONNECTION = delta winding). Factor 0225A Uph / Udelta is determined by the transformation ratio of the secondary-side voltages: U N prim. U N sec. U N sec. -------------------- ⁄ ------------------ ⁄ -----------------3 3 3

314

7UM62 Manual C53000-G1176-C149-3


The resulting factor between the secondary windings is 3/√3 = 1.73. For situations where the displacement voltage is measured by the device and other types of voltage transformer connections are utilized, the setting of address 0225A should be modified accordingly. Factor 0224 FACTOR UE considers all of the transformation ratios between the primary voltage and the voltage fed to the device terminals, i.e. it includes the voltage divider that is connected upstream. For a primary nominal transformer voltage of 6.3 kV, a secondary voltage of 500 V in case of full displacement and a voltage divider ratio of 1:5, this factor would be: 6.3 kV ⁄ ( 3 ) 5 FACTOR UE = æè --------------------------------- ⋅ ---öø = 36.4 500 V 1 For additional hints, please refer to section 2.3 under “Transformation Ratio UE“. In Figure A-29 a loading resistor connected to the generator c.t. reduces the interference voltage from network-side earth faults. The maximum earth fault current is limited to approx. 10 A. The resistor can be a primary or secondary resistor with neutral earthing transformer. The neutral earthing transformer should have a low transformation ratio to avoid a small secondary resistance. The resulting higher secondary voltage can be reduced by means of a voltage divider. Address 0223 UE CONNECTION is set to Neutral transformer. Figure A-30 shows the connection of the DC voltage protection for systems with startup converter. The amplifier 7KG6 amplifies the signal measured at the shunt to a maximum of 10 V or 20 mA, depending on the connected equipment. Input TD1 can be adapted to the type of signal (voltage or current) by means of wire jumpers (see also 3.1.3.3 “Switching Elements on Printed Circuit Boards”). Figure A-31 shows in an exemplary way how the rotor earth fault protection is connected to a generator with static excitation. The earthing must be connected to the earthing brush. The coupling device 7XR61 must be complemented by the external resistors 3PP1336 if the circulating current is apt to exceed 0.2 A due to the 6th harmonic component in the excitation voltage. This can be the cause with excitation voltages UExc of 150 V and higher. The IEE 1 input evaluates the earth fault current flowing between the rotor and the ground as a result of injecting a voltage into the rotor circuit by means of the additional source device 7XR61. The matching factor FACTOR IEE1 is set to = 1.0. Figure A-34 shows how a connection is made with only two plant-side voltage transformers in open delta connection (V connection). Figure A-33 shows a typical connection of the protection relay to a large asynchronous motor. The voltages for voltage and zero voltage monitoring are usually picked up at the busbar. Where several motors are connected to the busbar, the directional earth fault protection allows to detect single-pole earth faults and thus to open breakers selectively. A toroidal transformer is used for detection of the earth fault current. Factor 0213 FACTOR IEE2 considers the transformation ratio between the primary and the secondary side of the summation current transformer IEE 2. Binary Inputs and Outputs

The masking options for the binary inputs and outputs, i.e. the procedure for matching the 7UM62 to the individual plant, are described in the SIPROTEC® 4 System Manual. The tables of section A.9 in the Appendix show the allocation of all binary inputs and outputs and of the LEDs to physical outputs when the device is delivered from the factory. Please check also the conformity of the front panel labeling strips with the actually configured signaling functions.

7UM62 Manual C53000-G1176-C149-3

315


Changing Setting Groups with Binary Inputs

If binary inputs are used to switch setting groups, please observe the following: • If the configuration is performed from the operator panel or using DIGSI® 4, the address 0302 CHANGE must be set to the option Binary Input. • One binary input must be dedicated for the purpose of changing setting groups when two groups are to be switched. This input is named “>Set Group Bit 0”. • The logical binary input must be allocated to a physical input module in order to allow control. An input is treated as not energized when it is not assigned to any physical input. • If the binary input is configured as a make circuit, i.e. as active when voltage is applied (H active), the setting groups are assigned as follows: – not energized: Setting group A – energized: Setting group B • The status of the signal controlling the binary input to activate a particular setting group must remain constant as long as that particular group is to remain active.

Trip Circuit Monitoring

A circuit with two binary inputs (see Figure 2-121) is recommended for trip circuit monitoring. The binary inputs must have no common potential, and their operating point must be sensible less than half the rating of the DC control voltage. When using only one binary input, a resistor R is inserted into the circuit on the system side, instead of the missing second binary input (see Figure 2-124). Please note that the response times are as long as approx. 300 s. Section 2.39.2 shows how the resistance is calculated.

3.1.3

Hardware Modifications

3.1.3.1

General Hardware adjustments might be necessary or desired. For example, a change of the pickup threshold for some of the binary inputs might be advantageous in certain applications. Terminating resistors might be required for the communication bus. In either case, hardware modifications are needed. The modifications are done with jumpers on the printed circuit boards inside the 7UM62. The hints given in Sections 3.1.3.2 to 3.1.3.5 should be observed in any case whenever hardware modifications are made.

Power Supply Voltage

There are different ranges for the input voltage of the various power supplies. Refer to the data for the 7UM62 ordering numbers in Section A.1 of the Appendix. The power supplies with the ratings [60/110/125 VDC] and [110/125/220/250 VDC 115 VAC] are interchangeable. Four jumper settings determine the rating. The settings necessary to convert one range to the other are provided below in Sub-section 3.1.3.3, under the side title “Processor Printed Circuit Board C–CPU–2”. When the device is delivered, these jumpers are set according to the name-plate sticker. Typically, these settings are not changed.

Live Status Contact

The contacts of the live status (alarm) relay connected to terminals F3 and F4 of the device can be either normally closed or normally open. The choice is made with the setting of jumper X40. The appropriate setting of the jumper for the contact type desired, and the location of the jumper on the printed circuit board, are described below in “Processor Printed Circuit Board C–CPU–2“.

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7UM62 Manual C53000-G1176-C149-3


Nominal Currents

The rating of the current input transformers of the device can be changed to 1 A or 5 A with jumper settings that determine the secondary loading of the transformers. When the device is delivered, these jumpers are set according to the name-plate sticker. The physical arrangements of these jumpers that correspond to the different current ratings are described below, Subsection 3.1.3.3 “C-I/O–2 Input/Output Board” for side 1 and „C-I/O–6 Input/Output Board“ for side 2. All the relevant jumpers of one side must be in the same position, i.e. there must be one of the jumpers X61 through X64 for each of the input transformers and additionally the common jumper X60. If nominal current ratings are changed, then the new ratings must be altered under Addresses 203 IN-SEC I-SIDE1 or 0212 IN-SEC I-SIDE2 in the Power System Data1 (see Sub-section 2.3). Note: The jumper settings must correspond to the secondary device currents configured at addresses 0203 and 0212. If they do not, the device is blocked and outputs an alarm.

Control Voltages for Binary Inputs

When the device is delivered from the factory, the binary inputs are set to operate with a DC control voltage that corresponds to the rated DC voltage of the power supply. In general, to optimize the operation of the inputs, the pickup voltage of the inputs should be set to most closely match the actual control voltage being used. In some cases such as the one described in the note below, lowering the pickup voltage might be necessary. 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 physical arrangement of the binary input jumpers in relation to the pickup voltages is explained below, Sub-section 3.1.3.3. Note: If the 7UM62 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.

Changeover Contacts

Input/output modules can have relays that are equipped with changeover contacts. The device terminals can be connected to either the NC or the NO contact; the choice is made by jumpers. The relays and cards for which this applies are stated in Section 3.1.3.3 under the side titles "C–I/O–2 Input/Output Board" and "C–I/O–6 Input/Output Board".


The measuring transducers TD 1 (e.g. for DC voltage/DC current protection) and TD 2 (e.g. for input of the temperature for the overload protection) allow to select whether voltages or currents will be processed as input quantities. To change the default setting (measured quantities will be voltages), a few jumpers must be moved. An overview of the jumper settings is given in the Tables 3-14 and 3-15 in Section 3.1.3.3 under the side title “C–I/O–6 Input/Output Board“.

7UM62 Manual C53000-G1176-C149-3

317


Caution! If the jumpers are set to “current” input, connection of a voltage may destroy the board! For measuring transducer TD 3 (detects e.g. the excitation voltage for the underexcitation protection) an analog low-pass can be activated or deactivated; the choice is made by jumpers. For more information see Table 3-16 in Section 3.1.3.3 under the side title “C–I/O–6 Input/Output Board“. Note: The jumper settings must correspond to the mode set at addresses 0295, 0296 (voltage or current input) and 0297 (with/without filter). If they do not, the device is blocked and outputs an alarm.

Exchanging Interfaces

The serial interfaces can only be exchanged in the versions for panel flush mounting and cubicle mounting. Which interfaces can be exchanged, and how this is done, is described in Section 3.1.3.4 under the side title “Exchanging Interface Modules“.

Terminating Resistors for RS485 and Profibus DP (Electrical)

For reliable data transmission, an RS 485 bus or the electrical Profibus DP should be terminated with resistors at the last device on the bus. The printed circuit boards (p.c.b.) of the C–CPU–2 processor module and of the RS485 or Profibus interface module are equipped for this purpose with terminating resistors that are switched in by means of jumpers. Only one of the three possibilities may be used. The physical location of the jumpers on the p.c.b. is described in Section 3.1.3.3 under the side title “Processor Printed Circuit Board C–CPU–2“ for the C–CPU–2 processor module, and in Section 3.1.3.4 under the side title “Serial Interfaces with Bus Capability“ for the interface modules. Both jumpers must always have the same setting. As delivered from the factory, the resistors are switched out.

Spare Parts

3.1.3.2

Spare parts can be the battery that provides for storage of the data in the batterybuffered RAM in case of a power failure, and the miniature fuse of the internal power supply. Their physical location is shown in Figure 3-7. The ratings of the fuse are printed on the board next to the fuse itself. When exchanging the fuse, please observe the hints given in the SIPROTEC®4 System Manual in the chapter “Maintenance”.

Disassembling the Device Important! It is assumed for the following steps that the device is not operative. To perform work on the printed circuit boards, such as checking or moving switching elements or exchanging modules, the buffer battery or the miniature fuse, proceed as follows:

318

7UM62 Manual C53000-G1176-C149-3


Caution! Jumper-setting changes that affect nominal values of the device render the ordering number and the corresponding nominal values on the nameplate sticker invalid. If such changes are necessary, the changes should be clearly and fully noted on the device. Self adhesive stickers are available that can be used as replacement nameplates.

o

The following equipment is needed: − Grounded mat for protecting components subject to damage from electrostatic discharges (ESD). − Screwdriver with a 6 mm wide tip, − #1 Philips screwdriver, − 4.5 mm socket or nut driver.

o o o o

Unfasten the screw-posts of the D-subminiature connector on the back panel at location “A” and “C”. This activity does not apply if the device is for surface mounting. If the device has more communication interfaces at locations “B” and/or “D” on the rear, the screws located diagonally to the interfaces must be removed. This activity does not apply if the device is for surface mounting. Remove the four corner caps on the front cover and loosen the screws that become accessible. Carefully pull off the front cover. The front cover is connected to the CPU board with a short ribbon-cable.

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. Do not insert or remove the port plugs under live conditions!

o o o o

At one end, disconnect the ribbon-cable between the front cover and the CPU board (). To disconnect the cable, push up the top latch of the plug connector and push down the bottom latch of the plug connector. Carefully pull off the front cover. Disconnect the ribbon-cables between the C-CPU-2 board () and the I/O boards ( to , depending on the variant ordered). Remove the boards and set them on the grounded mat to protect them from ESD damage. A greater effort is required to withdraw the CPU board, especially in versions of the device for surface-mounting, because of the communication connectors. Check the jumpers according to Figures 3-7 to 3-11, and Tables 3-1 to 3-8. Change or remove the jumpers as necessary. The locations of the printed circuit boards are shown in Figures 3-5 (for 1/2 Size Housing) and 3-6 (for Full Size Housing).

7UM62 Manual C53000-G1176-C149-3

319


1 3 4

Slot 5

Slot 19

Slot 33

1

4

3

C-CPU-2 Processor p.c.b. C-I/O-2 Input/Output p.c.b. C-I/O-6 Input/Output p.c.b.

BI1 to BI5

BI6 and BI7

Binary Inputs (BI)

Figure 3-5

7UM621: Front View (1/2 Size Housing) after Removing the Front Cover (Simplified and Reduced)

1 2 3 4 1

42 1

Slot 5 1

BI1 to BI5 Figure 3-6

320

Slot 19

42

Slot 33

Slot 19

Slot 33

4

2

3

BI6 and BI7

BI8 to BI15

C-CPU-2 Processor p.c.b. C-I/O-1 Input/Output p.c.b. C-I/O-2 Input/Output p.c.b. C-I/O-6 Input/Output p.c.b.

Binary Inputs (BI)

7UM622: Front View (Full Size Housing) after Removing the Front Cover (Simplified and Reduced)

7UM62 Manual C53000-G1176-C149-3


Switching Elements on Printed Circuit Boards The layout of the p.c.b for the C–CPU–2 processor module is shown in Figure 3-7. Check the provided nominal voltage of the integrated power supply according to Table 3-1, the non-energized position of the live status contact (jumper X40 according to Table 3-2), the selected pickup voltages of the binary inputs BI1 through BI5 according to Table 3-3 and of the integrated RS232/RS485 interface according to Tables 3-4 through 3-6. The location and ratings of the miniature fuse (F1) and of the buffer battery (G1) are shown in Figure 3-7.

3

Processor Printed Circuit Board C–CPU–2

2 1 X51

3.1.3.3

Fuse F1

24/48V DC T4H250V

321 321 X105

321

3 2 1 X103 X109

123

X90

1 2 3

X111 X110 X108

X107

1 2 3

X104 X106

X25 4 3 2 1 4 3 X24 2 1 4 3 2 1 X23

1

2

3 4

X52

X22 4 3 2 1 4 3 2 1 X21

X55

1 2

3

2

1 2 3 X53

1

X40

60-250V DC/115 V AC T2H250V

Cable binder Lithium battery 3 V/1 Ah, Type CR 1/2 AA

–

+

Battery

G1

Figure 3-7

7UM62 Manual C53000-G1176-C149-3

C-CPU–2 Board Showing the Jumpers for the Power Supply, Binary Inputs BI1 To BI5 and the Battery and Miniature Fuse (Simplified)

321


Table 3-1

Jumper Settings for the Nominal Voltage of the Integrated Power Supply on the C–CPU–2 Board

Jumper 60/110/125 VDC

Nominal Voltage 110/125/220/250 VDC 115 VAC

X51

1–2

2–3

X52

1–2 and 3-4

2–3

X53

1–2

2–3

X55

not used

1–2

24/48 VDC

Jumpers X51, X52, X53 and X55 are not used

Can be interchanged

Table 3-2

Not changeable

Jumper Settings for the Non-Energized Position of the Live Status Contact on the C–CPU–2 Board

Jumper

Non-Energized Position Open

Non-Energized Position Closed

Factory Setting

X40

1–2

2–3

2–3

Table 3-3

Jumper Settings for the Pickup Voltages of the Binary Inputs BI1 through BI5 on the C–CPU–2 Board

Binary Input

Jumper

17 VDC Pickup1)

73 VDC Pickup2)

BI1

X21

1–2

2–3

BI2

X22

1–2

2–3

BI3

X23

1–2

2–3

BI4

X24

1–2

2–3

BI5

X25

1–2

2–3

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 VDC to 220 VDC and 115 VAC.

The R485 interface can be converted into an RS232 interface by modifying the setting of the appropriate jumpers. Jumpers X105 through X110 must be set on the same position. Table 3-4

Jumper Settings of the Integrated RS232/RS485 Interface on the C–CPU–2 Board

Jumper

RS232

RS485

X103 and X104

1–2

1–2

X105 to X110

1–2

2–3

On delivery the jumpers are always set according to the configuration ordered.

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7UM62 Manual C53000-G1176-C149-3


With jumper X111, CTS is activated which is necessary for the communication with the modem. Table 3-5

Jumper setting of CTS (Clear-To-Send) on the processor printed circuit board C-CPU-2

Jumper

/CTS of interface RS232

/CTS controlled by /RTS

X111

1–2

2–3 *)

*) default setting in releases from 7SA6...../CC to date Jumper setting 2–3: the connection to the modem is usually done with star coupler or optical fibre converter. Therefore the modem control signal according to RS232 standard DIN 66020 is not available. Modem signals are not required since communication to SIPROTEC® devices is always carried out in the half duplex mode. Use connetion cable with ordering number 7XV5100–4. Jumper setting 1–2: this setting makes the modem signal available, i. e. for a direct RS232-connection between the SIPROTEC® 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). Note: For a direct connection to DIGSI® 4 with interface RS232 jumper X111 must be plugged in position 2–3. If there are no external matching resistors in the system, the last devices on a RS485-bus must be configured via jumpers X103 and X104.

Table 3-6

Jumper Settings Relating to the Terminating Resistors of the RS485 Interface on the C–CPU–2 Board

Jumper

Terminating Resistor Connected

Terminating Resistor Disconnected

Factory Set

X103

2–3

1–2

1–2

X104

2–3

1–2

1–2

Note: Both jumpers must always be set for the same position.

Jumper X90 has currently no function. The factory setting is 1–2. Terminating resistors can also be implemented outside the device (e.g. in the plug connectors). In that case the terminating resistors provided on the interface card or on the C–CPU–2 card must be switched out.

7UM62 Manual C53000-G1176-C149-3

323


+5 V 390 Ω A/A´ 220 Ω B/B´ 390 Ω

Figure 3-8

324

Terminating Resistors (External)

7UM62 Manual C53000-G1176-C149-3


The layout of the p.c.b for the C–I/O–1 board is shown in Figure 3-9.

X40

C–I/O–1 Input/ Output Board

LMH

X36 X35

LMH

X34 X33

LMH

H L

LMH

(AD2) (AD1) (AD0)

X32 X31

X73 X72 X71

X30 X29

LMH

X28 X27

LMH

X26 X25

LMH

X24 X23

LMH

X22 X21

1 2 3

Figure 3-9

7UM62 Manual C53000-G1176-C149-3

Jumpers on the C–I/O–1 Board for the Binary Inputs BI8 to BI15 (Simplified)

325


In the version 7UM622, the contact type can be changed for one specific relay (BO13) from normally open to normally closed (see overview diagrams in section A.2 of the Appendix). Table 3-7

Jumper Settings for the Contact of Relay R13 (Binary Output BO 13)

Jumper Non-Energized Position Open (NO Contact) X40

Table 3-8

Non-Energized Position Closed (NC Contact)

Factory Setting

2–3

1–2

1–2

Factory Jumper Settings for the Pickup Voltages of the Binary Inputs BI 8 through BI 15 on the C–I/O–1 board of the 7UM622

Binary Input

Jumper

17 VDC Pickup1)

73 VDC Pickup2)

BI 8

X21/X22

L

M

BI 9

X23/X24

L

M

BI 10

X25/X26

L

M

BI 11

X27/X28

L

M

BI 12

X29/X30

L

M

BI 13

X31/X32

L

M

BI 14

X33/X34

L

M

BI 15

X35/X36

L

M

1

) Factory settings for devices with power supply voltages of 24 VDC to 125 VDC. Factory settings for devices with power supply voltages of 110 VDC to 220 VDC and 115 VAC.

2)

Bus Address

Jumpers X71, X72 and X73 on the I/O-1 board are used to set the bus address and must not be changed. Table 3-9 shows the factory setting of the jumpers. The physical location of the modules is shown in Figures 3-5 and 3-6. Table 3-9

326

Factory Jumper Setting on the C–I/O–1 Board of the 7UM622

Jumper

Factory Setting

X71

L

X72

H

X73

H

7UM62 Manual C53000-G1176-C149-3



X41 3 2 1


(AD1) (AD2)

5A 3 2 1A 1 X61

5A 3 2 1A 1 X60

3 3 L 2 2 1 1 H X71 X72 X73

(AD0)

T5

X62 1A 1 2 5A 3

T6

Figure 3-10

5A 3 2 1A 1 X64

T8

X63 1A 1 2 5A 3

T7

C–I/O–2 board Showing the Jumpers Settings to be Checked

For one specific relay (BO 6) the contact type can be changed from normally open to normally closed (see overview diagrams in section A.2 of the Appendix):

Table 3-10

7UM62 Manual C53000-G1176-C149-3

Jumper Settings for Choosing the Contact Type of Binary Output BO 6 on the C–I/O–2 Board

Jumper

NO Contact

NC Contact

Factory Setting

X41

1–2

2–3

1–2

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The rated current settings of the input current transformers are checked on the C–I/O–2 board. All jumpers must be in the same position, i.e. there must be one jumper each (X61 to X64) for each of the input transformers, and the common jumper X60. However: In the version with sensitive earth fault current input (input transformer T8) there is no jumper X64.

Jumpers X71, X72 and X73 on the C–I/O-2 board are used to set the bus address and must not be changed. Table 3-11 shows the factory setting of the jumpers. Table 3-11

328

Factory Jumper Setting on the C–I/O–2 Board

Jumper

Factory Setting

X71 (AD0)

1–2 (H)

X72 (AD1)

1–2 (H)

X73 (AD2)

2–3 (L)

7UM62 Manual C53000-G1176-C149-3




X21 LMH 1 2 3

L MH

1 X41 2 3

X22

X42

X95

1 2 3

X93

1 2 3

X91

1 2 3

X60 1A 5A

1 2 3

U 21 I 3 X94

UI

1 2 3

1 2 3

X69

X68

X67 U I

1 2 3

U 21 I 3 X92 X61 1A 5A 1 2 3

T9

(AD1) (AD0)

1 1A 2 3 5A X62

3 3 L 2 2 1 1 H X73 X72 X71

T10

(AD2)

T11

T8 X64 1A 5A 1 2 3

1 1A 2 3 5A X63

Figure 3-11

C–I/O–6 board Showing the Jumpers Settings to be Checked

Table 3-12

Factory Jumper Settings for the Pickup Voltages of the Binary Inputs BI 6 and BI 7 on the C–I/O–6 board

1

Binary Input

Jumper

17 VDC Pickup1)

73 VDC Pickup2)

BI 6

X21

L

M

BI 7

X22

L

M

) Factory settings for devices with power supply voltages of 24 VDC to 125 VDC. Factory settings for devices with power supply voltages of 110 VDC to 220 VDC and 115 VAC.

2)

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329


For two specific relays (BO 11 and BO 12) the contact type can be changed from normally open to normally closed (see overview diagrams in section A.2 of the Appendix):

Table 3-13

Jumper Settings for Choosing the Contact Type of Binary Outputs BO 11 and BO 12 on the C–I/O–6 Board

Binary Output

Jumper

NO Contact

NC Contact

Factory Setting

BO 11

X41

1–2

2–3

1–2

BO 12

X42

1–2

2–3

1–2

The rated current settings of the input current transformers are checked on the C–I/O–6 board. All jumpers must be in the same position, i.e. there must be one jumper each (X61 through X64) for each of the input transformers, and the common jumper X60. However: In the version with sensitive earth fault current input (input transformer T8) there is no jumper X64.

Table 3-14

Jumper Settings for the Input Characteristic (U/I) of Measuring Transducer 1

Jumper

Voltage Input ±10 V

Current Input (4–20/20 mA)

Factory Setting

X94

1–2

2–3

1–2

X95

1–2

2–3

1–2

X67

1–2

2–3

1–2

Table 3-15

Jumper Settings for the Input Characteristic (U/I) of Measuring Transducer 2

Jumper

Voltage Input ±10 V

Current Input (4–20/20 mA)

Factory Setting

X92

1–2

2–3

1–2

X93

1–2

2–3

1–2

X68

1–2

2–3

1–2

Caution! If the jumpers are set to “current” input, connection of a voltage may destroy the board!

Table 3-16

Jumper

Low-Pass Filter Inactive

Low-Pass Filter Active

Factory Setting

X91

1–2

2–3

2–3

X69

1–2

2–3

2–3

*

330

Jumper Settings for Activating/Deactivating the 10 Hz Low-Pass Filter of Measuring Transducer 3 *

Measuring transducer 3 has only a voltage input (± 10 V)

7UM62 Manual C53000-G1176-C149-3


Note: The jumper settings must correspond to the mode set at addresses 0295, 0296 (voltage or current input) and 0297 (with/without filter). If they do not, the device is blocked and outputs an alarm. After any changes to the jumper settings, you should therefore immediately change the corresponding parameter settings using DIGSI® 4. Jumpers X71, X72 and X73 on the I/O-6 board are used to set the bus address and must not be changed. Table 3-17 shows the factory setting of the jumpers.

Table 3-17

Factory Jumper Setting on the I/O-6 Board

Jumper

Factory Setting

X71 (AD0)

1–2 (H)

X72 (AD1)

2–3 (L)

X73 (AD2)

1–2 (H)

Note: Measuring transducers that are not used should be shorted at the input terminals.

7UM62 Manual C53000-G1176-C149-3

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3.1.3.4

Interface Modules

Exchanging Interface Modules

The interface modules are located on the C–CPU–2 board ( in Figure 3-5 and 3-6). Figure 3-12 shows the p.c.b. with the location of the modules.

Mounting position (rear of housing)

Analog output

D

System interface or analog output

B

Figure 3-12

C–CPU–2 board with Interface Modules

Please observe the following: • The interface modules can only be exchanged in devices for panel flush mounting and cubicle mounting. Devices for panel surface mounting with two-tier terminals can only be converted in the factory. • You can fit only those interface modules that are also part of the standard configurations of the device as specified in the Ordering Data in the Appendix A.1.

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7UM62 Manual C53000-G1176-C149-3


Table 3-18

Exchange Interface Modules

Interface

Location

Exchange Module RS232 RS485 FO 820 nm Profibus DP RS485

System Interface

Profibus DP twin ring B Modbus RS485 Modbus 820 nm DNP3.0, RS485 DNP3.0, 820 nm

Analog Interface

2 x 0 to 20 mA RS232

Service InterfaceT

C RS485

Analog Interface

D

2 x 0 to 20 mA

The order numbers of the exchange modules can be found in the Appendix in Section A.1.1 Accessories.

Serial Interfaces with Bus Capability

If the device variant used has interfaces with bus capability, the bus should be terminated with resistors at the last device on the bus. In the case of the 7UM62, these are variants with RS485 or Profibus interfaces. The terminating resistors are located on the RS485 or Profibus interface module, which is on the C–CPU–2 board ( in Figure 3-5 and 3-6), or directly on the p.c.b. of the CPU–2 board (see Section 3.1.3.3 under the side title “Processor Printed Circuit Board C–CPU–2“, Table 3-6). Figure 3-12 shows a view of the C–CPU–2 board with the location of the modules. The module for the RS485 interface is shown in Figure 3-13, the module for the Profibus interface in Figure 3-14. On delivery the jumpers are set so that the terminating resistors are switched out. Both jumpers of a module must be set on the same position.

7UM62 Manual C53000-G1176-C149-3

333


1 2 3 8X

X3 X6 X7 X4 X5

1 2 3

Terminating Resistors

X12

Jumper Disconnected

2–3

1–2*)

X10 1 2 3

X4

2–3 *)

Figure 3-13

1 2 3

1–2*) Factory Set

X13

X3

1 2 3

X11

Connected

1 2 3 1 2 3

C53207A324-B180

Location of the Jumpers for Configuring the Terminating Resistors of the Interface

C53207-A322-

2 3 4 B100 B101

Terminating Resistors Jumper Connected

Disconnected

X3

1–2

2–3*)

X4

1–2

*)

2–3 *)

Figure 3-14

X4

3 2 1

3 2 1 X3

Factory Set

Location of the Jumpers for Configuring the Profibus–Interface Terminating Resistors

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/Profibus interface module or directly on the C-CPU-2 board card must be switched out (refer Figure 3-8). In that case the terminating resistors provided on the RS485/Profibus interface module or directly on the C-CPU-2 board card must be switched out. RS232 can be changed to RS485 and vice versa by setting the jumpers on the interface cards. Figure 3-13 shows the physical location of the jumpers. Table 3-19 shows which jumper settings are associated to RS232 and RS485 respectively. When the device is delivered from the factory, the jumper setting corresponds to the configuration ordered and need not be changed. Table 3-19

Configuration of Jumpers for RS 232 or RS 485 on the Interface Card

Jumper

X5

X6

X7

X8

X10

X11

X12

X13

RS 232

1–2

1–2

1–2

1–2

1–2

2–3

1–2

1–2

RS 485

2–3

2–3

2–3

2–3

2–3

2–3

1–2

1–2

Jumpers X5 through X10 must be set on the same position!

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7UM62 Manual C53000-G1176-C149-3


Analog Output

The AN20 analog output board (see Figure 3-15) has 2 floating channels with a current range of 0 to 20 mA (unipolar, max. 350 Ω). The location on the C–CPU–2 board is “B” or/and “D” depending on the variant ordered (see Figure 3-12).

Figure 3-15

3.1.3.5

AN20 Analog Output Board

To Reassemble the Device:

o

o o o o o o o

7UM62 Manual C53000-G1176-C149-3

Carefully insert the boards into the case. The installation locations of the boards are shown in Figures 3-5 and 3-6. For the model of the device designed for surfacemounting, use the metal lever to insert the C–CPU–2 board. The installation is easier with the lever. By first attaching to the I/O board(s), connect the ribbon cable between the I/O board(s) and the C–CPU–2 board. Be especially careful not to bend any of the connector pins! Do not use any force! Be sure that the plug connectors latch. Connect the ribbon cable between the C–CPU–2 board and the front cover. Be especially careful not to bend any of the connector pins! Do not use any force! Be sure that the plug connectors latch. Close the locking clips of the plug connectors. Carefully replace the front cover being mindful of the ribbon-cable. Fasten the cover to the case with the screws. Insert and tighten the screw-posts for the D-subminiature connector at location “A” on the rear of the device. This activity does not apply if the device is for surface mounting. Insert and tighten the screws for the communication interfaces at locations “B” and “C” on the back panel of the device. This activity does not apply if the device is for surface mounting. Replace the four corner covers.

335


3.2

Checking Connections and System (Plant) Integration

3.2.1

Checking the Data Connections of Serial Interfaces The following tables shows the pin-assignments for the various serial interfaces and for the time synchronization interface of the device.

Operator 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, Subsection A.1 for an ordering description of the cable.

System Interface

When a serial interface of the device is connected to a a central control system (SCADA), the data connection must be checked. A visual check of the transmit channel and the receive channel is important. In the RS232 and the FO interface, each connection is dedicated to one transmission direction. The data output of one device must be connected to the data input of the other device, and vice versa. The data cable connections must conform to DIN 66020 and ISO 2110 (see also Table 3-20): − TxD

data transmit

− RxD

data receive

− RTS

request to send

− CTS

request to send

− GND

signal/chassis ground

The cable screen is to be grounded at both ends. In environments with extremely high electromagnetic interference, the EMC immunity can be improved by running the GND conductor as a separate, individually screened wire pair.

5 9 6 1 Operator interface front side

P-Slave AME

RS232-FO RS232 RS485

The location of the connections is shown in Figure 3-16.

1 6

1 6

9 5

9 5

Serial system interface rear side Figure 3-16

336

Time synchronization interface rear side (panel flush mounting)

9 pin D-subminiature Connector

7UM62 Manual C53000-G1176-C149-3

3.2 Checking Connections and System (Plant) Integration

. Table 3-20

Installation of the D-Subminiature Ports

Pin No. PC Interface at Front

RS 232

1

RS 485

Profibus DP Slave, RS 485

DNP3.0, Modbus, RS485

Screen (with screen ends electrically connected)

2

RxD

RxD

–

–

–

3

TxD

TxD

A/A’ (RxD/TxD–N)


A

4

–

–

–

CNTR–A (TTL)

RTS (TTL)

5

GND

GND

C/C’ (GND)

C/C’ (GND)

GND1

6

–

–

–

+ 5 V voltage supply (max. load < 100 mA)

VCC1

7

–

RTS

–*)

–*)

–

8

–

CTS



B

9

–

–

–

–

–

*) Pin 7 also can carry the RS 232 RTS signal to an RS 485 interface. Pin 7 must therefore not be connected!

RS 485 Termination

The RS 485 interface is capable of half-duplex mode with the signals A/A’ and B/B’ with a common relative potential C/C’ (GND). Verify that only the last device on the bus has the terminating resistors connected, and that the other devices on the bus do not. The jumpers for the terminating resistors are on the interface card mounted on the C–CPU–2 board. Refer to Figure 3-13 (RS485) and to Figure 3-14 (Profibus). Terminating resistors can also be implemented outside the device (e.g. in the plug connectors). In that case the terminating resistors provided on the interface card must be switched out. 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.

Analog Output

The two analog values are output as currents on a 9-pin DSUB female connector. The outputs are isolated. Table 3-21

7UM62 Manual C53000-G1176-C149-3

Pin Assignment of the DSUB Female Connector for the Analog Output

Pin No. 1

Designation Channel 1 positive

2

–

3

–

4

–

5

Channel 2 positive

6

Channel 1 negative

7

–

8

–

9

Channel 2 negative

337


Time Synchronization Interface

Either 5 VDC, 12 VDC or 24 VDC time synchronization signals can be processed if the connections are made as indicated in Table 3-22. Table 3-22

Pin Assignments for the D-Subminiature Port of the Time Synchronization Interface

Pin No. 1

Designation P24_TSIG

Signal Meaning Input 24 V

2

P5_TSIG

Input 5 V

3

M_TSIG

Return Line

4

–*)

–*)

5

Screen

Screen Potential

6

–

–

7

P12_TSIG

Input 12 V

8

P_TSYNC*)

Input 24 V*)

9

Screen

Screen Potential

*) assigned but not used For the pin assignment of the time synchronization interface in panel surface-mounted devices, please refer to the Appendix (Figures A-22 to A-25). Optical Fibers

Signals transmitted via optical fibers are unaffected by interference. The fibers guarantee electrical isolation between the connections. Transmit and receive connections are shown with the symbols for transmit and for receive. The normal setting for the optical fiber interface is ”Light off.” If this setting is to be changed, use the operating program DIGSI® 4, as described in the SIPROTEC® 4– System Manual.

WARNING! Laser rays! Do not look directly into the optical fiber cables!

3.2.2

Checking the Device Connections

General

The device connections must be checked to ensure the correct integration of the device e.g. in the cubicle. The check includes, among others, the wiring and the functionality as specified in the set of drawings, the visual inspection of the protection system and a simplified functional test of the protective device.

Auxiliary Voltage Supply

Before applying power supply voltage or measuring quantities for the first time, be sure the device has been in the operating area for at least two hours. This time period allows the device to attain temperature equilibrium, and prevents dampness and condensation from occurring.

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7UM62 Manual C53000-G1176-C149-3


Note: If a redundant supply is used, there must be a permanent, i.e. uninterruptible connection between the minus polarity connectors of system 1 and system 2 of the d.c. voltage supply (no switching device, no fuse), because otherwise there is a risk of voltage doubling in case of a double earth fault.

o

Close the protective switches to apply voltage to the power supply. Check the polarity and magnitude of the voltage at the device terminals or at the connector modules.

Visual Inspection

Check the cubicle and the devices for damage, condition of the connections etc., and device earthing.

Secondary Testing

This test does not undertake to check the individual protection functions for the accuracy of their pick-up values and characteristic curves. Unlike analog electronic or electromechanical protective devices, no protection function test is required within the framework of the device test, since this is ensured by the factory tests. Protection functions are only used to check the device connections. A plausibility check of the analog-digital converter with the operational measured values is sufficient since the subsequent processing of the measured values is numerical and thus internal failures of protection functions can be ruled out. Where secondary tests are to be performed, a three-phase test equipment providing test currents and voltages is recommended (e.g. Omicron CMC 56 for manual and automatic testing). The phase angle between currents and voltages should be continuously controllable. The accuracy which can be achieved during testing depends on the accuracy of the testing equipment. The accuracy values specified in the Technical data can only be reproduced under the reference conditions set down in IEC 60255 resp. VDE 0435/ part 303 and with the use of precision measuring instruments. Tests can be performed using the currently set values or the default values. If unsymmetrical currents and voltages occur during the tests it is likely that the asymmetry monitoring will frequently operate. This is of no concern because the condition of steady-state measured values is monitored and, under normal operating conditions, these are symmetrical; under short circuit conditions these monitoring systems are not effective. Note: During dynamic testing, at least one a.c. measured quantity should be present at one of the analog inputs, with a sufficient amplitude. The measured quantities of the earth paths (IEE, UE) cannot be used for the integrated sampling frequency adaptation. During tests concerning IEE or UE, at least one a.c. measured quantity must be applied to one of the phase inputs.

7UM62 Manual C53000-G1176-C149-3

339


Secondary Test of the Differential Protection

A test set with 6 current outputs is recommended for secondary testing. This section gives you hints how to proceed if less current sources are available. The test current can be injected individually for each winding, thus simulating each time a transformer fault with single-ended infeed. The preset parameter for I-DIFF> as pick-up value (address 2021) applies for three or two-phase testing. The pickup value for single-phase testing depends on the method the zero sequence current is treated within the relay: If the zero sequence current is eliminated, then the pickup value is increased to 1.5 times the set value because of the elimination of the zero sequence current; this corresponds to conventional circuitry when the current is fed in via matching transformers. If the zero sequence current is not eliminated (isolated starpoint), the pickup value corresponds to the setting value I-DIFF> even during single-phase testing. Checking the pickup value is performed by slowly increasing the test current for each winding with the test set. Tripping occurs when the pickup value, converted according to the matching factor, is reached. When the test current falls below approximately 0.7 times the pickup value, the relay drops off. In the method described above, the pickup values for single-ended infeed are tested. It is also possible to check the entire characteristic. Since trip current and restraint current cannot be fed in separately (they can, however, be read out separately in the test measurements), a separate test current has to be applied to each of the two windings. When testing with the operational parameters, it should be noted that the setting value IDIFF > refers to the rated current of the transformer, i.e. current which results from: S N Transf [ MVA ] ⋅ 1000 IN Transf = ------------------------------------------------------------ [A] 3 ⋅ U N Winding [ kV ] for three-phase transformers with SN Transf – MVA rating of transformer UN Winding

– Rated voltage of the respective winding; if a winding is regulated, then the parameterized voltage according to Section 2.11.2.2 applies

Furthermore, the pickup values can change with single -and two-phase testing depending on the vector group of the protected transformer; this corresponds to conventional circuitry, when currents are applied via matching current transformers. Table 3-23 shows these changes as a factor kVG depending on the vector group and the type of fault, for three-phase transformers. In order to obtain the pickup value, the setting value I-DIFF> (parameter address 2021) must be multiplied by the factor I N Transf ---------------------------------- ⋅ k VG I N CT (primary)

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7UM62 Manual C53000-G1176-C149-3


Table 3-23

Correction Factor kVG Depending on Vector Group and Fault Type

Type of Fault

Reference Winding (High Voltage Side)

Even VG Numeral (0, 2, 4,6, 8, 10)

Odd VG Numeral (1, 3, 5, 7, 9, 11)

Three-phase

1

1

1

Two-Phase

1

1

√3/2 = 0.866

3/2 = 1.5

3/2 = 1.5

√3 = 1.73

1

1

√3 = 1.73

Single-Phase with I0 elimination Single-Phase without I0 elimination

The pickup values are checked for each winding by slowly increasing the test current with the secondary test set. Tripping is initiated when the converted pickup value is reached.

Example (Application as “mere transformer protection”): Three-phase transformer SN = 57 MVA, vector group Yd5 Primary (higher) voltage 110 kV Current transformers 300 A/1 A Secondary (lower) voltage25 kV Current transformers 1500 A/1 A The following applies for the primary winding: S N Transf [ MVA ] ⋅ 1000 57 [ MVA ] ⋅ 1000 I N Transf = ------------------------------------------------------------ [A] = -------------------------------------------- [A] = 299.2 A 3 ⋅ U N Winding [ kV ] ( 3 ⋅ 110 ) [ kV ]

In this case the rated current of the winding is practically equal to the current transformer rated current. Thus, the pickup value (referred to the rated relay current) complies with the set IDIFF> of the relay when three or two-phase testing is performed (kVG = 1 for reference winding). With single-phase testing and zero sequence current elimination, a pickup value 1.5 times higher must be expected. The following applies for the secondary winding: S N Transf [ MVA ] ⋅ 1000 57 [ MVA ] ⋅ 1000 I N Transf = ------------------------------------------------------------ [A] = -------------------------------------------- [A] 3 ⋅ U N Winding [ kV ] ( 3 ⋅ 25 ) [ kV ]

7UM62 Manual C53000-G1176-C149-3

= 1316 A

341


When testing this winding, the pickup value (referred to the rated relay current) will amount to: I N Transf I N Transf 1316 A ------------------- = --------------------------------⋅k ⋅ IDIFF> = ------------------- ⋅ k VG ⋅ IDIFF> 1500 A I N Relay I N CT (primary) SG = ( 0.877 ⋅ k VG ⋅ IDIFF > ) Because of the odd vector group numeral, the following pickup values apply: Three-phase

kVG = 1

IPickup ------------------ = 0.877 ⋅ IDIFF > I N Relay

Two-phase

kVG = √3/2


Single-phase

kVG = √3


Wiring

It is particularly important to check the correct wiring and allocation of all device interfaces. The test function described in section 3.3.3 for checking the binary inputs and outputs is a useful instrument for this. For analog inputs a plausibility check can be performed as described above under the side title “Secondary Testing”.

Functional Test

The only functional test required for protective relays is a plausibility check of the operational measured values by means of some secondary test equipment; this is to ensure that no damage has occurred during transit (see also side title “Secondary Testing”).


Note: In devices where the undervoltage protection function is configured and activated, please note the following: special measures have been taken to ensure that the device does not pick up immediately after applying the auxiliary power supply, as a result of the measuring voltage that is not yet present at the moment of power-up. However, the device does pick up as soon as operating state 1 (measuring quantities exist) has been attained.

LED Indications

After tests which cause LED indications to appear, these should be reset, at least once by each of the possible methods: the reset bottom on the front plate and via the remote reset relay. Please note that LEDs are automatically reset when a new fault occurs, and that you can choose whether a new annunciation is made on pickup or on output of a trip command (parameter 7110 FltDisp.LED/LCD).

Test Switches

Check the functions of all test switches that are installed for the purposes of secondary testing and isolation of the device. Of particular importance are test switches in current transformer circuits. Be sure these switches short-circuit the current transformers when they are in the test mode.

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7UM62 Manual C53000-G1176-C149-3


3.2.3

Checking the Integration in the Plant

3.2.3.1

General Hints

Warning! The following procedures are carried out with dangerous voltages present. Therefore, only qualified people who are familiar with and adhere to the safety procedures and precautionary measures shall perform the procedures. This test is performed to ensure that the protective device is correctly integrated into the plant to be protected. One important step in the test is the check of the protection configuration (masking and setting values) for conformity with the plant requirements. An integration test across all interfaces allows to check on one hand the cubicle wiring and the functionality in accordance with the set of drawings, and on the other hand the correct wiring between the sensor or transformer and the protective device. This test does not undertake to check the individual protection functions for the accuracy of their pick-up values and characteristic curves.

Auxiliary Voltage Supply

Check the voltage magnitude and polarity at the input terminals.

Note: If a redundant supply is used, there must be a permanent, i.e. uninterruptible connection between the minus polarity connectors of system 1 and system 2 of the d.c. voltage supply (no switching device, no fuse), because otherwise there is a risk of voltage doubling in case of a double earth fault.

Caution! Operating the device on a battery charger without a connected battery can lead to unusually high voltages and consequently, the destruction of the device. For limit values see Sub-section 4.1.2 under Technical Data.

Visual Inspection

− Check the cubicle and the devices for damage; − Check the earthing of the cubicle and of the protective device; − Check the external cabling for condition and completeness.

7UM62 Manual C53000-G1176-C149-3

343


Inventory of the Technical Plant Data

In order to check the protection configuration (masking and setting values) for conformity with the plant requirements, it is necessary to make an inventory of the technical data for the individual components of the primary plant. These components include, among others, the generator or motor, the unit transformer (step-up transformer) and the voltage and current transformers. Where deviations from the planning data are found, the settings of the protection must be modified accordingly.

Analog Inputs

The check of the current and voltage transformer circuits includes: • Inventory of the technical data • Visual inspection of the transformers, e.g. for damage, mounting position and connections • Check of the transformer earthing, especially the earthing of the broken delta winding in only one phase • Check of the cabling for conformity with the circuit diagram

Other checks that may be necessary for a specific job include: • Measuring the cable insulation • Measuring the transformation ratio (VT, CT) and the polarity • Measuring the burden • Checking the functions of test switches, if used for secondary testing. • Measuring transducers/ Measuring transducer connection Binary Inputs and Outputs

See also section 3.3.3. G

Setting the binary inputs:

− Check the jumper settings for the pick-up thresholds and modify, if necessary (see section 3.1.3, Figures 3-7, 3-9 and 3-11, as well as Tables 3-3, 3-8 and 3-12) − Check the pick-up threshold – if possible – with a variable d.c. voltage source

Auxiliary Contact of VT Protective Switches

344

G

Check the tripping circuits from the command relays and the tripping lines down to the various components (circuit breakers, excitation circuit, stop valves, switchover devices etc.)

G

Check the signal processing from the signal relays and the signal lines down to the station control and protection system; to do so, energize the signal contacts of the protective device and check the texts in the station control and protection system

G

Check the control circuits from the output relays and the control lines down to the circuit breakers and disconnectors etc.

G

Check the binary input signals from the signal lines down to the protective device by activating the external contacts

Since it is very important for the undervoltage protection, the impedance protection and the voltage-dependent definite time and inverse time overcurrent protection that these functions are blocked automatically if the circuit breaker for the voltage transformers has tripped, the blocking should be checked along with the voltage circuits. Open for this the VT protective switches.

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When the voltage on the binary input connected to this auxiliary contact is removed, the message “>FAIL:Feeder VT ON” should appear in the Event Log. When the voltage is restored, the message “>FAIL:Feeder VT OFF” should occur. If one of these messages does not appear, then the connections and the configuration settings should be checked. If the ON and OFF messages are exchanged, then the breaker auxiliary contact type should be checked and corrected if necessary.

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3.3

Commissioning

Warning! When operating an electrical device, certain parts of the device inevitably have dangerous voltages. Severe personal injury or property damage can result if the device is not handled properly. Only qualified people shall work on and around this device after becoming thoroughly familiar with all warnings and safety notices in this instruction manual as well as with the applicable safety steps, safety regulations, and precautionary measures. The main points to observe are: • The device is to be grounded to the substation ground before any other connections are made. • Hazardous voltages can exist in the power supply and at the connections to current transformers, voltage transformers, and test circuits. • Hazardous voltages can be present in the device even after the power supply voltage has been removed, i.e. capacitors can still be charged. • After removing voltage from the power supply, wait a minimum of 10 seconds before re-energizing the power supply. This wait allows the initial conditions to be firmly established before the device is re-energized. • The limit values given in Technical Data (Chapter 10) must not be exceeded, neither during testing nor during commissioning. When testing the device with directly connected test equipment, make sure that no other measurement quantities are connected and that the trip and close circuits to the circuit breakers and other primary switches are disconnected from the device.

DANGER! Current transformer secondary circuits must be short-circuited before the current leads to the device are disconnected! If test switches are installed that automatically short-circuit the current transformer circuits, opening these test switches (placing them in the "Test" position) is sufficient provided the short-circuit function has been previously tested.

During the commissioning procedure, switching operations will be carried out. It is assumed for the tests described here that this is possible without danger. Therefore, these tests are not intended for operational checks.

Warning! The following procedures are carried out with dangerous voltages present. Therefore, only qualified people who are familiar with and adhere to the safety procedures and precautionary measures shall perform the procedures.

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3.3.1

Test Mode and Blocking Data Transmission If the SIPROTEC®4 device is connected to a central or master computer system via the system interface, then the information that is transmitted can be influenced (see Table “Protocol-dependent functions” in the Appendix A.13). If Test mode is set ON, then a message sent by the device to the master system has an additional test bit. This bit allows the message to be recognized as resulting from testing and not an actual fault or power system event. If DataStop is set ON, transmission to the master station is blocked. The procedures for setting Test mode and DataStop are described in SIPROTEC® 4 System Manual. Note that when DIGSI® 4 is being used, the program must be in the Online operating mode for the test features to be used.

3.3.2

Testing the System Interface

Preliminary Notes

If the device provides a system interface, and if this interface is used to communicate with a central or master computer system, the DIGSI® 4 software can be used to test whether the messages are being transmitted correctly. This test option should however definitely not be used while the device is in service on a live system.

DANGER! The initiation or extraction of messages via the system interface using the test function constitutes an actual exchange of information between the device and the control system. Connected plant such as e.g. circuit breakers or isolators may be switched as a result of this! Note: After termination of the test mode, the device will reboot. Thereby, all annunciation buffers are erased. If required, the events in these buffers should be extracted with DIGSI® 4 prior to the test. The interface test can be done using DIGSI® 4 in the online operating mode:

Structure of the Test Dialogue Box

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G

Open the Online directory by double-clicking; the operating functions for the device appear.

G

Click on Test; the function selection appears in the right half of the screen.

G

In the view of the list, double click on the dialog box Test–Indications for System Interface. The dialog box Generate Indications is opened (refer to Figure 3-17).

In the column Indication, the display text of all messages are shown, which were assigned to the system interface in the matrix during configuration. In the column SETPOINT status the state of the message that has to be tested can be defined. Depending on the message type, different prompts are provided for this purpose (e.g. event coming/event going). By clicking in a field, it becomes possible to select the desired state in a pull-down list.

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Figure 3-17

Changing the Operating State

Dialog Box: Generate indications

Following the first operation of one of the keys in the column Action a prompt for the entry of password No. 6 (for hardware test menus) appears. After correct entry of the password, individual messages can be initiated. To do this, click on the button Send in the corresponding line. The corresponding message is initiated and can now be retrieved as part of the operational alarms in the SIPROTEC® device, as well as from the central or master station of the plant. Further tests remain possible while the dialog box is open.

Test in the Transmission Direction

Exiting the Procedure

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For all information that has to be transmitted to the control system, open the dropdown list in the column SETPOINT status and test the alternatives listed there: G

Ensure that any switching operations that may result from these tests can be executed without danger (see above under DANGER!).

G

With the function to be tested, click on send, and check that the corresponding information is received at the central or master station, and, if required, the expected response results.

To end the interface test, click on Close. The dialog box closes. The device becomes unavailable for a brief start-up period immediately after this.

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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 in DIGSI® 4. This feature can be used, for example, to verify control wiring from the device to substation equipment (operational checks), during commissioning. This test feature shall not be used while the device is in service on a live system.

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® device. Connected equipment such as circuit breakers will be operated by these actions! Note: After the Hardware Test is complete, the device enters a start-up phase. All message buffers are erased. If necessary, the buffer contents can be read out and saved using DIGSI® 4. The interface test can be done using DIGSI® 4 in the online operating mode:

Hardware Test: Dialog Box

G

Open the Online directory by double-clicking; the operating functions for the device appear.

G

Click on Test; the function selection appears in the right half of the window.

G

Double-click in the list view on Hardware Test. The dialog box of the same name opens (see Figure 3-18).

The dialog box is horizontally divided into three groups: BI for binary inputs, REL for output relays, and LED for light-emitting diodes. Each of these groups is associated with an appropriately marked switching area. By clicking in an area, components within the associated group can be turned on or off. In the Status column, the present conditions of the hardware components are symbolically shown. The present physical conditions of the binary inputs and output relays are shown as symbols for open and closed contacts. The present condition of a light-emitting diode is shown as the symbol for an LED, turned on or off. The possible intended condition of a hardware component is indicated with clear text under the Schedule column, which is next to the Status column. The intended condition offered for a component is always the opposite of the present state. The right-most column indicates the operating equipment, commands, or messages that are configured (masked) to the hardware components.

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Figure 3-18

Changing Hardware Conditions

Dialog Box for Hardware Test — Example

The displays of the intended conditions are shown as switching fields. To change the condition of a hardware component, click on the associated switching field in the Schedule column. If the password was activated for Hardware Test, then Password No. 6 will be requested before the first hardware modification is allowed. Only after entry of the correct password a condition change will be executed. Further condition changes remain possible while the dialog box is open.

Testing the Output Relays

Testing the Binary Inputs

You can make each output relay pick up individually, and in this way test the wiring between the output relays of the 7UM62 and the plant, without having to generate the indications allocated to them. As soon as the first condition change is initiated for any output relay, all output relays are separated from the device functionality and can now only be operated by the Hardware Test function. This means, for example, that a switching command that is caused by a protection function or by a control command from the operator panel will not be executed. G

Make sure that there is no risk involved in carrying out the switching operations triggered by the output relays (see above under DANGER!).

G

Test each output relay using the associated Scheduled field in the dialog box.

G

Close the test procedure (see side title below “Ending the procedure”) to avoid unintentional switching operations in the course of further testing.

To test the wiring between the plant and the binary inputs of the 7UM62, you must initiate in the plant the condition that activates the respective input and read out the effect at the device. To do so, open once again the dialog box Hardware Test to view the physical position of the binary input. No password is required yet. G

350

Trigger in the plant each of the functions that activates the binary input.

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G

Check the reaction in the Status column of the dialog box. To do so, the dialog box must be updated. This is described below under the side title “Updating the display”.

If you want to check the effects of a binary input signal without actually performing switching operations in the plant, you can do so by activating individual binary inputs by means of the Hardware Test function. As soon as you have initiated the first condition change of a binary input, and entered password no. 6, all binary inputs are separated from the device side functionality and can only be operated by the Hardware Test function. This means, for example, that external signals to binary inputs would be ignored by the device if their status conditions change and the test procedure had not been closed. G

Close the test procedure (see side title below “Ending the procedure”).

LED Test

The LEDs can be tested in a similar way as other I/O components. As soon as the first condition change is initiated for any output relay, all output relays are separated from the device functionality and can now only be operated by the Hardware Test function. This means, for example, that no LED will light up on receiving a signal from a protection function, or in case of an LED reset from the device front panel.

Updating the Display

When the dialog box Hardware Test is opened, the present conditions of the hardware components at that moment are read in and displayed. An update occurs: − for each component, if a command to change the condition is successfully performed, − for all hardware components if the Update field is clicked, − for all hardware components with cyclical updating if the Automatic Update (20sec) field is marked.

Ending the Procedure

3.3.4

To end the interface test, click on Close. The device becomes unavailable for a brief start-up period immediately after this. The dialog box closes. Then all hardware components are returned to the operating conditions.

Testing the Breaker Failure Scheme If the device has a breaker failure protection, and that function is used, its integration in the plant must be checked under operating conditions. It is particularly important for tests within the plant that the trip command in case of a breaker failure should be correctly retransmitted to the adjacent circuit breakers. Adjacent circuit breakers are those breakers that must trip in case of a breaker failure to cut off the short-circuit current. This means that they are those circuit breakers that feed the faulted line. It is not possible to define a generally applicable, detailed test specification since the definition of adjacent circuit breakers depends to a large extent of the plant layout.

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3.3.5

Checking the Analog Outputs 7UM62 can be equipped with up to 2x2 analog outputs. Where analog outputs are provided, and used, their functioning should be tested. Since various types of measured values or events can be output, the test to be performed depends on the type of values for which it will be used. These values must be generated (e.g. with some secondary test equipment). Make sure that the values are correctly output at their destination.

3.3.6

Testing User-Defined Functions (CFC) A 7UM62 has a vast capability for allowing functions to be defined by the user, especially 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 the possible interlocking conditions of the circuit breakers and other primary switching devices. They must be considered and tested.

3.3.7

Checking the Rotor Earth Fault Protection at Stand-Still

3.3.7.1

Rotor Earth Fault Protection (R, fn) The rotor earth fault protection can be checked with the machine at stand-still. The coupling unit, however, must be supplied with an external a.c. voltage 100 V to 125 V, or 230 V (50 Hz or 60 Hz). Please refer also to connection diagram Figure 2-95 in Section 2.30.1). Switch rotor earth fault protection (address 6001 ROTOR E/F) to Block. Relay. In the case of machines with rotating rectifier excitation (Figure 3-19 left), an earth fault is installed between the two measurement slip rings with the measurement brushes in place. In case of machines with excitation via slip rings (Figure 3-19 right) the earth fault is installed between one slip ring and earth. The unit now measures as earth impedance only the reactance of the coupling unit and the brush resistance (in series with a protective resistor for the coupling capacitors and/or a damping resistor). These values can be read out under the Operational Measured Values: R total = x.xx kΩ X total = x.xx kΩ ϕZtotal = z.z ° Rinput corresponds to the series resistance (brushes plus protective resistor) and Xinput corresponds to the capacitive reactance (a negative value indicates an inductive reactance). If both values are indicated as 0, then the connections of Urotor or Irotor have wrong polarity. Change the polarity of one of the connections and repeat the measurement. It must then be checked that the setting values R SERIES = xxx Ω (address 6007)

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X COUPLING = yyy Ω (address 6006) correspond with the above values. Remove earth fault bridge. An earth fault is now fitted as described above via a resistor of the warning resistance, (RE< WARN, address 6002, 10 kΩ when delivered from factory. The earth resistance calculated by the unit can be read out under the Operational Measured Values as Rotor. If substantial deviation occurs between the actual rotor earth resistance and the indicated resistance, the accuracy can be improved by correction of the c.t. angle error PHI I RE (address 6009). This c.t. angle error correction is only effective for the rotor earth fault protection function. An earth fault is now fitted as described above via a resistor of approximately 90% of the trip resistance (RE<< TRIP, address 6003, 2 kΩ when delivered). The rotor earth fault protection initiates a pick-up signal and after 6005 T-TRIP-RE<< (0.5 s when delivered from factory) a trip annunciation (LED 1 and binary output 2) in both cases this is a group indication “Device Trip”). In the case of machines with excitation via slip rings, the above test is repeated for the other slip ring. Remove earth fault resistor.

Excitation equipment

Excitation machine

Coupling unit

Excitation via rotating rectifiers with measurement brushes Figure 3-19

Coupling unit

Excitation equipment fed via slip rings

Types of Excitation

Lift measurement brushes or interrupt measurement circuit. Alarm “Failure R/E/F” is indicated after a time delay of approx. 5 s (not allocated on delivery). Close measurement circuit. If the alarm “Failure R/E/F” is also present with the measurement circuit closed, then the rotor-earth capacitance is less than 0.15 µF. In this case, a measurement circuit supervision is not possible; the alarm “Failure R/E/F” then should not be marshalled to any binary output. Set parameter 5106 IEE< = 0.

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After the completion of the test, check that all provisional measures for testing have been reversed: − Earthing bridge or resistor has been removed, − Measurement circuit has been closed, − Controller unit connected to its operational supply a.c. voltage (refer also connection diagram in Figure 2-95 in Section 2.25.1). Tests with the running machine are described later under section 3.4.9.

3.3.7.2

Rotor Earth Fault Protection (1 to 3 Hz) The rotor earth fault protection can be checked with the machine at stand-still. For this purpose, the series device 7XT71 must be supplied with an external AC voltage of 100 V to 125 V AC (see also to connection diagram Figure A-36 in the Appendix). Switch the rotor earth fault protection (address 6101 REF 1-3Hz) to Block relay. In fault-free condition, the following operational measured values are read out from the protection device and evaluated (see Table 3-24).The operational measured values can be found in the earth fault measured values (in DIGSI see tab “earth fault measured values”).

Table 3-24

Operational Measured Values of the Rotor Earth Fault Protection

Measured Value

Comments

fgen = xx.x Hz

Shows the frequency of the injected square-wave voltage. The frequency can be set by a jumper in the 7XT71. The default setting is approx. 1.5 Hz (tolerance approx. ± 10 %).

Ugen = xx.x V

This measured value indicates the current amplitude of the injected square-wave voltage. It amounts to approx. 50 V (tolerance of the 7XT71 can be up to ± 4 V).

Igen = X.xx mA

This measured value is nearly zero in fault-free condition. If a fault resistor is installed between rotor and earth, the current to be expected can be estimated as follows:

Ugen Igen ≈ ------------------------------R E + Rtotal RE: Fault resistor Rtotal: Coupling resistance (20 kΩ + 720 Ω = 20.720 kΩ)

354

Qc = x.xxx mAs

This measured value indicates the charge which is a function of the rotor earth capacitance. Half of the measured value must be set at address 6106 as Qc <. If the capacitance is very small, it may be necessary to deactivate the measuring circuit monitoring (setting value 0).

Rearth = xxx.x kΩ

This measured value indicates the rotor earth resistance. In faultfree condition, the upper limit value 999.9 kΩ is displayed. If it is not, there must be some additional capacitance in the excitation system. The square-wave voltage frequency in the 7XT71 must be reduced by a jumper. No polarity reversal may occur in the measuring current Igen for at least 3 cycles. To visualize what is going on, a test fault record (instantaneous values record) should be started and track TD2, which models Igen, should be checked (see Figure 3-20).

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Figure 3-20

Test Fault Record

After this the fault resistors for the warning and the trip stage are installed, and the operational measured value Rearth is read out. The two measured values are the basis for the setting values of the warning stage (address 6102 RE< WARN) and the trip stage (address 6104 RE<< TRIP). Finally, the warning and the trip stage are checked. The test resistance for this is approx. 90 % of the set value. On generators or motors with excitation by sliprings, the test is performed for both sliprings. Remove the earth fault resistor and lift the measuring brushes or interrupt the measuring circuit. After a delay of approx. 10 s, the indication „REF 1-3Hz open“ is issued (not masked on delivery). Re-close the measuring circuit. If you want to perform an automatic test by means of a test resistor, this mechanism needs to be tested as well. To do so, connect the test resistor at the slipring to the earth, and activate the test via binary input („>Test REF 1-3Hz“). Next, check the indications for the following four test steps to be performed. 1.

Measuring circuits closed

Indication „Test REF PASSED“

2.

Open circuit at 1st coupling resistor

Indication „1 Cir. open“

3.

Open circuit at 2nd coupling resistor

Indication „2 Cir. open“

4.

Re-establish connections

Indication „Test REF PASSED“

Stop the automatic test and check again the operational measured value Rearth. It must display 999.9 kΩ. Finally, switch the AC voltage source of the 7XT71 off. After about 5 s, the protection device issues the indication „Fail REF 1-3Hz“ (not masked on delivery).

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To eliminate interference which might originate from the running machine, in particular from the excitation system, it is recommended to perform an additional operational check as described in Section 3.4.9.2.

3.3.8

Checking the 100–% Stator Earth Fault Protection The 100-% stator earth fault protection can be checked with the machine at stand-still, because the measuring principle for the earth resistance calculation is independent of whether the machine is at stand-still, rotating or excited. As a prerequisite for the check, however, a supply for the 20 Hz generator 7XT33 must be provided; depending on the project in hand, this may be a DC voltage supply or an external voltage source (3 x 100 V, 50/60 Hz) (see also the connection diagram of Figure A-37 in the Appendix). Switch the 100-% stator earth fault protection to Block relay (address 5301 100% SEF-PROT.). For the following parameters, the default settings must be maintained for a first commissioning. 5309

PHI I SEF = 0°

5310A SEF Rps = 0.0 Ω 5311A Rl-PARALLEL =∞ Ω The measured quantities USEF and ISEF fed to the device can now be read out in the earth fault measured values (in DIGSI under Ins (earth fault measured values)): U SEF= xx.x V I SEF= xx.x mA Please note that these measurements are pure r.m.s. values which only correspond to the 20 Hz quantities if the generator is standing still. The voltage measured is influenced by the loading resistor RL, the 20 Hz resistance of the band pass (RBP approx. 8 Ω), the voltage divider (üVlt.Divider, usually 5/2) and, in the final analysis, by the 20 Hz supply voltage (U20Hz generator, approx. 25 V). The value can be estimated as follows: RL U 20Hz-generator U SEF = ------------------------ ⋅ --------------------------------------R BP + R L ü Vlt.Divider The flowing current ISEF is determined by the stator earth capacitance and is very small. The device calculates from these values the earth resistance RSEF referred to the protection device side. The primary earth resistance RSEFp on the machine side is obtained by multiplying the secondary value with the conversion factor set in the Power System Data 1 (address 275 FACTOR R SEF). Both resistance values, including the phase angle between the 20 Hz voltage and the 20 Hz current (ϕSES = ϕU - ϕI) can be read out in the operational measured values: R SEF= = xxxx Ω RSEFp= xxx.xx kΩ j SEF= xx.x° In fault-free condition, the measured phase angle ϕ SES across the existing stator earth capacitances should be approx. –90°. If it is not, the value to complement it to –

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90° must be determined and set as PHI I SEF = –90° – ϕ SES. If the value displayed is, for example, ϕ SES = –75°, PHI I SEF = –15° must be set at address 5309. This will change the measured value to approx. –90°. The value displayed for R SEF must be in fault-free condition the maximum possible value of 9999 Ω. The maximum value for the primary earth resistance R SEFp depends on the selected conversion factor (FACTOR R SEF address 275). Switch off the voltage supply for the 20 Hz generator, or block the binary input. The indication „Failure SEF“ will appear (not masked on delivery). This proves that a failure of the 20 Hz generator is reliably detected. If this indication appears already with the 20 Hz generator in operation, the monitoring threshold (address 5307 U20 MIN) should be reduced. This can be the case if the loading resistance is very small (< 1 Ω). Now a variable resistor is inserted as earth resistance e.g. between generator starpoint and earth.

DANGER! Hazardous voltages can be present in the generator even at stand-still. If the external 20 Hz bias voltage of the stator winding is switched on, it amounts to approx. 1 % to 3 % of the primary rated voltage of the generator to be protected! Set the primary earth resistance to 0 Ω (short-circuit) and read out the operational measured value R SEF. This value must be nearly zero. If the transfer resistance of the earthing or neutral transformer is not negligible, it can be compensated. To do so, set the measured value R SES at address 5311A as SEF Rps. Then the pickup value for the trip stage is specified. Set the primary earth resistance to the tripping value (e.g. 2 kΩ) and read out the measured value R SEF. In case of major deviations between fault resistance and measured value, the correction angle PHI I SEF, address 5309, should be slightly modified for a better match. You can also use for this the operational measured value PHI SEF. It may also be necessary to slightly change SEF Rps. Finally, the fault resistance is read out, and set as the tripping value at address 5304 R<< SEF TRIP. Now the primary-side earth resistor for the alarm stage (e.g. 5 kΩ) is inserted, and the fault resistance (R SEF) is read out. This value must be set at address 5302 as R< SEF ALARM. For the settings, only secondary values should be used. If you find during the conversion from secondary to primary values that the theoretical conversion factor is not quite correct, FACTOR R SEF should be modified to match the measuring results (for conversion formulae refer to Section 2.29.2). Finally, a series of measurements is performed, starting with 0 kΩ and proceeding in steps of 1 kΩ. If changes are made to the correction angle (PHI I SEF address 5309) or to the contact resistance (SEF Rps, address 5310A), the settings for the trip stage (R<< SEF TRIP) and the alarm stage (R< SEF ALARM) must be matched as required. Now the earth resistance is reduced to about 90 % of the resistance for the alarm stage (address 5302 R< SEF ALARM). After the delay time T SEF ALARM set at address 5303 (10 s on delivery), the stator earth fault protection issues an alarm „SEF100 Alarm.“ (not masced on delivery). Further reduce the earth resistance to 90 % of what the trip stage pickup value would be for the protection device side (R<< SEF TRIP, address 5304). The protection is-

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sues a pickup indication, and, after T SEF TRIP address 5305 (1 s on delivery), a trip indication. Remove the test resistor. If the indication „20 Hz voltage missing” to be received from the 20 Hz generator is marshalled to one of the binary inputs, and the delivery setting of this input has been changed for this purpose, the binary input can be checked as well. Switch off the supply voltages of the 20 Hz generator. Feedback „>U20 failure“ (not masked on delivery). Indication „Failure SEF“ (not masked on delivery). Reconnect the supply voltages of the 20 Hz generator. If you make use of the possibility to block the 100-% stator earth fault protection by binary input, the functioning of the input should be checked. Activate binary input „>SEF100 BLOCK“. Feedback „SEF100 BLOCKED“. Further tests are performed with the machine running (Section 3.4). Note: If within the framework of routine tests the band pass 7XT34 is to be checked as well, short-circuit the earthing or neutral transformer on the secondary side with the machine standing still, and switch the 20 Hz generator on. Multiply the operational measured value I SES with the transformation ratio of the miniature CT (e.g. 400 A/ 5 A). The current flow must be higher than 3 A. If the current is noticeably less, the resonance frequency of the band pass has changed. It can be better matched by adding or removing capacitors (see also operating instructions for the 7 XT33, Order No. C53000–B1174–C129). Finally, remove the shorting link and check the galvanic isolation with the operational measured value U SEF.

3.3.9

Checking the DC Voltage/DC Current Circuit

Preparation

Set the DC voltage/DC current protection (address 7201 DC PROTECTION) to Block. Relay. You can now modify the plant voltage to match the conditions of the intended application, and verify the response of the 7UM62. A voltage above or below the threshold voltage (address 7204) (the appropriate choice is made under the address 7203) causes the protection to initiate first an alarm “DC Prot.pick.up” (not marshalled on delivery), and after a time T DC = (address 7206) the alarm “DC Prot. TRIP” (not marshalled on delivery). The DC voltage protection is then switched operative (address 7201 DC PROTECTION = ON) or – if it will not be used – switched off (DC PROTECTION = OFF).

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3.3.10 Trip/Close Tests for Primary Equipment Control by Local Command

At the end of commissioning, actual 7UM62 tripping and closing should be verified for all the relevant circuit breakers and primary switching devices, unless this has been done already in connection with the Hardware Test described in Section 3.3.3. The feedback of the status of the primary equipment, through the equipment’s auxiliary contacts to the binary inputs of the 7UM62, should be checked during the testing. Be sure the 7UM62 always indicates the true position of the equipment in the device messages. The procedure for the control is described in SIPROTEC® 4–System Manual. Make sure that the switching authority is set according to the source of commands that is used. The switching mode can be chosen as interlocked or non-interlocked. Note that non-interlocked switching presents safety risks.

Control from a Remote Control Center

7UM62 Manual C53000-G1176-C149-3

If the device has a connection to a remote control center, trip/close tests should be performed from that control center as well. Here again, make sure that the switching authority is set according to the source of commands that is used.

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3.4

Primary Commissioning Tests with the Generator

3.4.1

General Hints

Warning! When operating an electrical device, certain parts of the device inevitably have dangerous voltages. Severe personal injury or property damage can result if the device is not handled properly. Only qualified people shall work on and around this device after becoming thoroughly familiar with all warnings and safety notices in this instruction manual as well as with the applicable safety steps, safety regulations, and precautionary measures.

It is necessary to perform switching operations during commissioning. The tests described below assume that no risk is involved in such operations. They are therefore not suitable for checks during operation.

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.).

Safety Instructions

All relevant safety rules and regulations (e.g. VDE 105, VBG4 or comparable national regulations) must be complied with. Before undertaking any work, observe the following “5 safety rules”: 1. Isolate from supply 2. Secure against accidental reclosing 3. Verify the safe isolation from supply 4. Perform earthing and short-circuiting 5. Cover or fence in live parts in the vicinity The main points to observe are: • The device is to be grounded to the substation ground before any other connections are made. • Hazardous voltages can exist in the power supply and at the connections to current transformers, voltage transformers, and test circuits. • Hazardous voltages can be present in the device even after the power supply voltage has been removed, i.e. capacitors can still be charged. • After removing voltage from the power supply, wait a minimum of 10 seconds before re-energizing the power supply. This wait allows the initial conditions to be firmly established before the device is re-energized. • The limit values given in Technical Data (Section 4.1) must not be exceeded, neither during testing nor during commissioning.

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3.4 Primary Commissioning Tests with the Generator

DANGER! Current transformer secondary circuits must be short-circuited before the current leads to the device are disconnected! If test switches are installed that automatically short-circuit the current transformer circuits, opening these test switches (placing them in the "Test" position) is sufficient provided the short-circuit function has been previously tested.

All secondary test equipment must be removed. Connect measurement values. All installation preparations according to sections 3.1 and 3.2 must have been completed. Primary tests are performed with the generator. Order of the Test Procedure

Primary testing is usually performed in the following order: − Short–circuit tests, − Voltage tests, − Earth fault tests, − Synchronization, − Tests with the generator connected to the network The following hints are arranged in this order. All protection functions should be initially switched OFF (condition as delivered from factory) so that they do not influence one another. During primary testing the functions are progressively switched to being operative. If a particular protection function is not required at all, it should be “de– configured” (refer to Section 2.2). It is then treated as DISABLED. Switching on of a particular function can be performed in two different ways. The setting addresses concerned are shown in the respective sections. − Block relay: The protection function is operative and outputs annunciations and measured values. However, the trip command is blocked and it is not transmitted to the trip matrix. − Protection function ON: The protection function is operative and outputs annunciations and measured values. The trip command activates the trip relays which have been marshalled to the protection function. If the protection command is not marshalled to any trip relay, tripping does not occur.

Preparation

− Install an EMERGENCY OFF button for direct trip of the excitation − Block all protection functions (= Block relay) − Set the definite or inverse overcurrent protection function roughly to the nominal generator current, and set the trip to only on the excitation − Set the overvoltage protection function roughly to 30 % of the nominal generator voltage for the short-circuit test, and to roughly 110 % of the nominal voltage for the voltage tests, as well as to trip on excitation

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Adaptation of Sampling Frequency

Note:

Factory Setting

Note:

The device contains a sampling frequency adaptation; this ensures that the protection functions are always processed with algorithms matched to the actual frequency. This explains the wide frequency range and the small frequency influence (refer to Section 4.34). However, it requires that measurement values be present before a dynamic test can take place, so that the sampling frequency adaptation can operate. If a measurement value is switched from 0 to the device without a different measurement value having been present beforehand, an additional time delay of approximately 120 ms is incurred since the device must firstly calculate the frequency from the measurement value. In addition, no output signal is possible if no measurement value is connected. A trip signal, once issued, of course, is maintained for at least the duration of the parameterized reset time (TMin TRIP CMD) (refer also to Section 2.3)

When the protection device is delivered from the factory, all protective functions have been switched off. This has the advantage that each function can be separately tested without being influenced by other functions. The required functions must be activated for testing and commissioning. Operating Range of the Protection Functions

For commissioning tests with the generator, care should be taken that the operating range of the protection functions as specified in section 4.34 is not exceeded and that the measuring quantities applied are high enough. Where tests are performed with reduced pick-up values, the pick-up value may appear to deviate from the setting value (e.g. in the unbalance stage or the earth fault protection) if the measuring quantities are too small to block the protection function, i.e. if operating state 1 (= protection function active) is not yet attained. However, this effect will not interfere with commissioning since no checks of the pickup values are performed that involve the generator.

Commissioning Tool Using a WEB Browser

The 7UM62 features a web-based commissioning tool to assist during commissioning, and to perform routine tests. With this tool all indications and measured values can be easily read out. For tests, vector diagrams and selected characteristics can be visualized. If you want to use the commissioning tool, please refer to the help files provided on the subject. Instructions on how to install the long-distance data transmission network and work with the browser can be found on an Internet website (www.siemens.siprotec.de) in the download area of the “7SD52” protective relay (title: “Commissioning Tool Help”). The IP address required for the browser depends on the port used for connecting the PC: • Connection to the front operator interface: IP address 141.141.255.160 • Connection to the rear service interface (port C): IP address 141.143.255.160 To give you a first idea of the possibilities you have, the figures below show a selection of displays. Figure 3-21 shows the vectors of flowing currents. As the current direction towards the protected object is defined as positive, the angle of the phase currents is rotated by 180°. The magnitudes are the same, and the phase rotation is the same as well. This

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means that the current connection on side 1 and side 2 is OK. A similar display is available for the voltage and current vectors of side 2.

Figure 3-21

Currents Flowing through the Protected Object

For a test of the differential protection, the differential and restraint currents are entered in the characteristic. The characteristic shown is a function of the settings for the differential protection. In Figure 3-22, a load current has been simulated. A small differential current in phase L3 is visible.

Figure 3-22

7UM62 Manual C53000-G1176-C149-3

Differential and Restraint Currents - Example of Plausible Measurements

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3.4.2

Checking the Current Circuits

General

The checks of the current circuits are performed with the generator to ensure the correct cabling, polarity, phase sequence, CT ratio etc., not in order to verify individual protection functions in the device.

Preparation

Switch unbalanced load protection (address 1701) and overload protection (address 1601) to Block relay. With the primary plant voltage-free and earthed, install a three-pole short-circuit bridge which is capable of carrying rated current (e.g. earthing isolator) to the generator lineside terminals.

DANGER! Primary measurements must only be carried out with the generator at stand– still on disconnected and grounded equipment of the power system. After the preparatory measures described in section 3.4.1, all current transformer circuits (protection, measuring, metering) can be checked with the remanent excitation. Note on Testing

The checks of the current transformer circuits are carried out with max. 20 % of the rated transformer current. Tests with generator currents of more than 20 % are not normally required for the digital protective device. Operation of the generator at rated current during commissioning may only be necessary when the short-circuit characteristic is measured for the first time.

Absolute Current Values

The currents are stated among the operational measured values. They are read out from the device front panel or from the PC via the operator interface and compared with the actual measured values. If significant deviations are found, the CT connections are not correct.

Phase Rotation

The phase rotation must conform with the configured phase sequence (address 0271 PHASE SEQ. under Power System Data 1); if it does not, an indication “Fail Ph. Seq.“ will be output. In such a case, the allocation of phases to the measuring quantities must be checked and corrected, if necessary. The unbalanced load (negative sequence) can be read out under the operational measured values. It must be practically zero. If this is not the case, check for crossed current transformer leads: If the unbalanced load amounts to about 1/3 of the phase currents then current is flowing in only one or in only two of the phases. If the unbalanced load amounts to about 2/3 of the phase currents, then one current transformer has wrong polarity. If the unbalanced load is about the same as the phase currents, then two phases have been crossed. After correcting the wrong connection, the test must be repeated. Remove short–circuit bridges.

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Calibrating the Impedance Protection

Set impedance protection (address 3301) to IMPEDANCE PROT. = Block relay: With the primary plant voltage-free and earthed, install a three-pole short-circuit bridge which is capable of carrying rated current (e.g. earthing isolator) to the primary side of the unit transformer.

DANGER! Primary measurements must only be carried out with the machine at stand–still on disconnected and earthed equipment of the power system. Start-up machine and slowly excite to 20 % of rated machine current. Note on Testing

A test with about 20 % of the rated generator current is sufficient for checking the transformer connections and the operational measured values. If the relative shortcircuit voltage of the transformer is small, the voltage values measured are very low, so that it may be necessary to increase the generator current somewhat. A test with the full rated generator current is only required for the quantitative calibration of the impedance protection (e.g. for calibrating the transformer uK). The relay calculates from the currents and voltages the impedance between the point of installation (voltage transformers) and the short-circuit bridge, i.e. normally the short-circuit impedance of the unit transformer. Read out the reactance and resistance values in the measured values. Note that the secondary values depend on the rated relay current, 1 A or 5 A. In the case of the transformer impedance, the following results: Primary transformer impedance: 2

UN Z T prim = u sc ⋅ ---------S N

with

usc UN SN

- percent impedance voltage of transformer - rated voltage of transformer - rated apparent power of transformer

In secondary values: 2

N CT U N N CT Z T sec = Z T prim ⋅ ----------- = u sc ⋅ ---------- ⋅ ----------N VT S N N VT with

NCT NVT

- current transformer ratio - voltage transformer ratio

If substantial deviations or wrong sign occur, then the voltage transformer connections are incorrect. After shutdown and de-excitation of the generator, and removal of the short-circuit bride, the short-circuit tests are completed. No further tests are required for unbalanced load protection, overcurrent time protection, thermal overload protection, impedance protection and out-of-step protection. Switch the overcurrent time protection and the impedance protection operative (address 1201: O/C I> = ON resp. address 1401 O/C Ip = ON, address 3301: IMPEDANCE PROT. = ON). They serves from now on as short-circuit protection. If used, the I>> stage (address 1301 O/C I>> = ON), the thermal overload protection (address 1601: Ther. OVER LOAD = ON), the unbalanced load protection (address 1701: UNBALANCE LOAD = ON) and the out-of-step protection (address 3501: OUTOF-STEP = ON) can be switched to be operative. Otherwise, they are set to OFF.

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3.4.3

Checking the Differential Protection

Preparation

Before commencing any primary tests, make sure that the configured object is actually the one you want to protect, and that the correct amplitude matching for the current ratings of the protected object and the main primary c.t.s, and the correct vector group matching are set. Set the differential protection (address 2001) to Block. relay, or interrupt the trip command lines. The test arrangement varies dependent of the application. On network power transformers and asynchronous machines a low-voltage test equipment is preferably used. A low-voltage current source is used to energize the protected object, which is completely disconnected from the network (Figure 3-23). A short-circuit bridge, which is capable of carrying the test current, is installed outside the protected zone and allows the symmetrical test current to flow. On power station unit transformers and synchronous machines, the checks are performed during the current tests, with the generator itself supplying the test current (Figure 3-24). The current is produced by a three-pole short-circuit bridge which is installed outside the protected zone and is capable of carrying rated current for a short time. The generator is started but not yet excited. Check by means of remanent currents that no current transformer is open or short-circuited. In order to achieve this, read out the operational measured values and check the operational currents one by one. Even when the currents and the measurement accuracy are still very small, the described errors can already be detected. The test current for commissioning tests must be at least 2 % of the rated relay current.

M 400 V 3~ 400 V

400 V 3~ 400 V

7UM62

Test source Figure 3-23

7UM62

Test source

Current Test with Low-Voltage Current Source

G

7UM62

7UM62 7UM62

Figure 3-24

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Current Test in a Power Station

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Symmetrical Current Test

The operational measured values supplied by the 7UM62 allow a fast commissioning without external instruments. The indices of the measured currents are defined as follows: The symbol for current I is followed by the phase identifier Lx and by the index of the side of the protected object (e.g. the transformer winding). Example: IL1S1

Absolute Value Measurement

Current in phase L1 on side 1.

Compare the currents displayed at Measurement → Secondary Values → Operational values, secondary with those that are actually flowing. IL1S1 = IL2S1 = IL3S1 = IL1S2 = IL2S2 = IL3S2 = If deviations occur that cannot be explained by measuring tolerances, either the connection or the test arrangement is wrong: • Disconnect the protected object (shut down generator), and earth it, • Check and correct the connections and the test arrangement, • Repeat the test and re-check the measured values.

Angle Measurement

If the current magnitudes are consistent, the next step is to check the phase angle relations between the currents (ϕIL1S1, ϕIL2S1, ϕIL3S1, ϕIL1S2, ϕIL2S2, ϕIL3S2). The angle differences are referred to winding L1 of side 1. Check the angles that are output by the device for side 1 at Measurement → Secondary Values → Angles. All angles are referred to IL1S1. Consequently, a clockwise phase rotation should produce roughly the following results: ϕL1S1 = 0° ϕL2S1 = 240° ϕL3S1 = 120° If the angles are not correct, wrong polarity or phase interchange at side 1 is the cause. • Disconnect the protected object (shut down generator), and earth it, • Check and correct the connections and the test arrangement, • Repeat the test by renewed measurement request and re-check the measured values. Check the angles that are output by the device for side 2 at Measurement → Secondary Values → Angles. All angles are referred to IL1S1. If the angles are not correct, wrong polarity or phase interchange at side 2 is the cause; proceed as for side 1. The polarities of the through-flowing currents are here defined in such a manner, that for currents of equal phase flowing through the protected object, the angle difference at the two measuring points is 180° between currents of the same phase, provided that the connections are correct. Exception: Transverse differential protection, where both currents must be in phase. The theoretical angles depend on the protected object and – in the case of transformers – on the vector group. They are listed in Table 3-25 for clockwise phase rotation.

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The polarity of the current connections and the parameterized polarity are taken into consideration when the angles are displayed. Thus, if all three angles differ by 180° from the theoretical value, the polarity of one complete transformer set is wrong. This can be corrected by checking and changing the corresponding plant parameters: Address 0201 STRPNT->OBJ S1 for the primary winding, Address 0210 STRPNT->OBJ S2 for the secondary winding,

Table 3-25

Displayed Phase Angle Dependent on the Protected Object (Three-Phase)

Protect. Object→ ↓ Phase Angle

Generator/Motor

Transformer with Vector Group Numeral 1) 0

1

2

3

4

5

6

60°

30°

0°

7

8

9

10

ϕL1S2

180°

180° 150° 120°

90°

ϕL2S2

60°

60°

330° 300° 270° 240° 210° 180° 150° 120°

ϕL3S2

300°

1)

30°

0°

300° 270° 240° 210° 180° 150° 120°

11

330° 300° 270° 240° 210°

90°

60°

30°

0°

90° 330°

Values are valid for measurement if the higher voltage side is defined as side 1; when measuring from the lower voltage side, 360° minus the stated angle is valid

Differential and Restraint Currents

Before the tests with symmetrical currents are terminated, the differential and restraint currents are checked. Even though the tests which have been carried out so far should have revealed most of the possible connection errors, matching errors or wrong vector group allocations cannot be ruled out. Switch to the operational measured values to read out the calculated values. When assessing the currents, note that the differential and restraint values are referred to the rated current of the protected object. This fact should be kept in mind when comparing them to the test currents. If considerable differential currents occur, recheck the following parameters: For transformer protection (as per Section 2.12.2.2): addresses 0241, 0249 and 0202 (matching of winding 1), 0243, 0249 and 0211 (matching and vector group of winding 2); For generator or motor protection (as per Section 2.12.2.2): addresses 0251 and 0252 (matching of machine ratings); The symmetrical current tests are now completed. Disconnect the protected object (shut down generator) and earth it, remove the test equipment. Switch the differential protection to being operative (address 2001: DIFF. PROT. = ON); it works now as a short-circuit protection for all subsequent tests.

3.4.4

Checking the Earth Current Differential Protection

Preparation

The primary test checks the correct integration of the 7UM62 into the system, especially the CT connection. Before commencing any primary tests, make sure that the configured object is actually the one you want to protect. To do so, verify the settings used in the configuration of the protection function, in Power System Data 1 and in the protection function itself. Set the earth current differential protection (address 2101 REF PROT.) to Block relay, or interrupt the trip command lines.

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Primary tests of power units are performed with the generator itself. On transformers, a low-voltage test source is used. Before the test, the CT connections have to be visually checked for correctness. Note: When performing the short-circuit test (3-phase short-circuit) for the earth current differential protection, check that the three current transformers (side 1 or side 2 – whichever side is used for the earth current differential protection) are identical in design. To do so, read out the percentages of the operational measured values 3I0-1 and 3I0-2 (in DIGSI in the differential protection measured values). If the CTs are correctly matched, the values must be zero. Values that are not zero must be taken into account for the protection settings. Primary Test with Generator

This test is performed in addition to the current test. The protection must be set to maximum sensitivity. The zero voltage release must be blocked (address 2103 REF U0>RELEASE = 0). For the test, one phase is earthed and the generator is excited (see Figure 3-25). The test current must not exceed the permissible negative-sequence current. If this current amounts e.g. to I2perm. = 10 % IN,G, the test current must be less than 30 % IN,G. On the other hand, the current is determined by the low-resistance starpoint earthing. 10 % of the rated generator current are sufficient for testing.

either connection possible

Figure 3-25

7UM62

Testing the Earth Current Differential Protection on the Generator

For the external fault, read out the percentages of the operational measured values (on the device: Measured values→ I -Diff,I-Stab): 3I0–1

Calculated zero sequence current of side 1

3I0–2

Calculated zero sequence current of side 2 or measured earth current IEE2 (depending on configuration)

I0–Diff

Calculated differential current

I0–Stab

Calculated restraint (stabilizing) current

Both zero sequence currents 3I0-1 and 3I0-2 must be equal, and correspond to the current fed in. The differential current I0-Diff is nearly zero. The restraint (stabilizing) current I0-Stab is twice the flowing current. If the differential and the restraint current are equal, the polarity of one CT must be wrong. This can also be seen from the phase angle EDS |∆Φ| shown on the device in the phase angles, or in DIGSI. 0° means an internal fault, and 180° an external fault. Minor deviations are caused by CT errors.

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If there are deviations, a connection error can be normally assumed. If necessary, modify the wiring, or, in Power System Data 1, the allocation of the CT starpoint for the phase CTs or the earth CT IEE2. For the phase CTs, keep in mind that they are also used by other protection functions, such as the differential current protection, and check for possible interaction. If the differential current protection has already been checked, and the CTs of side 1 and 2 are used for the earth current differential protection as well, the above errors can be excluded. If the IEE2 input is used, a wrong polarity of the connections is not uncommon. Check the connection and/or the starpoint allocation in Power System Data 1 (address 214 GRD TERM. IEE2). The default setting assumes that terminal Q7 is looking towards the protected object. If there are deviations in the measured values, the measured quantities are probably not properly matched. Check the parameter settings of the protected object and of the CTs in Power System Data 1. To do so, proceed as follows: − Shut down and earth generator − Check and correct connections, if necessary, or modify settings in Power System Data 1 − Repeat measurement If the earth current differential protection is used on a transformer, a comparative test is performed (see Figure 3-26). Measured value 3I0-1 is allocated to side 1 and 3I0-2 to the earth current IEE2. The test method is similar to the one described above. For the test current, it is essential to ensure that on the generator side the continuously permissible unbalanced load current is not exceeded. With a wye-delta connection, the single-phase fault is modeled on the generator side as a phase to phase fault.

7UM62 Figure 3-26

Test with Secondary Test Equipment

Testing the Earth Current Differential Protection on the Transformer

Measurements are always performed from the side with the earthed starpoint. In transformers, there must be a delta winding (d-winding or compensating winding). The winding not involved in the test remains open, because the delta winding automatically provides for a low resistance of the zero sequence current path. The test arrangement varies dependent of the application. Figures 3-27 to 3-30 show examples of test arrangements, with Figure 3-27 being the preferred type for generator protection.

DANGER! Primary measurements must only be carried out on disconnected and earthed equipment of the power system. Danger to life exists even on disconnected equipment because of capacitive coupling from other energized equipment of the power system!

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∼

Test source

7UM62 Figure 3-27

∼

Measurement of the Zero Sequence Currents in a Wye-Delta Transformer

Test source

7UM62 Figure 3-28

∼

Measurement of the Zero Sequence Currents in a Delta-Delta Transformer with Compensating Winding

Test source

7UM62 Figure 3-29

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Measurement of the Zero Sequence Currents in a Zigzag Winding

371


∼

Test source

7UM62 Figure 3-30

Measurement of the Zero Sequence Currents in a Delta Winding with Artificial Starpoint

A zero sequence current of at least 2 % the rated generator current is required per phase, i.e. the test current is at least 6 %. In the protection function, the sensitive pickup threshold must be set, and the zero voltage release disabled. − Switch on test current − Perform absolute value measurement with test current switched on Read out the measured quantities on the device under: Measured values → I-Diff,I-Stab: 3I0–1

Calculated zero sequence current of side 1 or side 2 (depending on configuration)

3I0–2

Measured earth current IEE2

I0–Diff

Calculated differential current

I0–Stab

Calculated restraint (stabilizing) current

Both zero sequence currents 3I0-1 and 3I0-2 must be equal, and correspond to the current fed in. The differential current I0-Diff is nearly zero. The restraint (stabilizing) current I0-Stab is twice the flowing current. If the differential and the restraint current are equal, the polarity of one CT must be wrong. Minor deviations are caused by CT errors. When checking the phase CTs of the allocated side, the measured values (device: Measurement → Operational values, secondary) per phase will be 1/3 each of the applied zero sequence current. The phase angle is the same in all 3 phases due to the zero sequence current. If there are deviations, a connection error can be normally assumed (see side title “Primary Test with Generator”) − Disconnect test source and protected object − Check and correct connections and test arrangement − Repeat measurement Checking the Zero Voltage Release

372

If the zero voltage release is used, it must be checked during the test of the stator earth fault protection (see Section 3.4.6). In the presence of an earth fault, the indication

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F.No. 05841 „REF U0> releas.“ must appear. When performing the test, keep in mind that the zero voltage is calculated from the three phase voltages and converted on the secondary side to the phase-to-phase voltage (equivalent to √3 U0). The value thus obtained is the same as for a broken delta winding. Blocking by Overcurrent

If the above measurement have been successfully performed, and the measured phase currents were plausible, it can be assumed that the current measurement works correctly. You only need to check the correct setting in the protection function (address 2102 = REF I> BLOCK). The pickup values are checked by injecting a current by means of some secondary test equipment (CTs need not be disconnected). • After completion of the tests, disconnect the test source and the protected object (shut down generator) • If parameters have been changed for the tests, restore the settings required for operation. • After completion of the earth fault protection tests, switch the earth current differential protection to be operative.

3.4.5

Checking the Voltage Circuits

General

The voltage circuits of the machine are checked to ensure the correct cabling, polarity, phase sequence, transformer ratio etc. of the voltage transformers - not to check individual protection functions of the device.

Earthing of the Voltage Transformers

When checking the voltage transformers, particular attention should be paid to the open delta windings because these windings may only be earthed in one phase.

Preparation

Set the overvoltage protection function to about 110 % of the rated generator voltage and give the trip on excitation. Switch frequency protection (address 4201) and overflux protection (address 4301) to Block relay. Check in the unexcited condition of the machine with the help of remanent voltages, that all short-circuit bridges are removed.

Note on Testing

The checks of all voltage transformer circuits (protection, measuring, metering etc.) are carried out with about 30 % of the rated transformer voltage. Tests with generator voltages of more than 30 % are only required when the idle characteristic is measured for the first time. The measuring circuit supervision of the rotor earth fault protection (see below) can be checked when testing the voltage circuits, or after the synchronization.

Amplitudes

Read out voltages in all three phases in the operational measured values. They can be compared with the actual voltages. The voltage of the positive sequence system U1 must be approximately the same as the indicated phase voltages. If this is not, the voltage transformer connections are incorrect (crossovers).

Phase Rotation

The phase rotation must conform with the configured phase sequence (address 0271 PHASE SEQ. under Power System Data 1); if it does not, an indication “Fail Ph.

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Seq.“ will be output. The allocation of measuring quantities to phases must be checked and corrected, if necessary. If signification deviations are found, check, and if necessary correct, the voltage transformer circuits and repeat the test. It is also possible to use for this check the operational measured value of positivesequence component U1 of the voltages: U1 ≠ UL-E indicates a wiring error. Measuring Circuit Supervision of the Rotor Earth Fault Protection

If the sensitive earth fault protection is used for rotor earth fault protection, the measuring circuit supervision of that protection function can be checked with the generator under voltage: − Start up the generator and excite it to rated voltage. Apply measurement brushes if necessary. Inject a test voltage between the rotor circuit and the earth by interposing the additional source device 7XR61. The earth current IEE that is flowing now can be read out on the device among the operational measured values. The value obtained is the capacitive spill current flowing in fault-free operation. − IEE< (address 5106) should be set to about 50 % of this capacitive spill current. It should also be checked that the set value IEE> (address 5102) is at least twice this measured spill current. Correct the set value if necessary.


The frequency protection function is verified by a plausibility check of the instantaneous machine speed and the associated operational measured value that is indicated.

Overexcitation

The frequency protection function is verified by a plausibility check of the instantaneous machine speed and the associated operational measured value that is indicated. U Instantaneous machine voltage Rated primary voltage of the UN U fN Instant. overexcitation = ---- ⋅ -------protected object f UN f Instantaneous frequency, in accordance with the machine frequency in Hz fN Rated frequency The voltage tests are completed after the generator has been shut-down. The required voltage and frequency protection functions are switched to be operative (address 4001: UNDERVOLTAGE = ON or OFF), (address 4101: OVERVOLTAGE = ON or OFF), (address 4201: O/U FREQUENCY = ON or OFF) and (address 4301: OVEREXC. PROT. = ON or OFF). Partial functions can be switched to be inoperative by appropriate limit value settings (e.g. f* set to rated frequency).

3.4.6

Checking the Stator Earth Fault Protection The procedure for checking the stator earth fault protection depends mainly on whether the generator is connected to the network in unit connection or in busbar connection. In both cases correct functioning and protected zone must be checked. In order to check interference suppression of the loading resistor, and in order to verify the protected zone of the earth fault protection, primary tests are suggested, once with an earth fault at the machine terminals (e.g. with 20 % of the rated transformer voltage) and once with a network earth fault.

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3.4.6.1

Unit Connection

General

In the event of an external (high-voltage side) short-circuit, an interference voltage is transmitted via the coupling capacitance CC (Figure 3-31) which induces a neutral displacement voltage on the generator side. To ensure that this voltage is not interpreted by the protection as an earth fault within the generator, it is reduced by a suitable loading resistor to a value which corresponds to approximately one half the pick-up voltage U0> (address 5002). On the other hand, the earth fault current resulting from the loading resistor in the event of an earth fault at the generator terminals should not exceed 10 A, if possible.

CC

CG

RB RT UE CG CL CTr CC

– – – – – – –

CTr

Loading resistor Voltage divider Neutral displacement voltage at 7UM62 Generator-earth capacitance Line–earth capacitance Winding–earth capacitance of block transformer Coupling capacitance of block transformer

Figure 3-31

Calculation of Protected Zone

CL

RB RT UE

7UM62

Unit Connection with Earthing Transformer

Coupling capacitance CC and loading resistor RB represent a voltage divider (equivalent circuit diagram Figure 3-32), whereby RB' is the resistance RB referred to the machine terminal circuit. UC

UNU/√3

ωCC UR’

UNU UC CC UR’ RB’

~

UR’

UNU √3

U C

Rated voltage on upper–voltage side of block transformer Voltage at coupling capacitance CK Total coupling capacitance between upper–voltage and lower–voltage windings Voltage across loading resistor Loading resistor of earthing transformer, referred to machine circuit.

Figure 3-32

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RB’

Equivalent Diagram and Vector Diagram

375


Since the reactance of the coupling capacitance is much larger than the referred resistance of the loading resistor RB', UC can be assumed to be UC ≈ UNU/√3 (compare also vector diagram Figure 3-32), whereby UNU/√3 is the neutral displacement voltage with a full displacement of the network (upper-voltage) neutral. The following applies: ,

,

RB UR ----------------------- = --------------------------1 ⁄ ( ωC C ) U NU ⁄ ( 3 ) ,

,

U R = R B ⋅ ωC C ⋅ U NU ⁄ ( 3 ) Inserting the voltage transformation ratio TR of the earthing transformer: 2

, TR U R = -------- ⋅ U R 3

, TR R B = æ --------ö ⋅ R B è 3 ø

and

we obtain: TR U R = -------- ⋅ R B ⋅ ωC C ⋅ U NU ⁄ ( 3 ) 3 Together with the voltage divider 500 V/100 V this corresponds to a displacement voltage of: 1 TR U E = --- ⋅ -------- ⋅ R B ⋅ ωC C ⋅ U NU ⁄ ( 3 ) 5 3 The pick-up value for the neutral displacement voltage U0> should amount to at least twice the value of this interference voltage. Example: Network:

UNU = fN = CC =

Voltage transformer

110 kV 50 Hz 0.01 µF 10 kV/0.1 kV


TR

=

36

Loading resistor

RB

=

10

Ω

1 36 –1 –6 3 110 U E = --- ⋅ ------ ⋅ 10 Ω ⋅ 314 s ⋅ 0.01 ⋅ 10 F ⋅ ---------- ⋅ 10 V = 4.8 V 5 3 3 10 V has been chosen as the setting value for U0> in address 5002 which corresponds to a protective zone of 90% (Figure 3-33). Note: When using a neutral earthing transformer, TR must be inserted as the voltage transformation ratio instead of TR/3. The result is the same since the neutral earthing transformer has only one winding.

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UE U ERD> Pick–up value

1,0

Earth fault on machine side Value extrapolated to 100 % UNmach

0,5 Earth fault on upper voltage side 10 %

40 % corresponds to 90 % protected zone

Figure 3-33

Checking for Generator Earth Fault

100 % U UN mach

Neutral displacement voltage during earth faults

Switch stator earth fault protection S/E/F PROT. (address 5001) to Block relay. If the sensitive earth fault protection is used for stator earth fault protection, it must be set to Block relay as well under address 5101. With the primary plant voltage-free and earthed, install a single-pole earth fault in the proximity of the generator terminals.

DANGER! Primary measurements must only be carried out with the generator at stand– still on disconnected and grounded equipment of the power system. Start up generator and slowly excite (however, not above UN/√3) until the stator earth fault protection picks-up. Read out UE from the operational measured values and check for plausibility. If the connections are correct, this value corresponds with the machine terminal voltage in percent, referred to rated machine voltage (if applicable, deviating rated primary voltage of earthing transformer or neutral earthing transformer must be taken into account). This value also corresponds with the setting value U0> under address 5002 If the plant comprises more voltage transformers with broken delta windings, the voltage UE must be measured on them as well. For protection zone Z the following applies: U sec N – U0> Z = ---------------------------------- ⋅ 100 % U sec N Example: Machine voltage at pick-up

0.1 x Usec N

Measured value

UE

= 10 V

Setting value

U0>

= 10 V

Protected zone

Z

= 90 %

Read out the indication “Uearth Lx” in the fault annunciations. The “Lx” indicates the faulted phase provided voltages are connected to the voltage protection inputs of 7UM62. Shut down generator. Remove earth fault bridge.

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Check Using Network Earth Fault

With the primary plant voltage-free and earthed, install a single-pole earth fault bridge on the primary side of the unit transformer.

DANGER! Primary measurements must only be carried out with the generator at stand– still on disconnected and grounded equipment of the power system.

Caution! The starpoints of the unit transformer must not be connected to earth during this test! Start up machine and slowly excite to 30 % of rated machine voltage. Read out UE in the OPERATIONAL MEASURED VALUES. This value is extrapolated to rated machine voltage (Figure 3-33). The fault value thus calculated should correspond, at the most, to half the pick-up value U0> (address 5002), in order to achieve the desired safety margin. Shut down generator. Remove earth fault bridge. If the starpoint of the high-voltage side of the unit transformer is to be earthed during normal operation, re-establish starpoint earthing. Switch stator earth fault protection to be operative: address 5001 S/E/F PROT. = ON. If the sensitive earth fault detection is used for stator earth fault protection, switch it to be operative as well: address 5101 O/C PROT. Iee> = ON.

3.4.6.2

Busbar Connection Firstly, the correct functioning of the loading equipment must be checked: sequencing, time limit, etc., as well as the plant data, the earthing transformer and the value of the load resistor (tapping). Switch stator earth fault protection (address 5001) to Block relay. If the sensitive earth fault detection is used for stator earth fault protection, switch it to Block relay as well under address 5101. With the primary plant earthed and voltage-free, install earth fault bridge between generator terminals and toroidal current transformer (Fig. 3-34).

DANGER! Primary measurements must only be carried out with the generator at stand– still on disconnected and grounded equipment of the power system.

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G Σ UN ------3 100 ---------- V 3

RL

100 ---------- V 3

UE

IEE2

7UM62 Figure 3-34

Earth Fault with Busbar Connection

The generator circuit breaker must be closed for this test and the generator galvanically connected with the load equipment. If the plant conditions do not allow this, the hints given overleaf under the side title “Directional check without Loading Resistor” must be observed. Start up generator and slowly excite until the stator earth fault protection picks up: alarm “U0> picked up” (not allocated when delivered from factory). At the same time the alarm “3I0> picked up” should appear, if marshalled. Read out UE and IEE under OPERATIONAL MEASURED VALUES. If the connections are correct, this value corresponds with the machine terminal voltage in percent, referred to rated machine voltage (if applicable, deviating rated primary voltage of earthing transformer or neutral earthing transformer must be taken into account). This value also corresponds to the setting value U0> in address 5002. The measured value IEE2 should be approximately equal to or slightly higher than the setting value 3I0> under address 5003.This is to ensure that the protection zone that is determined by the setting value U0> is not reduced by a too slow pick-up. For protection zone Z the following applies: U sec N – U0> Z = ---------------------------------- ⋅ 100 % U sec N Example:

7UM62 Manual C53000-G1176-C149-3

Machine voltage at pick-up

0.1 x Usec N

Measured value

UE

= 10 V

Setting value

U0>

= 10 V

Protected zone

Z

= 90 %

379


With Directional Determination

The earth fault directional determination requires a check of the current and voltage connections for correctness and correct polarity. The machine continues to be excited to a voltage that corresponds to a displacement voltage above the pick-up value. If the polarity is correct, the trip indication “S/E/F TRIP“ is output (LED 6 when delivered from factory). A cross check is then performed. After the generator has been de-excited and shut down, the earth fault bridge is installed on the other side of the current transformers (as viewed from the machine).

DANGER! Primary measurements must only be carried out with the generator at stand– still on disconnected and grounded equipment of the power system. After restarting and exciting the generator above the pick-up value of the displacement voltage, “U0> picked up” picks up (LED 2 for global indication of a device pick-up when delivered from factory), however “3I0 picked up” does not pick up and tripping does not occur. The measured value IEE should be negligible and on no account should it be larger then half the setting value 3I0>. Shut down and de-excite generator. Remove earth fault bridge. Directional Check with Toroidal CTs without Loading Resistor

If loading equipment is not available and if an earth fault test with the network is not possible, then the following test can be performed with secondary measures, however with the symmetrical primary load current: With current supplied from a toroidal residual current transformer, a voltage transformer (e.g. L1) is by-passed which simulates the formation of a neutral displacement voltage (Figure 3-35). From the same phase, a test current is fed via a current-limiting impedance Z through the toroidal transformer. The connection and direction of the current conductor through the toroidal transformer is to be closely checked. If the current is too small for the relay to pick-up, then its effect can be increased by feeding the conductor several times through the toroidal transformer. For Z either a resistor (30 to 500 Ω) or a capacitor (10 to 100 µF) in series with an inrush-current-limiting resistor (approximately 50 to 100 Ω) is used. With correct connections, the described circuit results in the alarms: “U0 > picked up”, “3I0> picked up” and finally “S/E/F Trip” (LED 6).

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G l

k

Z

L1 L2 L3

n

Q7

Q8

e

R14

R13

UE

IEE2

7UM62 Figure 3-35

Directional Check with C.T.'s in Holmgreen Connection

Directional Check with Toroidal Residual Current Transformers

If the current is supplied from a set of c.t.'s in Holmgreen connection (Figure 3-36), the displacement voltage is obtained in the same manner as in the above circuit. Only the current of that current transformer which is in the same phase as the by-passed voltage transformer in the delta connection is fed into the current path. In case of active power in generator direction, the same conditions apply for the relay - in principle - as with an earth fault in generator direction in a compensated network and vice versa.

G

L1 L2 L3

n

e

RT Q7

Q8

R14

R13

UE

IEE2

7UM62 Figure 3-36

7UM62 Manual C53000-G1176-C149-3

Directional Check with Current Transformers in Holmgreen Connection

381


If, in an isolated network, the voltage connections for the reactive current measurement should be maintained for testing, then it should be noted that with a power flow with inductive component in forwards direction results in a backwards direction for the earth fault relay (contrary to an earth fault in this direction). Shut down generator after completion of the directional tests. Correct connections must be re-established and re-checked. Spill Current

For calibration to the spill current, a three-pole short-circuit bridge that is able to withstand rated current is installed at the circuit breaker. Start up generator and slowly excite until the rated machine current is reached. Read out the operational measured value IEE2. This measured values determines the setting value of address 5003 3I0>. Parameter 3I0> should be about twice that measured value to ensure a sufficient security distance between the earth fault current used for directional determination and the spill current. Next, check whether the protection zone determined by the setting value U0> must be reduced. Switch the stator earth fault protection to be operative: address 5001 S/E/F PROT. = ON.

3.4.7

Testing the 100–% Stator Earth Fault Protection The 100-% stator earth fault connection is tested together with the 90-% stator earth fault protection (see Section 3.4.6.1, Unit Connection). Set the 100-% stator earth fault connection (address 5301 100% SEF-PROT.) to Block relay (if you have not done so already). Also, the accessories of the protection device must be operational. The tests to be performed are described in more detail below.

Check without Earth Fault

Start up the generator and excite it to maximum generator voltage. The protection does not pick up. The operational measured values need to be checked as well (see also Section 3.3.8). Read out the r.m.s. current I SEF. The fault value thus obtained should not exceed half the pickup value SEF I>> (address 5306) to allow for the desired safety margin. Shut down the generator.

Check Performed with an Earth Fault in the Machine Zone

Connect the 20 Hz generator 7XT33 to the DC voltage or to an external three-phase voltage source. With the primary equipment disconnected and earthed, insert a single-pole earth fault bridge in the generator terminal circuit.

DANGER! Primary measurements may only be carried out with the generator at stand–still on disconnected and grounded equipment of the power system. Start up the generator and excite it slowly (but to less than UN/√3) until the 90-% earth fault protection (Pickup threshold U0>) has picked up (see also Section 3.4.6.1, side title “Checking for Generator Earth Fault”).

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With the earth fault bridge in place, the resistance stages of the 100-% protection (warning and trip stage) must pick up immediately on switching in the supply voltage of the 20 Hz generator. To check the pickup behaviour of the current stage SEF100 I>>, read out the measured value I SEF from the operational measured values at approx. 10 % to 20 % of the displacement voltage. The value thus obtained should be about the same as the pickup value SEF I>> selected at address 5306. This ensures that the current stage of the 100-% stator earth fault protection covers a protection zone of about 80 % to 90 % of the winding in addition to the 100 % resistance calculation. Check Using Network Earth Fault

With the primary plant voltage-free and earthed, install a single-pole earth fault bridge on the primary side of the unit transformer.

DANGER! Primary measurements may only be carried out with the generator at stand–still on disconnected and grounded equipment of the power system.

Caution! The starpoints of the unit transformer must not be connected to earth during this test! Start up the generator and slowly excite to 30 % of rated machine voltage (max. 60 %). The 100-% and the 90-% stator earth fault protection do not pick up. The checks to be performed for the 90-% stator earth fault protection are described in Section 3.4.6.1, side title “Checking for Generator Earth Fault”. For the 100-% stator earth fault protection, read out the operational measured value I SEF. This value is extrapolated to approx. 1.3 times the rated machine voltage. The current thus extrapolated should not exceed half the pick-up value SEF I>> (address 5306) in order to achieve the desired safety margin of the current stage of the 100-% stator earth fault protection. Shut down and de-excite the generator. Remove earth fault bridge. If the starpoint of the high-voltage side of the unit transformer is to be earthed during normal operation, re-establish starpoint earthing. If the 20 Hz generator is to be fed by the voltage transformers of the machine terminals, the appropriate connections, or a different type of supply connection (e.g. DC voltage supply from a battery) must now be permanently made. If no more special tests are to be made, switch the 100-% stator earth fault protection to be operative: address 5301 100% SEF-PROT. = ON.

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3.4.8

Checking the Sensitive Earth Fault Protection when Used for Rotor Earth Fault Protection If the sensitive earth fault protection is used for rotor earth fault protection, it must first be set to Block relay under address 5101.

Caution! Make sure that the checked rotor circuit is completed isolated from the earth, to avoid that the earthing resistor that is interposed for test purposes causes a double earth fault! An earth fault is simulated via a resistor which is roughly equivalent to the desired trip resistance. In generators with rotating rectifier excitation, the resistor is placed between the measurement slip rings; in generators with excitation via slip rings between one slip ring and earth. Start up generator and excite to rated voltage. If applicable place measurement brushes into operation. It is irrelevant in this context whether the sensitive earth fault protection picks up or not. The earth fault current IEE that is flowing now can be read out on the device among the operational measured values. Check that this measured earth fault current is roughly equal to the pick-up value IEE> for sensitive earth fault detection that has been set in address 5102. However, it must not be set to less that the double value of the spill current that has been determined in section 3.4.5 for healthy insulation. For generators with excitation via slip rings, the test is repeated for the other slip ring. Shut down generator. Remove earth fault resistor. The sensitive earth fault detection used for rotor earth fault protection is then set to be operative: O/C PROT. Iee> = ON in address 5101.

3.4.9

Checking the Rotor Earth Fault Protection During Operation

3.4.9.1

Rotor Earth Fault Protection (R, fn) In Section 3.3.7, the rotor earth fault protection was checked with the machine at stand-still. In order to exclude possible interference on the measurement circuit by the running generator, an additional test during operation is recommended.

Caution! Make sure that the checked rotor circuit is completed isolated from the earth, to avoid that the earthing resistor that is interposed for test purposes causes a double earth fault! An earth fault is simulated via a resistor of approximately 90% of the trip resistance (RE<< TRIP, address 6003). In machines with rotating rectifier excitation (Figure 319 left), the resistor is placed between the measurement slip rings; in machines with excitation via slip rings (Figure 3-19 right) between one slip ring and earth.

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Start up generator and excite to rated voltage. If applicable place measurement brushes into operation. The rotor earth fault protection initiates pick-up and, after T-TRIP-RE<< (10 s when delivered from factory), trip annunciation (LED 2 and LED 1 as group indications for device pickup and device trip). The earth resistance calculated by the device can be read out in the earth fault annunciations as Re. For generators with excitation via slip rings, the test is repeated for the other slip ring. Shut down generator. Remove earth fault resistor. Switch the rotor earth fault protection ROTOR E/F = ON under address 6001.

3.4.9.2

Rotor Earth Fault Protection (1 to 3 Hz) In Section 3.3.7.2, the rotor earth fault protection was checked with the machine at stand-still. In order to exclude possible interference on the measurement circuit by the running generator, and specifically by the excitation system, an additional test during operation is recommended.

Caution! Make sure that the checked rotor circuit is completed isolated from the earth, to avoid that the earthing resistor that is interposed for test purposes causes a double earth fault! An earth fault is simulated via a resistor of approximately 90% of the trip resistance (address 6104 RE<< TRIP). In machines with rotating rectifier excitation (Figure 319 left), the resistor is placed between the measurement slip rings; in machines with excitation via slip rings (Figure 3-19 right) between one slip ring and earth. Start up the generator and excite to the rated voltage. If applicable place measurement brushes into operation. Check the operational measured value Rearth and the pickup indication (“REF 1-3Hz Fault”) and, after T-TRIP-RE<< (10 s on delivery) has expired, check the trip indication (“REF 1-3Hz Trip”) as well. Set the resistance to approx. 90 % of the warning stage (address 6102 RE< WARN), read out the operational measured value Rearth, and check the warning message (“REF 1-3Hz Warn”). If there is heavy interference from the excitation system, it may be necessary to reduce the resistance set for the warning threshold. Remove the earthing resistor and check the operational measured values as well as the measuring circuit supervision “REF 1-3Hz open” in fault-free condition. If spontaneous indications are issued by the measuring circuit monitoring, reduce the pickup value (address 6106 Qc) or de-activate the monitoring. For generators with excitation via slip rings, the test is repeated for the other slip ring. Shut down generator. Remove earth fault resistor. Switch the rotor earth fault protection REF 1-3Hz = ON under address 6101.

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385


3.4.10 Tests with the Generator Connected to the Network 3.4.10.1 Checking the Correct Connection Polarity The following test instructions apply to a synchronous generator. Run up generator and synchronize with network. Slowly increase driving power input (up to approximately 5%). The active power is read out under the operational measured values (percent values) as a positive active power P in percent of the rated apparent power SN. If a negative active power value should be read out, then the actual polarity relationship between current transformers and voltage transformers does not accord with the polarity parameterized under address 0210 (STRPNT->OBJ S2: Yes/No) or a wrong setting has been selected for address 1108 (ACTIVE POWER: Generator/ Motor). Re-parameterize address 0210. If the power reading is still incorrect, the fault must be in the instrument transformer connections (e.g. cyclic exchange of phases): − Fix faults of the transformer lines (current and/or voltage transformers); observe for this the safety rules! − Repeat test.

3.4.10.2 Measurement of Motoring Power (Reverse Power) and Angle Error Correction For a generator, leave the reverse power protection and the forward active power supervision switched to OFF for the moment. This function and the following measurements are not required for motors. The motoring power is – as an active power – almost constant and independent of the reactive power, i.e. independent of the excitation current. However, the protection relay may calculate different active power values dependent of the excitation because of possible angle errors of the current and voltage transformers. The motoring power curve then would not be a straight line in parallel to the real axis of the power diagram of the machine. Therefore, the angle deviations should be measured at three measuring points of the power diagram and the correction parameter W0 should be established. The angle errors caused by the device’s internal input transformers have already been compensated in the factory. This check is recommended if the reverse power protection is set to “sensitive”. Reduce driving power to zero by closing the regulating valves. The generator now takes motoring energy from the network.

Caution! For a turbine set, the intake of reverse power is only permissible for a short time, since operation of the turbine without a certain throughput of steam (cooling effect) can lead to overheating of the turbine blades! 1. Adjust excitation until the reactive power amount to approximately Q = 0. To check this, read out the active power with sign (negative) in the operational measured values and note it down as P0 (see table below). Read out the reactive power with sign in the operational measured values and note it down as Q0 (see table below). 2. If possible slowly increase excitation to 0.3 times rated apparent power of generator (overexcited).

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7UM62 Manual C53000-G1176-C149-3


− Read out the motoring power with polarity (negative sign) in the operational measured values and note it down as P1 (see table below). − Read out the reactive power with polarity (positive sign) in the operational measured values and note it down as Q1 (see table below). 3. If possible reduce excitation to approximately 0.3 times rated apparent power of generator (underexcited).

Caution! Underexcitation may cause the generator fall out of step!

− Read out the motoring power with polarity (negative sign) in the operational measured values under and note it down as P2 (see table below). − Read out the reactive power with polarity (negative sign) in the operational measured values and note it down as Q2 (see table below). 4. Adjust generator to no-load excitation and shut down or select the desired operational state. underexcited Q2

P/PN

overexcited Q1

Q/QN

P1 P2

Figure 3-37

P0

Item

Active power

Reactive power

1

P0

Q0

2

P1

Q1

3

P2

Q2

Determination of the Correction Angle W0

The read-out measured values P1, and P2 are now used to carry out angle error correction. Calculate according to the following formula: P –P

1 2 ϕcorr = atan --------------------

Q1 – Q2

The power values must be inserted with their correct polarity as read out! Otherwise faulty result! This angle ϕcorr is entered with reversed sign as the new correction angle under address 0204 CT ANGLE W0: New setting CT ANGLE W0 = – ϕcorr A quarter of the sum of the measured values P1 + P2 is set as pick-up value of the reverse power protection P> REVERSE under address 3102.

3.4.10.3 Calibrating the Reverse Power Protection If the generator is connected with the network, reverse power can be caused by − closing of the regulating valves, − closing of the trip valve Because of possible leakages in the valves, the reverse power test should – if possible – be performed for both cases.

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387


In order to confirm the correct settings, repeat reverse power test again. For this, the reverse power protection (address 3101) is set to BLOCK relay in order to check its effectiveness (using the annunciations). Start up generator and synchronize with network. Close regulating valves. From the operational measured value for the active power, the motoring power measured with the device can be derived. 50 % of that value should be taken as the setting for the reverse power protection. Increase driving power. Stop Valve

The last test with the stop valve can be performed with a live trip. It is assumed that the binary input “>SV tripped” is marshalled correctly and is controlled by the stop valve status (by a pressure switch or a limit switch at the stop valve). Close stop valve. From the operational measured value for the active power, the motoring power measured with the device can be derived. If that value should be found to be less than the reverse power with the stop valves closed, 50 % of that value should be taken as the setting for the reverse power protection.

Shut down the generator by activating the reverse power protection on: Switch ON the reverse power protection (address 3101) and - if used - the forward power supervision (address 3201).

3.4.10.4 Checking the Underexcitation Protection Underexcitation

The angle error correction value CT ANGLE W0, which has been determined in section 3.4.10.2 and configured under address 0204 for use with the angle error correction, applies also to the underexcitation protection. In section 3.4.10.2, the measured values of the reactive power have been read out, and thus a plausibility check of that measured value with directional check has been carried out. No further checks are required. If you choose nevertheless to perform an additional load level measurement and by this a directional check, proceed as follows:

Caution! Underexcitation may cause the generator to fall out of step, in particular with increased active power!

Check with Load

Set the underexcitation protection to Block relay (address 3001). The proper functioning is checked by approaching freely selected load levels under overexcited and then underexcited conditions. The plausibility check is carried out by reading out the relevant operational measured values and comparing them to the measured values obtained from the station control and protection system. Switch the underexcitation protection ON (address 3001).

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7UM62 Manual C53000-G1176-C149-3


Note:

If operation with capacitive load is not possible, then load points can also be checked in the inductive (overexcited) range. In this case, the polarity of the current transformer connections must be re-parameterized (address 0223). Thus, the characteristics of the underexcitation protection are mirrored around the origin. It must be noted that the reverse power protection must be switched OFF (address 3101) as its characteristic is also mirrored from the motor into the generator range.

Stability Limit

Since the protective device shows each load level through the operational measured values, it is not necessary to approach the underexcitation limit line.

3.4.10.5 Checking the Directional Function of the Overcurrent Time Protection When the polarity of the connections is checked as described in subsection 3.4.10.1, the direction of the protection function I>> (section 2.7) is unambiguously determined by the definition of the reference arrow (generator reference-arrow system). When the generator produces an active power (operational measured value P is positive), and address 1108 ACTIVE POWER is set to Generator, the power system is located in forward direction and the generator in reverse direction. In order to exclude accidental misconnections, it is recommended to carry out a check with a low load current. Proceed as follows: − Set the directional high current stage 1301 O/C I>> to Block relay and the pick-up value I>> (address 1302) to the most sensitive value (= 0.05 A with a rated current of 1 A and 0.25 A with a rated current of 5 A). − Increase the load current (ohmic, or ohmic inductive) until it exceeds the pick-up value, and, as soon as the pick-up annunciations (FNo. 1801 through 1803) have appeared, read out the annunciations 01806 “I>> forward” and 01807 “I>> backward”. − Compare the indicated direction with the setpoint (setting value and address 1304 Phase Direction). In the standard application with terminal-side current transformers (Figure 2-11), address 1304 Phase Direction must be set to REVERSE, and the indication “I>> forward” (FNo. 01806) must appear. − Re-set the pick-up value in address 1302 back to the original value and the protection function in address 1301 to ON.

3.4.11 Triggering Oscillographic Recordings At the end of commissioning, an investigation of switching operations of the circuit breaker(s) or primary switching device(s), under load conditions, should be done to assure the stability of the protection during the dynamic processes. Oscillographic recordings (also called fault records) obtain the maximum information about the behaviour of the 7UM62. Requirements

To obtain oscillographic records, Address 0104 FAULT VALUE under the DEVICE CONFIG. menu must be set to Instantaneous values or RMS values. Along with the capability of recording waveform data during system faults, the 7UM62 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 “>Trig.Wave.Cap.”

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(FNo 00000004). Triggering for the oscillographic recording then occurs when the input is energized. For example, an auxiliary contact of the circuit breaker or primary switch may be used to control the binary input for triggering. An oscillographic recording that is externally triggered (that is, without a protective element pick-up 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. The externally triggered record has a number for establishing a sequence. Triggering with DIGSI® 4

To trigger oscillographic recording with DIGSI® 4, click on Test in the left part of the window. Double click the entry Test Wave Form in the list in the right part of the window to trigger the recording. See Figure 3-38. 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 DIGRA® program or the Comtrade Viewer program is required to view and analyse the oscillographic data.

Figure 3-38

390

Triggering oscillographic recording with DIGSI® 4

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3.5 Final Preparation of the Device

3.5

Final Preparation of the Device Verify all terminal screws are tight and secure. Do not overtighten. Ensure that all pin connectors are properly inserted. Verify the wires to the terminals are tightly connected. Make sure the communication cables are firmly connected; however, do not overtighten the screws.

Caution! Do not use force! The stud torque must not be exceeded, since the threads and terminal screws may be damaged! 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 masking are especially important (Section 2.2) as well as the power system data, and activated Groups A and B. All desired elements and functions must be set ON. See Chapter 2. Keep a copy of all of the in-service settings on a PC. Check the internal clock of the device. If necessary, set the clock or synchronize the clock if the element is not automatically synchronized. For assistance, refer to the SIPROTEC®4–System Manual. The Annunciation memory buffers should be cleared, particularly the Event Log and Trip Log. Future information will then only apply for actual system events and faults. To clear the buffers, press MAIN MENU → Annunciation → Set/Reset. Refer to the SIPROTEC®4 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 MAIN MENU → Annunciation → Statistic. Refer to the SIPROTEC®4 System Manual if more information is needed. Press the

ESC

key, several times if necessary, to return to the default display.

Clear the LEDs on the front panel by pressing the LED key. Any binary outputs that were picked up prior to clearing the LEDs are reset when the clearing action is performed. Future illuminations of the LEDs will then apply only for actual events or faults. Pressing the LED 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 “RUN” LED must be on. The red “ERROR” 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

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4

Technical Data

This chapter provides the technical data of the SIPROTEC® 4 7UM62 device and the individual functions of the device, including the limiting values that under no circumstances may be exceeded. The electrical and functional data for devices equipped with all options are followed by the mechanical data with dimensional drawings.

7UM62 Manual C53000-G1176-C149-3

4.1

General Device Data

395

4.2

Definite-Time Overcurrent Protection (ANSI 50, 67)

406

4.3

Inverse-Time Overcurrent Protection (ANSI 51, 67)

407

4.4


412

4.5


414

4.6


416

4.7

Differential Protection for Generators and Motors (ANSI 87G/87M)

417

4.8

Differential Protection for Transformers (ANSI 87T)

419

4.9

Earth Current Differential Protection (ANSI 87GN/TN)

422

4.10


423

4.11


424

4.12

Forward Power Supervision (ANSI 32F)

425

4.13


426

4.14


427

4.15


428

4.16


430

4.17


431

4.18


432

4.19

Rate-of-Frequency-Change Protection (ANSI 81R)

434

4.20


435

4.21


436

4.22


437

4.23

100–%–Stator Earth Fault Protection with 3rd Harmonics (ANSI 27/59TN 3rd Harm.) 438

393

4 Technical Data

394

4.24

100–% Stator Earth Fault Protection with 20 Hz Voltage Injection (ANSI 64G, –100 %) 439

4.25

Rotor Earth Fault Protection (R, fn, ANSI 64R)

440

4.26

Sensitive Rotor Earth Fault Protection with 1 to 3 Hz (ANSI 64R)

441

4.27


442

4.28


443

4.29


444

4.30

Inadvertent Energization (ANSI 50/27)

445

4.31


446

4.32

Thermoboxes for Temperature Detection

447

4.33

Additional Functions

448

4.34

Operating Ranges of the Protection Functions

455

4.35

Dimensions

457

7UM62 Manual C53000-G1176-C149-3

4.1 General Device Data

4.1

General Device Data

4.1.1

Analog Inputs

Current Inputs

Nominal Frequency

fN

50 Hz or 60 Hz

Nominal Current

IN

1 A or 5 A

Ground Current, SensitiveIEE

(adjustable)

≤ 1.6 A

Burden per Phase and Ground Path – At IN = 1 A Approx. 0.05 VA – At IN = 5 A Approx. 0.3 VA – Sensitive Ground Fault Detection 1 A Approx. 0.05 VA AC Current Overload Capability – Thermal (rms)

– Dynamic (Current pulse)

100 30 4 250

· IN < 1 s · IN < 10 s · IN continuous · IN for 0.5 cycle

AC Current Overload Capability for Sensitive Ground Fault Detection – Thermal (rms) 300 A < 1 s 100 A < 10 s 15 A continuous – Dynamic (impulse) 750 A for 0.5 cycle Voltage Inputs


Analog Output(s) (for Operational Measured Values)

Secondary Nominal Voltage Measuring Range Burden at 100 V

100 V to 125 VAC 0 V to 170 VAC Approx. 0.3 VA

AC Voltage Input Overload Capacity – Thermal (rms)

230 V continuous

Measuring range between

–10 V and +10 V or –20 mA and +20 mA

Input resistance for DC voltage Input resistance for DC Current

Approx. 1 MΩ Approx. 10 Ω

Voltage Input Overload Capacity

60 V– continuous

Current Input Overload Capacity

100 mA– continuous

Nominal Range Operating Range

0 to 20 mA– 0 to 22.5 mA–

– Connection for Flush Mounted Case

Rear panel, mounting loc. "B" or/and "D" 9-pin DSUB port

for Panel-Surface Mounted Case – Max. Burden

7UM62 Manual C53000-G1176-C149-3

At the terminal on the case bottom or/and at the housing top 350 Ω

395

4 Technical Data

4.1.2

Power Supply

Direct Voltage

Voltage Supply Via Integrated Converter Nominal Power Supply Direct Voltage VPS nom Permissible Voltage Ranges

24/48 VDC 19 to 58 VDC

60/110/125 VDC 48 to 150 VDC

Nominal Power Supply Direct Voltage VPSnom 110/125/220/250 VDC Permissible Voltage Ranges 88 to 300 VDC

Permissible AC Ripple Voltage, peak to peak

≤15 % of the power supply voltage

Power Consumption 7UM621 7UM622

quiescent

Approx. 5.3 W Approx. 5.5 W

energized

Approx. 12 W Approx. 15 W

7UM621 7UM622

Bridging Time for Failure/Short Circuit

Alternating Voltage

Power Consumption 7UM621 7UM622

quiescent

7UM621 energized 7UM622 Bridging Time for Failure/Short Circuit

115 VAC (50/60 Hz) 92 to 132 VAC

Approx. 5.5 VA Approx. 5.5 VA Approx. 13 VA Approx. 15 VA ≥ 200 ms

Binary Inputs and Outputs

Binary Inputs

396

50 ms at V ≥ 48 VDC (UH,N = 24/48 V) 50 ms at V ≥110 VDC (UH,N = 60..125 V) 20 ms at V ≥ 24 VDC (UH,N = 24/48 V) 20 ms at V ≥ 60 VDC (UH,N = 60..125 V)

Voltage Supply via Integrated Converter Nominal Power Supply Alternating Voltage VPS AC Permissible Voltage Ranges

4.1.3

≥ ≥ ≥ ≥

Number 7UM621∗– 7UM622∗–

7 (configurable) 15 (configurable)

Nominal Voltage Range Current Consumption, Energized

24 VDC to 250 VDC, bipolar Approx. 1.8 mA, independent of the control voltage

Switching Thresholds

Adjustable voltage range with jumpers

7UM62 Manual C53000-G1176-C149-3


Output Relays1)

Binary inputs: – For Nominal Voltages 24/48/60/ 110/125 VDC

2 ranges UPU ≥ 19 VDC UDO ≤ 14 VDC

– For Nominal Voltages 110/125/ 220/250 VDC

UPU ≥ 88 VDC UDO ≤ 66 VDC

Maximum Permissible Voltage

300 VDC

Impulse Filter on Input

220 nF Coupling Capacitor at 220 V with recovery time > 60 ms

Output Relays for Commands/Annunciations Number

7UM621∗– 7UM622∗–

Switching Capability

MAKE BREAK

12 (1 NO contact each, 3 optionally as NC contacts) 20 (1 NO contact each, 4 optionally as NC contacts) 1 Alarm relay (NC contact or NO contact, switch selectable)

Switching Voltage

1000W/VA 30 W/VA 40 W resistive 25 W at L/R ≤ 50 ms 250 V

Permissible Current per Contact and Total Current on Common path

5 A continuous 30 A for 0.5 s

1

) UL–listed with the following nominal value: 120 VAC 240 VAC 240 VAC 24 VDC 48 VDC 240 VDC 120 VAC 240 VAC

LEDs

4.1.4

Number RUN (green) ERROR (red) User-programmable LEDs (red)

Pilot duty, B300 Pilot duty, B300 5 A General Purpose 5 A General Purpose 0.8 A General Purpose 0.1 A General Purpose 1/6 hp (4.4 FLA) 1/2 hp (4.9 FLA)

1 1 14

Communications Interfaces

PC Front Interface

7UM62 Manual C53000-G1176-C149-3

– Connection

Front panel, non-isolated, RS 232, 9-pin DSUB port for connecting a personal computer

– Operation

with DIGSI® 4

397

4 Technical Data

– Transmission Speed

Rear Service–/ Modem– Interface

– Maximum Distance of Transmission

Min. 4800 Baud; max. 115200 Baud Factory Setting: 38400 Baud; Parity: 8E1 15 meters / 49 feet

– Connection

Isolated interface for data transfer

– Operation

With DIGSI® 4


Min. 4800 Bd, max. 38400 Bd Factory Setting: 38400 Bd

RS232/RS485

Depends on order code

– Connection for Flush Mounted case

Rear panel, mounting location “C“ 9-pin DSUB port

for Panel-Surface Mounted Case – Test Voltage

At the terminal on the case bottom 500 VAC

RS232 – Maximum Distance of Transmission

15 meters / 49 feet

RS485 – Maximum Distance of Transmission SCADA Interface

1 km / 3280 feet / 0.62 mile

IEC 60870–5–103 RS232/RS485 Depends on order code

Floating interface for data transfer to a master terminal

RS232 – Connection for Flush Mounted Case

For Panel SurfaceMounted Case

At the terminal on the case bottom

– Test Voltage

500 VAC




15 meters / 49 feet

RS485 – Connection for Flush Mounted Case


398

Rear panel, mounting location “B“ 9-pin DSUB port

rear panel, installation location “B“ 9-pin DSUB Port RS 485 at the terminal on the case bottom Profibus cable

– Test Voltage

500 VAC




1 km / 3280 feet / 0.62 mile

Fibre Optical Link – Connector Type With Flush-Mounted Case

ST–Connector Rear panel, mounting location “B“

7UM62 Manual C53000-G1176-C149-3


For Panel SurfaceMounted Case – Optical Wavelength

On the case bottom λ = 820 nm

– Laser Class 1 Under EN 60825–1/ –2 using glass fiber 50/125 µm or using glass fiber 62.5/125 µm – Optical Link Signal Attenuation – Channel Distance – Character Idle State Profibus RS485 (DP) – Connection for Flush Mounted Case

For Panel SurfaceMounted Case – Test Voltage Transmission Speed – Maximum Distance of Transmission

DNP3.0 RS485 – Connection for Flush-Mounted Case For Panel SurfaceMounted Case

rear panel, installation location “B“ 9-pin DSUB Port RS 485 At the terminal on the case bottom 500 V AC up to 12 M Baud 1 km / 3280 feet / 0.62 mile at≤ 93.75 kBd 500 m /1640 feet / 0.31 mile at≤ 187.5 kBd 200 m / 660 feet at ≤ 1.5 MBd 100 m/ 330 feet at ≤ 12 MBd rear panel, mounting location “B“ 9-pin DSUB Port RS 485 on the case bottom

– Test Voltage

500 VAC


up to 19200 Baud


1 km / 3280 feet / 0.62 mile

MODBUS RS485 – Connection for Flush-Mounted Case For Panel SurfaceMounted Case

rear panel, mounting location “B“ 9-pin DSUB Port RS 485 on the case bottom

– Test Voltage

500 VAC


up to 19200 Baud


1 km / 3280 feet / 0.62 mile

Profibus Fibre Optical Link (DP) – Connection

For Flush-Mounted Case

ST–Connector, for FMS single ring or twin ring, depending on order; for DP only double ring rear panel, mounting location “B“


On the case bottom

– Transmission Speed Recommended:

7UM62 Manual C53000-G1176-C149-3

Max. 8 dB, with glass fiber 62.5/125 µm Max. 1.5 km (0.95 miles) selectable: factory setting “Light off”

Up to 1.5 M Baud > 500 k Baud

399

4 Technical Data

– Optical Wavelength

λ = 820 nm

– Laser Class 1 Under EN 60825–1/ –2 Using glass fiber 50/125 µm or Using glass fiber 62.5/125 µm – Optical Link Signal Attenuation – Channel Distance

Max. 8 dB, with glass fiber 62.5/125 µm Max. 1.5 km (0.95 miles)

DNP3.0 Fibre Optical Link – Connection For Flush-Mounted Case For Panel SurfaceMounted Case

ST–Connector, rear panel, mounting location “B“ On the case bottom


Up to 19200 Baud


λ = 820 nm



MODBUS Fibre Optical Link – Connection For Flush-Mounted Case For Panel SurfaceMounted Case

ST–Connector, Rear panel, mounting location “B“ On the case bottom


Up to 19200 Baud


λ = 820 nm



Analog Output Module (Electrical)

2 ports with 0 mA to 20 mA

– Connection for Flush Mounted Case

Rear panel, mounting location “B“ and “D” 9-pin DSUB Port RS 485

For Panel SurfaceMounted Case – Test Voltage Clock

500 VAC

– Time Synchronization DCF77/IRIG B–Signal – Connection For Flush-mounted Case Rear panel, mounting location “A“ 9-pin DSUB port For Panel SurfaceMounted Case – Signal Rated Voltage

400

On the case bottom

At the terminal on the case bottom Selectable 5 V, 12 V or 24 V

7UM62 Manual C53000-G1176-C149-3


– Signal Levels and Burdens:

VIHigh

6.0 V

Rated Signal Voltage 12 V 15.8 V

VILow

1.0 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

RI

890 Ω at VI = 4 V 640 Ω at VI = 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

5V

4.1.5

24 V 31 V

Electrical Tests

Specifications

Standards:

IEC 60255 (Product Standards) ANSI/IEEE C37.90.0,.C37.90.0.1 and C37.90.0.2 UL 508 DIN 57 435 Part 303 See also standards for individual functions

Insulation Tests

Standards:

IEC 60255–5, IEC 60870–2–1

– High Voltage Test (Routine Test) Current Inputs, Voltage Inputs, Output Relays

2.5 kV (rms) AC

– High Voltage Test (Routine Test) Power Supply and Binary Inputs

3.5 kVDC

– High Voltage Test (Routine Test) Measuring Transducers

3.0 kVDC

– High Voltage Test (Routine Test) Only Isolated Communications and Time Synchronization Interfaces and Analog Outputs (Ports A – D)

500 V (rms) AC

– Impulse Voltage Test (Type Test) 5 kV (peak): 1.2/50 µs: 0.5 Ws: 3 positive All Circuits Except Communications and 3 negative impulses in intervals of 5 s and Time Synchronization Interfaces, Analog Outputs, Class III EMC Tests for Immunity (Type Tests)

7UM62 Manual C53000-G1176-C149-3

Standards:

IEC 60255–6 and –22 (Product standards), EN 50082–2 (Generic standard) DIN 57 435 Part 303 ANSI/IEEE C37.90.1 and C37.90.2

– High Frequency Test IEC 60255–22–1, Class III and VDE 0435 Part 303, Class III

2.5 kV (Peak): 1 MHz: τ = 15 µs; 400 Surges per s: Test Duration 2 s Ri = 200 Ω

– Electrostatic Discharge IEC 60255–22–2 Class IV and IEC 61000–4–2, Class IV

8 kV contact discharge: 15 kV airdischarge, both polarities: 150 pF: Ri = 330 Ω

401

4 Technical Data

– Irradiation with HF Field, Non-Modulated IEC 60255–22–3 (Report) Class III

10 V/m: 27 MHz to 500 MHz

– Irradiation with HF Field, Amplitude Modulated IEC 61000–4–3, Class III

10 V/m: 80 MHz to 1000 MHz: 80 % AM: 1 kHz

– 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 Variables/ 4 kV: 5/50 ns: 5 kHz: Burst length = 15 ms; Burst 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 (SURGE), IEC 61000–4–5 Installation Class 3 Power Supply Measuring Inputs, Binary Inputs and Relay Outputs

1.2/50 µs

common mode: diff. mode: common mode: diff. mode:

2 kV: 12 Ω: 9 µF 1 kV: 2 Ω: 18 µF 2 kV: 42 Ω: 0.5 µF 1 kV: 42 Ω: 0.5 µF

– Line Conducted HF, Amplitude Modul. 10 V: 150 kHz to 80 MHz: 80 % AM: 1 kHz IEC 61000–4–6, Class III – Power System Frequency Magnetic Field IEC 61000–4–8, Class IV IEC 60255–6

30 A/m continuous: 300 A/m for 3 s: 50 Hz 0.5 mT: 50 Hz

– Oscillatory Surge Withstand Capability 2.5 to 3 kV (Peak Value): 1 MHz to 1.5 MHz ANSI/IEEE C37.90.1 damped 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 Pulse per s; 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 C37.90.2 amplitude and pulse modulated

EMC Tests For Noise Emission (Type Test)

402

– Damped Oscillations Similar to IEC 60694–4–12, IEC 61000–4–12

2.5 kV (Peak Value), polarity alternating 100 kHz, 1 MHz, 10 MHz and 50 MHz, Ri = 200 Ω

Standard:

EN 50081 (Generic Standard)

– Radio Noise Voltage to Lines, Only Power Supply Voltage IEC–CISPR 22

150 kHz to 30 MHz Limit Class B

– Radio Noise Field Strength IEC–CISPR 11

30 MHz to 1000 MHz Limit Class A

7UM62 Manual C53000-G1176-C149-3


4.1.6

Mechanical Stress Tests

Vibration and Shock Stress During Operation

Vibration and Shock Stress During Transport

4.1.7

Standards:

IEC 60255–21 and IEC 60068

– Vibration IEC 60255–21–1, Class 2 IEC 60068–2–6

Sinusoidal 10 Hz to 60 Hz: ±0.075 mm amplitude; 60 Hz to 150 Hz: 1 g acceleration frequency sweep rate 1 Octave/min 20 cycles in 3 orthogonal axes.

– Shock IEC 60255–21–2, Class 1 IEC 60068–2–27

Half-sine shaped acceleration 5 g, duration 11 ms, 3 shocks in each direction of 3 orthogonal axes

– Seismic Vibration IEC 60255–21–3, Class 1 IEC 60068–3–3

Sinusoidal 1 Hz to 8 Hz ± 3.5 mm amplitude (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

Standards:

IEC 60255–21 and IEC 60068–2

– Vibration IEC 60255–21–1, Class 2 IEC 60068–2–6

Sinusoidal 5 Hz to 8 Hz: ±7.5 mm Amplitude; 8 Hz to 150 Hz: 2 g acceleration Frequency sweep rate1 Octave/min 20 cycles in 3 orthogonal axes.

– Shock IEC 60255–21–2, Class1 IEC 60068–2–27

Half-sine shaped Acceleration 15 g, duration 11 ms, 3 shocks in each direction of 3 orthogonal axes.

– Continuous Shock IEC 60255–21–2, Class 1 IEC 60068–2–29

Half-sine shaped Acceleration 10 g, duration 16 ms, 1000 shocks in each direction of 3 orthogonal axes.

Climatic Stress Tests

Ambient Temperatures

– Type tested (acc. IEC 60068–2–1 and –2, Test Bd for 16 h)

–13 °F to +185 °F or –25 °C to +85 °C

– Temporarily allowed operating temperature (tested for 96 h) – 4 °F to +158 °F or –20 °C to +70 °C

7UM62 Manual C53000-G1176-C149-3

403

4 Technical Data

– Recommended permanent operating temperature (acc. IEC 60255–6) +23 °F to +131 °F or –5 °C to +55 °C Visability of display may be impaired above +131 °F – Limiting temperature during permanent storage

–13 °F to +131 °F or –25 °C to +55 °C

– Limiting temperature during transport

–13 °F to +158 °F or –25 °C to +70 °C

STORE AND TRANSPORT THE DEVICE WITH FACTORY PACKAGING. Humidity

Permissible Humidity

Mean value per year ≤75% relative humidity, on 56 days of the year up to 93% relative humidity. CONDENSATION MUST BE AVOIDED

Siemens recommends that all devices 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 protective device is designed for use in an industrial environment and an electrical utility environment. Proper installation procedures should be followed to ensure electromagnetic compatibility (EMC). 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 while the protective device is energized. When handling the modules or the device outside of the case, standards for components sensitive to electrostatic discharge (ESD) must be observed. The modules and device are not endangered when inserted into the case.

4.1.9

Certifications

UL listing

Models with threaded terminals

7UM62∗∗–∗B∗∗∗–∗∗∗∗ 7UM62∗∗–∗E∗∗∗–∗∗∗∗

UL recognition

Models with plug–in terminals

7UM62∗∗–∗D∗∗∗–∗∗∗∗

404

7UM62 Manual C53000-G1176-C149-3


4.1.10 Construction Case

7XP20

UL–certification conditions:

“For use on a Flat Surface of a Type 1 Enclosure”

Dimensions

see dimensional drawings, Section 4.35

Weight (Mass) – In Case for Flush Mounting, 1/2 of 19” – In Case for Flush Mounting, 1/1 of 19”

16.5 pounds (7.5 kg) 22 pounds (9.5 kg)

– In Case for Surface Mounting, 1/2 of 19” 26.5 pounds (12 kg) – In Case for Surface Mounting, 1/1 of 19” 33 pounds (15 kg) International Protection Under IEC 60529 – In the Surface Mounted Case – in the Flush Mounted Case and in Model with the Detached Operator Interface Front Back – For Human Safety

7UM62 Manual C53000-G1176-C149-3

IP 51

IP 51 IP 50 IP 2x Terminals covered with protection cap

405

4 Technical Data

4.2

Definite-Time Overcurrent Protection (ANSI 50, 67)

Pickup and Delay Time Ranges/ Resolutions

Pickup Current

50–1

0.25 A to 100.00 A1) (Increments 0.05 A)1)

Pickup Current

50–2


Delay Times T

50–1, 50–2,

0.00 s to 60.00 s (Increments 0.01 s) or ∞ (does not expire)


U<

10.0 V to 125.0 V

(Increments 0.1 V)

Holding Time of Undervoltage Seal–In

0.10 s to 60.00 s

(Increments 0.01 s)

Inclination of Directional Characteristic

–90° el. to +90° el.

(Increments 1° el.)

The set times are pure delay times. Inherent Operating Times

Pickup Times 50–1, 50–2 – Current = 2 x Pickup Value – Current = 10 x Pickup Value

Approx. 35 ms Approx. 25 ms

Dropout Times 50–1, 50–2

Approx. 50 ms

Dropout

Dropout/Pickup (Ratio) 50–1 Dropout/Pickup (Ratio) 50–2 Dropout/Pickup (Ratio) U< Pickup Value – Dropout Value (∆ϕ)

Approx. 0.95 for I/IN ≥ 0.3 0.90 to 0.99 (Increments 0.01) Approx. 1.05 2° electrical

Tolerances

Pickup Current 50–1, 50–2

1 % of setting value or 50 mA1)


U<

1 % of setting value or 0.5 V

Delay Times

T

1 % of setting value or 10 ms

Angle Tolerance

ϕ

1° electrical

Influencing Variables for Pickup

Power Supply Direct Voltage in Range 0.8 ≤ UPS/ UPS nominal ≤ 1.15

1%

Temperature in Range 23 °F ≤ ϑamb ≤ 131 °F –5 °C ≤ ϑamb ≤ 55 °C

0.3 % / 10 °F 0.5 % / 10 K

Frequency in Range 0.95 ≤ f/fN ≤ 1.05

<1%

Harmonic Currents – Up to 10 % 3rd Harmonics – Up to 10 % 5th Harmonics

<1% <1%

1)

406

For IN = 1 A, divide all limits and increments by 5.

7UM62 Manual C53000-G1176-C149-3

4.3 Inverse-Time Overcurrent Protection (ANSI 51, 67)

4.3

Inverse-Time Overcurrent Protection (ANSI 51, 67)

Pickup and Time Multiplier Ranges/ Resolutions

Trip Time Characteristics As Per IEC

Pickup Current

51


Time Multipliers for 51 IEC Characteristics

Tp

0.05 s to 3.20 s (Increments 0.01 s) or ∞ (delay does not expire)

Time Multiplier for 51 ANSI Characteristics

D

0.50 to 15.00 (Increments 0.01) or ∞ (delay does not expire)

Undervoltage Release

U<

10.0 V to 125.0 V

(Increments 0.1 V)

As per IEC 60255-3, Section 3.5.2 or BS 142 (See also Figure 4-1) NORMAL INVERSE (Type A)

0.14 t = ---------------------------------- ⋅ T p [s] 0.02 ( I ⁄ Ip ) –1

VERY INVERSE (Type B)

13.5 t = --------------------------- ⋅ T p [s] 1 ( I ⁄ Ip ) – 1

EXTREMELY INV. (Type C)

80 t = --------------------------- ⋅ T p [s] 2 ( I ⁄ Ip ) – 1 For All Characteristics t Tp I Ip

Trip time in seconds Setting value of the time multiplier Fault current Setting value of the pickup current

The trip times for I/Ip ≥ 20 are identical to those for I/Ip = 20.

Tolerances


Pickup Threshold

Approx. 1.10 · Ip

Dropout Threshold

Approx. 1.05 · Ip for Ip/IN ≥ 0.3

Pickup Currents Ip

1 % of setting value, or 50 mA1)

Voltage Threshold U<

1 % of setting value, or 0.5 V

Trip Time for 2 ≤ I/Ip ≤ 20

5 % of reference (calculated) value + 1 % current tolerance, respectively 40 ms


1%


0.3 % / 10 °F 0.5 % / 10 K


<1%


<1% <1%

1

) For IN = 1 A, divide all limits and increments by 5.

7UM62 Manual C53000-G1176-C149-3

407

4 Technical Data

100

100

t [s]

t [s] 30

30

20

20 Tp

10

10

3.2

5

5 1.6

3 2 1 0.5

Tp

3

3.2

0.8

2

0.4

1

1.6

0.2

0.5

0.8

0.3

0.4

0.3 0.2

0.1

0.1

0.05

0.2 0.2

0.05

0.1 0.05

0.05 1

2

3

5

7

10

20

1

I/Ip

3

5

10

20 I/Ip

0, 14 t = -------------------------------------- ⋅ T [s] p 0, 02 (I ⁄ Ip ) –1

Normal inverse: (Type A)

2

0.1

Very inverse: (Type B)

13, 5 t = ---------------------------- ⋅ T p [s] 1 (I ⁄ I ) – 1 p

100

t [s] 20 10 5 3 2 1

Tp 3.2

0.5

t Tp I Ip

Trip time in seconds Setting value of the time factor Fault current Setting value of the pickup current

1.6

0.3 0.2

0.8 0.1

0.4 0.1 0.2

0.05

0.05 1

2

3

5

10

20 I/Ip

80 Extremely Inverse: t =80--------------------------⋅ T [s] Extremely inverse: - ⋅ 2T -[s] t = --------------------------p p 2 (Type C) ( I ⁄ I (Type C) ( I ⁄ I ) – 1p ) – 1 p

Figure 4-1

408

Trip Characteristics of the Inverse-time Overcurrent Protection, as per IEC 60755–3 (Phases and Ground)

7UM62 Manual C53000-G1176-C149-3


Trip Time Characteristics As Per ANSI

As per ANSI/IEEE (see also Figures 4-2 and 4-3)

VERY INVERSE

æ 3.922 ö t = ç --------------------------- + 0.0982÷ ⋅ D [s] 2 è ( I ⁄ Ip ) – 1 ø

INVERSE

æ ö 8.9341 t = ç --------------------------------------- + 0.17966÷ ⋅ D [s] 2.0938 è ( I ⁄ Ip ) ø –1

MODERATELY INV.

æ 0.0103 ö t = ç ---------------------------------- + 0.0228÷ ⋅ D [s] 0.02 è ( I ⁄ Ip ) ø –1

EXTREMELY INVERSE

æ 5.64 ö t = ç --------------------------- + 0.02434÷ ⋅ D [s] 2 è ( I ⁄ Ip ) – 1 ø

DEFINITE INVERSE

æ ö 0.4797 t = ç --------------------------------------- + 0.21359÷ ⋅ D [s] è ( I ⁄ I p ) 1.5625 – 1 ø For all Characteristics t D I Ip

= Trip time in seconds = Setting value of the time multiplier = Fault Current = Setting value of the pickup current

The trip times for I/Ip ≥ 20 are identical to those for I/Ip = 20.

Tolerances


Pickup Threshold

Approx. 1.10 · Ip

Dropout Threshold

Approx. 1.05 · Ip for Ip/IN ≥ 0.3 corresponds to approx. [0.95 · pickup threshold]

Pickup Currents Ip

1 % of setting value, or 50 mA1)

Voltage Threshold U<

1 % of setting value, or 0.5 V

Trip Time for 2 ≤ I/Ip ≤ 20

5 % of reference (calculated) value + 1 % current tolerance, respectively 40 ms


1%


0.3 % / 10 °F 0.5 % / 10 K


<1%

1)

7UM62 Manual C53000-G1176-C149-3


409

4 Technical Data

500

500

t [s]

t [s] 200

200

100

100

50

50

30 20

20

10

10

30

5

5

D [s]

3 2

D [s]

3

15

2

10

1

10

1

5

15

0.5 0.3 0.2

5

0.5

2

0.3 0.2

1

0.1

1

0.1

0.5

0.5

0.05 1

2

3

5

10

2

0.05

20

1

2

3

5

10

I/Ip æ ö 3, 922 t = ç ---------------------------- + 0, 0982÷ ⋅ D [s] ç ÷ 2 è (I ⁄ Ip ) – 1 ø

VERY INVERSE

20 I/Ip

INVERSE

æ ö 8, 9341 t = ç --------------------------------------------- + 0, 17966÷ ⋅ D [s] ç ÷ 2, 0938 –1 è ( I ⁄ Ip ) ø

500 t [s] 200 100 50 30 20 10 5

D [s]

3

15 10

2 1

t D I Ip

trip time in seconds setting value of the time factor fault current setting value of the pickup current

5

0.5 2

0.3 0.2

1

0.1

0.5

0.05 1

2

3

5

10

20 I/Ip

MODERATELY INVERSE

Figure 4-2

410

æ ö 0, 0103 t = çç -------------------------------------- + 0, 0228÷÷ ⋅ D [s] 0, 02 –1 è ( I ⁄ Ip ) ø

Trip Time Characteristics of the Inverse-time Overcurrent Protection, as per ANSI/IEEE

7UM62 Manual C53000-G1176-C149-3


500

500

t [s]

t [s] 200

200

100

100

50

50

30 20

30 20

10

10

5 3

5

D [s]

3

15

2

2

10

1

5

1

D [s] 15

0.5

10

0.3 0.2

5

0.1 0.05 1

2

3

5

0.5 10

0.5

2

0.3 0.2

1

0.1

0.5

2

1

0.05 20

1

2

3

5

EXTREMELY INVERSE

Figure 4-3

I/Ip

æ ö 5, 64 t = çç ---------------------------- + 0, 02434÷÷ ⋅ D [s] 2 è (I ⁄ Ip ) – 1 ø

t D I Ip

20

10

I/Ip

DEFINITE INVERSE

æ ö 0, 4797 t = ç --------------------------------------------- + 0, 21359÷ ⋅ D [s] ç ÷ 1, 5625 –1 è ( I ⁄ Ip ) ø

Trip time in seconds Setting value of the time factor Fault current Setting value of the pickup current

Trip Time Characteristics of the Inverse-time Overcurrent Protection, as per ANSI/IEEE

7UM62 Manual C53000-G1176-C149-3

411

4 Technical Data

4.4


Setting Ranges/ Resolutions

K-Factor per IEC 60255-8

0.10 to 4.00

Time Constant τ Extension K-Factor kt - Factor when Machine Stopped

30 s to 32000 s (Increments 1 s) 1.0 to 10.0 relative to the time constant for the machine running (Increments 0.1)

Thermal Alarm (Θ ALARM)

ΘAlarm/ΘTrip

70 % to 100 % of the trip temperature rise (Increments 1 %)

Current Overload Alarm (I ALARM)

IAlarm


Rated Temperature Rise at Rated Sec. Current

40 °C to 200 °C 104 °F to 392 °F

(Increments 1 °C) (Increments 1 °F)

Cooling Medium Temperature for Scaling

40 °C to 300 °C 104 °F to 572 °F


Current Limiting


IMax therm.

Emergency Time Trip Characteristic Curve for (I/ k · IN) ≤ IMax therm.

Tolerances

Influencing Variables Referring to [k · IN]

10 s to 15000 s

(Increments 1 s)

See also Figure 4-4 Trip Characteristic Curve

Dropout Relations

(Increments 0.01)

I ö 2 æ I pre ö 2 æ ------------ – ------------è k ⋅ INø è k ⋅ I Nø t = τ ⋅ ln -----------------------------------------------I ö2 æ ------------ –1 è k ⋅ I Nø

Where:

t τ I Ipre k

Θ/Θtrip

Drops out with ΘAlarm

Θ/ΘAlarm

Approx. 0.99

I/IAlarm

Approx. 0.95

Referring to k · IN

2 % or 50 mA1); 2 % class per IEC 60255–8

Thermal Trip and Alarm Times

3 % or 1 s for I/(k ·IN) > 1.25; 3 % class per IEC 60255–8

Trip time Temperature rise time constant Load current Pre-load current Setting factor per VDE 0435 Part 3011 and IEC 60255–8 Nominal current of the device IN IMax therm. Current threshold up to which the above formula is valid

Power Supply DC Voltage (UDC) in Range 0.8 ≤ UPS/ UPS nominal ≤ 1.15 1% Temperature in Range 23 °F≤ ϑamb ≤ 131 °F –5 °C ≤ ϑamb ≤ 55 °C

0.3 % / 10 °F 0.5 % / 10 K


<1%

1


412

7UM62 Manual C53000-G1176-C149-3

4.4 Thermal Overload Protection (ANSI 49)

100

100 t [min]

t [min]

50

Parameter: Setting Value of Time Constant

30

50

30

τ [min] 20

20 1000

10

500

5

Parameter: Setting Value of Time Constant

10

τ [min]

5 200

1000

3

3 2

2 100

1

500

1 50 200

0.5

0.5 20

0.3 0.2

100

0.3 0.2

10

50

0.1

0.1 5

20 1

0.05 1

2

3

4

5

2

0.05

6 7 8 I/k

10 12

1

2

5

2 3

4

10 5

· IN

without pre-load and with IMax therm.= 8 ⋅ k ⋅ IN:

I ö2 æ ------------èk ⋅ I ø N t = τ ⋅ ln -------------------------------- [min] I -ö 2 æ ------------èk ⋅ I ø – 1 N

1

6 7 8 10 12 I/k · IN

with 90 % pre-load and with IMax therm.= 8 ⋅ k ⋅ IN:

2

I pre ö I -ö 2 æ ------------æ -------------÷ –ç èk ⋅ I ø è k ⋅ I Nø N t = τ ⋅ ln --------------------------------------------------- [min] I ö2 æ ------------- –1 èk ⋅ I ø N

illi Anwender

Figure 4-4

Trip Time Characteristic Curves for the Thermal Overload Protection (49)

7UM62 Manual C53000-G1176-C149-3

413

4 Technical Data

4.5



Permissible Unbalanced Load I2>/IN (Warn. Stage too)

3.0 % to 30.0 %

(Increments 0.1 %)

Tripping Stage (Definite Time)I2>>/IN

10 % to 100 %

(Increments 1 %)

Delay Times

T(I2>), T(I2>>) 0.00 s to 60.00 s (Increments 0.01 s) or ∞ (does not expire)

Asymmetry Factor

K

2.0 s to 100.0 s

(Increments 0.1 s)

Time for Cool Down

TCool down

0 s to 50000 s

(Increments 1 s)

Trip Characteristic

refer also to Figure 4-5 Trip Characteristic of the Thermal Replica K t = ---------------------2 ( I2 ⁄ IN ) Where:

Inherent Operating Times

t – Tripping time K – Asymmetry factor I2 – Negative sequence current – Nominal current of the device IN I2 perm. – Continuously permissible negative sequence current

Pickup Times Warning Stage I2>, Tripping Stage I2>>

Approx. 50 ms

Dropout Times Warning Stage I2>, Tripping Stage I2>>

Approx. 50 ms

Dropout

Warning Stage I2>, Tripping Stage I2>> Thermal Replica

Approx. 0.95 drop-off at I2 < I2 perm.

Tolerances

Pickup Values I2>, I2>>

3 % of setting value or 0.3 % unbal. load

Delay Times T


Thermal Replica for 2 ≤ I2/I2 perm.≤ 20

5 % of reference (calculated) value + 1 % current tolerance, or 600 ms


414


1%


0.3 % / 10 °F 0.5 % / 10 K


1%


1% 1%

7UM62 Manual C53000-G1176-C149-3

4.5 Unbalanced Load (Negative Sequence) Protection (ANSI 46)

Schieflast Negative Sequence t = f (I2/In)

100

10000 40 30 20

s 2000 1000

10

400

Parameter: Setting value FACTOR K 40 s 30 s 20 s 15 s 10 s

200 100

t

6 4 3

40 20 10

2 1

5s

4 1

2

2 1 0.05

0.07

3

0.1

4

0.2

5

6

0.3

7

0.4

8

9 10

0.5

2s 0.7

1

I2/In

K t = ---------------------2 ( I2 ⁄ IN ) Figure 4-5

Trip Characteristics of the Thermal Negative Sequence Protection Stage

7UM62 Manual C53000-G1176-C149-3

415

4 Technical Data

4.6

Startup Overcurrent Protection (ANSI 51) Pickup Current I>

0.10 to 20.00 A

(Increments 0.01 A) 1)

Delay Times T

0.00 to 60.00 s

(Increments 0.01 s) or ∞ (does not expire)


Pickup Times I>

120 ms or higher (dep. on signal frequency)

Dropout Times I>

120 ms or higher (dep. on signal frequency)

Dropout

Current Threshold I>

80 % or 0.05 I/In

Tolerances

Current Threshold I> f ≥ 3 Hz, I/IN < 5

<10 %

Delay Times T

1 % or 10 ms

Power Supply Direct Voltage in Range 0.8 ≤ UH/UHN ≤ 1.15

≤1%

Temperature in Range –5 °C ≤ ϑamb ≤ 55 °C

≤ 0.5 %/10 K

Frequency in Range 2 Hz ≤ f ≤ 10 Hz

≤ 10 %

Harmonics – Up to 10 % 3rd Harmonics – Up to 10 % 5th Harmonics

≤ 100 % (Considered in calculation) ≤ 100 % (Considered in calculation)

Setting Ranges/ Resolution


1)

416

With IN = 5 A multiply all thresholds and increments with 5.

7UM62 Manual C53000-G1176-C149-3

4.7 Differential Protection for Generators and Motors (ANSI 87G/87M)

4.7

Differential Protection for Generators and Motors (ANSI 87G/87M)


Pickup Characteristic

Pickup Times

Differential Current

IDIFF>/IN Gen

High-Current Stage

IDIFF>>/IN Gen 0.5 to 12.0 or ∞ (no trip)

Slope 1 Base Point 1 Slope 2 Base Point 2

I/IN Gen I/IN Gen


7UM62 Manual C53000-G1176-C149-3

(Increments 0.01) (Increments 0.1)

see also Figure 4-6 0.10 to 0.50 (Increments 0.01) 0.00 to 2.00 (Increments 0.01) 0.25 to 0.95 (Increments 0.01) 0.00 to 10.,00 (Increments 0.01)

Start Detection I/IN Gen Factor for Increase of Characteristic at Start Max. Permissible Starting Time

0.00 to 2.,00

(Increments 0.01)

1.0 to 2.0 0.0 to 180.0 s

(Increments 0.1) (Increments 0.1 s)

Add-On Stabilization I/IN Gen Duration of Add-On Stabilization

2.00 to 15.00 (Increments 0.01) (2 to 250) ⋅ dur. of period (system frequ.) or ∞ (does not expire)

Tripping time delay for IDIFF> and IDIFF>>

0.00 s to 60.00 s or ∞ (ineffective)

(Increments 0.01 s)

without parallel operation of other protection functions 50 Hz

60 Hz

− with ≥ 1.5 ⋅ setting IDIFF>/IN Gen, approx.

35 ms

35 ms

− with ≥ 1.5 ⋅ setting IDIFF>>/IN Gen, approx.

25 ms

22 ms

− with ≥ 5 ⋅ setting IDIFF>>/IN Gen, approx.

18 ms

17 ms

Dropout/Pickup Ratio Tolerances

0.05 to 2.00

Approx. 0.7

With Preset Transformer Parameters – Pickup Characteristic

± 3 % of setpoint value (for I < 5 ⋅ IN)

– Additional Delay Time

± 1 % of setting value or 10 ms

Power Supply Direct Voltage in Range 0.8 ≤ VPS/ VPS nominal ≤ 1.15

1%


0.3 % / 10 °F 0.5 % / 10 K


1 % (see also Figure 4-7)

417

4 Technical Data

I diff --------- 10 IN


9 2031 8 I DIFF>>

d

7 6

Tripping

5

Blocking c

4

SLOPE 2

3

SLOPE 1

2 1

2021 I DIFF>

b

Add-On Stabilization

a 1

2

3

4

5

6

7

8

9

10 11 12 13 14 15 16 17 18

BASE POINT 2 BASE POINT 1

I stab ----------IN

Figure 4-6 Pickup Characteristic for Generator or Motor Differential Protection

IXf 2

IDIFF>>/IN (settable) Setting value e.g. 0.1

1

0.6

Tripping

0.4

Legend: IDIFF Differential current = | I1 + I2 | IfN Current at system frequency Current at any frequency IXf within specified range

0.3 0.2

0.1

Blocking

0.05

0

10

20

30

40

50

60

70

80

f/Hz

Figure 4-7 Influence of Frequency in Generator or Motor Differential Protection

418

7UM62 Manual C53000-G1176-C149-3

4.8 Differential Protection for Transformers (ANSI 87T)

4.8

Differential Protection for Transformers (ANSI 87T)



Pickup Times

Differential Current

IDIFF>/IN transf 0.05 to 2.00

High-Current Stage

IDIFF>>/IN Transf 0.5 to 12.0 (Increments 0.1) or ∞ ( stage ineffective)

Slope 1 Base Point 1 Slope 2 Base Point 2

I/IN Transf I/IN Transf

7UM62 Manual C53000-G1176-C149-3

see also Figure 4-8 0.10 to 0.50 (Increments 0.01) 0.00 to 2.00 (Increments 0.01) 0.25 to 0.95 (Increments 0.01) 0.00 to 10.00 (Increments 0.01)

Start Detection I/IN Transf Factor for Increase of Characteristic at Start Max. Permissible Starting Time

0.00 to 2.00

(Increments 0.01)

1.0 to 2.0 0.0 to 180.0 s

(Increments 0.1) (Increments 0.1 s)


I/IN Transf

2.00 to 15.00

(Increments 0.01)

Inrush Stabilization Harmonics)

I2fN/IfN

10 % to 80 % (Increments 1 %) see also Figure 4-9

Stabilization (nth harm.) InfN/IfN (n = 3rd or 5th Harmonics)

10 % to 80 % (Increments 1 %) see also Figure 4-10

Release of Blocking I/IN Transf by Higher-Order Harmonics

0.5 to 12.0

(Increments 0.1)

Tripping Delay Time for IDIFF> and IDIFF>>


(Increm. 0.01 s)

Duration of Add-On Stabilization

(2 to 250) ⋅ dur. of period (system frequ.) or ∞ (ineffective)

Time for Cross-Blocking for 2nd, 3rd or 5th Harmonics

(0 to 1000) ⋅ dur. of period (system frequ.) or ∞ (continuous)

without parallel operation of other protection functions 50 Hz

60 Hz

− with ≥ 1.5 ⋅ Setting IDIFF>/IN Transf, approx.

35 ms

35 ms

− with ≥ 1.5 ⋅ Setting IDIFF>>/IN Transf, approx.

25 ms

22 ms

− with ≥ 5 ⋅ Setting IDIFF>>/IN Transf, approx.

18 ms

17 ms

Dropout/Pickup Ratio Tolerances

(Increments 0.01)

Approx. 0.7

With Preset Transformer Parameters – Pickup Characteristic

± 3 % of setpoint value (for I < 5 ⋅ IN)

– Inrush Restraint

± 3 % of setting value (for I2fN/IfN ≥ 15 %)

– Additional Delay Times

± 1 % of setting value or 10 ms

419

4 Technical Data



1%


0.3 % / 10 °F 0.5 % / 10 K


1 % (see also Figure 4-11)

I diff --------- 10 IN


9 d

2031 8 I DIFF>>

7 6

Tripping

5

Blocking SLOPE 2

c

4 3

SLOPE 1

2 1

2021 I DIFF>

b


a 1

2

3

4

5

6

7

8

9

10 11 12 13 14 15 16 17 18

BASE POINT 2 BASE POINT 1

Figure 4-8

I stab ----------IN

Pickup Characteristic of the Transformer Differential Protection

IfN IN Can be set to e.g. IDIFF>>/IN = 10

10.0

Tripping

5,0

2.0

Blocking

Can be set to e.g. 2ndharmonics = 15 %

1.0 Can be set to e.g. IDIFF>/IN = 0.2

0.5 0.2 0.1 0

0.1

0.2

0.3

0.4

0.5

I2f IfN

Figure 4-9 Restraining Influence of 2nd Harmonics in Transformer Differential Protection

420

7UM62 Manual C53000-G1176-C149-3

4.8 Differential Protection for Transformers (ANSI 87T)

IfN IN Can be set to e.g. IDIFF max n/IN = 4

4.0

Tripping

2.0

Blocking Can be set to e.g. 5th harmonic = 40 %

1.0

Can be set to e.g. IDIFF>/IN = 0.2

0.5

0.2

0.1 0

Figure 4-10

0.1

0.2

0.3

0.4

0.5

I5f IfN

Restraining Influence of Higher-Order Harmonics

IXf IDIFF>>/IN (settable) Setting value e.g. 5.0

12 10 5 3 2

Tripping 1.0

Blocking

0.5

(Blocking by 2nd harmonics)

0.3 0.2 0.15 0.05

Setting value e.g. 0.15 IDIFF>/IN (settable)

Blocking 10

20

30

40

50

60

70

80 f/Hz

Legend: IDIFF Differential current = | I1 + I2 | IfN Current at system frequency Current at any frequency IXf within specified range

Figure 4-11

7UM62 Manual C53000-G1176-C149-3

Influence of Frequency in Transformer Differential Protection

421

4 Technical Data

4.9

Earth Current Differential Protection (ANSI 87GN/TN)


Differential Current I-REF> I/InO

0.05 to 2.00

Characteristic: Basepoint I/InO

0.05 to 2.00

Characteristic: Slope

0.00 to 0.95

(Increments 0.01)

Delay Times T

0.00 to 60.00


Phase Current Blocking I> I/InO

1.0 to 2.5

(Increments 0.1)

Zero Voltage Release U0>

1.0 to 100.0

(Increments 0.1 V) oder disabled


Pickup Times

Approx. 25 to 55 ms

Dropout Times

Approx. 60 ms

Dropout


Approx. 0.90

Dropout/Pickup Ratio

Approx. 0.95


5 % of setpoint value or 0.02 I/InO

Phase Current Blocking I>

1 % of setting value or 0.01 I/InO

Zero Voltage Release U0>


Delay Times T



≤1%


≤ 0.5 %/10 K


≤1%


≤1% ≤1%

Tolerances


422

(Increments 0.01)

7UM62 Manual C53000-G1176-C149-3

4.10 Underexcitation (Loss-of-Field) Protection (ANSI 40)

4.10



Conductance Sections

1/xd CHAR.

0.25 to 3.00

(Increments 0.01)

Angle of Inclination

α1, α2, α3

50° to 120°

(Increments 1°)

Delay Time

T


Undervoltage Lock-Out

10.0 V to 125.0 V (Increments 0.1 V)

Excitation Voltage Uexc. < (via external upstream voltage divider)

0.50 V to 8.00 V

(Increments 0.01 V)


Pickup Times

Dropout

– Stator Criterion 1/xd CHAR., α Approx. 0.95 – Rotor Criterion Uexc. Approx. 1.05 or + 0.5 V – Undervoltage Lock-Out U1< Approx. 1.1

Tolerances

– – – – –



1%


0.3 % / 10 °F 0.5 % / 10 K


1%


1% 1%

7UM62 Manual C53000-G1176-C149-3

– Stator Criterion 1/xd CHAR., α Approx. 60 ms – Rotor Criterion Uexc. Approx. 60 ms – Undervoltage Lock-Out U1< Approx. 50 ms

Stator Criterion 1/xd CHAR. Stator Criterion α Rotor Criterion Uexc. Undervoltage Lock-Out U1< Delay Times T

3 % of setting value 1° electrical 1° or 0.1 V 1 % of setting value or 0.5 V 1 % of setting value or 10 ms

423

4 Technical Data

4.11



Reverse Power

Pr>/SN

–0.50 % to –30.0 %(Increments 0.01 %)

Delay Times

T


Pr>

Approx. 360 ms at 50 Hz Approx. 300 ms at 60 Hz

– Reverse Power

Pr>

Approx. 360 ms at 50 Hz Approx. 300 ms at 60 Hz

Dropout

– Reverse Power

Pr>

Approx. 0.6

Tolerances

– Reverse Power

Pr>

0.25 % SN ± 3 % of set value at Q < 0.5 SN (SN: rated apparent power, Q: reactive power)

– Delay Times

T



Pickup Times – Reverse Power Drop-Off Times


424


1%


0.3 % / 10 °F 0.5 % / 10 K


<1%


<1% <1%

7UM62 Manual C53000-G1176-C149-3

4.12 Forward Power Supervision (ANSI 32F)

4.12

Forward Power Supervision (ANSI 32F)



Forward Power

Pf
0.5 % to 120.0 % (Increments 0.1 %)

Forward Power

Pf>/SN

1.0 % to 120.0 % (Increments 0.1 %)

Delay Times

T


Pf<, Pf>

Approx. 360 ms at 50 Hz with high–accuApprox. 300 ms at 60 Hz racy measurement

Pickup Times – Forward Power

Approx. 60 ms at 50 Hz with high–speed Approx. 50 ms at 60 Hz measurement Dropout Times – Forward Power

Pf<, Pf>

Approx. 360 ms at 50 Hz with high–accuApprox. 300 ms at 60 Hz racy measurement Approx. 60 ms at 50 Hz with high–speed Approx. 50 ms at 60 Hz measurement

Dropout

– Forward Power

Pf< Pf>

Approx. 1.10 or 0.5 % of SN Approx. 0.90 or –0.5 % of SN

Tolerances

– Forward Power

Pf<, Pf>

0.25 % SN ± 3 % of set value with high–accuracy measurement 0.5 % SN ± 3 % of set value with high–speed measurement (SN: rated apparent power)

– Delay Times Influencing Variables for Pickup

7UM62 Manual C53000-G1176-C149-3

T



1%


0.3 % / 10 °F 0.5 % / 10 K


<1%


<1% <1%

425

4 Technical Data

4.13


Overcurrent Fault Detection

Pickup Current Drop-Off ratio

0.50 A to 100.00 A1) (Increm. 0.05 A)1) Approx. 0.95

Measuring Tolerances acc.to VDE 0435 part 303

1 % of set value or 50 mA1)

Undervoltage Seal-In U<

10.0 V to 125.0 V

Drop-Off ratio

Approx. 1.05

1)

Impedance Measurement

IMP I>

(Increments 0.1 V)


Characteristic Impedance Z1 (Based on IN = 5 A2) Impedance Z1B (Based on IN = 5 A2) Impedance Z2 (Based on IN = 5 A2)

Polygonal, 3 independent stages 0.01 Ω to 26.00 Ω2) (Increments 0.01 Ω) 0.01 Ω to 13.00 Ω2) (Increments 0.01 Ω) 0.01 Ω to 13.00 Ω2) (Increments 0.01 Ω)

Measuring Tolerances as per VDE0435 part 303 with Sinusoidal Quantities

ê∆Z/Z ê ≤ 5 % for 30° ≤ ϕK ≤ 90° or 10 mΩ

2

) Secondary values for IN = 5 A; for IN = 1 A multiply all values by 5; the increment is always 0.01 Ω.


Difference Power Swing Polygon/ Trip Polygon (Based onIN = 1 A2)

0.10 Ω to 30.00 Ω

(Increments 0.01 Ω)

Rate of Change dz/dt (Based onIN = 1 A2)

1.0 Ω/s to 600.0 Ω/s (Increments 0.1 Ω/s)

Power Swing Blocking Action Time

0.00 s to 60.00 s

(Increments 0.01 s)

2)

Secondary values for IN = 1 A, for IN = 5 A devided all values by 5; the increment is always the same.

Times


426

Delay Times

T

0.00 s to 60.00 s

(Increments 0.01 s)

Shortest Tripping Time Typical Tripping Time Dropout Time

35 ms Approx. 40 ms Approx. 50 ms

Holding Time of Undervoltage Seal-In

0.10 s to 60.00 s

Time Expiry Tolerances

1 % of set value or 10 ms


1%


0.3 % / 10 °F 0.5 % / 10 K


<1%


<1% <1%

(Increments 0.01 s)

7UM62 Manual C53000-G1176-C149-3

4.14 Out-of-Step Protection (ANSI 78)

4.14


Pickup

Power Swing Polygon

Positive Sequence Component I1>/IN Negative Sequence ComponentI2
20.0 % to 400.0 % 5.0 % to 100.0 %

Dropout/Pickup Ratios – I1> – I2<

Approx. 0.95 Approx. 1.05

(Increm. 0.1 %) (Increm. 0.1 %)

Measuring Tolerances acc. to VDE 0435 Part 303

3 % of setting value

Impedance Za (based on IN = 5 A1) Impedance Zb (based on IN = 5 A1) Impedance Zc (based on IN = 5 A1) Impedance Zd–Zc (based on IN = 5 A1)

0.04 Ω to 26.00 Ω1) 0.02 Ω to 26.00 Ω1) 0.02 Ω to 26.00 Ω1) 0.00 Ω to 26.00 Ω1)

(Increm. 0.01 Ω) (Increm. 0.01 Ω) (Increm. 0.01 Ω) (Increm. 0.01 Ω)


60.0° to 90.0°

(Increments 0.1°)

Number of Permissible Power Swings Characteristic 1 Characteristic 2

1 to 4 1 to 8

Measuring Tolerances acc. to VDE 0435 ê∆Z/Z ê ≤ 5 % for 30° ≤ ϕK ≤ 90° or 10 mΩ with Sinusoidal Quantities 1

) Secondary values for IN = 5 A; for IN = 1 A multiply all values by 5; the increment is always 0.01 Ω. Times


7UM62 Manual C53000-G1176-C149-3

0.20 s to 60.00 s

(Increments 0.01 s)

Holding Time of Out-of-Step Annunciation

0.02 s to 0.15 s

(Increments 0.01 s)

Delay Time Tolerances



1%


0.3 % / 10 °F 0.5 % / 10 K


<1%


<1% <1%

Holding Time of Pickup

TH

427

4 Technical Data

4.15


Setting Ranges / Resolution

Measurement Quantities:

PositiveSequence Voltages

Pickup Voltage (27)

U<, U<<, Up< 10.0 V to 125.0 V

(Increments 0.1 V)

Dropout Ratio (27-1 and 27-2 only)

U<, U<<

1.01 to 1.20

(Increments 0.01)

Delay Time (27-Delay)

T U<, T U<<


Time Multiplier TMUL for Inverse Characteristic

0.10 s to 5.00 s

Add-On Delay Time TUp< for Inverse Characteristic

0.00 s to 60.00 s (Increm. 0.01 s) or ∞ (does not expire)

(Increm. 0.01 s)

The set time are pure delay times.


Pickup Times

Approx. 50 ms

Dropout Times

Approx. 50 ms


Based on the pickup value of the inverse characteristic

1.01 or 0.5 V absolute

Tripping Characteristic for Inverse Function

see also Figure 4-12 1 t = ---------------- ⋅ T MUL + T Up< U 1 – ------Up Meaning:

t U Up TMUL T Up<

Tolerances

– Pickup Voltages – Delay Times T, TUp< – Voltage-Time Characteristic

Influencing Variables

Power Supply DC voltage (VDC) in Range 0.8 ≤ VPS/ VPS nominal ≤ 1.15 1%

428

Tripping time Current voltage Pickup voltage being ∞ at that moment (= parameter 4402) Time multiplier (parameter 4403) Add-on delay time (4404)

1 % of set value, or 0.5 V 1 % of set value, or 10 ms 1 % based on U, or 30 ms


0.3 % / 10 °F 0.5 % / 10 K


<1%

Harmonics - Up to 10 % 3rd Harmonics - Up to 10 % 5th Harmonics

<1% <1%

7UM62 Manual C53000-G1176-C149-3

Voltage

4.15 Undervoltage Protection (ANSI 27)

Tripping Time Figure 4-12 Tripping Times of the Inverse Undervoltage Protection for Setting Value Up< = 75 V, Without Additional Trip Delay (TUp< = 0)

7UM62 Manual C53000-G1176-C149-3

429

4 Technical Data

4.16


Setting Ranges / Resolution

Measurement Quantities:

Maximum of the phase–to–phase voltages, calculated from the phase–to–earth voltages

Pickup Voltage 59-1, 59-2

U>, U>>

30.0 V to 170.0 V

(Increments 0.1 V)

Dropout Ratio for 59-1, 59-2

U>, U>>

0.90 to 0.99

(Increments 0.01)

Delay Time 59-Delay

T U>, T U>>


The set time are pure delay times.


Pickup Times

Approx. 50 ms

Dropout Times

Approx. 50 ms

Tolerances

– Pickup Voltages – Delay Times


430

T

1 % of set value, or 0.5 V 1 % of set value, or 10 ms

Power supply DC voltage (VDC) in Range 0.8 ≤ UPS/ UPS nominal ≤ 1.15 1% Temperature in Range 23 °F ≤ ϑamb ≤ 131 °F –5 °C ≤ ϑamb ≤ 55 °C

0.3 % / 10 °F 0.5 % / 10 K


<1%

Harmonics - Up to 10 % 3rd Harmonics - Up to 10 % 5th Harmonics

<1% <1%

7UM62 Manual C53000-G1176-C149-3

4.17 Frequency Protection (ANSI 81)

4.17



Number of Frequency Elements

4: each can be 81/O or 81/U

Pickup Frequency

f> or f< 40.00 Hz to 65.00 Hz (Increments 0.01 Hz) (81–1 to 81–4)

Delay Time

T f1 (81–1) 0.00 s to 600.00 s T f2 to T f4 0.00 s to 100.00 s (81–2 to 81–4)

Undervoltage Blocking (U1 Positive Sequence Voltage)

10.0 V to 125.0 V

(Increments 0.01 s) (Increments 0.01 s) (Increments 0.1 V)

The set times are pure delay times.


Pickup Times

f>, f< 81/O or 81/U

Approx. 100 ms

Dropout Times

T (f<, f<) 81/O or 81/U

Approx. 100 ms

Dropout Frequency

∆f = | Pickup Value – Dropout Value |

Approx. 20 mHz

Dropout Voltage

Dropout Ratio for Undervoltage Blocking

Approx. 1.05

Tolerances

– Pickup Frequencies

f>, f< 81/O or 81U

– Undervoltage Blocking – Delay Times Influencing Variables

7UM62 Manual C53000-G1176-C149-3

10 mHz (at U = UN; f = fN) 1 % of set value or 0.5 V

T (f<, f<) 81/O or 81/U

1 % of set value or 10 ms

Power Supply DC Voltage (UDC) in Range 0.8 ≤ UPS/ UPS nominal ≤ 1.15 0.1 % Temperature in Range 23 °F ≤ ϑamb ≤ 131 °F –5 °C ≤ ϑamb ≤ 55 °C

0.3 % / 10 °F 0.5 % / 10 K


<1% <1%

431

4 Technical Data

4.18



U / UN Overexcitation (Ratio >) f / fN (Warning Stage) U / UN >) f / fN

Overexcitation (Ratio (Stepped Characteristic)

Time Delay (Warning Stage and Stepped Charact.


T

1.00 to 1.20

(Increments 0.01)

1.00 to 1.40

(Increments 0.01)

0.00 s to 60.00 s

(Increments 0.01 s)

or ∞ (does not expire)

Pair of Values for Characteristic of

U/f

Thermal Replica

T

1.05 / 1.10 / 1.15 / 1.20 / 1.25 / 1.30 / 1.35 / 1.40 0 s to 20000 s (Increments 0.01 s)

Time for Cool Down

TCOOL DOWN

0 s to 20000 s

(Increments 1 s)

Warning Stage and Stepped Characteristic – Pickup Times at 1.1 Times Approx. 60 ms setting value – Dropout Times

Approx. 60 ms

Dropout

Dropout/Pickup

Approx. 0.95

Tripping time characteristic

Thermal Replica acc. to Presettings

Refer to Figure 4-13

Tolerances

Pickup on U/f

3 % of setting value )

Delay Times T


Thermal Replica

5 %, related to U/f ± 600 ms


1%


0.3 % / 10 °F 0.5 % / 10 K


<1%


<1% <1%


432

7UM62 Manual C53000-G1176-C149-3

4.18 Overexcitation (Volt/Hertz) Protection (ANSI 24)

10000

t [s]

3000 2000 1000 500 300 200 100 50 30 20 10 5 3 2

T U/f>>

1 1.1

U/f> (Pickup/warning stage)

Figure 4-13

7UM62 Manual C53000-G1176-C149-3

1.2

1.3

U⁄f ----------------UN ⁄ fN

1.4

U/f>>

Tripping Time Characteristic of Thermal Replica and of Stepped Stage of the Overexcitation Protection (Pre–settings)

433

4 Technical Data

4.19

Rate-of-Frequency-Change Protection (ANSI 81R)



Dropout

Tolerances


434

Stages, can be +df/dt> or–df/dt

4

Pickup Values df/dt

0.1 to 10 Hz/s

(Increments 0.1 Hz/s)

Delay Times T

0.00 to 60.00 s


Undervoltage Lock-Out U1>

10.0 to 125.0 V

(Increments 0.1 V)

Window Length

1 to 25 cycles

Pickup Times df/dt

Approx. 150 ms to 500 ms (dep. on window length)

Dropout Times df/dt

Approx. 150 ms to 500 ms (dep. on window length)

Dropout Difference ∆f/dt

0.02 to 0.99 Hz/s (settable)


Approx. 1.05

Frequency Rise Measuring Window < 5 Measuring Window ≥ 5

Approx. 5 % or 0.15 Hz/s at U > 0.5 UN Approx. 3 % or 0.1 Hz/s at U > 0.5 UN



Delay Times

1 % or 10 ms


≤1%


≤ 0.5 %/10 K


≤1% ≤1%

7UM62 Manual C53000-G1176-C149-3

4.20 Jump of Voltage Vector

4.20

Jump of Voltage Vector Stage ∆ϕ

2° to 30°

(Increments 1°)

Delay Time T

0.00 to 60.00 s


Reset Time TReset

0.10 to 60.00 s


Undervoltage Lock-Out U1>

10.0 to 125.0 V

(Increments 0.1 V)


Pickup Times ∆ϕ

Approx. 75 ms

Dropout Times ∆ϕ

Approx. 75 ms

Dropout

–

–

Tolerances

Angle Jump

0.5° at U > 0.5 UN



Delay Times T

1 % or 10 ms


≤1%


≤ 0.5 %/10 K


≤1%


≤1% ≤1%



7UM62 Manual C53000-G1176-C149-3

435

4 Technical Data

4.21



Displacement Voltage

U0>

2.0 V to 125.0 V

(Increments 0.1 V)

Residual Current

IE>

2 mA to 1000 mA (Increments 1 mA)

Inclination of Directional Characteristic

0° to 360°

Delay Times


T

(Increments 1°)

The set times are pure delay times. Inherent Operating Times

– Pickup Times

UE IE Direction

Approx. 50 ms Approx. 50 ms Approx. 70 ms

– Dropout Times

UE IE Direction

Approx. 50 ms Approx. 50 ms Approx. 70 ms

Dropout

Displacement Voltage UE Residual Current IE> Hysteresis of directional characteristic

Approx. 0.70 Approx. 0.70 Approx. 10° tow. line

Tolerances

Displacement Voltage Residual Current Delay Times

1 % of setting value or 0.5 V 1 % of setting value or 0.5 mA 1 % of setting value or 10 ms



1%


0.3 % / 10 °F 0.5 % / 10 K


<1%


<1% <1%

436

UE IE> T

7UM62 Manual C53000-G1176-C149-3

4.22 Sensitive Earth Fault Protection (ANSI 51GN, 64R)

4.22



Overcurrent pick-up

IEE>

2 mA to 1000 mA

Delay Time

TIEE>


Overcurrent Pick-Up

IEE>>

2 mA to 1000 mA

Delay Time

TIEE>>


Measured Value Supervision when Used as Rotor Earth Fault Protection IEE<

(Increments 1 mA)

(Increments 1 mA)

1.5 mA to 50.0 mA (Increments 0.1 mA) or 0.0 mA (ineffective)


– Pickup Times – Dropout Times – Measured Value Supervision

Approx. 60 ms Approx. 50 ms Approx. 2 s

Dropout

Overcurrent Pick-Up IEE>, IEE>> Measured Value Superv. IEE<

Approx. 0.95 or 1 mA Approx. 1.10 or 1 mA

Tolerances

Overcurrent Pick-Up Delay Times T

1 % of setting value or 0.5 mA 1 % of setting value or 10 ms



1%


0.3 % / 10 °F 0.5 % / 10 K


<1%


<1% <1%

Note: For the purpose of high sensitivity, the linear range of the measuring input for the sensitive ground fault acquisition is from 2 mA to 1600 mA.

7UM62 Manual C53000-G1176-C149-3

437

4 Technical Data

4.23



Pick–Up Value for 3rd Harmonic in Undervoltage Stage U0 (3rd HARM)< 0.2 V to 40.0 V

(Increments 0.1 V)

Pick–Up Value for 3rd Harmonic in Overvoltage Stage U0 (3rd HARM)> 0.2 V to 40.0 V

(Increments 0.1 V)

Delay Time

TSEF (3rd HARM) 0.00 s to 60.00 s (Increments 0.01 s) oder ∞ (does not expire)

Release Threshold

P/Pmin >

10 % to 100 % or 0 (ineffective)

U/U1 min>

50.0 V to 125.0 V (Increments 0.1 V) or 0 (ineffective)

(Increments 1 %)


– Pickup Times – Dropout Times

Dropout

Undervoltage Stage Overvoltage Stage Release Thresholds

Tolerances

– Displacement Voltage 3 % of setting value or 0.1 V – Delay Time TSEF (3rd HARM) 1 % of setting value or 10 ms



1%


0.3 % / 10 °F 0.5 % / 10 K


<1%

438

Approx. 80 ms Approx. 80 ms U0 (3rd HARM)< U0 (3rd HARM)> P/Pmin > U/U1 min>

Approx. 1.10 or 0.1 V Approx. 0.90 or 0.1 V Approx. 0.90 Approx. 0.95

7UM62 Manual C53000-G1176-C149-3

4.24 100–% Stator Earth Fault Protection with 20 Hz Voltage Injection (ANSI 64G, –100 %)

4.24

100–% Stator Earth Fault Protection with 20 Hz Voltage Injection (ANSI 64G, –100 %) Alarm Stage RSEF<

20 to 700 Ω

(Increments 1 Ω)

Tripping Stage RSEF<<

20 to 700 Ω

(Increments 1 Ω)

Earth Currrent StageISEF>

0.02 to 1.50 A

(Increments 0.01 A)

Delay Time

0.00 to 60.00 s

(Increments 0.01 s or ∞ (does not expire))

U20

0.3 to 15.0 V

(Increments 0.1 V)

I20

5 to 40 mA

(Increments 1 mA)

Correction Angle

–60° to +60°

(Increments 1°)

Pickup Time RSEF<, RSEF<<

≤ 1.3 s

Pickup Time ISEF>

≤ 250 ms

Dropout Time RSEF<, RSEF<<

≤ 0.8 s

Dropout Time ISEF>

≤ 120 s

Dropout


Approx. 1.2 to 1.7

Tolerances

Resistance

Approx. 5 % or 2 Ω

Current

3 % or 3 mA

Delay Time

1 % or 10 ms


≤1%


≤ 0.5 %/10 K


≤1%


≤1% ≤1%


Supervision Threshold of 20 HZ Voltage



7UM62 Manual C53000-G1176-C149-3

439

4 Technical Data

4.25

Rotor Earth Fault Protection (R, fn, ANSI 64R)


Alarm Stage

RE ALARM

3.0 kΩ to 30.0 kΩ (Increments 0.1 kΩ)

Tripping Stage

RE TRIP

1.0 kΩ to 5.0 kΩ

(Increments 0.1 kΩ)

Delay Times

TRE ALARM


(Increments 0.01 s)

TRE TRIP


(Increments 0.01 s)

Reactance in the XCOUPLING Coupling Circuit (Capacitive)

–100 Ω to 800 Ω

(Increments 1 Ω)

Resistance in the Coupling Circuit

RSERIES

0 Ω to 999 Ω

(Increments 1 Ω)

Pickup Value of Warning Stage

I RE<

1.0 mA to 50.0 mA (Increments 0.1 mA) or 0.0 (stage is inactive)

Correction Angle for W0 I RE Rotor Earth Fault Current Permissible Rotor Earth Capacity CE

(Increments 0.1°)

For the tolerances stated, and for detecting an interruption of the measuring circuit 0.15 µF ≤ CE ≤ 3.0 µF Permissible Operating Range of the Injected Voltage (Warning U RE< at U ≤ 20 V∼)

Times

–15.0° to +15.0°

20 V∼ to 100 V~

Pickup Times – Warning Stage, Tripping Stage

≤ 80 ms

Dropoff Times – Warning Stage, Tripping Stage

≤ 80 ms

Dropoff/Pickup Ratios

– RE WARN, RE TRIP – Alarm – Alarm

Approx. 1.25 Approx. 1.20 or 0.5 mA dropout difference Approx. 5 V dropout difference

Tolerances

– Warning Stage, Tripping Stage

5 % for RE ≤ 5 kΩ and 0.15 ≤ CE/µF≤ 3 10 % for RE ≤ 10 kΩ and 0.15 ≤ CE/µF≤ 3 10 % for 10 ≤ RE/kΩ ≤ 30 and CE ≤ 1 µF

– Delay Times

1 % or 10 ms

Influencing Variables for Pickup Values

T


1%


0.3 % / 10 °F 0.5 % / 10 K


440

I RE< U RE<

3 % for CE ≤ 0,15 µF 10 % for 0,15 ≤ CE/µF≤ 1

7UM62 Manual C53000-G1176-C149-3

4.26 Sensitive Rotor Earth Fault Protection with 1 to 3 Hz (ANSI 64R)

4.26

Sensitive Rotor Earth Fault Protection with 1 to 3 Hz (ANSI 64R)


Warning Stage

RE WARN

5 kΩ to 80 kΩ

(Increments 1 kΩ)

Tripping Stage

RE TRIP

1 kΩ to 10 kΩ

(Increments 1 kΩ)

Delay Time Pickup Value of Open Rotor Circuit

0.00 s to 60.00 s (Increments 0.01 s) or ∞ (does not expire) QC<

0.01 to 1.00 mAs

(Increments 0.01 mAs)


Pickup Time

Approx. 1 to 1.5 s (depends on 7XT71)

Dropout Time

Approx. 1 to 1.5 s

Dropout

Resistance RE

Approx. 1.25

Charge QC<

1.2 or 0.01 mAs

Resistance

Approx. 5 % or 0.5 kΩ at 0.15 µF≤CE< 1 µF Approx. 10 % or 0.5 kΩ at 1 µF≤CE< 3µF

Charge

5 % or 0.005 mAs

Delay Time

1 % or 10 ms

Permissible Rotor-Earth Capacitance

0.15 to 3 µF


≤1%


≤ 0.5 %/10 K


≤1%


≤1% ≤1%

Tolerances


7UM62 Manual C53000-G1176-C149-3

441

4 Technical Data

4.27


Setting Ranges/ Increments

ISTARTUP

Pickup Threshold

IMOTOR START 3.00 A to 5.00 A1)

Permissible Starting Time TSTARTUP Permissible Locked Rotor Time Trip Time Characteristic


Motor Starting Current

1.0 s to 180.0 s

(Increments 0.05 A)1) (Increments 0.1 s)

TLOCKED_ROTOR0.5 s to 120.0 s (Increments 0.1 s) or ∞ (step is ineffective) I STARTUP 2 t = æ ------------------------ö ⋅ T STARTUP è I rms ø

Trip Time Characteristics for Irms > IMOTOR START Meaning:

ISTARTUP

Motor starting current setting

Irms

Actual current flowing

IMOTOR START

Pickup threshold setting, used to detect motor startup

t

Trip time in seconds

Dropout Ratio

Irms/IMOTOR START

approx. 0.95

Tolerance

Pickup Threshold

1 % of set value, or 50 mA1)

Time Delay

5 % or 30 ms


1%

Temperatur in range 23 °F ≤ ϑamb ≤ 131 °F –5 °C ≤ ϑamb ≤ 55 °C

0.3 % / 10 °F 0.5 % / 10 K

Frequency in range 0.95 ≤ f/fN ≤ 1.05

<1%

Harmonic currents – Up to 10 % 3. Harmonic – Up to 10 % 5. Harmonic

<1% <1%


1)

442

for IN = 1 A, divide all limits and increments by 5.

7UM62 Manual C53000-G1176-C149-3

4.28 Restart Inhibit for Motors (ANSI 66, 49Rotor)

4.28


Setting Ranges/ Increments

Starting CurrentBased IStart/IMOTnom on Nominal Motor Current

1.5 to 10.0

(Increments 0.1)

Max. Permissible Starting Time

TMOT START

3.0 s to 120.0 s

(Increments 0.1 s)


TEQUAL

0.0 min to 60.0 min (Increments 0.1 min)

Max. Permissible nWARM Number of Warm Starts

1 to 4

(Increments 1)

Difference between Cold and Warm Starts

nCOLD - nWARM 1 to 2

(Increments 1)


kτSTOP

1.0 to 100.0

(Increments 0.1)

Extension of Time kτRUNNING Constant at Motor Running

1.0 to 100.0

(Increments 0.1)


0.2 to 120.0 min

(Increm. 0.1 min)

Restart Threshold

n COLD – 1 Θ Re.Inh = Θ L max perm ⋅ --------------------------n COLD

RestartTimes T Wait time = T Equal + T Re.In. Θ Hist Θ Hist ⋅ n COLD -) T Re.Inh = τ ⋅ ln(-----------------) = τ ⋅ ln(---------------------------------Θ Re.Inh n COLD – 1

Meaning:

ΘRe.Inh.

Temperature threshold below which a restart is possible

ΘL max perm. Maximum permissible rotor overtemperature (= 100 % in operational measured value ΘR/ΘR Trip)

7UM62 Manual C53000-G1176-C149-3

nCOLD

Number of permissible starts in cold condition

TWait time

Time after which a restart of the motor is possible

TEqual

Equalization time during which the thermal replica is "frozen"

TRe.Inh.

Time for the thermal replica to drop below the restart threshold again, depends on:

ΘHist

History leading to the rotor temperature

τ

Rotor time constant (internally calculated)

443

4 Technical Data

4.29


Pickup and Delay Time Ranges/ Resolutions Initiating Time

Pickup of 50 Element

BF.I>

0.20 A to 10.00 A 1)(Increments 0.05 A)1)

Delay Time

TRIP-Timer

0.06 s to 60.00 s or ∞ (no trip)

(Increments 0.01 s)

Pickup Times (protection initiates) - For Internal Start

Approx. 50 ms

- Using Controls

Approx. 50 ms

- For External Start

Approx. 50 ms

Reset Time

Approx. 50 ms BF.I> TRIP-Timer

1 % of set value, or 50 mA1) 1 % or 10 ms

Tolerances

Pickup Current Delay Time


Power Supply DC voltage (UDC) in Range 0.8 ≤ UPS/ UPS nominal ≤ 1.15 1% Temperature in Range 23 °F ≤ ϑamb ≤ 131 °F –5 °C ≤ ϑamb ≤ 55 °C

0.3 % / 10 °F 0.5 % / 10 K


<1%


<1% <1%

1


444

7UM62 Manual C53000-G1176-C149-3

4.30 Inadvertent Energization (ANSI 50/27)

4.30

Inadvertent Energization (ANSI 50/27)


Overcurrent Pick-Up

ISTAGE

0.5 A to 100.0 A1) (Increments 0.5 A)1) or ∞ (does not expire)

Release

U1<

10.0 V to 125.0 V (Increments 0.1 V)

Delay Time

PICK UP T U1<


Drop Out Delay Time

DROP OUT T U1< 0.00 s to 60.00 s (Increments 0.01 s) or ∞ (does not expire)


– Pickup Times – Dropout Times

Approx. 25 ms Approx. 35 ms

Dropout

I>>> Release Threshold

U1<

Approx. 0.80 or 250 mA1) Approx. 1.05

Overcurrent pick-up

I>>>

5 % of setting value or 100 mA1)

Release

U1<


Delay Times

T


Tolerances


Power Supply DC Voltage (UDC) in Range 0.8 ≤ UPS/ UPS nominal ≤ 1.15 1% Temperature in Range 23 °F ≤ ϑamb ≤ 131 °F –5 °C ≤ ϑamb ≤ 55 °C

0.3 % / 10 °F 0.5 % / 10 K


1%


<1% <1%

1)

7UM62 Manual C53000-G1176-C149-3


445

4 Technical Data

4.31



Voltage Increase Voltage Decrease

U=> U=<

0.1 V to 8.5 V 0.1 V to 8.5 V

(Increments 0.1 V) (Increments 0.1 V)

Current Increase Current Decrease

I=> I=<

0.2 mA to 17.0 mA (Increments 0.1 mA) 0.2 A to 17.0 mA (Increments 0.1 mA)

For Measurement of Sinusoidal Voltages 0.1 Vrms to 7.0 Veff (Increments 0.1 Vrms) For Measurement of Sinusoidal Currents 0.2 mA to 14.0 mA (Increments 0.1 mA) Delay Time

TGSS


(Increment 0.01 s)

Pickup Times – Increase U>, I> in Operating State 1 in Operating State 0

≤ 60 ms ≤ 200 ms

at f = fN

– Decrease U<, I< in Operating State 1 in Operating State 0

≤ 60 ms ≤ 200 ms

at f = fN

Dropout Times

Same as pickup times

– Voltage Increase U=> – Voltage Decrease U=<

Approx. 0.95 or –0.05 V Approx. 1.05 or +0.05 V

– Current Increase I=> – Current Decrease I=<

Approx. 0.95 or –0.1 mA Approx. 1.05 or +0.1 mA

– Voltage Thresholds – Current Thresholds – Delay Times

1 % of setting value, or 0.1 V 1 % of setting value, or 0.1 mA 1 % of setting values, or 10 ms

The set times are pure delay times. Times

Dropout/Pickup Ratios

Tolerances


446

T

Power Supply DC Voltage (VDC) in Range 0.8 ≤ VPS/ VPS nominal ≤ 1.15 1% Temperature in Range 23 °F ≤ ϑamb ≤ 131 °F –5 °C ≤ ϑamb ≤ 55 °C

0.3 % / 10 °F 0.5 % / 10 K


1%

7UM62 Manual C53000-G1176-C149-3

4.32 Thermoboxes for Temperature Detection

4.32

Thermoboxes for Temperature Detection

Temperature Detectors

Alarm Threshold Values

7UM62 Manual C53000-G1176-C149-3

Number of Thermoboxes Possible

1 or 2

Number of Temperature Detectors per Thermobox

max. 6

Type of Measurement

Pt 100 Ω oder Ni 100 Ω oder Ni 120 Ω

Location Setting

“Oil” or “Ambient” or “Winding” or “Bearing” or “Other”

For Each Measuring Point: Stage 1

–50 °C to 250 °C –58 °F to 482 °F or ∞ (No event)


Stage 2

–50 °C to 250 °C –58 °F to 482 °F or ∞ (No event)


447

4 Technical Data

4.33

Additional Functions

Operational Measured Values

Operating Measured Values for Currents - Range - Tolerance

IL1, S1, IL2, S1, IL3,S1, IL1, S2, IL2, S2, IL3,S2 in A or kA primary; in A secondary, or in % of INom 10 % to 200 % INom 0.2 % of measured value or 10 mA ± 1 Digit 3I0 in A or kA primary; in A and in % of INom secondary

Operating Measured Values for Sensitive Ground Fault Protection - Range - Tolerance

IEE1, IEE2 0 mA to 1600 mA 0.2 % of measured value or 10 mA ± 1 Digit Positive sequence current I1 in A or kA primary; in A secondary, or in % of INom Negative sequence current I2 in A or kA primary; in A secondary, or in % of INom

Differential Protection Currents - Range - Tolerance Operating Measured Values for Voltages (Phase-Ground) - Range - Tolerance Operating Measured Values for Voltages (Phase-Phase) - Range - Tolerance

IDiffL1, IDiffL2, IDiffL3, IStabL1, IStabL2, IStabL3 in I/INO 10 % to 200 % IN 3 % of measured value, or ±10 mA ±1 Digit UL1-N, UL2-N, UL3-N in kV primary; in V secondary or in % of UNom 10 % to 120 % UNom 0.2 % of measured value or ± 0.2 V ± 1 Digit UL1-L2, UL2-L3, UL3-L1 in kV primary, in V secondary or in % of UNom 10 % to 120 % UNom 0.2 % of measured value or ± 0.2 V ± 1 Digit UE and 3U0 in kV primary, in V secondary or in % of UNom Positive sequence voltage U1 and Negative sequence voltage U2 in kV primary; in V secondary or in % of UNom

448

Operating Measured Values for Resistances and Reactances - Tolerance

R, X in Ω primary and secondary 1%

Operating Measured Values for Power - Range - Tolerance

S, Apparent Power in kVA (MVA or GVA) primary, and in % SNom 0 % to 120 % SNom 1 % ± 0.25 % SN with SNom = √3 · UNom · INom

7UM62 Manual C53000-G1176-C149-3

4.33 Additional Functions

- Range - Tolerance

P, Real power (with sign) in kW (MW or GW) primary, and in % SNom 0 % to 120 % SNom 1 % ± 0.25 % SN with SNom = √3 · UNom · INom

- Range - Tolerance

Q, Reactive power (with sign) in kVAr (MVAr or GVAr) primary and in % SNom 0 % to 120 % SNom 1 % ± 0.25 % SN with SNom = √3 · UNom · INom

Operating Measured Values for Power Factor - Range - Tolerance Operating Measured Values for Power Angle - Range - Tolerance Counter Values for Energy

- Range - Tolerance Operating Measured Values for Frequency - Range - Tolerance

–1 to +1 1 % ± 1 Digit ϕ –90° to +90° 0.1° Wp, Wq (real and reactive energy) in kWh (MWh or GWh) and in kVARh (MVARh or GVARh) 81/2 digits (28 bit) for VDEW protocol 91/2 digits (31 bit) in the unit 7UM62 1 % ± 1 Digit f in Hz 40 Hz < f < 65 Hz 10 mHz at U > 0.5 ⋅ UN

Thermal Measurement Overload Protection

Θ/ΘTrip, Θ/ΘTrip L1, Θ/ΘTrip L2, Θ/ΘTrip L3

Thermal Measurement Stator Overload Protection Unbalanced Load Protection Overexcitation Protection U/f of Rotor (Restart Inhibit) Coolant temperature

ΘS/ΘL1Trip, ΘS/ΘL2Trip, ΘS/ΘL3Trip Θi2/ΘTrip ΘU/f/ΘTrip ΘRot/ΘTrip Depends on connected temperature sensor

- Range - Tolerance

7UM62 Manual C53000-G1176-C149-3

cos ϕ (p.f.)

0 % to 400 % 5 % class accuracy per IEC 60255-8

Operational Measured Values for Rotor Earth Fault Protection (1–3 Hz) - Range - Tolerance

0.5 Hz to 4.0 Hz 0.1 Hz

Amplitude of Rotor Voltage Injection - Range - Tolerance

Ugen in V 0.0 V to 60.0 V 0.5 V

Rotor Circuit Current - Range - Tolerance

Igen in mA 0.00 mA to 20.00 mA 0.05 mA

449

4 Technical Data

Charge at Polarity Reversal - Range - Tolerance

QC in mAs 0.00 mAs to 1.00 mAs 0.01 mAs

Rotor Earth Resistance - Range - Tolerance

Rearth in kΩ 0.0 kΩ to 9999.9 kΩ < 5 % or 0.5 kΩ Rearth < 100 kΩ for Ce< 1µF < 10 % or 0.5 kΩ Rearth < 100 kΩ for Ce< 4µF

Operational Measured Values for 100-%-Stator Earth Fault Protection (20 Hz) Stator Circuit Voltage Injection USEF in V - Range 0.0 V to 200.0 V - Tolerance 0.2 % of measured value, or ± 0.2 V ± 1 Digit

Min/Max Report

Earth Current of Stator Circuit - Range - Tolerance

ISEF in A 0.0 mA to 1600.0 mA 0.2 % of measured value, or ± 10 mA ± 1 Digit

20 Hz Phase Angle - Range - Tolerance

ϕSEF in ° – 180.0° to + 180.0° 1.0 %

Stator Earth Resistance (sec.) - Range - Tolerance

RSEF in Ω 0 Ω to 9999 Ω 5 % or 2 Ω

Stator Earth Resistance (prim.) - Range - Tolerance

RSEFP in Ω 0.00 to 9999.99 Ω 5 % or (5 Ω ⋅ conversion factor)

Report of Measured Values

With date and time

Reset

– Automatic

Time of day adjustable (in minutes). Time frame and starting time adjustable (in days, 1 to 365 days, and ∞).

Reset

– Manual

Using binary input Using keypad Using communication

Min/Max Values for Current

I1 (positive sequence)

Min/Max Values for Voltage

U1 (positive sequence)

Min/Max Values for 3rd Harmonics in Displacement Voltage

UE3H

Min/Max Values for Power/ Other

P, Q

Min/Max Values for Frequency

f

Power Meter

Four-Quadrant Meter - Tolerance

WP+; WP–; WQ+; WQ– 1%

Analog Outputs (optional)

Number

max. 4 (depending on variant)

Measured Values that Can be Output

I1, I2, U1, |P|, |Q|, |cos ϕ|, f; ΘS/ΘS TRIP, ΘRot/ΘRot TRIP in %

450

7UM62 Manual C53000-G1176-C149-3


Range

0 mA to 22.5 mA

Minimum Threshold (Limit of Validity:)

0.0 mA to 5.0 mA (Increments 0.1 mA)

Maximum Threshold

22.0 mA (fixed)

Configurable Reference Value 20 mA Measured Values Supervision

10.0 % to 1000.0 %(Increments 0.1 %)

Current Asymmetry

Imax/Imin > I - balance factor, for I > I - balance limit. Factor and limit are adjustable.

Voltage Asymmetry

Umax/Umin > U - balance factor, for U > U - balance limit. Factor and limit are adjustable.

Current Sum

| iL1+ iL2+ iL3 | > I - sum threshold value, adjustable.

Voltage Sum

|UL1 + UL2 + UL3 + kU · UE | > SUM.thres. U, with kU = Uph/Udelta

Current Phase Sequence

Clockwise (L1, L2, L3)/ counter-clockwise (L1, L3, L2)

Voltage Phase Sequence

Clockwise (L1, L2, L3)/ counter-clockwise (L1, L3, L2)

Limit Value Monitor

Can be configured with CFC IL < Limit value LV (ANSI 37-1)

Trip Log

Recording of indication of the last 8 power system faults

Time Stamping

Resolution for Event Log (Operational Messages)

1 ms

Resolution for Trip Log (Fault Records)

1 ms

Time Deviation (Internal Clock)

Maximum 0.01 %

Buffer Battery

Lithium Battery, 3 V / 1 Ah, type CR 1/2 AA Self-discharging time > 5 years Message “Fail Battery” if battery charge is low

7UM62 Manual C53000-G1176-C149-3

451

4 Technical Data

Waveform Capture (Fault Recorder)

Optionally instantaneous values or r.m.s. values – Instantaneous Values − Recording Time

Total of 5 s Pre-event and post-event recording and memory time adjustable

− Sampling Rate for 50 Hz Sampling Rate for 60 Hz

1 sample/1.25 ms (16 sam/cyc) 1 sample/1.04 ms (16 sam/cyc)

− Channels

uL, uL2, uL3, uE, iL1, S1, iL2,S1, iL3,S1, iEE, iL1, S2, iL2,S2, iL3,S2, iEE2, uDC or iDC of the three measuring transducers (TD)

– R.m.s. Values − Recording Time

Total of 80 s Pre-event and post-event recording and memory time adjustable

− Sampling Rate for 50 Hz Sampling Rate for 60 Hz

1 sample/20 ms (1 sam/cyc) 1 sample/16.67 ms (1 sam/cyc)

− Channels

U1, UE, I1, I2, IEE1, IEE2, P, Q, ϕ, R, X, f–fN

Statistics (Circuit Breaker)

Saved Number of Trips

Up to 9 digits

Accumulated Interrupted Current

Up to 4 digits (kA) per pole

Operating Hours Counter

Operating Hours Range Criterion to Count

Up to 6 digits Current exceeds an adjustable current threshold (BkrClosed I MIN)

Trip Circuit Monitor (ANSI 74TC)

With one or two binary inputs.

Commissioning Start-up Aids

Phase Rotation Check Operating Measured Values Circuit Breaker / Switching Device Test Creation of a Fault Record

Clock

Time Synchronization

IRIG-B/DCF77-signal Binary signal Communication

User-Defined Functions (CFC)

Selection Guide for Function Modules and Task Levels Task Level Function Module

452

Description

MW_ BEARB

PLC1_ PLC_ SFS_ BEARB BEARB BEARB

ABSVALUE

Magnitude calculation

X

–

–

–

ADD

Addition

X

X

X

X

AND

AND–Gate

–

X

X

X

BOOL_TO_CO

Boolean to control (conversion)

–

X

X

–

BOOL_TO_DI

Boolean to Double Point (conversion)

–

X

X

X

7UM62 Manual C53000-G1176-C149-3


Task Level Function Module

Description

MW_ BEARB

PLC1_ PLC_ SFS_ BEARB BEARB BEARB

BOOL_TO_IC

Boolean to Internal Single Point (conversion)

–

X

X

X

BUILD_DI

Create Double Point Annunciation

–

X

X

X

CMD_CHAIN

Command chain

–

X

X

–

CMD_INF

Command information

–

–

–

X

CONNECT

Connection

–

X

X

X

D_FF

D–Flipflop

–

X

X

X

D_FF_MEMO

Status memory for restart

–

X

X

X

DI_TO_BOOL

Double Point to Boolean (conversion)

–

X

X

X

DIV

Division

X

–

–

–

DM_DECODE

Double Point decoding

X

X

X

X

DYN_OR

Dynamic OR-Gate

X

X

X

X

LIVE_ZERO

Live–Zero monitoring, non-linear curve

X

–

–

–

LONG_TIMER

Timer (max. 1193 h)

X

X

X

X

LOOP

Signal loop

–

X

–

–

LOWER_SETPOINT

Lower limit

X

–

–

–

MUL

Multiplication

X

–

–

–

NAND

NAND–Gate

–

X

X

X

NEG

Negator

–

X

X

X

NOR

NOR–Gate

–

X

X

X

OR

OR–Gate

–

X

X

X

RS_FF

RS–Flipflop

–

X

X

X

SQUARE_ROOT

Radizierer

X

–

–

–

SR_FF

SR–Flipflop

–

X

X

X

SUB

Subtraction

X

–

–

–

TIMER

Timer

–

X

X

–

UPPER_SETPOINT

Upper limit

X

–

–

–

X_OR

XOR–Gate

–

X

X

X

ZERO_POINT

Zero suppression

X

–

–

–

Maximum number of TICKS in the task levels

7UM62 Manual C53000-G1176-C149-3

453

4 Technical Data

Run-Time Level

Limits in TICKS

MW_BEARB (Measured value processing)

10000

PLC1_BEARB (Slow PLC processing)

1900

PLC_BEARB (Fast PLC processing)

200

SFS_BEARB (Interlocking)

10000

In the following table, the amount of TICKS required by the individual elements of a CFC chart is shown. A generic module refers to a module for which the number of inputs can be changed. Typical examples are the logic modules AND, NAND, OR, NOR. Processing times in TICKS required by the individual elements Individual Element

Setting Group Switchover of the Function Parameters

454

Amount of TICKS

Module, basic requirement

5

each input more than 3 inputs for generic modules

1

Connection to an input

6

Connection to an output signal

7

Additional for each configuration sheet

1

Number of Available Setting Groups

2 (parameter group A and B)

Switchover Performed

Using the keypad DIGSI® 4 using the front operator interface with protocol via system interface using binary input

7UM62 Manual C53000-G1176-C149-3

4.34 Operating Ranges of the Protection Functions

4.34 Table 4-1

Operating Ranges of the Protection Functions Operating Ranges of the Protection Functions

Protection function

Operat. cond. 0 Operational condition 1 Operat. cond. 0 f ≤ 10 Hz 11 Hz< f/Hz ≤ 40 40 Hz ≤ f/Hz ≤ 69 f ≥ 70 Hz

Definite-time overcurrent prot. (50, 51, 67)

active

active

active

active

Inverse-time overcurrent protection (51V)

inactive

active

active

inactive

Thermal overload protection (49)

inactive1)

active

active

inactive1)

Unbalanced load protection (46)

inactive1)

active

active

inactive1)

Startup overcurrent protection (51)

active

inactive

inactive

active

Differential protection (87G/87T)

active

active

active

active

Earth current differential protection (87GN/TN)

inactive

active

active

inactive

Underexcitation protection (40)

inactive

active

active

inactive

Reverse power protection (32R)

inactive

active

active

inactive

Forward power supervision (32F)

inactive

active

active

inactive

Impedance protection (21)

inactive

active

active

inactive

Out–of–step protection (78)

inactive

active

active

inactive

Undervoltage protection (27)

inactive2)

active

active

inactive2)

Overvoltage protection (59)

active

active

active

active

Overfrequency protection (81/O)

inactive

active

active

inactive3)

Underfrequency protection (81/U)

inactive

active

active

inactive

Overexcitation protection U/f> (24)

inactive1)

active

active

inactive1)

Inverse undervoltage protection (27)

inactive2)

active

active

inactive2)

inactive

active4)

active

inactive

Jump of voltage vector

inactive

active5)

active5)

inactive

90–% Stator earth fault prot. (59N, 64G, 67G)

active

active

active

active

Sensitive earth fault protection (51GN, 64F)

inactive

active

active

inactive

100–% S/E/F with 3rd harm. (27TN, 59TN)

inactive

active

active

inactive

100–% stator earth fault protection(20 Hz) (64G)

active

active

active

active

Rotor earth fault protection (64R)

active

active

active

active

Rotor earth fault protection (64R)

active

active

active

active

Motor starting time supervision (48)

inactive

active

active

inactive

Restart inibit for motors (66, 49Rotor)

inactive

active

active

inactive

Breaker Failure Protection (50BF)

inactive

active

active

inactive

Inadvertent energization (50/27)

active

active

active

active

DC voltage protection (59NDC, 51NDC)

active

active

active

active

Threshold Monitoring

inactive

active

active

inactive

External trip coupling

active

active

active

active

Temperature detection by thermoboxes

active

active

active

active

Rate-of-frequency-change protection (81R)

7UM62 Manual C53000-G1176-C149-3

455

4 Technical Data

1)

Thermical replica registers cooling-down Pick -up – when already present – is maintained 3) Pick -up – when already present – is maintained, if the measured voltage is not too small 4) 25 Hz < f/Hz ≤ 40 Hz 5) Function is only active at rated frequency ± 3 Hz 2)

Operational Condition 1

The frequency follow-up circuit can operate only , when at least one a.c. measured quantity is present at one of the the analog inputs (uL1, uL2, uL3, iL1, iL2, iL3, currents on side 2), with an amplitude of at least 5 % of rated value (operational condition 1).

Operational Condition 0

If no suitable a.c. measured values are present, or if the frequency is below 11 Hz or above 70 Hz, the relay cannot operate (operational condition 0).

456

7UM62 Manual C53000-G1176-C149-3

4.35 Dimensions

4.35

Dimensions

Housing for Panel Flush Mounting or Cubicle Installation (Size 1/2)

29.5

172

34

29.5

Mounting plate

172

29 30 225 220

Mounting plate

2

K

Q

J

244

266

244

266

F R

2

D

C

B

A

34

Side view (with screwed terminals)

Side view (with clamp terminals)

Rear view

221 +2

245 + 1

255.8 ± 0.3

5 or M4

5.4

6

13.2

180 ± 0.5

7.3

206.5 ± 0.3

Dimensions in mm

Panel cut-out

Figure 4-14

Dimensions 7UM621 for Panel Flush Mounting or Cubicle Installation (size 1/2)

7UM62 Manual C53000-G1176-C149-3

457

4 Technical Data

Housing for Panel Flush Mounting or Cubicle Installation (Size 1/1)

29.5

172

34

29.5

172

2

244

266

Monting plate

244

266

Mounting plate

29 30

2

34

Side view (with clamp terminals)

Side view (with screwed terminals)

450 445

446 +2

6

5 or M4

F

N

D

C

B

A

245 + 1

K 5 or M4

6

6

5 or M4

J 5 or M4

5,4

Q

P

255,8 ± 0,3

R

Rear view

6

7,3 13,2 216,1 ± 0,3

13,2 13,2

425,5 ± 0,3 Panel cut-out (view from the device front)

Dimensions in mm

Figure 4-15

458

Dimensions 7UM622 for Panel Flush Mounting or Cubicle Installation (size 1/1)

7UM62 Manual C53000-G1176-C149-3

4.35 Dimensions

Panel Mounting (Housing size 1/2)

240 219

10,5 75

76

100

9

29,5

280 320 344

225

260

266

51

1

25

26

50

71 Front view

Side view

Dimensions in mm Figure 4-16 Dimensions 7UM621 for Panel Mounting (size 1/2)

Panel Mounting (Housing size 1/1)

465 444

10,5 150 200

9

1

280 320 344

450

29,5

266

101 151

260

50 100

51

71

Front view

Side view

Dimensions in mm Figure 4-17 Dimensions 7UM622 for Panel Mounting (size 1/1)

n

7UM62 Manual C53000-G1176-C149-3

459

4 Technical Data

460

7UM62 Manual C53000-G1176-C149-3

A

Appendix

This appendix is primarily a reference for the experienced user. This Chapter provides ordering information for the models of 7UM62. General diagrams indicating the terminal connections of the 7UM62 models are included. Connection examples show the proper connections of the device to primary equipment in typical power system configurations. Tables with all settings and all information available in a 7UM62 equipped with all options are provided.

7UM62 Manual C53000-G1176-C149-3

A.1

Ordering Information and Accessories

462

A.2

General Diagrams (IEC)

482

A.3

General Diagrams (ANSI)

486

A.4

Connection Examples

488

A.5

100–% Stator Earth Fault Protection with Primary Load Resistor

499

A.6

Definition of the Active Power Measurement

502

A.7

Current Transformer Requirements

504

A.8

Overview of the Masking Features of the User Defined Information

506

A.9

Default Settings

511

A.10

Interoperability List

517

A.11

Functions Overview

519

A.12

Settings

523

A.13

List of Information

549

A.14

List of Measured Values

578

A.15

Protocol-Dependent Functions

584

461

A Appendix

A.1

Ordering Information and Accessories

6

Multifunctional Machine Protection Housing, Number of Binary Inputs and Outputs Housing 1/2 19”, 7 BI, 12 BO, 1 Live Status Contact Housing 1/1 19”, 15 BI, 20 BO, 1 Live Status Contact Nominal Current IN = 1 A, Iee (sensitive) IN = 5 A, Iee (sensitive) Auxiliary Voltage (Power Supply, Pick-up Threshold of Binary Inputs) DC 24 to 48 V, pick-up binary inputs 17 V 1) DC 60 to 125 V, pick-up binary inputs 17 V 1) DC 110 to 250 V, AC 115 V, pick-up binary inputs 73 V 1)

7

7UM62

_

8

9 10 11 12

2 4 5

B D E

A B C

SCADA Interface or Analog Output (Port B) no SCADA interface IEC protocol, electrical RS232 IEC protocol, electrical RS485 IEC protocol, optical 820 nm, ST-plug Analog outputs 2 x 0 to 20 mA For more interface options see “Additional Information L”

0 1 2 3 7 9

+ L 0

Profibus DP Slave, RS485 Profibus DP Slave, optical, double ring Modbus RS485 Modbus , optical DNP3.0, RS485 DNP3.0, optical, 820 nm, ST-plug

A B D E G H

Service Interface (DIGSI 4/Modem) (Port C) DIGSI 4, electrical RS232 DIGSI 4, electrical RS485 with analog output port (Port D) see “Additional information M”

(Port D) Thermobox, optical 820 nm, ST-connector Thermobox, electrical RS485 Analog outputs 2 x 0 to 20 mA 1)

0

1 5

Region-Specific Default/Language Settings and Function Versions Region DE, 50 Hz, IEC, German language (may be changed) Region world, 50/60 Hz, IEC/ANSI, English language (may be changed) Region US, 60 Hz, ANSI, US-English language (may be changed)

Additional information M (Port C) DIGSI 4, Modem RS232 DIGSI 4, Modem/Thermobox, RS485

13 14 15

1 2

Construction Surface mounting housing for panel, 2 tier terminals top/bottom Flush mounting housing with plug-in terminals (2/3 pin connector) Flush mounting housing for panel/cubicle, screw-type terminals (ring lugs)

Additional Information L (Port B)

_

1 2 9

+

M 1 2

A F K

continued next page 463 the BI tresholds per binary input can be adjusted in 2 stages by means of jumpers.

462

7UM62 Manual C53000-G1176-C149-3

A.1 Ordering Information and Accessories

6

Multifunctional Machine Protection

7UM62

7

_

8

9 10 11 12

Measuring Functionalities without extended measuring functionality Min/Max values, energy counter Protective Elements Basic Generator Elements, included in all versions Overcurrent protection with undervoltage seal in Overcurrent protection, directional Inverse time O/C protection Thermal overload protection Negative sequence protection Differential protection Loss-of-field protection Reverse power protection Forward power supervision Undervoltage protection Overvoltage protection Frequency protection Overexitation (Volt/Hertz) protection Stator earth fault protection, non–directional, directional Sensitive earth fault protection (also as rotor earth fault protection) Rotor earth fault protection (fn, R measurement) Motor starting time supervision Breaker failure protection Phase sequence supervision 4 external trip commands Trip circuit monitoring Fuse failure monitor Threshold supervision

Standard Generator Protection, consisting of: Basic Generator elements, + comprising: Impedance protection 100 % stator earth fault protection with 3rd harmonic Inadvertent energization protection Full Generator Protection, consisting of: Standard Generator protection, + comprising: Out-of-step protection DC voltage/DC current protection Startup overcurrent protection Earth current differential protection Asynchronous Motor Protection,consisting of: Basic Generator Elements without underexcitation and overexitation protection but with motor restart inhibit

_

13 14 15

0

0 3

A (I> +U<) (I>>, dir.) (t=f(I) +U<) (I2t) (I2>, t=f(I2)) (∆I) (1/xd) (–P) (P>, P<) (U<, t=f(U)) (U>) (f<, f>) (U/f) ((U0>, 3I0>, ∠U0, 3I0) (IEE>) (RE<) (Ian2t) (Imin>) (L1; L2; L3) (external trip) (TC mon.) ((U2/U1; I1/I2)

ANSI 51 ANSI 50/51/67 ANSI 51V ANSI 49 ANSI 46 ANSI 87G/87M/87T ANSI 40 ANSI 32R ANSI 32F ANSI 27 ANSI 59 ANSI 81 ANSI 24 ANSI 59N, 64G, 67G ANSI 50/51GN, 64R ANSI 64R (fN) ANSI 48 ANSI 50BF ANSI 47 --ANSI 74TC ANSI 60FL B

(Z<) (U0 (3. Harm.)) (I>, U<)

ANSI 21 ANSI 59TN, 27TN3.H ANSI 50/27 C

(∆Z/∆t) (Udc>) (I>)

ANSI 78 ) ANSI 59N (DC)/51N (DC) ANSI 51 ANSI 87GN/TN F

(I2t)

ANSI 66, 49 Rotor

H Transformer Protection,consisting of: Basic Generator Protection, without underexcitation protection, unbalanced load protection and motor starting time supervision Functionality/Additional Functions without

A

Sensitive Rotor Earth Fault Protection (Square-wave voltage injection 1–3 Hz, Re<80 kΩ) and 100 % stator earth fault protection (Principle of 20 Hz voltage injection)

ANSI 64R (1 to 3 Hz)

Earth Current Differential Protection

ANSI 87GN/TN

C

Network Decoupling (df/dt and vector jump)

ANSI 81R

E

ANSI 64G (100 %)

All additional functions

Ordering example:

B

G

7UM6211–4EA99–0BA0 + L0B + M1K here: Pos. 11 = 9 stands for L0B, i.e. version with Profibus DP system port on the rear optical, double ring here: Pos. 12 = 9 stands for M1K, i.e. version with rear service port DIGSI 4, modem RS232 and analog outputs 2 x (0 to 20 mA)

7UM62 Manual C53000-G1176-C149-3

463

A Appendix

A.1.1

Accessories

Interface Modules

Terminal Block Covering Caps

Exchange Modules for Interfaces Name

Order No.

RS232

C53207-A351-D641-1

RS485

C53207-A351-D642-1

FO 820 nm

C53207-A351-D643-1

Profibus DP RS485

C53207-A351-D611-1

Profibus DP double ring

C53207-A351-D613-1

Modbus RS485

C53207-A351-D621-1

Modbus 820 nm

C53207-A351-D623-1

DNP3.0 RS485

C53207-A351-D631-1

DNP3.0 820 nm

C53207-A351-D633-1

Analog output AN20

C53207-A351-D661-1

Covering cap for terminal block type

Order No.

18 terminal voltage, 12 terminal current block

C73334-A1-C31-1

12 terminal voltage, 8 terminal current block

C73334-A1-C32-1

Short circuit links for purpose/terminal type

Order No.

Voltage connections, 18 terminal, or 12 terminal

C73334-A1-C34-1

Current connections,12 terminal, or 8 terminal

C73334-A1-C33-1

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

Lithium-Battery 3 V/1 Ah, Type CR 1/2 AA

Order No

VARTA

6127 101 501

Short Circuit Links

Pin Connectors

Mounting Rail for 19"-Racks

Battery

464

7UM62 Manual C53000-G1176-C149-3


Coupling Unit

The sensitive earth fault protection can be used as rotor earth fault protection. The system frequency bias voltage for the rotor circuit is generated and coupled to the rotor circuit via a coupling unit. Coupling unit for rotor earth fault protection (R, fn)

Order No.

Coupling unit for panel flush mounting

7XR6100-0CA00

Series resistor for rotor earth fault protection (R, fn)

Order No.

Series resistor (2 x 105 Ω)

3PP1336-0DZ-013002

Voltage divider

Order No.

Voltage divider 5:1; 5:2

3PP1336-1CZ-013001

Voltage divider 10:1; 20:1

3PP1326-0BZ-012009

Controller unit

Order No.

In housing for panel surface mounting – with terminals at both sides

7XT7100-0BA00

In housing for panel flush mounting – with terminals at the rear side

7XT7100-0EA00

Resistor unit

Order No.

In housing for panel surface mounting

7XR6004-0BA00

In housing for panel flush mounting

7XR6004-0CA00

20-Hz-Generator

Order No.


7XT3300-0BA00


7XR3300-0CA00

20-Hz-Band-Pass Filter

Order No.


7XT3400-0BA00


7XR3400-0CA00

Series Resistor

Voltage Divider

Controller Unit

Resistor Unit

20-Hz-Generator

20-Hz-Band-Pass Filter

7UM62 Manual C53000-G1176-C149-3

465

A Appendix

Interface Cable

Operating Software DIGSI® 4

An interface cable is necessary for communication between the SIPROTEC device and a PC. Requirements for the computer are Windows 95 or Windows NT4 and the operating software DIGSI® 4. Interface cable between PC or SIPROTEC device

Order No.

Cable with 9-pin male/female connections

7XV5100-4

Software for setting and operating SIPROTEC® 4 devices 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 Graphical Analysis Program SIGRA

Graphic Tools

DIGSI REMOTE 4

SIMATIC CFC 4

466

7XS5402-0AA0

Software for graphical visualization, analysis, and evaluation of fault data. Option package of the complete version of DIGSI® 4 Graphical analysis program SIGRA®

Order No.

Full version with license for 10 computers

7XS5410-0AA0

Graphical Software to aid in the setting of characteristic curves and provide zone diagrams for overcurrent and distance protective devices. Option package of the complete version of DIGSI® 4. Graphic Tools 4

Order No.


7XS5430-0AA0

Software for remotely operating protective devices via a modem (and possibly a star connector) using DIGSI® 4. (Option package of the complete version of DIGSI® 4. DIGSI REMOTE 4

Order No.


7XS5440-1AA0

Graphical software for setting interlocking (latching) control conditions and creating additional function is SIPROTEC 4 devices. Option package for the complete version of DIGSI® 4. SIMATIC CFC 4

Order No.

Full version with license for 10 machines

7XS5450-0AA0

7UM62 Manual C53000-G1176-C149-3


A.1.1.1

Schematic Diagram of the Accessories

4A1 4B1 ≈ 4 µF

3A1 3B1 2B1

≈ 33 Ω/50 W

2A1 1B2

≈ 0.75 H 1A4

230 V

1A3 100 to 125 V 1A1

Figure A-1

0V

0V

Schematic Diagram of Coupling Unit 7XR6100-0∗A00

105 Ω 1

Figure A-2

7UM62 Manual C53000-G1176-C149-3

3

4

Schematic Diagram of Series Resistor 3PP1336-0DZ-013002

500 Ω 2

3 500 V

Figure A-3

105 Ω 2

11.6 Ω 1

1B4 1B3 ≈ 60 V ≈ 36 V–49 V 1B1

500 Ω 4

250 Ω 5 100 V

6 0V

Schematic Diagram of Voltage Divider 5:1; 5:2; 3PP1336-1CZ-013001

467

A Appendix

500 Ω

500 Ω

1

Figure A-4

9000 Ω

2

3

4

Schematic Diagram of Voltage Divider 10:1; 20:1; 3PP1326-0BZ-012009

Surface mounting housing Flush mounting housing

27

27

UOutput

L

7

7

9

9

25

Auxiliary voltage 230 VAC

~X

230 VAC

15 =

N 11

7XR60

25

15 UMeas

100...115 VAC

17

11 120, 125 VAC

19

UControl

21

17

7UM 19 21

Factory Set: 100 - 125 VAC

Figure A-5

General Diagram of Controller Unit 7XT7100-0∗A00

2

3,33 kΩ

3

4

5

6

7

8

9

10 12

20 kΩ

20 kΩ

20 kΩ

3

6

5

8

7

10

9

12

468

17

1

2

Figure A-6

11

15

16

4

B

13

14

18

1

A

20 kΩ

11

General Diagram of Resistor Unit 7XR6004-0∗A00

7UM62 Manual C53000-G1176-C149-3


1A1 U L1 ( L1, UH+ )

U L2 (N, U H- ) U L3

4A1

1A2

20 Hz

1A3

L+ 2A1 EXTERNAL BLOCK 2A3

4A3

to 77XT34 to XT43 (Ban pass) (Band d pas s)

Surface mounting case / Flush mounting case

3A2

BI

3A1

L+

3A3 DEVICE OPERATIVE

1A4

Figure A-7

7UM62 Manual C53000-G1176-C149-3

General Diagram of 20-Hz-Generator 7XT3300-0∗A00

469

A Appendix

Surface mounting case / Flush mounting case

1B3 10 mF

0R68, 4 x 50 W

1B4

INPUT BANDPASS

600 mH

47 mF

1B1

OUTPUT BANDPASS 47 mF

330R, 50 W

1A1 1A2

330R, 50 W

VOLTAGE DIVIDER 330R, 50 W

1A3 1A4 330R, 50 W

Figure A-8

470

330R, 50 W

General Diagram of 20-Hz-Band-Pass Filter 7XT3400-0∗A00

7UM62 Manual C53000-G1176-C149-3


1.1.1.2

Dimensional Drawing of the Accessories

29.5

172

150 145

30

244

266

Mounting plate

B

A

4 3

1)

2 1

2)

Rear view Connector modules

Side view

146 + 2 1)

Screwed terminal for max. 4 mm2; Twin spring crimp connector in parallel for max. 2.5 mm; max. torque value 1.2 Nm. 2)

245 + 1

255.8

± 0.3

5 or M4

Current connectors:

Further connectors:

Screwed terminal for max. 1.5 mm2; Twin spring crimp connector in parallel for max. 1.5 mm; max. torque value 0.8 Nm.

5.4

6

13.2

105 ± 0.5

7.3

131.5 ± 0.3

Panel cut-out

Figure A-9

Dimensions in mm

Dimensions of Coupling Unit 7XR6100-0CA0 for Panel Flush Mounting

7UM62 Manual C53000-G1176-C149-3

471

A Appendix

Mounting plate

30

B

244

266

312.8

209.5

150 145

A

1

4 3

)

2 2)

1

Connector modules Side view

Rear view

6.4

300 ± 0.3

5 or M4

15

120 ± 0.3

Dimensions on the mounting plate

Dimensions in mm Figure A-10 Dimensions of Coupling Unit 7XR6100-0BA0 for Panel Surface Mounting

472

7UM62 Manual C53000-G1176-C149-3


Drip–proof roof Drip-proof roof

Space required for

Space required for removing the cover removing the cover

Cover Cover

Table A-1 Type

3PP1 Degree of Protection IP 20 (with Drip–Proof Roof IP 23); Dimensions in mm a

b

c

d

e

f

g

h

i

k

l

m

z

3PP1 32

267

187

3 x 16

7

160

230

10

110

50

30

10

196

33

3PP1 33

267

187

3 x 16

7

160

230

10

146

50

30

10

196

33

Figure A-11 Dimensions 3PP13: 3PP132 for voltage divider 3PP1326-0BZ-012009 (20 : 10 : 1) 3PP133 for voltage divider 3PP1336-1CZ-013001 (5 : 2 : 1) for series resistor 3PP1336-0DZ-013002

7UM62 Manual C53000-G1176-C149-3

473

A Appendix

recommended space to the next 180 unit

77

260 9

266

30

280

300

31 31

29.5

8

7

1 2

100

55

A Current connections (terminals 1 to 6):

View A

20

Connections for earthing

not used in 7XT71 Voltage connections (terminals 7 to 31): isolated ring cable lug: for bolts 4 mm diameter max. major diameter 9 mm type: e.g. PIDG of Messrs. Tyco Electronics AMP for copper wires with cross*section 1.0 mm2 to 2.6 mm2 AWG 17 to 13 solid bare copper wire directly: cross*section 0.5 mm2 to 2.6 mm2 AWG 20 to 13 flexible wire requires end sleeves max. torque value 1.8 Nm or 16 in-lbs

Dimensions in mm

Figure A-12 Dimensions of Controller Unit 7XT7100-0BA00 for Panel Surface Mounting

474

7UM62 Manual C53000-G1176-C149-3


29.5

172

37

75 70

Mounting plate 31 29 27

2244 44

2266 66

30

11 9

8

7

Connec tions for earthing Connections terminals 71 +2 Current connections (terminals 1 to 6):

0,3

5 or M4 245 +1

+

255.8

not used in 7XT71 Voltage connections (terminals 7 to 31): isolated ring cable lug: for bolts 4 mm diameter max. major diameter 9 mm type: e.g. PIDG of Messrs. Tyco Electronics AMP for copper wires with cross*section 1.0 mm2 to 2.6 mm2 AWG 17 to 13 Snap-in terminal: for copper wires with cross*section 0.5 mm2 to 2.5 mm2 AWG 20 to 13 max. torque value 1.8 Nm or 16 in-lbs

55.4 .4

66 Dimensions in mm 7.3

56.5 +0.3 Panel cutout

Figure A-13 Dimensions of Controller Unit 7XT7100-0EA00 for Panel Flash Mounting

7UM62 Manual C53000-G1176-C149-3

475

A Appendix

29.5

172

34

244

266

Mounting plate

Side view (with screwed terminals) 225 220

221 + 2

2 1 4 3 6 5 8

5 or M4

7 9

B

255.8 ± 0.3

12 11 14 13 16 15 18 17

2

245 + 1

10

1 4 3 6 5 8

A

7

6

10 9 12

5.4

11

Rear view

13.2

180 ± 0.5

7.3

206.5 ± 0.3

Panel cut-out

Dimensions in mm

Figure A-14 Dimensions of Resistor Unit 7XR6004-0CA00 for Panel Flash Mounting

476

7UM62 Manual C53000-G1176-C149-3


34

244

209.5

312.8

266

Mounting plate

Side view (with screwed terminals) 225 220 4.5

2 1 4 3 6 5 7 10 9

B

12 11 14 13 16 15 18 17

300 ± 0.3

8

2 1 4 3 6 5 8

A

7 10 9 12

6.4

11

Rear view

Dimensions in mm

12.5

100 ± 0.3 200 ± 0.3

Fixing points of the mounting plate

Figure A-15 Dimensions of Resistor Unit 7XR6004-0BA00 for Panel Surface Mounting

7UM62 Manual C53000-G1176-C149-3

477

A Appendix

29.5

30

172

225 220

Mounting plate

B

A

4 3 2 1

+2

221

5 or M4

Connector modules

Connectors: Screwed terminal for max. 1.5 mm2. Twin spring crimp connector in paral lel for max. 1.5 mm2.

Panel cut-out

6

13.2 7.3

180 206.5

+0.5 +0.3 -

Dimensions in mm

Figure A-16 Dimensions of 20-Hz-Generator 7XT3300-0CA00 for Panel Flash Mounting

478

7UM62 Manual C53000-G1176-C149-3


225 220

30

244

266

312

209,5

B

A

4 3 2 1

Connector modules

.3

Connectors: Screwed terminal for max. 1.5 mm2. Twin spring crimp connector in paral lel for max. 1.5 mm2.

300 +- 0.3

ø4.5 oder M5

12.5

6.4

Dimensions in mm

100 +- 0,3 200 +- 0.3 .3

Figure A-17 Dimensions of 20-Hz-Generator 7XT3300-0BA00 for Panel Surface Mounting

7UM62 Manual C53000-G1176-C149-3

479

A Appendix

29.5

225 220

30

172 Mounting plate

266

244

Set square *)

B

A

221 +2 32

Dimensions in mm

31.8 +- 0.3 (180 +- 0.5 )

M4(4x)

*) For panel flush mounting, 2 set squares C73165- A63-C201-1 are necessary since the mounting rails of the device are not sufficient for the high weight of the device. Fix the set squares to the panel, us ing 8 standard screws size M6, ac cording to the drawing. Mount the device to the set squares using standard sqrews size M4. If the device is mounted in switchgear cabinets, the set squares can be omitted provided the cabinet po sesses adequate solid mounting rails. If not, use 2 set squares C73165-A63-C200-3 (size 28 31.8 +- 0.3 SEP = 19 inches).

( 206.5 +- 0.3 )

239.5 +- 0.3

6 -+ 0.3

234.9 -+ 0.3

(245)

(255.8)

310.6 +1

Ø5.5(4x)

Hole diameter 7 mm (8 ×) for screws size M6

Figure A-18 Dimensions of 20-Hz-Band-Pass Filter 7XT3400-0CA00 for Panel Flash Mounting

480

7UM62 Manual C53000-G1176-C149-3


172

225

30

220 Side view 31.8 +- 0.3

B

A

234.9 -+ 0.3

244

29,5

31.8 +- 0.3 .3

Set square *)

239.5 +- 0,3 32

Distance piece *) Dimensions in mm

*) 2 set squares C73165- A63-C201-1 and 4 distance pieces C73165-A63-C203-1 are necessary for panel surface mounting. Fix the set squares to the mounting rails of the device, using 8 standard screws size M4. Fit threaded holes, sleeves, or bolts size M6 into the panel, according to the above draw ing. Fasten the device with the fixed set sqares to the panel and ensure correct distance by means of the distance pieces. When using fixed bolts: Fit the distance pieces onto the bolts and fasten the device by means of female screws.

Top view

Figure A-19 Dimensions of 20-Hz-Band-Pass Filter 7XT3400-0BA00 for Panel Surface Mounting

7UM62 Manual C53000-G1176-C149-3

481

A Appendix

A.2

General Diagrams (IEC)

A.2.1

Housing for Panel Flush Mounting or Cubicle Installation

7UM621∗–∗D/E IL1S2 IL2S2 IL3S2 IEE2

BO1 BO2 BO3 BO4 BO5 BO6

R1 R2 R3 R4 R6 R5 1 2

R8

3 2

J1 J2 J3 J4 J5 J6 J7 J8

(+) (–) (+) (–) (+) (–)

IL1S1

BO7

IL2S1

BO8

IL3S1

BO9

IEE1

BO10

R15 R17 R18 R16 R13 R14

UL1 UL2 UL3

F5 F6 F7 F8 F9 F10 K9 K10 K11 K12

BI1 BI2 BI3 BI4 BI5

K13 K14 K15 K16 K17 K18

UE

BO11

R7 R9 R10 R11 R12 K1 K2 K3 K4

1 2

K6

3 2

BO12

K5

1 2

K8

3 2

Life status contact

Powersupply

K7

1 2

F4

3 2

(~)

F3 +

F1

-

F2

BI6 BI7

Analog output or Thermobox

D

TD1

Service Port or Thermobox

C


B

TD2 TD3

Time Synchronization

A

Front oper. interface Earthing at Side Wall of Housing

For the pin assignment of Interfaces, refer to Table 3-20 to 3-22 in Subsection 3.2.1

Q1 Q2 Q3 Q4 Q5 Q6 Q7 Q8

Interference suppression capacitors at the relay contacts, Ceramic, 4.7 nF, 250 V

Figure A-20 General Diagram 7UM621∗−∗D/E (Panel Flush Mounting or Cubicle Installation)

482

7UM62 Manual C53000-G1176-C149-3

A.2 General Diagrams (IEC)

7UM622∗–∗D/E

J1 J2 J3 J4 J5 J6 J7 J8 R15 R17 R18 R16 R13 R14 F5 F6 F7 F8 F9 F10 K9 K10 K11 K12 P17 P18 N1 N2 N3 N4 N6 N5 N7 N8 N9 N10 N11 N12 (+) (–) (+) (–) (+) (–)

K13 K14 K15 K16 K17 K18

IL1S2 IL2S2 IL3S2 IEE2


R1 R2 R3 R4 R6 R5 1 2

R8

3 2

IL1S1 IL2S1 IL3S1 IEE1 UL1 UL2 UL3 UE BI1 BI2 BI3 BI4 BI5 BI6 BI7 BI8 BI9 BI10 BI11 BI12

BO8 BO9 BO10 BO11

1 2

BI15

K6

3 2

BO12

K5

1 2

K8

3 2

BO13

K7

1 2

P4

3 2

P3 P6 P7 P8 P5 P9 P10 P11 P12 P13 P14 P15 P16

BO14 BO15 BO16 BO17 BO18 BO19 BO20

Life status contact

1 2

F4

3 2

BI13 BI14

R7 R9 R10 R11 R12 K1 K2 K3 K4

BO7

Power supply

(~)

F3 +

F1

-

F2


D

Service port or Thermobox

C


B

Time synchronization

A

TD1 TD2 TD3

For the pin assignment of the interfaces see tables 3-20 to 3-22 in subsection 3.2.1

Q1 Q2 Q3 Q4 Q5 Q6 Q7 Q8

Front oper. interface Earthing at rear wall of housing

Interference suppression capacitors at the relay contacts Ceramic, 4.7 nF250 V

Figure A-21 General Diagram 7UM622∗−∗D/E (Panel Flush Mounting or Cubicle Installation)

7UM62 Manual C53000-G1176-C149-3

483

A Appendix

A.2.2

Housing for Panel Surface Mounting

7UM621∗–∗B

IL3S2

BO1 BO2 BO3 BO4 BO5

IEE2

BO6

IL1S2 IL2S2

74 99 73 98 72 97 1 2

71

3 2

14 39 13 38 12 37 11 36

(+) (–) (+) (–) (+) (–)

IL1S1

BO7

IL2S1

BO8

IL3S1

BO9

IEE1

BO10

20 19 44 45 21 46

UL1 UL2 UL3

58 57 56 55 54 83 88 63 87 62

BI1 BI2 BI3 BI4 BI5

86 61 85 60 84 59

TD1

UE

BO11

96 95 70 94 69 92 67 91 66

1 2

65

3 2

BO12

90

1 2

64

3 2

Life status contact

Power supply

89

1 2

52

3 2

(~)

51 +

15

-

16

BI6

Earthing terminal (26)

BI7 2 27 3 28 4 29 1

Time synchronization TD2 TD3


D

Service port or Thermobox

C

System interface or analog output Front oper. interface Earthing at side wall of housing

*)

B

IN SYNC IN 12 V COM SYNC COMMON IN 5 V IN 24 V Screen

For the pin assignment of the interfaces see tables 3-20 and 3-21 in subsection 3.2.1

25 50 24 49 23 48 22 47

*) optical only IEC


Figure A-22 General Diagram 7UM621∗–∗B (Panel Surface Mounting)

484

7UM62 Manual C53000-G1176-C149-3

A.2 General Diagrams (IEC)

7UM622∗–∗B

25 75 24 74 23 73 22 72 45 44 94 95 46 96 108 107 106 105 104 158 172 122 171 121 90 40 89 39 86 36 35 85 84 34 83 33 82 32 (+) (–) (+) (–) (+) (–)

170 120 169 119 168 118

IL1S2 IL2S2 IL3S2 IEE2


149 199 148 198 147 197 1 2

146

3 2

IL1S1 IL2S1 IL3S1 IEE1 UL1 UL2 UL3 UE BI1 BI2 BI3 BI4 BI5 BI6 BI7 BI8 BI9

196 195 145 194 144 176 126 175 125

BO7 BO8 BO9 BO10 BO11

1 2

124

3 2

BO12

174

1 2

123

3 2

BO13

173

1 2

140

3 2

190 139 188 138 189 187 137 186 136 185 135 184 134

BO14 BO15 BO16 BO17 BO18 BO19 BO20

BI10 BI11 BI12

Life status contact

BI13

Power supply

1 2

102

3 2

+

101 37

-

38

(~)

Earthing terminal (51)

BI14 2 52 3 53 4 54 1

BI15 TD1


TD2 TD3 Analog output or Thermobox

D

Service interface or Thermobox

C

System interface or analog output Front oper. interface Earthing at side wall of housing

*)

B

IN SYNC IN 12 V COM SYNC COMMON IN 5 V IN 24 V Screen For the assignment of the interfaces see tables 3-20 and 3-21 in subsection 3.2.1

50 100 49 99 48 98 47 97

*) optical only IEC


Figure A-23 General Diagram 7UM622∗–∗B (Panel Surface Mounting)

7UM62 Manual C53000-G1176-C149-3

485

A Appendix

A.3

General Diagrams (ANSI)

7UM621∗– Surface-mounting housing Flush-mounting housing Q1 Q2 Q3 Q4 Q5 Q6 Q7 Q8

20 19 44 45 21 46

R 15 R 17 R 18 R 16 R 13 R 14

VA VB VC

14 39 13 38 12 37 11 36

J1 J2 J3 J4 J5 J6 J7 J8

IA,S1

IA,S2 IB,S2 IC,S2 IG,sens. (EE2)

7UM621

R 1 R 2 R 3 R 4 R 5 R 6 R 7 R 8

VN(E) R9

86 61 85 60

K 13 K 14 K 15 K 16

R 10 IB,S1 R 11 IC,S1 IG,sens.(EE1) +

TD1 (Start-up)

+

TD 2 (TEMP)

+

84 59

K 17 K 18

58

F5

BI 1

57

F6

BI 2

56

F7

BI 3

55

F8

BI 4

54 83

F9 F 10

BI 5

88 63 87 62

K9 K 10 K 11 K 12

BI 6

R 12 Live status contact (NC or NO with Jumper) Power supply

=

= + (~) -

TD 3 (DC-EXC)

BI 7

74 99 73 98 72 97 96 71 95 70 94 69

K1 K2 K3 K4 K5 K6

92 67 91 66 90 65

K7 K8

89 64

F3 F4

51 52

F1

15

F2

16

Port Serial Thermal/ or 2 x 20 mA Service interface IEC 60870-5-103 PROFIBUS DP MODBUS RTU

IRIG B/DCF77 Front port

R1 R2 R3 R4 R6 R5 R7 R8 R9 R 10 R 11 R 12

Earth connection at housing back plate

D

C

B (optical only IEC)

A

2 27 3 28 4 29 1

(see manual)

25 50 24 49 23 48 22 47

Figure A-24 General diagram 7UM621∗−

486

7UM62 Manual C53000-G1176-C149-3

A.3 General Diagrams (ANSI)

7UM622∗– Surface-mounting housing Flush-mounting housing 50 100 49 99 48 98 47 97

Q1 Q2 Q3 Q4 Q5 Q6 Q7 Q8

45 44 94 95 46 96

R 15 R 17 R 18 R 16 R 13 R 14

VA VB VC

25 75 24 74 23 73 22 72

J1 J2 J3 J4 J5 J6 J7 J8

IA,S1

170 120 169 119

K 13 K 14 K 15 K 16

TD 1 (Start-up)

168 118

K 17 K 18

TD 3 (EXC.)

R 17

108

F5

BI 1

R 18

107

F6

BI 2

106

F7

BI 3

105

F8

BI 4

104 158

F9 F 10

BI 5

172 122 171 121

K9 K 10 K 11 K 12

BI 6

90 40 89 39 86

P 17 P 18 N1 N2 N3

BI 8

36

N4

BI 11

IA,S2

7UM622 IB,S2

R1 R2 R3 R4 R6 R5 R7 R8 R9 R 10 R 11 R 12

149 199 148 198 147 197 196 146 195 145 194 144

K1 K2 K3 K4 K5 K6

176 126 175 125 174 124

R12

K7 K8

173 123

R 13

P3 P4 P6 P7 P8 P5 P9 P10 P 11 P12 P13 P 14 P 15 P 16

190 140 139 188 138 189 187 137 186 136 185 135 184 134

F3

101

F4

102

F1

37

F2

38

R 2 R 3

IC,S2 IG,sens.

R 1

(EE2)

R 4 R 5 R 6 R 7 R 8

VN(E) R 9 R10 IB,S1 R11 IC,S1 IG,sens.(EE1)

TD 2 (Temp)

R 14 R 15 R 16

R 19 R 20

BI 7

Live status contact (NC or NO with jumper) Power supply

=

= + (~) -

BI 9 BI 10 Port

N6 N5 N7 N8 N9 N10 N11 N12

BI 12 BI 13 BI 14

Service interface IEC 60870-5-103 PROFIBUS DP MODBUS RTU

BI 15 IRIG B/DCF77 Front port

Earth connection at housing back plate

D

C B (optical only IEC)

A

2 52 3 53 4 54 1

(see manual)

35 85 84 34 83 33 82 32

Serial Thermal/ or 2 x 20 mA

Figure A-25 General diagram 7UM622∗−

7UM62 Manual C53000-G1176-C149-3

487

A Appendix

A.4

Connection Examples A (L1) B (L2) C (L3)

ANSI 52

RL

7UM62 J1 J2 J3 J4 J5 J6

e

n

IC(L3)S1 VA(L1) VB(L2) VC(L3)

R13

VE

R14 Q8

l

Q7

Rotor earth current injection

IB(L2)S1

R15 R17 R18 R16

k

Excitation voltage injection

IA(L1)S1

K17 +

IEE2

TD3

K18

J7

IEE1

J8

Q1 Q2 Q3 Q4 Q5 Q6

IA(L1)S2

Measuring transducer:

K13 +

TD1

-Temperature injection - or DC voltage injection

K14 K15 +

IB(L2)S2 IC(L3)S2

TD2

K16

Figure A-26 Bus–Bar Connection Current and voltage connections to three transformers, core balance neutral current transformers and broken delta voltage transformers (e–n).

488

7UM62 Manual C53000-G1176-C149-3

A.4 Connection Examples

A (L1) B (L2) C (L3)

ANSI 52

7UM62

e

n

Excitation voltage injection

J1 J2 J3 J4 J5 J6

IA(L1)S1

R15 R17 R18 R16

VA(L1) VB(L2) VC(L3)

R13

VE

IB(L2)S1 IC(L3)S1

R14 K17 +

TD3

K18 Q7 Q8

IEE2

do not earth here

RE

low resistance if necessary (for protection of resistor

Q1 Q2 Q3 Q4 Q5 Q6

IA(L1)S2

Measuring transducer:

K13 +

TD1

- Temperature injection - or DC voltage injection

K14 K15 +

IB(L2)S2 IC(L3)S2

TD2

K16 J7 J8

IEE1

Figure A-27 Busbar System with Low-Ohmic, Switchable Starpoint Resistors Connection on each side to three current transformers and three voltage transformers (phase-to-ground voltages) –earth fault detection as differential current measuring by two CT sets; detection of displacement voltage at broken delta winding (e–n).

7UM62 Manual C53000-G1176-C149-3

489

A Appendix

A (L1) B (L2) C (L3)

ANSI 52

Yd5

Earthing transformer with measuring winding

7UM62 R15 R17 R18 R16


R13

VE

e RL n

R14

For 100 % stator earth fault protection

J7 J8

IEE1

J1 J2 J3 J4 J5 J6

IA(L1)S1

K17 +

TD3

IB(L2)S1 IC(L3)S1

Divider 3PP1326 VExc.

Excitation

Rotor earth-current injection

Measuring transducer: - Temperature injection - or DC voltage injection

K18 Q7 Q8

IEE2

Q1 Q2 Q3 Q4 Q5 Q6

IA(L1)S2

K13 +

TD1

IB(L2)S2 IC(L3)S2

K14 K15 +

TD2

K16

Figure A-28 Block Connection with Isolated Starpoint Connection on each side to three current transformers and three voltage transformers (phase-to-earth voltages). Differential protection function only used for the generator; Detection of displacement voltage at a broken delta winding (e–n).

490

7UM62 Manual C53000-G1176-C149-3


A (L1) B (L2) C (L3)

ANSI 52

7UM62 J1 J2 J3 J4 J5 J6

IA(L1)S1 IB(L2)S1 IC(L3)S1

Yd11

R15 R17 R18 R16


Divider 3PP1326 K17 +

Excitation

VExc. Rotor earth current injection

RL

RE

TD3

K18 Q7 Q8

IEE2

Q1 Q2 Q3 Q4 Q5 Q6

IA(L1)S2

R13

VE

IB(L2)S2 IC(L3)S2

R14 max. 10A Neutral transformer

For 100 % stator earth-fault protection

J7 J8

IEE1

Measuring transducer: - 1-3Hz-Rotor earth fault protection - or Temperature injection - or DC voltage injection

K13 +

TD1

K14 K15 +

TD2

K16

Figure A-29 Block Connected Generator with Neutral Earthing Transformer Block Connection with Isolated Starpoint Connection on each side to three current transformers and three voltage transformers (phase-to-earth voltages). Differential protection function connected via generator and unit transformer; Loading resistor connected either directly to starpoint circuit or via matching transformers.

7UM62 Manual C53000-G1176-C149-3

491

A Appendix

7UM62 K15 +

TD2

K16 K17 +

UExc.

Exc.

+ 12

7KG6 - 11 (Amplifier)

TD3

K18

+ 31

K13 +

- 32

K14

TD1

connections shall be twisted and screened

max. 10 cm Shunt: 10 A/ 150 mV

Figure A-30 Startup Earth Fault Protection Connection of DC Voltage Input TD1 with Series-Connected Amplifier 7KG6 for Systems with Startup Converter

Connection to the phase-to-phase VT voltage

7UM62

100 V - 125 V AC

+

Exc.

105Ω 4A1

3PP1336

7XR61 4B1

-

1A3 1A1 2B1 1B3 1B1

J8 J7

IEE1

R13 R14

VE

105Ω

Figure A-31 Rotor Earth Fault Protection – with additional source 7XR61 for injecting a nominal-frequency test voltage between the rotor circuit and the earth, with series-connected resistor 3PP1336

492

7UM62 Manual C53000-G1176-C149-3


Connection to the phase-to-phase VT voltage

7UM6

100 V - 125 V AC

+

Exc.

105Ω 4A1

3PP1336

7XR61 4B1

-

1A3 1A1 2B1

J7 J8

IEE1

1B3 1B1

105Ω

Figure A-32 Rotor Earth Fault Protection – with series device 7XR61for injection of a rated-frequency voltage into the rotor circuit if the sensitive earth current input is used.

7UM62 Manual C53000-G1176-C149-3

493

A Appendix

A (L1) B (L2) C (L3)

ANSI 52 e

7UM62

n R13

VE

R14 R15 R17 R18 R16


J1 J2 J3 J4 J5 J6

IA(L1)S1

k

Q8

IEE2

l

Q7 K13 + RTD module

7XV5662 (6 meas. junctions)

Measuring transducer K14 for injection of any analog signal K15 + e.g. speed, vibration, pressure K16 K17 + To serial interface

IB(L2)S1 IC(L3)S1

TD1

TD2

TD3

K18 J7

IEE1

J8 Q1 Q2 Q3 Q4 Q5 Q6

FromRTD module

IA(L1)S2 IB(L2)S2 IC(L3)S2

Port PortCCoder or DD

Figure A-33 Asynchronous Motor Connection to three voltage transformers (phase-to-earth voltages, usually picked up at the busbar); Displacement voltage detection at broken delta winding, three current transformers on each side; Earth fault direction detection by toroidal CTs

494

7UM62 Manual C53000-G1176-C149-3


L1

L2

L3

7UM61 7UM62 R15 R17 R18 R16

VU A(L1) L1 VU B(L2) L2 VU L3 C(L3)

Figure A-34 Voltage Transformer Connections for Two Voltage Transformers in Open Delta Connection (V Connection)

A B

C

L1

L3

L2

7UM6 7UM62 R15 R17 R18 R16

V UA(L1)

A(L1),

V UB(L2) B(L2) V UC(L3) C)L3)

Figure A-35 Voltage Transformer Connection with L2 Earthed on the Secondary Side

Connection to the phase-to-phase VT voltage 7UM62 120 V 100 V 110 V 7

7XT71

9 11

+

Exc.

40 kΩ

27

19 21

7XR6004

Control input

15 -

40 kΩ

17

Measuring input

K13 + K14

TD1

K15 +

TD2

K16

25

Figure A-36 Rotor Earth Fault Connection 1 to 3 Hz – with 1-3 Hz generator 7XT71 and resistor device 7XR6004.

7UM62 Manual C53000-G1176-C149-3

495

A Appendix

7UM62

At gas turbines: Injection of cold gas temperature

K15 + K16 K17 +

Excitation

VExc.

1B1

7XT34

7XT33 1B4

4A1

1A1 Neutral transformer

400A 5A P1

P2

Wiring shielded

RL 1A4

1A3

BE

4A3

S1 S2

1A1 1A2 1A3 2A1 2A3 3A2 3A3 3A1

DC +VH -VH

7KG6 - 11 (Amplifier)

K18

AC VA(L1) UB(L2) UC(L3)

External block Device operative R13 max 200 V

+ 12

TD3

Auxiliaryvoltage

20-HzGenerator

20-HzBandpass

TD2

VE

R14 J8 J7

IEE1

+ 31

K13 +

TD1

- 32

K14 Wiring twisted and shielded

max. 10 cm Shunt: 10 A/ 150 mV

Figure A-37 100–% Stator Earth Fault Protection – with 20 Hz generator 7XT33 and band pass 7XT34

496

7UM62 Manual C53000-G1176-C149-3


A (L1) B (L2) C (L3)

Q7

Q8

J6 J5 J4 J3 J2 J1

Q6 Q5 Q4 Q3 Q2 Q1

7UM62 IEE2

IC(L3)S2 IB(L2)S2 IA(L1)S2


Figure A-38 Earth current differential protection (generator)

A (L1) B (L2) C (L3)

Q8

Q6 Q5 Q4 Q3 Q2 Q1

Q7

J6 J5 J4 J3 J2 J1

7UM62 IC(L3)S2 IB(L2)S2 IA(L1)S2

IEE2


Figure A-39 Earth current differential protection (transformer)

7UM62 Manual C53000-G1176-C149-3

497

A Appendix

A.4.1

Connection Examples for RTD-Box

7UM62

7UM62

Port D

7XV5650 T1 FO/RS485 Converter

A B

A’ A B B’

A Port C or D B

7XV566 RTD-Box Bus number: 00 A’ and B’ jumpers for the terminating resistors

A’ A

7XV566 RTD-Box

B B’

Bus number: 00 A’ and B’ jumpers for the terminating resistors

A’ A

7XV566 RTD-Box

Figure A-40 Simplex operation with one RTD-Box above: optical design (1 FO); below: design with RS485

7UM62

7UM62

Port D

R1 7XV5650 T1 FO/RS485 Converter

A B

A Port C or D B

B B’


A’ A

7XV566 RTD-Box

B B’


Figure A-41 Half-duplex operation with one RTD-Box above: optical design (2 FOs); below: design with RS485

7UM62

Port C1)

R1 7XV5650 T1 FO/RS485 Converter

A B

A B

Bus number: 01

A’ A

7XV566 RTD-Box

B B’

7UM62

A Port C2) B

1

) for 7SJ64 port D 2 ) for 7SJ64 optionally port C or D

7XV566 RTD-Box

A


7XV566 RTD-Box Bus number: 01

B A’ A

7XV566 RTD-Box

B B’


Figure A-42 Half-duplex operation with two RTD-Boxes above: optical design (2 FOs); below: design with RS485

498

7UM62 Manual C53000-G1176-C149-3

A.5 100–% Stator Earth Fault Protection with Primary Load Resistor

A.5

100–% Stator Earth Fault Protection with Primary Load Resistor Some power systems with generators in unit connection have a load resistor installed directly in the generator starpoint to reduce interference. Figure A-43 shows the connection of the 20 Hz generator and the band pass in this application, and the integration of the protection device. The 20 Hz voltage is injected into the generator starpoint via a powerful voltage transformer and drops off at the primary load resistor. In the presence of an earth fault, an earth current flows through the CT in the starpoint. The protection function detects and processes this current in addition to the 20 Hz voltage (see also Section 2.29). 20 Hz generator

20 Hz band pass

7XT33

7XT34 1B1 RL

UN √3

1B4 4A1 BI

1A1 500 V 1A4

1A3

4A3

Voltage transformer

Supply voltage DC AC 1A1 +U UL1 H 1A2 -U U H L2 1A3 UL3 2A1 External 2A3 blocking 3A2 3A3 Device 3A1 OK

7UM62

R13

UE

R14 J8 Transformation ratio 1:1

Figure A-43

Voltage Transformer Specification

Current Transformer Specification

7UM62 Manual C53000-G1176-C149-3

IEE1

J7

Connection: 100–% Stator Earth Fault Protection to a Primary Load Resistor

An unearthed voltage transformer with a low primary-secondary impedance must be used for the 20 Hz frequency. Primary voltage:

UN,Generator / √3 (non-saturated up to UN,Generator)

Secondary voltage:

500 V

Power for 20 s (50 Hz or 60 Hz)

3 kVA

Primary-secondary impedance at 20 Hz

Zps < RL (but at least < 1000 Ω)

Can be obtained e.g. from:

Ritz Messwandlerbau Salomon-Heine Weg 72 D-20251 Hamburg (Phone +49 (0) 40511123 333)

As the transformation ratio is 1:1, a current transformer with a maximum number of ampere windings must be chosen. The CT is installed directly in the starpoint on the earth side, downstream of the load resistor. Type:

5P10 or 5P15 (or 1FS10)

Rated secondary current:

1A

Transformation ratio:

1 (1A/1A)

499

A Appendix

A.5.1

Protection Settings The settings recommended are the same as in Section 2.29. In addition, the correction angle (address 5309 PHI I SEF) and the ohmic contact resistance of the voltage transformer must be determined during the primary tests, and set at address 5310A SEF Rps. The conversion factor for the resistance (secondary – primary and vice versa) is: ü VT ⋅ ü Divider FACTOR R SEF = --------------------------------ü CT Example: Primary load resistor: Voltage transformer: Ohmic divider: Current transformer:

RL = 1250 Ω üVT = 10.5 kV/√3/500 V üDivider = 1650 Ω/660 Ω (5:2) üCT = 1A/1A

10.5 kV 5 ---------------------------- ⋅ --3 ⋅ 500 V 2 FACTOR R SEF = ------------------------------------ = 30.3 1A --------1A Trip stage: primary 2 kΩ, secondary 66 Ω Alarm stage: primary 5 kΩ, secondary 165 Ω urrent stage: U N.Generator 10.5 kV ---------------------------------------------------3 3 SEF100I>> = 0, 1 ⋅ ---------------------------------- = 0, 1 ⋅ ----------------------------------------- ≈ 500 mA R L ⋅ ü CT 1250 Ω ⋅ 1A/1A

A.5.2

Commissioning The procedure is the same as described in Section 3.3. Measurements are carried out with the generator at standstill, and randomly selected tests are then repeated with the generator running. The following paragraph describes the method of adjustment. A decade resistor (0 to 10 kΩ) is required for the tests.

Generator at Standstill

1. After checking the connections, a supply voltage is applied to the 20 Hz generator and the protection device. The following parameters must be set as follows (delivery settings): address 5309 PHI I SEF = 0 ° and address 5310A SEF Rps = 0 Ω. In fault-free condition (RE infinite), read out the angle j SEF= from the operational measured values, and set the appropriate correction angle (see below). Due to the capacitive earth current, the angle measured must be negative. If it is not, the connection at the current input must be rotated. The correction angle is: Phi corr = –90 Grad –(Phi measured) Example: Phi measured = –47 Grad, Phi corr = –90 ° + 47 ° = –43 ° The correction angle is set at address 5309 PHI I SEF. 2. Create a short-circuit (RE = 0 Ω) in the generator starpoint, and read out the measured fault resistance (address 00764 R SEF=) from the operational measured values. This resistance is set at address 5310A SEF Rps.

500

7UM62 Manual C53000-G1176-C149-3

A.5 100–% Stator Earth Fault Protection with Primary Load Resistor

3. Insert now on the primary side a resistance which corresponds to the tripping value (e.g. 2 kΩ). Check the measured fault resistance (R SEF=). If this resistance differs very much from the value expected, modify SEF Rps accordingly and, if necessary, make a fine adjustment with the correction angle (PHI I SEF). Read out now the fault resistance, and set this value as the tripping threshold at address 5303 R<< SEF TRIP. Next, insert a fault resistance for the alarm stage (e.g. 5 kΩ) on the primary side, and read out the fault resistance (R SEF=) from the operational measured values. This value is set at address 5302 as R< SEF ALARM. 4. Finally, a series of measurements is performed, starting with 0 kΩ and proceeding in steps of 1 kΩ. If changes are made to the correction angle (PHI I SEF) or to the contact resistance (SEF Rps), the settings for the trip stage (R<< SEF TRIP) and the alarm stage (R< SEF ALARM) must be matched as required. Running Generator

7UM62 Manual C53000-G1176-C149-3

With the generator running the trip stage and the alarm stage must be checked. Again, insert a fault resistance on the primary side, and check the fault resistance in the operational measured values. If the resistance differs from the values at standstill, the correction angle and/or the transfer resistance can be somewhat modified. To do so, adapt the settings at address 5302 R< SEF ALARM and 5303 R<< SEF TRIP. These values are also active with the generator at stand-still.

501

A Appendix

A.6

Definition of the Active Power Measurement The 7UM62 used the generator reference-arrow system. The power output is positive.

I G

U

Figure A-44 Definition of Positive Direction of Reference Arrows

Table A-2 shows the operating ranges for synchronous and asynchronous machines. Parameter 1108 ACTIVE POWER is set to Generator. “Normal condition” shows the active power under normal operating conditions: + means that a positive power is displayed on the protective device, – that the power is negative. Table A-2

Operating Ranges for Synchronous and Asynchronous Machines

Synchronous Generator

Synchronous Motor

+P

Stability limit

+P U

U

underexcited

underexcited ϕ

I

ϕ

overexcited

+Q

Reactive power Q is controlled by the excitation, Normal condition: +P and +Q

Asynchronous Generator

overexcited

Stability limit

+Q

I

Reactive power Q is controlled by the excitation, Normal condition: –P and +Q

Asynchronous Motor +P

+P PBREAK

P I

U

U

ϕ +Q

ϕ I

+Q PBREAK

Reactive power is drawn from the system to maintain the excitation; Normal condition: +P and –Q

502

P

The motor draws both active and reactive power from the system; Normal condition: –P and –Q

7UM62 Manual C53000-G1176-C149-3

A.6 Definition of the Active Power Measurement

Table A-2 shows that the operating ranges in generator and motor operation are mirrored around the reactive power axis. The measured power values also result from the above definition. If, for instance, the forward power monitoring or the reverse power protection is to be used in a synchronous motor, parameter 1108 ACTIVE POWER must be set to Motor. As a result, the actual active power (according to the above definition) is multiplied with –1. This means that the power diagram is mirrored around the reactive power axis and that the interpretation of the active power changes. This effect must be considered when evaluating the metered energy values. If, for instance, positive power values are to be obtained in an asynchronous motor, the current direction (parameter 0201 STARPNT SIDE 1) must be reversed. Parameter 1108 ACTIVE POWER remains set to Generator. This means that because of the generator reference-arrow system the earthing of the CTs that must be entered in the device is the opposite of the actual earthing. This leads to results that are comparable to those of a load reference-arrow system.

7UM62 Manual C53000-G1176-C149-3

503

A Appendix

A.7

Current Transformer Requirements The differential protection is of decisive importance for the requirements that the current transformers must meet. The highspeed trip stage (IDiff >>) uses instantaneous values and can therefore reliably trip high-current internal short-circuits. The other decisive factor for the requirements that the current transformers must meet are external short-circuits with their possible DC component. In case of a short-circuit flowing through the power transformers, a minimum of 5 ms should elapse before current transformer saturation occurs. Recommendations for dimensioning are given in Tables A-3 and A-4 on the basis of the IEC 60044-1 and 60044-6 standards. Table A5 shows the necessary equations for converting the requirements into the knee-point voltages. The primary nominal CT current is defined according to the rules of good engineering practice. It must be chosen higher than or equal to the nominal current of the protected object.

Table A-3

Overcurrent Factors

Required Actual Accuracy Limiting Factor

IpSSC K ALF' = K td ⋅ --------------I pN with

R BC + R Ct K ALF = --------------------------- ⋅ K ALF' R BN + R Ct

Ktd

Rated transient dimensioning factor

IpSSC

Primary short-circuit current

IpN

Rated primary ct current

RBC

Connected burden resistance

RBN

Rated burden resistance

RCt

Secondary winding resistance

Table A-4

Transformer Requirements

Transient dimensioning factor Ktd

504

Resulting Rated Accuracy Limiting Factor

Transformer

Generator

>4 τN ≤ 100 ms

> (4 to 5) τN > 100 ms

7UM62 Manual C53000-G1176-C149-3

A.7 Current Transformer Requirements

Table A-4

Transformer Requirements Transformer

Symmetrical short circuit current IpSC

Generator

1

1 xd ″

≈ ---------- ⋅ I pN, Tr

≈ -------- ⋅ I pN, G

u SC

Example

uSC = 0.1 n’ > 40

xd’’ = 0.12 n’ > (34 to 42)

Note: Always use identical transformers

Power ≥ 10 or15 VA

Note the internal burden!

Example of network transformer: 10P10 10 or15 VA (IsN = 1 A or 5 A)

Example: IN, G approx. 1000 to 2000 A 5P15 15 VA (IsN =1 A or 5 A) IN, G > 5000 A 5P20 30 VA (IsN =1 A or 5 A)

with

Table A-5

uSC

Short circuit voltage

xd’’

Subtransient reactance

IsN

Rated secondary ct current

τN

Network time constant

Knee-Point Voltages

IEC

British Standard

U = K ALF ⋅ ( R Ct + R BN ) ⋅ IsN

( R Ct + R BN ) ⋅ I sN U = --------------------------------------------- ⋅ K ALF 1.3

ANSI

K ALF U = 20 ⋅ I sN ⋅ ( R Ct + R BN ) ⋅ ------------20 IsN = 5 A (typical value)

with

7UM62 Manual C53000-G1176-C149-3

U

Knee-point voltage

KALF

Rated accuracy limiting factor

IsN

Rated secondary ct current

RBN

Rated burden resistance

RCt

Secondary winding resistance

505

A Appendix

A.8

Overview of the Masking Features of the User Defined Information

A.8.1

Source: BI, F, C; Destination: BO, LED, C

–

X

X

X

X

–

X

X

–

– SP

Single Point Indication Open/Close

X

–

X

X

X

X

–

X

X

–

– DP

Double Point Indication (Breaker indication “00” = not valid/transmitted as “3”)

X

–

X

–

–

X X1)

X

X

X2)

– DP_I

Double Point Indication (Breaker indication “00” = intermediate/transmitted as “0”)

X

–

X

–

–

X X1)

X

X

X2)

– OUT

Output Indication ON/OFF

–

–

X

X

X

X X1)

X

X

X2)

– OUT

Output Indication Open/Close

–

–

X

X

X

X X1)

X

X

X2)

– OUT

Protection ON/OFF

–

–

X

X

X

X

–

X

X

X2)

– OUT

Protection Open/Close

–

–

X

X

X

X

–

X

X

X2)

– IntSP

Internal Single Point Indication ON/OFF

–

X

X

X

X

X X1)

X

X

X2)

– IntSP

Internal Single Point Indication Open/Close

–

X

X

X

X

X X1)

X

X

X2)

– IntDP

Internal Double Point Indication (Breaker indication “00” = not valid/transmitted as “3”)

–

–

X

–

–

X X1)

X

X

X2)

– IntDP_I

Internal Double Point Indication (Breaker indication “00” = intermediate/transmitted as “0”)

–

–

X

–

–

X X1)

X

X

X2)

Transformer Tap Changer

X

–

–

–

–

–

–

–

–

–

PLC1 (slow) PLC (fast) Interlocking

X

CFC

Single Point Indication ON/OFF

Function Keys

– SP

Binary Inputs

Measurement

CFC Task level

CFC

Destination

LED

Source

Binary Outputs

Type of Information

• Annunciation: Single Point

Double Point

Output Slow

Output Fast

Tagging

Tap Changer – TxTap

• Control Commands without feedback: Single Controls – C_S

ON/OFF

–

–

X

X

–

X

–

X

X

X

– C_S

Open/Close

–

–

X

X

–

X

–

X

X

X

1) 2

506

Only for measurement setpoints (is processed cyclically every 600 ms); do not use for binary inputs. ) Only for commands (is triggered by commands only).

7UM62 Manual C53000-G1176-C149-3

A.8 Overview of the Masking Features of the User Defined Information

–

X

X

–

X

–

X

X

X

– C_SN

Open/Close

–

–

X

X

–

X

–

X

X

X


–

CFC

ON/OFF

Function Keys

– C_SN

Binary Inputs

Measurement

CFC Task level

CFC

Destination

LED

Source

Binary Outputs

Type of Information

Single Controls negated

Double Controls 1 Trip 1 Close – C_D2

ON/OFF

–

–

X

X

–

X

–

X

X

X

– C_D2

Open/Close

–

–

X

X

–

X

–

X

X

X

– C_D2


–

–

X

X

–

X

–

X

X

X

Double Controls 1 Trip 1 Close 1 Common – C_D3

ON/OFF

–

–

X

X

–

X

–

X

X

X

– C_D3

Open/Close

–

–

X

X

–

X

–

X

X

X

– C_D3


–

–

X

X

–

X

–

X

X

X


ON/OFF

–

–

X

X

–

X

–

X

X

X

– C_D4

Open/Close

–

–

X

X

–

X

–

X

X

X

– C_D4


–

–

X

X

–

X

–

X

X

X


ON/OFF

–

–

X

X

–

X

–

X

X

X

– C_D12

Open/Close

–

–

X

X

–

X

–

X

X

X

– C_D12


–

–

X

X

–

X

–

X

X

X

Double Controls negated – C_D2N

ON/OFF

–

–

X

X

–

X

–

X

X

X

– C_D2N

Open/Close

–

–

X

X

–

X

–

X

X

X

– C_D2N


–

–

X

X

–

X

–

X

X

X

1

) Only for measurement setpoints (is processed cyclically every 600 ms); do not use for binary inputs. Only for commands (is triggered by commands only).

2)

7UM62 Manual C53000-G1176-C149-3

507

A Appendix

–

X

X

–

X

–

X

X

X

Feedback

X

–

X

X

X

X

–

X

X

X

Control

–

–

X

X

–

X

–

X

X

X

Feedback

X

–

X

X

X

X

–

X

X

X

Control

–

–

X

X

–

X

–

X

X

X

Feedback

X

–

X

–

–

X

–

X

X

X

Control

–

–

X

X

–

X

–

X

X

X

Feedback

X

–

X

–

–

X

–

X

X

X


Measurement

–

LED

Control

CFC

CFC

Binary Outputs

Destination CFC Task level

Function Keys

Source Binary Inputs

Type of Information

• Control Commands with feedback: Single Controls – CF_S


– SP – CF_S


– SP – CF_S – DP – CF_S – DP_I

Double Point Indication (Breaker indication “00” = not valid/transmitted as “3”) Double Point Indication (Breaker indication “00” = intermediate/transmitted as “0”)

Double Controls 1 Trip 1 Close – CF_D2


– SP – CF_D2


– SP – CF_D2 – DP – CF_D2


– DP_I


– CF_D2


– TxTap

Control

–

–

X

X

–

X

–

X

X

X

Feedback

X

–

X

X

X

X

–

X

X

X

Control

–

–

X

X

–

X

–

X

X

X

Feedback

X

–

X

X

X

X

–

X

X

X

Control

–

–

X

X

–

X

–

X

X

X

Feedback

X

–

X

–

–

X

–

X

X

X

Control

–

–

X

X

–

X

–

X

X

X

Feedback

X

–

X

–

–

X

–

X

X

X

Control

–

–

X

X

–

X

–

X

X

X

Feedback

–

–

–

–

–

–

–

–

–

–

Control

–

–

X

X

–

X

–

X

X

X

Feedback

X

–

X

X

X

X

–

X

X

X

Control

–

–

X

X

–

X

–

X

X

X

Feedback

X

–

X

X

X

X

–

X

X

X

Control

–

–

X

X

–

X

–

X

X

X

Feedback

X

–

X

–

–

X

–

X

X

X

Control

–

–

X

X

–

X

–

X

X

X

Feedback

X

–

X

–

–

X

–

X

X

X

Control

–

–

X

X

–

X

–

X

X

X

Feedback

–

–

–

–

–

–

–

–

–

–

Control

–

–

X

X

–

X

–

X

X

X

Feedback

X

–

X

X

X

X

–

X

X

X

Double Controls 1 Trip 1 Close 1 Common – CF_D3


– SP – CF_D3


– SP – CF_D3 – DP – CF_D3


– DP_I


– CF_D3


– TxTap Double Controls 2 Trip 2 Close – CF_D4


– SP – CF_D4 – SP

508


Control

–

–

X

X

–

X

–

X

X

X

Feedback

X

–

X

X

X

X

–

X

X

X

7UM62 Manual C53000-G1176-C149-3

A.8 Overview of the Masking Features of the User Defined Information

–

–

X

X

–

X

–

X

X

X

Feedback

X

–

X

–

–

X

–

X

X

X


Control

–

–

X

X

–

X

–

X

X

X

– DP_I

Feedback

X

–

X

–

–

X

–

X

X

X

– CF_D4


Control

–

–

X

X

–

X

–

X

X

X

Feedback

–

–

–

–

–

–

–

–

–

–

Control

–

–

X

X

–

X

–

X

X

X

Feedback

X

–

X

X

X

X

–

X

X

X

Control

–

–

X

X

–

X

–

X

X

X

Feedback

X

–

X

X

X

X

–

X

X

X

Control

–

–

X

X

–

X

–

X

X

X

Feedback

X

–

X

–

–

X

–

X

X

X

Control

–

–

X

X

–

X

–

X

X

X

Feedback

X

–

X

–

–

X

–

X

X

X

Control

–

–

X

X

–

X

–

X

X

X

Feedback

–

–

–

–

–

–

–

–

–

–

– DP – CF_D4

– TxTap


Measurement

Control

LED


– CF_D4

CFC

CFC

Binary Outputs

Destination CFC Task level

Function Keys

Source Binary Inputs

Type of Information

Double Controls 1 Trip 2 Close – CF_D12


– SP – CF_D12


– SP – CF_D12 – DP – CF_D12


– DP_I


– CF_D12


– TxTap Double Controls 1 Trip 1 Close negated – CF_D2N


– SP – CF_D2N


– SP – CF_D2N – DP – CF_D2N


– DP_I


– CF_D2N


– TxTap

Control

–

–

X

X

–

X

–

X

X

X

Feedback

X

–

X

X

X

X

–

X

X

X

Control

–

–

X

X

–

X

–

X

X

X

Feedback

X

–

X

X

X

X

–

X

X

X

Control

–

–

X

X

–

X

–

X

X

X

Feedback

X

–

X

–

–

X

–

X

X

X

Control

–

–

X

X

–

X

–

X

X

X

Feedback

X

–

X

–

–

X

–

X

X

X

Control

–

–

X

X

–

X

–

X

X

X

Feedback

–

–

–

–

–

–

–

–

–

–

–

–

–

–

–

X

X

–

–

–

• Measured Values: – MV

Measured Value

– MVU

Measured Value, User Defined

–

–

X

–

–

–

X

–

–

–

– LV

Limit Value

–

–

–

–

–

X

X

–

–

–

– LVU

Limit Value, User Defined

–

–

–

–

–

X

X

–

–

–

• Metered Values: – MVMV

Metered Value of Measured Values

–

–

–

–

–

–

–

–

–

–

– PMV

Pulse Metered Values

X

–

–

–

–

–

–

–

–

–

7UM62 Manual C53000-G1176-C149-3

509

A Appendix

A.8.2

Destination: Indication Buffer, System Interface

Configuring an Indication Buffer as a Destination

Two indication buffers are available for selection: Operation (Event Log) Buffer (E) and Trip Log (T). The indications from protective functions are firmly assigned to these indication buffers. For the others, Table A-6 provides an overview of which indication type may be configured to which buffer. Table A-6

Overview of Indication Buffers

Information type ↓ \Message buffer →

Configuring the SCADA Interface as a Destination

E

T

Single Point Indications (SP)

X

X

Double Point Indications (DP)

X

Output Indications (OUT)

X

X

Internal Single Point Indications (IntSP)

X

X

Internal Double Point Indications (DP)

X

Transformer Tap Change Indications (TxTap)

X

Depending on the SCADA interfaces connected to the relay, the types of information displayed in Table A-7 may be configured. By placing an X in the matrix cell, the information is transferred to connected systems via the SCADA interface. . Table A-7

Overview of SCADA Interfaces

SCADA Interface → Information Type ↓

IEC

Profi- Modbus DNP3.0 bus DP

Single Point Indication (SP)

X

X

X

X

Double Point Indication (DP)

X

Output Indication (OUT)

X

X

X

X

Internal Single Point Indicator (IntSP)

X

X

X

X

Internal Double Point Indicator (IntDP)

X

X

Transformer Tap Change Indicator (TxTap) Command with/without Feedback (C_**)

X

Protective Measurement Value

X X

X

X

X

X

X

X

X

X

Protective Measurement Value with Time (MVT) Protective Measurement Value, User Defined (MVU) Pulsed Metered Value (PMV) Metered Value from Measurement Value (MVMV)

510

X

7UM62 Manual C53000-G1176-C149-3

A.9 Default Settings

A.9

Default Settings

A.9.1

Binary Inputs

Binary input

Abbreviation

FNo

Type of information

Description

Binary input 1

>SV tripped

5086

SP O/O

>Stop valve tripped

Binary input 2

>Uexc fail.

5328

SP

>Exc. voltage failure recognized

Binary input 3

>BLOCK f1 >BLOCK U< >S/E/F Iee off1)

5206 6506 51761)

SP O/O SP O/O1) SP

Generator circuit breaker open1)

>FAIL:Feeder VT >Useal-in BLK >BLOCK U/V

0361 1950 6503

SP O/O SP O/O SP

Voltage transformer protective switch tripped

Binary input 5

>Ext trip 1

4526

SP O/O

External trip signal 1

Binary input 6

>Ext trip 1

4546

SP O/O

External trip signal 2

Binary input 7

>Trig.Wave.Cap.

0004

SP

>Trigger Waveform Capture

----

----

No functions configured (reserve)

Binary input 4

Binary input 8....152) List Empty 1)

for busbar connection ) 7UM622 only

2

A.9.2

Binary Outputs (output relays)

Binary output

Abbreviation

FNo

Type

Description

Output relay 1

Error PwrSupply Fail Battery

0147 0177

OUT O/O OUT O/O

General indication: Internal monitoring

Output relay 2

Relay TRIP

0511

OUT O/O

Relay trip

Output relay 3

I> TRIP Diff TRIP Imp.Z1< TRIP Imp.Z1B< TRIP Imp.Z2< TRIP Imp.T3> TRIP I>> TRIP O/C Ip TRIP

1815 5671 3977 3978 3979 3980 1809 1900

OUT O/O OUT O/O OUT O/O OUT O/O OUT O/O OUT O/O OUT O/O OUT O/O

Trip by short-circuit protection

Output relay 4

IEE>> TRIP U0> TRIP S/E/F TRIP

1223 5187 5193

OUT O/O OUT O/O OUT O/O

Trip by eartfault protection

Output relay 5

U< TRIP U> TRIP U>> TRIP

6539 6570 6573


Trip by voltage protection

Output relay 6

f1 TRIP f2 TRIP

5236 5237

OUT O/O OUT O/O

Trip by frequency protection

Output relay 7

EXC<3 TRIP Exc
5343 5346

OUT O/O OUT O/O

Trip by underexcitation protection

7UM62 Manual C53000-G1176-C149-3

511

A Appendix

Binary output

Abbreviation

FNo

Type

Description

I> TRIP S/E/F TRIP U>> TRIP f1 TRIP f2 TRIP EXC<3 TRIP EXC
1815 5193 6573 5236 5237 5343 5346 5097 5098 5161 5671

OUT O/O OUT O/O OUT O/O OUT O/O OUT O/O OUT O/O OUT O/O OUT O/O OUT O/O OUT O/O OUT O/O

Marshalled via the tripping matrix:

I> TRIP S/E/F TRIP U>> TRIP f2 TRIP EXC<3 TRIP Exc
1815 5193 6573 5237 5343 5346 5098 5161 5671

OUT O/O OUT O/O OUT O/O OUT O/O OUT O/O OUT O/O OUT O/O OUT O/O OUT O/O


I> TRIP S/E/F TRIP f2 TRIP I2 Θ TRIP Diff TRIP

1815 5193 5237 5161 5671

OUT O/O OUT O/O OUT O/O OUT O/O OUT O/O


Output relay 11

List empty

----

----


Output relay 12

List empty

----

----

reserved for Breaker failure protection (refer to Section 2.28)

Output relays 13...201) List empty

----

----


Output relay 8

Output relay 9

Output relay 10

1)

512

Generator circuit breaker

De–excitation Generator

Stop valve

7UM622 only

7UM62 Manual C53000-G1176-C149-3

Relay 8

Relay 9

Relay 10

Relay 8

Relay 9

Relay 10

Relay 8

Relay 9

Relay 10

FigureA-45 Tripping matrix —

7UM62 Manual C53000-G1176-C149-3

pre–settings

FNo 5568

SEF 3H TRIP

FNro 5098

Pr+SV TRIP

FNo 1223

IEE>> TRIP

FNo 5671

Diff TRIP

FNo 5128

Pf< TRIP

FNo 1226

IEE> TRIP

FNo 5691

Diff> Trip

FNo 5129

Pf> TRIP

FNo 1471

BrkFailure TRIP

FNo 5692

Diff>> Trip

FNo 5160

I2>> TRIP

FNo 1521

ThOverload TRIP

FNo 5161

I2 Θ TRIP

FNo 1809

I>> TRIP

U0> TRIP

FNo 1815

I> TRIP

S/E/F TRIP

FNo 1900

O/C Ip TRIP

f1 TRIP

FNo 3977

Imp.Z1< TRIP Imp.Z1B< TRIP

Up< TRIP

FNo 6527 FNo 6539 FNo 6540

U< TRIP

FNo 5187

U<< TRIP

FNo 5193

FNo 6570

U> TRIP

FNo 6573

U>> TRIP

FNo 5237

f2 TRIP

FNo 3978

START-SUP TRIP

FNo 5238

f3 TRIP

FNo 3979

Imp.Z2< TRIP

FNo 5239

f4 TRIP

FNo 3980

Imp.T3> TRIP

FNo 5307

DC Prot. TRIP

FNo 4537

Ext 1 Gen.TRP

FNo 5343

Exc<3 TRIP

FNo 4557

Ext 2 Gen.TRP

FNo 5344

Exc<1 TRIP

FNo 4577

Ext 3 Gen.TRP

FNo 5345

Exc<2 TRP

FNo 4597

Ext 4 Gen.TRP

FNo 5346

Exc
FNo 4827

Re. Inhib.TRP

FNo 5371

U/f>>TRP

FNro 5071

O/STRP char.1

FNo 5372

U/f th.TRIP

FNo 5072

O/STRP char.2

FNo 5399

R/E/F TRIP

FNo 5097

Pr TRIP

FNo 5548

I.En. TRIP

FNo 6821

FNo 5236



De–excitation

Stop valve


De–excitation

Stop valve


De–excitation

Stop valve

513

A Appendix

A.9.3

LED Indicators

LED

Abbreviation

FNo

Type of information

Description

LED 1

Relay TRIP

0511

OUT O/O

Protective relay has tripped

LED 2

Relay PICKUP

0501

OUT O/O

Protective relay has picked up

LED 3

I> Fault L1

1811

OUT O/O

Fault L1

LED 4

I> Fault L2

1812

OUT O/O

Fault L2

LED 5

I> Fault L3

1813

OUT O/O

Fault L3

LED 6

IEE> TRIP U0> TRIP S/E/F TRIP

1226 5187 5193


Earth fault

LED 7

Error PwrSupply Fail Battery

0147 0177

OUT O/O OUT O/O

Hardware failure

LED 8

Diff TRIP

5671

OUT O/O

Trip by differential protection

LED 9

Pr TRIP Pr+SV TRIP

5097 5098

OUT O/O OUT O/O

Trip by reverse power protection

LED 10

Exc<3 TRIP Exc<1 TRIP Exc<2 TRIP Exc
5343 5344 5345 5346

OUT O/O OUT O/O OUT O/O OUT O/O

Trip by underexcitation protection

LED 11

I2>> TRIP I2 Θ TRIP

5160 5161

OUT O/O OUT O/O

Trip by unbalanced protection

LED 12

f1 TRIP f2 TRIP f3 TRIP

5236 5237 5238


Trip by overfrequency protection

LED 13

f4 TRIP

5239

OUT O/O

Trip by underfrequency protection

LED 14

U> TRIP U>> TRIP

6570 6573

OUT O/O OUT O/O

Trip by overvoltage protection

A.9.4

Function Keys

Function Key

514

Pre–settings

F1

Operating messages

F2

Operating measured values, primary

F3

Messages from the last eight network faults

F4

Jumping to the reset menu of the min/max values

7UM62 Manual C53000-G1176-C149-3


A.9.5

Establishing a Default Display

I1: 0.50kA cosϕ: U : 10.93kV f:50.00Hz P : 4.64MW Q : 2.86MVAR

Pri L1 L1 L3

1 2 3 E

L1 L1 L3

0.50kA 0.50kA 0.50kA 0.0A

12 23 31 E

6.31kV 6.30kV 6.29kV 2V

Side 1 122A 124A 123A DIFF 0.00A 0.00A 0.00A

Side 2 1222A 1243A 1231A STAB 0.00A 0.00A 0.00A

Figure A-46 Basic Displays of 7UM62

A.9.6

Spontaneous Display Messages The spontaneous display 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 A-47.

U0> picked up S/E/F TRIP PU Time 440ms TRIP Time 301ms

Protective Function that picked up first; Protective Function that dropped out last; Running time from general pickup to dropout; Running time from general pickup to the first trip command

Figure A-47 Display of spontaneous messages in the display – example

7UM62 Manual C53000-G1176-C149-3

515

A Appendix

A.9.7

Pre–Defined CFC Charts Some CFC Charts are already supplied with the SIPROTEC® device:

Device and System Logic

The single-point indication “>DataStop“ that can be injected by binary inputs is converted by means of a NEGATOR block into an indication “UnlockDT“ that can be processed internally (internal single point indication, IntSP), and assigned to an output. This would not be possible directly, i.e. without the additional block.

IN: Device, General >DataStop SP

OUT:Device, UnlockDT IntSP

Figure A-48 Logical Link between Input and Output

Set points

Using modules on the running sequence “measured value processing”, a low current monitor for the three phase currents is implemented. The output message is set high as soon as one of the three phase currents falls below the set threshold:

IN: Set points IL< LV IN: Measurement IL1S2 = MV OUT: Set points SP. IL< OUT IN: Set points IL< LV IN: Measurement IL2S2 = MV IN: Set points IL< LV IN: Measurement IL3S2 = MV

FigureA-49

516

Undercurrent Monitoring

7UM62 Manual C53000-G1176-C149-3

A.10 Interoperability List

A.10 Interoperability List 1.

Physical layer

1.1 X

Electrical interface EIA RS-485

X

Number of loads for one equipment: 32

1.2 X X

Optical interface Glass fibre Plastic fibre

X

F-SMA type connector BFOC/2,5 type connector

1.3 X

Transmission speed 9600 bit/s

X

19200 bit/s

2.

Link layer

There are no choices for the link layer 3.

Application layer

3.1

Transmission mode for application data Mode 1 (least significant octet first) as defined in 4.10 of IEC 60870-5-4

3.2 X

Common address of ASDU One common address of ADSU (identical with station address)

3.3 3.3.1 X X X

Selection of standard information numbers in monitor direction System functions in monitor direction 0 End of general interrogation 0 Time synchronization X 2 Reset FCB 3 Reset CU X 4 Start/restart 5 Power on X

3.3.2 3.3.3 3.3.4 3.3.5 3.3.6

see separate table in the device manual (Information List in the following section)

3.3.7

3.3.8

X 3.4 3.4.1 X 3.4.2

X

Measurands in monitor direction 144 Measurand I 146 Measurand I, V, P, Q 148 Measurands IL1,2,3, VL1,2,3, P, Q, f Generic functions in monitor direction 240 Read headings of all defined groups 243 Read directory of a single entry 245 End of general interrogation generic data 250 Write entry with execution

More than one common address of ASDU

145 147

Measurands I, V Measurands IN, VEN

241 244 249

Read values of all entries of one group Read value of a single entry Write entry with confirmation

251

Write entry aborted

Selection of standard information numbers in control direction System functions in control direction 0 Initiation of general interrogation 0 X General commands in control direction 16 Auto-recloser on / off 17 18 Protection on / off 19 X 23 Activate characteristic 1 24 X 25 Activate characteristic 3 26

7UM62 Manual C53000-G1176-C149-3

Time synchronization Teleprotection on / off LED reset Activate characteristic 2 Activate characteristic 4

517

A Appendix

3.4.3

Generic functions in control direction 240 Read headings of all defined groups 243 Read directory of a single entry 245 General interrogation of generic data 249 Write entry with confirmation 251 Write entry abort

3.5 X X X

Basic application functions Test mode Disturbance data Private data

3.6

Miscellaneous

Measurand

241 244 248 250

X

Read values of all entries of one group Read value of a single entry Write entry Write entry with execution

Blocking of monitor direction Generic services

max. value = rated value x 1.2 2.4

Current L1 Current L2 Current L3 Voltage L1-E Voltage L2-E Voltage L3-E Voltage L1-L2 Active power P Reactive power Q Frequency f

518

7UM62 Manual C53000-G1176-C149-3

A.11 Functions Overview

A.11 Functions Overview Addr.

Setting Title

Setting Options

Default Setting

Comments

103

Grp Chge OPTION

Disabled Enabled

Disabled

Setting Group Change Option

104

FAULT VALUE

Disabled Instantaneous values RMS values

Instantaneous values

Fault values

105

DIFF. PROT.

Disabled Enabled

Enabled


106

PROT. OBJECT

Generator/Motor 3 phase Transformer

Generator/Motor

Protection Object

112

O/C PROT. I>


Side 2

Overcurrent Protection I>

113

O/C PROT. I>>

Disabled Non-Directional on side 1 Non-Directional on side 2 Directional on side 1 Directional on side 2

Non-Directional on Overcurrent Protection I>> side 2

114

O/C PROT. Ip

Disabled with IEC-characteristic on side 1 with ANSI-characteristic on side 1 with IEC-characteristic on side 2 with ANSI-characteristic on side 2

Disabled


116

Therm.Overload

Disabled Enabled

Enabled


117

UNBALANCE LOAD Disabled Enabled

Enabled


118

O/C STARTUP

Disabled Enabled

Enabled


120

DIFF. PROT.

Disabled Generator/Motor 3 phase Transformer

Generator/Motor


121

REF PROT.

Disabled Generator/Motor with IEE2 Generator/Motor with 3I0 of Side 2 with Side 1 of Transformer with Side 2 of Transformer

Disabled

Restricted earth fault protection

130

UNDEREXCIT.

Disabled Enabled

Enabled


131

REVERSE POWER Disabled Enabled

Enabled


132

FORWARD POWER

Enabled


7UM62 Manual C53000-G1176-C149-3

Disabled Enabled

519

A Appendix

Addr.

Setting Title

Setting Options

Default Setting

Comments

133

IMPEDANCE PROT.

Disabled Enabled

Enabled


135

OUT-OF-STEP

Disabled Enabled

Enabled


140

UNDERVOLTAGE

Disabled Enabled

Enabled


141

OVERVOLTAGE

Disabled Enabled

Enabled


142

FREQUENCY Prot.

Disabled Enabled

Enabled

Over / Underfrequency Protection

143

OVEREXC. PROT.

Disabled Enabled

Enabled


144

INV.UNDERVOLT.

Disabled Enabled

Enabled


145

df/dt Protect.

Disabled with 2 df/dt stages with 4 df/dt stages

with 2 df/dt stages


146

VECTOR JUMP

Disabled Enabled

Enabled


150

S/E/F PROT.

Disabled non-directional only U0 non-directional with U0 & I0 directional

non-directional with U0 & I0


151

O/C PROT. Iee>

Disabled with Iee1 with Iee2

with Iee2


152

SEF 3rd HARM.

Disabled Enabled

Enabled

Stator Earth Fault Prot. 3rd Harmonic

153

100% SEF-PROT.

Disabled Enabled

Enabled


160

ROTOR E/F

Disabled Enabled

Enabled


161

REF 1-3Hz

Disabled Enabled

Enabled


165

STARTUP MOTOR

Disabled Enabled

Enabled


166

RESTART INHIBIT

Disabled Enabled

Enabled


170

BREAKER FAILURE


Side 2


171

INADVERT. EN.

Disabled Enabled

Enabled


172

DC PROTECTION

Disabled Enabled

Enabled


520

7UM62 Manual C53000-G1176-C149-3

A.11 Functions Overview

Addr.

Setting Title

Setting Options

Default Setting

Comments

173

ANALOGOUTPUT B1


Disabled


174

ANALOGOUTPUT B2


Disabled


175

ANALOGOUTPUT D1


Disabled


7UM62 Manual C53000-G1176-C149-3

521

A Appendix

Addr.

Setting Title

Setting Options

Default Setting

Comments

176

ANALOGOUTPUT D2


Disabled


180

FUSE FAIL MON.

Disabled Enabled

Enabled


181

M.V. SUPERV

Disabled Enabled

Enabled

Measured Values Supervision

182

Trip Cir. Sup.

Disabled with 2 Binary Inputs with 1 Binary Input

Disabled


185

THRESHOLD

Disabled Enabled

Enabled


186

EXT. TRIP 1

Disabled Enabled

Enabled


187

EXT. TRIP 2

Disabled Enabled

Enabled


188

EXT. TRIP 3

Disabled Enabled

Enabled


189

EXT. TRIP 4

Disabled Enabled

Enabled


190

RTD-BOX INPUT

Disabled Port C Port D Port E

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 Connection Type

522

7UM62 Manual C53000-G1176-C149-3

A.12 Settings

A.12 Settings NOTE: The following table lists all data which are available in the maximum complement of the device. Dependent on the ordered model, only those data may be present which are valid for the individual version. Addr.

Setting Title

Function

Setting Options

Default Setting

Comments

201

STRPNT->OBJ S1

Power System Data 1

YES NO

YES


202

IN-PRI I-SIDE1

Power System Data 1

1..100000 A

500 A


203

IN-SEC I-SIDE1

Power System Data 1

1A 5A

1A


204

CT ANGLE W0

Power System Data 1

-5.00..5.00 °

0.00 °

Correction Angle CT W0

205

FACTOR IEE1

Power System Data 1

1.0..100000.0

60.0


210

STRPNT->OBJ S2

Power System Data 1

YES NO

YES


211

IN-PRI I-SIDE2

Power System Data 1

1..100000 A

500 A


212

IN-SEC I-SIDE2

Power System Data 1

1A 5A

1A


213

FACTOR IEE2

Power System Data 1

1.0..100000.0

60.0


214

GRD TERM. IEE2

Power System Data 1

Terminal Q7 Terminal Q8

Terminal Q7

Grounded Terminal CT IEE2

221

Unom PRIMARY

Power System Data 1

0.10..400.00 kV

6.30 kV

Rated Primary Voltage

222

Unom SECONDARY

Power System Data 1

100..125 V

100 V

Rated Secondary Voltage (Ph-Ph)

223

UE CONNECTION

Power System Data 1

UE connected to neutral transformer UE connected to broken delta winding not connected UE connected to any VT UE connected to Rotor UE connected to Loading Resistor

UE connected to neutral transformer

UE Connection

224

FACTOR UE

Power System Data 1

1.0..2500.0

36.4

VT Ratio Prim./Sec. Ue

225A

Uph / Udelta

Power System Data 1

1.00..3.00

1.73

Matching Ratio Ph.-VT to Broken-Delta-VT

241

UN-PRI SIDE 1

Power System Data 1

0.40..800.00 kV

20.00 kV

Rated Primary Voltage Side 1

7UM62 Manual C53000-G1176-C149-3

523

A Appendix

Addr.

Setting Title

Function

Setting Options

Default Setting

Comments

242

STARPNT SIDE 1

Power System Data 1


Isolated

Starpoint of Side 1 is

243

UN-PRI SIDE 2

Power System Data 1

0.40..800.00 kV

6.30 kV

Rated Primary Voltage side 2

244

STARPNT SIDE 2

Power System Data 1


Isolated

Starpoint of side 2 is

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

5.30 MVA

Rated Apparent Power of the Transformer

251

UN GEN/MOTOR

Power System Data 1

0.40..800.00 kV

6.30 kV

Rated Primary Voltage Generator/Motor

252

SN GEN/MOTOR

Power System Data 1

0.20..5000.00 MVA

5.27 MVA

Rated Apparent Power of the Generator

270

Rated Frequency

Power System Data 1

50 Hz 60 Hz

50 Hz

Rated Frequency

271

PHASE SEQ.

Power System Data 1

L1 L2 L3 L1 L3 L2

L1 L2 L3

Phase Sequence

272

SCHEME

Power System Data 1

Direct connected to busbar Unit transformer connected

Direct connected to busbar

Scheme Configuration

274A

ATEX100

Power System Data 1

YES NO

NO

Storage of th. Replicas w/o Power Supply

275

FACTOR R SEF

Power System Data 1

1.0..200.0

37.0

Ratio Prim./Sec. R SEF

276

TEMP. UNIT

Power System Data 1

Degree Celsius Degree Fahrenheit

Degree Celsius

Unit of temparature measurement

280

TMin TRIP CMD

Power System Data 1

0.01..32.00 sec

0.15 sec

Minimum TRIP Command Duration

281

BkrClosed I MIN

Power System Data 1

0.04..1.00 A

0.04 A

Closed Breaker Min. Current Threshold

295

TRANSDUCER 1

Power System Data 1

10 V 4-20mA 20mA

10 V

Transducer 1

296

TRANSDUCER 2

Power System Data 1

10 V 4-20mA 20mA

10 V

Transducer 2

297

TRANSDUCER 3

Power System Data 1

with filter without filter

with filter

Transducer 3

302

CHANGE

Change Group

Group A Group B Binary Input Protocol

Group A

Change to Another Setting Group

401

WAVEFORMTRIG- Oscillographic GER Fault Records

Save with Pickup Save with TRIP Start with TRIP

Save with Pickup

Waveform Capture

524

7UM62 Manual C53000-G1176-C149-3

A.12 Settings

Addr.

Setting Title

Function

Setting Options

Default Setting

Comments

402

WAVEFORM DATA

Oscillographic Fault Records

Fault event Power System fault

Fault event

Scope of Waveform Data

403

MAX. LENGTH


0.30..5.00 sec

1.00 sec

Max. length of a Waveform Capture Record

404

PRE. TRIG. TIME


0.05..4.00 sec

0.20 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

Capture Time via Binary Input

1108

ACTIVE POWER

Power System Data 2

Generator Motor

Generator

Measurement of Active Power for

1201

O/C I>

O/C I> (with undervoltage seal-in)


OFF

Overcurrent Time Protection I>

1202

I>


0.05..20.00 A

1.35 A

I> Pickup

1203

T I>


0.00..60.00 sec; ∞

3.00 sec

T I> Time Delay

1204

U< SEAL-IN


ON OFF

OFF

State of Undervoltage Sealin

1205

U<


10.0..125.0 V

80.0 V

Undervoltage Seal-in Pikkup

1206

T-SEAL-IN


0.10..60.00 sec

4.00 sec


1207A I> DOUT RATIO


0.90..0.99

0.95

I> Drop Out Ratio

1301

O/C I>>

O/C I>> (with direction)


OFF

Overcurrent Time Protection I>>

1302

I>>


0.05..20.00 A

4.30 A

I>> Pickup

1303

T I>>


0.00..60.00 sec; ∞

0.10 sec

T I>> Time Delay

1304

Phase Direction


Forward Reverse

Reverse

Phase Direction

1305

LINE ANGLE


-90..90 °

60 °

Line Angle

7UM62 Manual C53000-G1176-C149-3

525

A Appendix

Addr.

Setting Title

Function

Setting Options

Default Setting

Comments

1401

O/C Ip

Inverse O/C OFF Time Protection ON Block relay for trip commands

OFF

Inverse O/C Time Protection Ip

1402

Ip

Inverse O/C 0.10..4.00 A Time Protection

1.00 A

Ip Pickup

1403

T Ip

Inverse O/C 0.05..3.20 sec; ∞ Time Protection

0.50 sec

T Ip Time Dial

1404

TIME DIAL: TD

Inverse O/C 0.50..15.00; ∞ Time Protection

5.00

TIME DIAL: TD

1405

IEC CURVE

Inverse O/C Normal Inverse Time Protection Very Inverse Extremely Inverse

Normal Inverse

IEC Curve

1406

ANSI CURVE

Inverse O/C Very Inverse Time Protection Inverse Moderately Inverse Extremely Inverse Definite Inverse

Very Inverse

ANSI Curve

1407

VOLT. INFLUENCE

Inverse O/C without Time Protection Voltage controlled Voltage restraint

without

Voltage Influence

1408

U<

10.0..125.0 V Inverse O/C Time Protection

75.0 V

U< Threshold for Release Ip

1601

Ther. OVER LOAD


OFF ON Block relay for trip commands Alarm Only

OFF


1602

K-FACTOR


0.10..4.00

1.11

K-Factor

1603

TIME CONSTANT


30..32000 sec

600 sec

Thermal Time Constant

1604

Θ ALARM


70..100 %

90 %

Thermal Alarm Stage

1605

TEMP. RISE I


40..200 °C

100 °C


1606

TEMP. RISE I


104..392 °F

212 °F


1607

TEMP. INPUT


Disabled 4-20 mA Fieldbus Temp. of RTD 1

Disabled

Temperature Input

1608

TEMP. SCAL.


40..300 °C

100 °C


1609

TEMP. SCAL.


104..572 °F

212 °F



0.10..4.00 A

1.00 A

Current Overload Alarm Setpoint

1610A I ALARM

526

7UM62 Manual C53000-G1176-C149-3

A.12 Settings

Addr.

Setting Title

Function

Setting Options

Default Setting

Comments

1612A Kτ-FACTOR


1.0..10.0

1.0

Kt-Factor when Motor Stops

1615A I MAX THERM.


0.50..8.00 A

3.30 A

Maximum Current for Thermal Replica

1616A T EMERGENCY


10..15000 sec

100 sec

Emergency Time

1701

UNBALANCE LOAD



OFF

Unbalance Load Protection

1702

I2>


3.0..30.0 %

10.6 %

Continously Permissible Current I2

1703

T WARN


0.00..60.00 sec; ∞

20.00 sec

Warning Stage Time Delay

1704

FACTOR K


2.0..100.0 sec; ∞

18.7 sec

Negativ Sequence Factor K

1705

T COOL DOWN


0..50000 sec

1650 sec


1706

I2>>


10..100 %

60 %

I2>> Pickup

1707

T I2>>


0.00..60.00 sec; ∞

3.00 sec

T I2>> Time Delay

1801

O/C STARTUP



OFF


1802

STARTUP I>


0.10..20.00 A

1.30 A

I> Pickup

1803

STARTUP T I>


0.00..60.00 sec; ∞

0.50 sec

T I> Time Delay

2001

DIFF. PROT.

Differential Pro- OFF tection ON Block relay for trip commands

OFF


2005

INC.CHAR.START

Differential Pro- OFF tection ON

OFF

Increase of Trip Char. During Start

2006

INRUSH 2.HARM.

Differential Pro- OFF tection ON

ON

Inrush with 2. Harmonic Restraint

2007

RESTR. n.HARM.

Differential Pro- OFF tection 3. Harmonic 5. Harmonic

OFF

n-th Harmonic Restraint

7UM62 Manual C53000-G1176-C149-3

527

A Appendix

Addr. 2021

Setting Title

Setting Options

Default Setting

Comments

Differential Pro- 0.05..2.00 I/InO tection

0.20 I/InO

Pickup Value of Differential Curr.

2026A T I-DIFF>

Differential Pro- 0.00..60.00 sec; ∞ tection

0.00 sec

T I-DIFF> Time Delay

2031

Differential Pro- 0.5..12.0 I/InO; ∞ tection

7.5 I/InO

Pickup Value of High Set Trip

2036A T I-DIFF>>

Differential Pro- 0.00..60.00 sec; ∞ tection

0.00 sec

T I-DIFF>> Time Delay

2041A SLOPE 1

Differential Pro- 0.10..0.50 tection

0.25


2042A BASE POINT 1


0.00 I/InO


2043A SLOPE 2


0.50


2044A BASE POINT 2


2.50 I/InO


2051A I-REST. STARTUP Differential Pro- 0.00..2.00 I/InO tection

0.10 I/InO

I-RESTRAINT for Start Detection

2052A START-FACTOR


1.0

Factor for Increasing of Char. at Start

2053

Differential Pro- 0.0..180.0 sec tection

5.0 sec


2056A I-ADD ON STAB.


4.00 I/InO

Pickup for Add-on Stabilization

2057A T ADD ON-STAB.

Differential Pro- 2..250 Cycle; ∞ tection

15 Cycle

Duration of Add-on Stabilization

2061

Differential Pro- 10..80 % tection

15 %

2nd Harmonic Content in IDIFF

2062A CROSSB. 2. HARM Differential Pro- 2..1000 Cycle; 0; ∞ tection

3 Cycle

Time for Cross-blocking 2nd Harm.

2071

30 %

n-th Harmonic Content in IDIFF

2072A CROSSB. n.HARM Differential Pro- 2..1000 Cycle; 0; ∞ tection

0 Cycle

Time for Cross-blocking nth Harm.

2073A IDIFFmax n.HM


1.5 I/InO

Limit IDIFFmax of n-th Harm.Restraint

2101

REF PROT.

Restricted Earth OFF Fault Protection ON Block relay for trip commands

OFF


2102

REF I> BLOCK

Restricted Earth 1.0..2.5 I/InO Fault Protection

1.5 I/InO

REF Pickup of Phase Current Blocking

2103

REF U0>RELEASE Restricted Earth 1.0..100.0 V; 0 Fault Protection

5.0 V

REF Pickup of U0> Release

528

I-DIFF>

Function

I-DIFF>>

T START MAX

2. HARMONIC

n. HARMONIC

Differential Pro- 10..80 % tection

7UM62 Manual C53000-G1176-C149-3

A.12 Settings

Addr.

Setting Title

Function

Setting Options

Default Setting

Comments

2110

I-REF>


0.10 I/InO

I-REF> Pickup

2112

T I-REF>

Restricted Earth 0.00..60.00 sec; ∞ Fault Protection

0.00 sec

T I-REF> Time Delay

2113A SLOPE

Restricted Earth 0.00..0.95 Fault Protection

0.25

Slope of Charac. I-REF> = f(I0-Rest)

2114A BASE POINT


0.00 I/InO

Base Point for Slope of Characteristic

3001

UNDEREXCIT.

Underexcitation OFF Protection ON Block relay for trip commands

OFF


3002

1/xd CHAR. 1

Underexcitation 0.25..3.00 Protection

0.41


3003

ANGLE 1

Underexcitation 50..120 ° Protection

80 °


3004

T CHAR. 1

Underexcitation 0.00..60.00 sec; ∞ Protection

10.00 sec


3005

1/xd CHAR. 2


0.36


3006

ANGLE 2


90 °


3007

T CHAR. 2


10.00 sec


3008

1/xd CHAR. 3


1.10


3009

ANGLE 3


90 °


3010

T CHAR 3


0.30 sec


3011

T SHRT Uex<


0.50 sec

T-Short Time Delay (Char. & Uexc<)

3012

EXCIT. VOLT.

Underexcitation ON Protection OFF

OFF

State of Excitation Volt. Supervision

3013

Uexcit. <

Underexcitation 0.50..8.00 V Protection

2.00 V

Excitation Voltage Superv. Pickup

3014A Umin

Underexcitation 10.0..125.0 V Protection

25.0 V

Undervoltage blocking Pikkup

3101

REVERSE POWER



OFF


3102

P> REVERSE


-30.00..-0.50 %

-1.93 %

P> Reverse Pickup

3103

T-SV-OPEN


0.00..60.00 sec; ∞

10.00 sec

Time Delay Long (without Stop Valve)

7UM62 Manual C53000-G1176-C149-3

529

A Appendix

Addr.

Setting Title

Function

Setting Options

Default Setting

Comments


0.00..60.00 sec; ∞

1.00 sec

Time Delay Short (with Stop Valve)

3105A T-HOLD


0.00..60.00 sec; ∞

0.00 sec

Pickup Holding Time

3201

FORWARD POWER



OFF


3202

Pf<


0.5..120.0 %

9.7 %

P-forw.< Supervision Pikkup

3203

Pf>


1.0..120.0 %

96.6 %

P-forw.> Supervision Pikkup

3204

T-Pf<


0.00..60.00 sec; ∞

10.00 sec

T-P-forw.< Time Delay

3205

T-Pf>


0.00..60.00 sec; ∞

10.00 sec

T-P-forw.> Time Delay

3206A MEAS. METHOD


Method accurate Method fast

Method accurate

Method of Operation

3301

IMPEDANCE PROT.

Impedance Pro- OFF tection ON Block relay for trip commands

OFF


3302

IMP I>

Impedance Pro- 0.10..20.00 A tection

1.35 A

Fault Detection I> Pickup

3303

U< SEAL-IN

Impedance Pro- ON tection OFF

OFF

State of Undervoltage Sealin

3304

U<

Impedance Pro- 10.0..125.0 V tection

80.0 V

Undervoltage Seal-in Pikkup

3305

T-SEAL-IN

Impedance Pro- 0.10..60.00 sec tection

4.00 sec


3306

ZONE Z1

Impedance Pro- 0.05..130.00 Ohm tection

2.91 Ohm

Impedance Zone Z1

3307

T-Z1

Impedance Pro- 0.00..60.00 sec; ∞ tection

0.10 sec


3308

ZONE Z1B


4.99 Ohm

Impedance Zone Z1B

3309

T-Z1B


0.10 sec

Impedance Zone Z1B Time Delay

3310

ZONE Z2


4.16 Ohm

Impedanz Zone Z2

3311

ZONE2 T2


0.50 sec


3312

T END


3.00 sec

T END: Final Time Delay

3313

POWER SWING

Impedance Pro- ON tection OFF

OFF


3104

530

T-SV-CLOSED

7UM62 Manual C53000-G1176-C149-3

A.12 Settings

Addr.

Setting Title

Function

Setting Options

Default Setting

Comments

3314

P/SPOL-TPOL


8.00 Ohm

Distance betw. Power Swing - Trip-Pol.

3315

dZ/dt

Impedance Pro- 1.0..600.0 Ohm/s tection

300.0 Ohm/s

Rate of Change of dZ/dt

3316A BLOCKING OF

Impedance Pro- Zone Z1 tection Zone Z1 and Z2

Zone Z1

Power Swing Blocking locks out

3317A T-ACTION P/S


3.00 sec

Power Swing Action Time

3501

OUT-OF-STEP



OFF


3502

I1> RELEASE


20.0..400.0 %

120.0 %

Pickup Current for Measuring Release I1>

3503

I2< RELEASE


5.0..100.0 %

20.0 %

Pickup Current for Measuring Release I2<

3504

Za


0.20..130.00 Ohm

4.50 Ohm

Resistance Za of the Polygon (width)

3505

Zb


0.10..130.00 Ohm

12.00 Ohm

Reactance Zb of the Polygon (reverse)

3506

Zc


0.10..130.00 Ohm

3.60 Ohm

Reactance Zc of Polygon (forward char.1)

3507

Zd - Zc


0.00..130.00 Ohm

6.40 Ohm

Reactance Dif. Char.1 Char.2 (forward)

3508

PHI POLYGON


60.0..90.0 °

90.0 °


3509

REP. CHAR. 1


1..4

1


3510

REP. CHAR. 2


1..8

4


3511

T-HOLDING


0.20..60.00 sec

20.00 sec

Holding Time of Fault Detection

3512

T-SIGNAL


0.02..0.15 sec

0.05 sec

Min. Signal Time for Annun. Char. 1/2

4001

UNDERVOLTAGE



OFF


4002

U<


10.0..125.0 V

75.0 V

U< Pickup

4003

T U<


0.00..60.00 sec; ∞

3.00 sec

T U< Time Delay

4004

U<<


10.0..125.0 V

65.0 V

U<< Pickup

4005

T U<<


0.00..60.00 sec; ∞

0.50 sec

T U<< Time Delay

7UM62 Manual C53000-G1176-C149-3

531

A Appendix

Addr.

Setting Title

Function

Setting Options

Default Setting

Comments

4006A U< DOUT RATIO


1.01..1.20

1.05

U< Drop Out Ratio

4101

OVERVOLTAGE



OFF


4102

U>


30.0..170.0 V

115.0 V

U> Pickup

4103

T U>


0.00..60.00 sec; ∞

3.00 sec

T U> Time Delay

4104

U>>


30.0..170.0 V

130.0 V

U>> Pickup

4105

T U>>


0.00..60.00 sec; ∞

0.50 sec

T U>> Time Delay

4106A U> DOUT RATIO


0.90..0.99

0.95

U> Drop Out Ratio

4107A VALUES U>


Voltage protection Voltage protection Measurement Values for with U-Phase-Phase with U-Phase-Phase U> Voltage protection with U-Phase-earth

4201

O/U FREQUENCY

Frequency Pro- OFF tection ON Block relay for trip commands

OFF

Over / Under Frequency Protection

4202

f1 PICKUP

Frequency Pro- 40.00..65.00 Hz tection

48.00 Hz

f1 Pickup

4203

f1 PICKUP


58.00 Hz

f1 Pickup

4204

T f1

Frequency Pro- 0.00..600.00 sec tection

1.00 sec

T f1 Time Delay

4205

f2 PICKUP


47.00 Hz

f2 Pickup

4206

f2 PICKUP


57.00 Hz

f2 Pickup

4207

T f2


6.00 sec

T f2 Time Delay

4208

f3 PICKUP


49.50 Hz

f3 Pickup

4209

f3 PICKUP


59.50 Hz

f3 Pickup

4210

T f3


20.00 sec

T f3 Time Delay

4211

f4 PICKUP


52.00 Hz

f4 Pickup

4212

f4 PICKUP


62.00 Hz

f4 Pickup

532

7UM62 Manual C53000-G1176-C149-3

A.12 Settings

Addr.

Setting Title

Function

Setting Options

Default Setting

Comments

4213

T f4


10.00 sec

T f4 Time Delay

4214

THRESHOLD f4

Frequency Pro- Freq. prot. stage tection automatic Freq. prot. stage overfreqency Freq. prot. stage underfreqency

Freq. prot. stage automatic

Handling of Threshold Stage f4

4215

Umin

Frequency Pro- 10.0..125.0 V; 0 tection

65.0 V

Minimum Required Voltage for Operation

4301

OVEREXC. PROT. Overexcitation Protection (U/f)


OFF


4302

U/f >


1.00..1.20

1.10

U/f > Pickup

4303

T U/f >


0.00..60.00 sec; ∞

10.00 sec

T U/f > Time Delay

4304

U/f >>


1.00..1.40

1.40

U/f >> Pickup

4305

T U/f >>


0.00..60.00 sec; ∞

1.00 sec

T U/f >> Time Delay

4306

t(U/f=1.05)


0..20000 sec

20000 sec


4307

t(U/f=1.10)


0..20000 sec

6000 sec


4308

t(U/f=1.15)


0..20000 sec

240 sec


4309

t(U/f=1.20)


0..20000 sec

60 sec


4310

t(U/f=1.25)


0..20000 sec

30 sec


4311

t(U/f=1.30)


0..20000 sec

19 sec


4312

t(U/f=1.35)


0..20000 sec

13 sec


4313

t(U/f=1.40)


0..20000 sec

10 sec


4314

T COOL DOWN


0..20000 sec

3600 sec


4401

INV. UNDERVOLT. Inverse Undervoltage Protection


OFF


4402

Up< PICKUP

10.0..125.0 V

75.0 V

Up< Pickup

7UM62 Manual C53000-G1176-C149-3

Inverse Undervoltage Protection

533

A Appendix

Addr.

Setting Title

Function

Setting Options

Default Setting

Comments

4403

T MUL


0.10..5.00 sec; 0

1.00 sec

Time Multiplier for Characteristic

4404

T Up<


0.00..60.00 sec; ∞

0.00 sec

T Up< Time Delay

4501

df/dt Protect.



OFF


4502

df1/dt >/<


-df/dt< negative rate -df/dt< negative rate Mode of Threshold (df1/dt of freq. change of freq. change >/<) +df/dt> positive rate of freq. change

4503

STAGE df1/dt


0.1..10.0 Hz/s; ∞

1.0 Hz/s


4504

T df1/dt


0.00..60.00 sec; ∞

0.50 sec


4505

df1/dt & f1


OFF ON

OFF


4506

df2/dt >/<



4507

STAGE df2/dt


0.1..10.0 Hz/s; ∞

1.0 Hz/s


4508

T df2/dt


0.00..60.00 sec; ∞

0.50 sec


4509

df2/dt & f2


OFF ON

OFF


4510

df3/dt >/<



4511

STAGE df3/dt


0.1..10.0 Hz/s; ∞

4.0 Hz/s


4512

T df3/dt


0.00..60.00 sec; ∞

0.00 sec


4513

df3/dt & f3


OFF ON

OFF


534

7UM62 Manual C53000-G1176-C149-3

A.12 Settings

Addr.

Setting Title

Function

Setting Options

Default Setting

Comments

4514

df4/dt >/<



4515

STAGE df4/dt


0.1..10.0 Hz/s; ∞

4.0 Hz/s


4516

T df4/dt


0.00..60.00 sec; ∞

0.00 sec


4517

df4/dt & f4


OFF ON

OFF


4518

U MIN


10.0..125.0 V; 0

65.0 V

Minimum Operating Voltage Umin

4519A df1/2 HYSTERES.


0.02..0.99 Hz/s

0.10 Hz/s


4520A df1/2 M-WINDOW


1..25 Cycle

5 Cycle

Measuring Window for df1/ dt & df2/dt

4521A df3/4 HYSTERES.


0.02..0.99 Hz/s

0.40 Hz/s


4522A df3/4 M-WINDOW


1..25 Cycle

5 Cycle

Measuring Window for df3/ dt & df4/dt

4601

VECTOR JUMP

Jump of Voltage OFF Vector ON Block relay for trip commands

OFF


4602

DELTA PHI

Jump of Voltage 2..30 ° Vector

10 °

Jump of Phasor DELTA PHI

4603

T DELTA PHI

Jump of Voltage 0.00..60.00 sec; ∞ Vector

0.00 sec

T DELTA PHI Time Delay

4604

T RESET


5.00 sec

Reset Time after Trip

4605A U MIN

Jump of Voltage 10.0..125.0 V Vector

80.0 V

Minimal Operation Voltage U MIN

4606A U MAX

Jump of Voltage 10.0..170.0 V Vector

130.0 V

Maximal Operation Voltage U MAX

4607A T BLOCK


0.10 sec

Time Delay of Blocking

5001

Stator Earth OFF Fault Protection ON Block relay for trip commands

OFF


S/E/F PROT.

7UM62 Manual C53000-G1176-C149-3

535

A Appendix

Addr.

Setting Title

Function

Setting Options

Default Setting

Comments

5002

U0>

Stator Earth 2.0..125.0 V Fault Protection

10.0 V

U0> Pickup

5003

3I0>

Stator Earth 2..1000 mA Fault Protection

5 mA

3I0> Pickup

5004

DIR. ANGLE

Stator Earth 0..360 ° Fault Protection

15 °

Angle for Direction Determination

5005

T S/E/F

Stator Earth 0.00..60.00 sec; ∞ Fault Protection

0.30 sec

T S/E/F Time Delay

5101

O/C PROT. Iee>



OFF


5102

IEE>


2..1000 mA

10 mA

Iee> Pickup

5103

T IEE>


0.00..60.00 sec; ∞

5.00 sec

T Iee> Time delay

5104

IEE>>


2..1000 mA

23 mA

Iee>> Pickup

5105

T IEE>>


0.00..60.00 sec; ∞

1.00 sec

T Iee>> Time Delay

5106

IEE<


1.5..50.0 mA; 0

0.0 mA

Iee< Pickup (Interrupted Circuit)

5201

SEF 3rd HARM.



OFF


5202

U0 3.HARM<


0.2..40.0 V

1.0 V

U0 3rd Harmonic< Pickup

5203

U0 3.HARM>


0.2..40.0 V

2.0 V

U0 3rd Harmonic> Pickup

5204

T SEF 3. HARM.


0.00..60.00 sec; ∞

0.50 sec

T SEF 3rd Harmonic Time Delay

5205

P min >


10..100 %; 0

40 %

Release Threshold Pmin>

5206

U1 min >


50.0..125.0 V; 0

80.0 V

Release Threshold U1min>

536

7UM62 Manual C53000-G1176-C149-3

A.12 Settings

Addr.

Setting Title

Function

Setting Options

Default Setting

Comments

5301

100% SEF-PROT.

100% StatorOFF Earth-Fault Pro- ON tection Block relay for trip commands

OFF


5302

R< SEF ALARM

100% Stator20..700 Ohm Earth-Fault Protection

100 Ohm

Pickup Value of Alarm Stage Rsef<

5303

R<< SEF TRIP

100% Stator20..700 Ohm Earth-Fault Protection

20 Ohm

Pickup Value of Tripping Stage Rsef<<

5304

T SEF ALARM

100% Stator0.00..60.00 sec; ∞ Earth-Fault Protection

10.00 sec

Time Delay of Alarm Stage Rsef<

5305

T SEF TRIP

100% Stator0.00..60.00 sec; ∞ Earth-Fault Protection

1.00 sec

Time Delay of Tripping Stage Rsef<<

5306

SEF I>>

100% Stator0.02..1.50 A Earth-Fault Protection

0.40 A

Pickup Value of I SEF>> Stage

5307

U20 MIN

100% Stator0.3..15.0 V Earth-Fault Protection

1.0 V

Supervision Threshold of 20Hz Voltage

5308

I20 MIN

100% Stator5..40 mA Earth-Fault Protection

10 mA

Supervision Threshold of 20Hz Current

5309

PHI I SEF

100% Stator-60..60 ° Earth-Fault Protection

0°

Correction Angle for I SEF 100%

5310A SEF Rps

100% Stator0.0..700.0 Ohm Earth-Fault Protection

0.0 Ohm

Resistance Rps

5311A Rl-PARALLEL

100% Stator20..700 Ohm; ∞ Earth-Fault Protection

∞ Ohm

Parallel Load Resistance

6001

ROTOR E/F

Rotor Earth OFF Fault Protection ON Block relay for trip commands

OFF


6002

RE< WARN

Rotor Earth 3.0..30.0 kOhm Fault Protection

10.0 kOhm


6003

RE<< TRIP

Rotor Earth 1.0..5.0 kOhm Fault Protection

2.0 kOhm


6004

T-WARN-RE<

Rotor Earth 0.00..60.00 sec; ∞ Fault Protection

10.00 sec


6005

T-TRIP-RE<<

Rotor Earth 0.00..60.00 sec; ∞ Fault Protection

0.50 sec


6006

X COUPLING

Rotor Earth -100..800 Ohm Fault Protection

398 Ohm

Coupling Reactance

7UM62 Manual C53000-G1176-C149-3

537

A Appendix

Addr.

Setting Title

Function

Setting Options

Default Setting

Comments

6007

R SERIES

Rotor Earth 0..999 Ohm Fault Protection

50 Ohm

Series Resistance (e.g. Meas. Brushes)

6008

I RE<

Rotor Earth 1.0..50.0 mA; 0 Fault Protection

2.0 mA

Pickup Value of Failure Detection Ire<

6009

PHI I RE

Rotor Earth -15.0..15.0 ° Fault Protection

0.0 °

Correction Angle for Ire

6101

REF 1-3Hz

Rotor Earth Fault Protection (1-3Hz)


OFF


6102

RE< WARN


5.0..80.0 kOhm

40.0 kOhm


6103

RE<< TRIP


1.0..10.0 kOhm

5.0 kOhm


6104

T-WARN-RE<


0.00..60.00 sec; ∞

10.00 sec


6105

T-TRIP-RE<<


0.00..60.00 sec; ∞

1.00 sec


6106

Qc <


0.00..1.00 mAs

0.02 mAs

Pickup Value of open Rotor Circuit (Qc)


1.0..10.0 kOhm

3.3 kOhm

Testing Resistor

6107A TEST RESISTOR

6501

STARTUP MOTOR Motor Starting Time Supervision


OFF


6502

START. CURRENT Motor Starting Time Supervision

0.10..16.00 A

3.12 A

Starting Current of Motor

6503

STARTING TIME


1.0..180.0 sec

8.5 sec

Starting Time of Motor

6504

LOCK ROTOR TIME


0.5..120.0 sec; ∞

6.0 sec

Permissible Locked Rotor Time

6505

I MOTOR START


0.60..10.00 A

1.60 A

Current Pickup Value of Motor Starting

6601

RESTART INHIBIT Restart Inhibit for Motors


OFF


538

7UM62 Manual C53000-G1176-C149-3

A.12 Settings

Addr.

Setting Title

Function

Setting Options

Default Setting

Comments

6602

IStart/IMOTnom


1.5..10.0

4.9

I Start / I Motor nominal

6603

T START MAX


3.0..320.0 sec

8.5 sec


6604

T EQUAL


0.0..320.0 min

1.0 min


6606

MAX.WARM STARTS


1..4

2

Permissible Number of Warm Starts

6607

#COLD-#WARM


1..2

1

Number of Cold Starts Warm Starts

6608

Kτ at STOP


1.0..100.0

5.0


6609

Kτ at RUNNING


1.0..100.0

2.0

Extension of Time Constant at Running

6610

T MIN. INHIBIT


0.2..120.0 min

6.0 min


7001

BREAKER FAILURE



OFF


7002

TRIP INTERN


OFF Start Breaker Failure with Bin.Outp.12 Start Breaker Failure with CFC

OFF

Start with Internal TRIP Command

7003

CIRC. BR. I>


0.04..2.00 A

0.20 A

Supervision Current Pickup

7004

TRIP-Timer


0.06..60.00 sec; ∞

0.25 sec

TRIP-Timer

7101

INADVERT. EN.



OFF


7102

I STAGE


0.1..20.0 A; ∞

0.3 A

I Stage Pickup

7103

RELEASE U1<


10.0..125.0 V; 0

50.0 V

Release Threshold U1<

7104

PICK UP T U1<


0.00..60.00 sec; ∞

5.00 sec

Pickup Time Delay T U1<

7105

DROP OUT T U1<


0.00..60.00 sec; ∞

1.00 sec

Drop Out Time Delay T U1<

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

7UM62 Manual C53000-G1176-C149-3

539

A Appendix

Addr.

Setting Title

Function

7201

DC PROTECTION

DC Voltage/ Current Protection


OFF


7202

MEAS.METHOD


Mean Value Root Mean Square

Mean Value

Measurement Method (MEAN/RMS Values)

7203

DC >/<


DC Voltage/Current Stage DC > DC Voltage/Current Stage DC <

DC Voltage/Current Stage DC >

Method of Operation (DC >/ <)

7204

U DC ><


0.1..8.5 V

2.0 V

DC Voltage Pickup

7205

I DC ><


0.2..17.0 mA

4.0 mA

DC Current Pickup

7206

T DC


0.00..60.00 sec; ∞

2.00 sec

Time Delay for Trip of DC Protection

7301

20 mA (B1) =

Analog Outputs 10.0..1000.0 %

200.0 %


7302

MIN VALUE (B1)

Analog Outputs 0.0..5.0 mA

1.0 mA


7303

20 mA (B2) =


200.0 %


7304

MIN VALUE (B2)


1.0 mA


7305

20 mA (D1) =


200.0 %


7306

MIN VALUE (D1)


1.0 mA


7307

20 mA (D2) =


200.0 %


7308

MIN VALUE (D2)


1.0 mA


8001

FUSE FAIL MON.

Supervision

OFF ON

OFF


8101

MEASURE. SUPERV


OFF ON

OFF


8102

BALANCE U-LIMIT Measurement Supervision

10..100 V

50 V

Voltage Threshold for Balance Monitoring

8103

BAL. FACTOR U


0.58..0.90

0.75

Balance Factor for Voltage Monitor

8104

BAL. I LIMIT S1


0.10..1.00 A

0.50 A


8105

BAL. FACT. I S1


0.10..0.90

0.50


8106

BAL. I LIMIT S2


0.10..1.00 A

0.50 A


540

Setting Options

Default Setting

Comments

7UM62 Manual C53000-G1176-C149-3

A.12 Settings

Addr.

Setting Title

Function

Setting Options

Default Setting

Comments

8107

BAL. FACT. I S2


0.10..0.90

0.50


8108

SUM.thres. U


10..200 V

10 V

Summation Thres. for Volt. Monitoring

8109

SUM.Fact. U


0.60..0.95; 0

0.75

Factor for Volt. Sum. Monitoring

8110

ΣI THRESHOLD S1 Measurement Supervision

0.05..2.00 A

0.10 A


8111

ΣI FACTOR S1

0.00..0.95

0.10


8112

ΣI THRESHOLD S2 Measurement Supervision

0.05..2.00 A

0.10 A


8113

ΣI FACTOR S2


0.00..0.95

0.10


8201

TRIP Cir. SUP.


OFF ON

OFF

TRIP Circuit Supervision

8501

MEAS. VALUE 1>

Threshold supervision

Disabled Disabled Active Power P Reactive Power Q Change of Active Power Delta P Positive Sequence Voltage U1 Negative Sequence Voltage U2 Zero Sequence Current I0 Positive Sequence Current I1 Negative Sequence Current I2 Power Angle PHI


8502

THRESHOLD MV1>


-200..200 %


8503

MEAS. VALUE 2<




8504

THRESHOLD MV2<


-200..200 %


7UM62 Manual C53000-G1176-C149-3


100 %

100 %

541

A Appendix

Addr.

Setting Title

Function

Setting Options

Default Setting

Comments

8505

MEAS. VALUE 3>




8506

THRESHOLD MV3>


-200..200 %


8507

MEAS. VALUE 4<




8508

THRESHOLD MV4<


-200..200 %


8509

MEAS. VALUE 5>




8510

THRESHOLD MV5>


-200..200 %


542

100 %

100 %

100 %

7UM62 Manual C53000-G1176-C149-3

A.12 Settings

Addr.

Setting Title

Function

Setting Options

Default Setting

Comments

8511

MEAS. VALUE 6<




8512

THRESHOLD MV6<


-200..200 %

100 %


8601

EXTERN TRIP 1

External Trip Functions


OFF


8602

T DELAY


0.00..60.00 sec; ∞

1.00 sec


8701

EXTERN TRIP 2



OFF


8702

T DELAY


0.00..60.00 sec; ∞

1.00 sec


8801

EXTERN TRIP 3



OFF


8802

T DELAY


0.00..60.00 sec; ∞

1.00 sec


8901

EXTERN TRIP 4



OFF


8902

T DELAY


0.00..60.00 sec; ∞

1.00 sec


9011A RTD 1 TYPE

RTD-Box


Pt 100 Ohm

RTD 1: Type

9012A RTD 1 LOCATION

RTD-Box


Winding

RTD 1: Location

7UM62 Manual C53000-G1176-C149-3

543

A Appendix

Addr.

Setting Title

Function

Setting Options

Default Setting

Comments

9013

RTD 1 STAGE 1

RTD-Box

-50..250 °C; ∞

100 °C


9014

RTD 1 STAGE 1

RTD-Box

-58..482 °F; ∞

212 °F


9015

RTD 1 STAGE 2

RTD-Box

-50..250 °C; ∞

120 °C


9016

RTD 1 STAGE 2

RTD-Box

-58..482 °F; ∞

248 °F


9021A RTD 2 TYPE

RTD-Box


not connected

RTD 2: Type


RTD-Box


Other

RTD 2: Location

9023

RTD 2 STAGE 1

RTD-Box

-50..250 °C; ∞

100 °C


9024

RTD 2 STAGE 1

RTD-Box

-58..482 °F; ∞

212 °F


9025

RTD 2 STAGE 2

RTD-Box

-50..250 °C; ∞

120 °C


9026

RTD 2 STAGE 2

RTD-Box

-58..482 °F; ∞

248 °F


9031A RTD 3 TYPE

RTD-Box


not connected

RTD 3: Type


RTD-Box


Other

RTD 3: Location

9033

RTD 3 STAGE 1

RTD-Box

-50..250 °C; ∞

100 °C


9034

RTD 3 STAGE 1

RTD-Box

-58..482 °F; ∞

212 °F


9035

RTD 3 STAGE 2

RTD-Box

-50..250 °C; ∞

120 °C


9036

RTD 3 STAGE 2

RTD-Box

-58..482 °F; ∞

248 °F


RTD-Box


not connected

RTD 4: Type

9041A RTD 4 TYPE

544

7UM62 Manual C53000-G1176-C149-3

A.12 Settings

Addr.

Setting Title

Function

Setting Options

Default Setting

Comments


RTD-Box


Other

RTD 4: Location

9043

RTD 4 STAGE 1

RTD-Box

-50..250 °C; ∞

100 °C


9044

RTD 4 STAGE 1

RTD-Box

-58..482 °F; ∞

212 °F


9045

RTD 4 STAGE 2

RTD-Box

-50..250 °C; ∞

120 °C


9046

RTD 4 STAGE 2

RTD-Box

-58..482 °F; ∞

248 °F


9051A RTD 5 TYPE

RTD-Box


not connected

RTD 5: Type


RTD-Box


Other

RTD 5: Location

9053

RTD 5 STAGE 1

RTD-Box

-50..250 °C; ∞

100 °C


9054

RTD 5 STAGE 1

RTD-Box

-58..482 °F; ∞

212 °F


9055

RTD 5 STAGE 2

RTD-Box

-50..250 °C; ∞

120 °C


9056

RTD 5 STAGE 2

RTD-Box

-58..482 °F; ∞

248 °F


9061A RTD 6 TYPE

RTD-Box


not connected

RTD 6: Type


RTD-Box


Other

RTD 6: Location

9063

RTD 6 STAGE 1

RTD-Box

-50..250 °C; ∞

100 °C


9064

RTD 6 STAGE 1

RTD-Box

-58..482 °F; ∞

212 °F


9065

RTD 6 STAGE 2

RTD-Box

-50..250 °C; ∞

120 °C


9066

RTD 6 STAGE 2

RTD-Box

-58..482 °F; ∞

248 °F


7UM62 Manual C53000-G1176-C149-3

545

A Appendix

Addr.

Setting Title

Function

Setting Options

Default Setting

Comments

9071A RTD 7 TYPE

RTD-Box


not connected

RTD 7: Type


RTD-Box


Other

RTD 7: Location

9073

RTD 7 STAGE 1

RTD-Box

-50..250 °C; ∞

100 °C


9074

RTD 7 STAGE 1

RTD-Box

-58..482 °F; ∞

212 °F


9075

RTD 7 STAGE 2

RTD-Box

-50..250 °C; ∞

120 °C


9076

RTD 7 STAGE 2

RTD-Box

-58..482 °F; ∞

248 °F


9081A RTD 8 TYPE

RTD-Box


not connected

RTD 8: Type


RTD-Box


Other

RTD 8: Location

9083

RTD 8 STAGE 1

RTD-Box

-50..250 °C; ∞

100 °C


9084

RTD 8 STAGE 1

RTD-Box

-58..482 °F; ∞

212 °F


9085

RTD 8 STAGE 2

RTD-Box

-50..250 °C; ∞

120 °C


9086

RTD 8 STAGE 2

RTD-Box

-58..482 °F; ∞

248 °F


9091A RTD 9 TYPE

RTD-Box


not connected

RTD 9: Type


RTD-Box


Other

RTD 9: Location

9093

RTD 9 STAGE 1

RTD-Box

-50..250 °C; ∞

100 °C


9094

RTD 9 STAGE 1

RTD-Box

-58..482 °F; ∞

212 °F


546

7UM62 Manual C53000-G1176-C149-3

A.12 Settings

Addr.

Setting Title

Function

Setting Options

Default Setting

Comments

9095

RTD 9 STAGE 2

RTD-Box

-50..250 °C; ∞

120 °C


9096

RTD 9 STAGE 2

RTD-Box

-58..482 °F; ∞

248 °F


RTD-Box


not connected

RTD10: Type

9102A RTD10 LOCATION RTD-Box


Other

RTD10: Location

9103

RTD10 STAGE 1

RTD-Box

-50..250 °C; ∞

100 °C


9104

RTD10 STAGE 1

RTD-Box

-58..482 °F; ∞

212 °F


9105

RTD10 STAGE 2

RTD-Box

-50..250 °C; ∞

120 °C


9106

RTD10 STAGE 2

RTD-Box

-58..482 °F; ∞

248 °F


RTD-Box


not connected

RTD11: Type



Other

RTD11: Location

9113

RTD11 STAGE 1

RTD-Box

-50..250 °C; ∞

100 °C


9114

RTD11 STAGE 1

RTD-Box

-58..482 °F; ∞

212 °F


9115

RTD11 STAGE 2

RTD-Box

-50..250 °C; ∞

120 °C


9116

RTD11 STAGE 2

RTD-Box

-58..482 °F; ∞

248 °F


RTD-Box


not connected

RTD12: Type


Other

RTD12: Location

9101A RTD10 TYPE

9111A RTD11 TYPE

9121A RTD12 TYPE


7UM62 Manual C53000-G1176-C149-3

547

A Appendix

Addr.

Setting Title

Function

Setting Options

Default Setting

Comments

9123

RTD12 STAGE 1

RTD-Box

-50..250 °C; ∞

100 °C


9124

RTD12 STAGE 1

RTD-Box

-58..482 °F; ∞

212 °F


9125

RTD12 STAGE 2

RTD-Box

-50..250 °C; ∞

120 °C


9126

RTD12 STAGE 2

RTD-Box

-58..482 °F; ∞

248 °F


548

7UM62 Manual C53000-G1176-C149-3

A.13 List of Information

A.13 List of Information NOTE: The following table lists all data which are available in the maximum complement of the device. Dependent on the ordered model, only those data may be present which are valid for the individual version. The symbol ’ > ’ indicates that the source of the indication is a binary input.

*

*

00004 >Trigger Waveform Capture (>Trig.Wave.Cap.)


SP

*

*

00005 >Reset LED (>Reset LED)

Device

SP

*

00007 >Setting Group Select Bit 0 (>Set Group Bit0)

Change Group

SP

00015 >Test mode (>Test mode)

Device

00016 >Stop data transmission (>DataStop)

1

LED BI

BO

135

49

1

GI

*

LED BI

BO

135

50

1

GI

*

*

LED BI

BO

135

51

1

GI

SP

*

*

LED BI

BO

135

53

1

GI

Device

SP

*

*

LED BI

BO

135

54

1

GI

00051 Device is Operational and Protecting (Device OK)

Device

OUT

ON OF F

*

LED

BO

135

81

1

GI

00052 At Least 1 Protection Funct. is Active (ProtActive)

Device

IntSP

ON OF F

*

LED

BO

70

18

1

GI

00055 Reset Device (Reset Device)

Device

OUT

ON

*

LED

BO

00056 Initial Start of Device (Initial Start)

Device

OUT

ON

*

LED

BO

70

5

1

00060 Reset LED (Reset LED)

Device

OUT_ Ev

ON

*

LED

BO

70

19

1

00067 Resume (Resume)

Device

OUT

ON

*

LED

BO

00068 Clock Synchronization Error (Clock SyncError)

Supervision

OUT

ON OF F

*

LED

BO

00069 Daylight Saving Time (DayLightSavTime)

Device

OUT

ON OF F

*

LED

BO

00070 Setting calculation is running (Settings Calc.)

Device

OUT

ON OF F

*

LED

BO

70

22

1

00071 Settings Check (Settings Check)

Device

OUT

*

*

LED

BO

00072 Level-2 change (Level-2 change)

Device

OUT

ON OF F

*

LED

BO

00110 Event lost (Event Lost)

Supervision

OUT_ Ev

ON

*

LED

BO

135

130

1

7UM62 Manual C53000-G1176-C149-3

M

Chatter Blocking

48

Binary Output

135

Function Key

BO

Binary Input

LED BI

LED

Data Unit (ASDU)

SP_Ev

Information-No

Device

IEC 60870-5-103

Type

00003 >Synchronize Internal Real Time Clock (>Time Synch)

Configurable in Matrix

General Interrogation

Log-Buffers

Marked in Oscill. Record

Type of Informatio n

Ground Fault Log On/Off

Function

Trip (Fault) Log On/Off

Description

Event Log On/Off

F.No.

GI

549

A Appendix


Log-Buffers

Data Unit (ASDU)


1

GI

*

LED

BO

135

145

1

GI

*

*

LED

BO

OUT

ON OF F

*

LED

BO

Supervision

OUT

*

*

LED

BO

70

46

1

GI

00161 Failure: General Current Supervision (Fail I Superv.)


OUT

ON OF F

*

LED

BO

70

32

1

GI

00164 Failure: General Voltage Supervision (Fail U Superv.)


OUT

ON OF F

*

LED

BO

70

33

1

GI

00165 Failure: Voltage Summation PhaseEarth (Fail Σ U Ph-E)


OUT

ON OF F

*

LED

BO

135

184

1

GI

00167 Failure: Voltage Balance (Fail U balance)


OUT

ON OF F

*

LED

BO

135

186

1

GI

00171 Failure: Phase Sequence (Fail Ph. Seq.)


OUT

ON OF F

*

LED

BO

70

35

1

GI

00176 Failure: Phase Sequence Voltage (Fail Ph. Seq. U)


OUT

ON OF F

*

LED

BO

135

192

1

GI

00177 Failure: Battery empty (Fail Battery)

Supervision

OUT

ON OF F

*

LED

BO

00181 Error: A/D converter (Error A/D-conv.)

Supervision

OUT

ON OF F

*

LED

BO

00191 Error: Offset (Error Offset)

Supervision

OUT

ON OF F

*

LED

BO

00193 Alarm: NO calibration data available (Alarm NO calibr)

Supervision

OUT

ON OF F

*

LED

BO

00194 Error: Neutral CT different from MLFB (Error neutralCT)

Supervision

OUT

ON OF F

*

LED

BO

00197 Measurement Supervision is switched OFF (MeasSup OFF)


OUT

ON OF F

*

LED

BO

135

197

1

GI

00203 Waveform data deleted (Wave. deleted)


OUT_ Ev

ON

*

LED

BO

135

203

1

ON

*

00125 Chatter ON (Chatter ON)

Device

OUT

ON OF F

00140 Error with a summary alarm (Error Sum Alarm)

Supervision

OUT

00147 Error Power Supply (Error PwrSupply)

Supervision

00160 Alarm Summary Event (Alarm Sum Event)

550

Chatter Blocking

136

OUT

Binary Output

135

Supervision

Function Key

BO

00113 Flag Lost (Flag Lost)

Binary Input

LED


M

Event Log On/Off

Information-No

IEC 60870-5-103

Type


LED

Function


Description


F.No.

7UM62 Manual C53000-G1176-C149-3



Log-Buffers


Data Unit (ASDU)


LED

BO

00211 Err:1A/5Ajumper different from settingS2 (Err1A/5AwrongS2)

Supervision

OUT

ON OF F

*

LED

BO

00212 Err: TD1 jumper different from setting (Err. TD1 jumper)

Supervision

OUT

ON OF F

*

LED

BO


Supervision

OUT

ON OF F

*

LED

BO


Supervision

OUT

ON OF F

*

LED

BO

00230 Failure: Current Summation on Side 1 (Fail. Σ I Side1)


OUT

ON OF F

*

LED

BO

135

155

1

GI

00231 Failure: Current Summation on Side 2 (Fail. Σ I Side2)


OUT

ON OF F

*

LED

BO

135

158

1

GI

00264 Failure: RTD-Box 1 (Fail: RTD-Box 1)

Supervision

OUT

ON OF F

*

LED

BO

135

208

1

GI

00265 Failure: Phase Sequence I side 1 (FailPh.Seq I S1)


OUT

ON OF F

*

LED

BO

135

156

1

GI

00266 Failure: Phase Sequence I side 2 (FailPh.Seq I S2)


OUT

ON OF F

*

LED

BO

135

157

1

GI

00267 Failure: RTD-Box 2 (Fail: RTD-Box 2)

Supervision

OUT

ON OF F

*

LED

BO

135

209

1

GI

00272 Set Point Operating Hours (SP. Op Hours>)

Set Points (Statistic)

OUT

ON OF F

*

LED

BO

135

229

1

GI

00284 Set Point I< alarm (SP. I<)

Set Points (Measured Values)

OUT

*

*

LED

BO

135

244

1

GI

00361 >Failure: Feeder VT (MCB tripped) (>FAIL:Feeder VT)

Power System Data 1

SP

ON OF F

*

LED BI

BO

150

38

1

GI

00394 >UE 3rd Harm. MIN/MAX Buffer Reset (>UE3h MiMa Res.)

Min/Max Measurement Setup

SP

ON

*

BI

BO

00396 >I1 MIN/MAX Buffer Reset (>I1 MiMa- Min/Max MeasureReset) ment Setup

SP

ON

*

BI

BO

00399 >U1 MIN/MAX Buffer Reset (>U1 MiMa Reset)


SP

ON

*

BI

BO

00400 >P MIN/MAX Buffer Reset (>P MiMa Reset)


SP

ON

*

BI

BO

7UM62 Manual C53000-G1176-C149-3

Chatter Blocking

*

Binary Output

ON OF F

Function Key

OUT

Binary Input

Supervision

LED

00210 Err:1A/5Ajumper different from settingS1 (Err1A/5AwrongS1)

Event Log On/Off

Information-No

IEC 60870-5-103

Type


Function


Description


F.No.

551

A Appendix


Log-Buffers


Data Unit (ASDU)


BI

BO

00407 >Frq. MIN/MAX Buffer Reset (>Frq MiMa Reset)


SP

ON

*

BI

BO

00409 >BLOCK Op Counter (>BLOCK Op Count)

Statistics

SP

ON OF F

*

LED BI

BO

00571 Fail.: Current symm. supervision side 1 (Fail. Isym 1)


OUT

ON OF F

*

LED

BO

150

196

1

GI

00572 Fail.: Current symm. supervision side 2 (Fail. Isym 2)


OUT

ON OF F

*

LED

BO

150

197

1

GI

00576 Primary fault current IL1 Side1 (IL1 S1:)

Power System Data 2

OUT

*

ON OFF

150

193

4


Power System Data 2

OUT

*

ON OFF

150

194

4


Power System Data 2

OUT

*

ON OFF

150

195

4


Power System Data 2

OUT

*

ON OFF

150

190

4


Power System Data 2

OUT

*

ON OFF

150

191

4


Power System Data 2

OUT

*

ON OFF

150

192

4

01020 Counter of operating hours (Op.Hours=)

Statistics

OUT

01202 >BLOCK IEE>> (>BLOCK IEE>>)


SP

ON OF F

*

LED BI

BO

151

102

1

GI

01203 >BLOCK IEE> (>BLOCK IEE>)


SP

ON OF F

*

LED BI

BO

151

103

1

GI

01221 IEE>> picked up (IEE>> picked up)


OUT

*

ON OFF

LED

BO

151

121

2

GI

01223 IEE>> TRIP (IEE>> TRIP)


OUT

*

ON

LED

BO

151

123

2

GI

01224 IEE> picked up (IEE> picked up)


OUT

*

ON OFF

LED

BO

151

124

2

GI

01226 IEE> TRIP (IEE> TRIP)


OUT

*

ON

LED

BO

151

126

2

GI

01231 >BLOCK sensitiv earth current prot. (>BLOCK Sens. E)


SP

*

*

LED BI

BO

01232 Earth current prot. is swiched OFF (IEE OFF)


OUT

ON OF F

*

LED

BO

151

132

1

GI

552

Chatter Blocking

*

Binary Output

ON

Function Key

SP

Binary Input


LED

00402 >Q MIN/MAX Buffer Reset (>Q MiMa Reset)

Event Log On/Off

Information-No

IEC 60870-5-103

Type


Function


Description


F.No.

7UM62 Manual C53000-G1176-C149-3



Log-Buffers


Data Unit (ASDU)


LED

BO

151

133

1

GI

01234 Earth current prot. is ACTIVE (IEE ACTIVE)


OUT

ON OF F

*

LED

BO

151

134

1

GI

01403 >BLOCK breaker failure (>BLOCK BkrFail)


SP

*

*

LED BI

BO

01422 >Breaker contacts (>Break. Contact)


SP

ON OF F

*

LED BI

BO

166

120

1

GI

01423 >ext. start 1 breaker failure prot. (>ext.start1 B/F)


SP

ON OF F

*

LED BI

BO

166

121

1

GI

01441 >ext. start 2 breaker failure prot. (>ext.start2 B/F)


SP

ON OF F

*

LED BI

BO

166

122

1

GI

01442 >int. start breaker failure prot. (>int. start B/F)


SP

ON OF F

*

LED BI

BO

166

123

1

GI

01443 Breaker fail. started intern (int. start B/ Breaker Failure F) Protection

OUT

ON OF F

*

LED

BO

166

190

1

GI

01444 Breaker failure I> (B/F I>)


OUT

ON OF F

*

LED

BO

166

191

1

GI

01451 Breaker failure is switched OFF (BkrFail OFF)


OUT

ON OF F

*

LED

BO

166

151

1

GI

01452 Breaker failure is BLOCKED (BkrFail BLOCK)


OUT

ON OF F

ON OFF

LED

BO

166

152

1

GI

01453 Breaker failure is ACTIVE (BkrFail ACTIVE)


OUT

ON OF F

*

LED

BO

166

153

1

GI

01455 Breaker failure protection: picked up (B/F picked up)


OUT

*

ON OFF

LED

BO

166

155

2

GI

01471 Breaker failure TRIP (BrkFailure TRIP)


OUT

*

ON

LED

BO

166

171

2

GI

01503 >BLOCK thermal overload protection (>BLK ThOverload)


SP

*

*

LED BI

BO

01506 >Reset memory for thermal replica O/ L (>RM th.rep. O/L)


SP

ON OF F

*

LED BI

BO

01507 >Emergency start O/L (>Emer.Start O/ Thermal Overload L) Protection

SP

ON OF F

*

LED BI

BO

167

7

1

GI

7UM62 Manual C53000-G1176-C149-3

M

Chatter Blocking

ON OFF

Binary Output

ON OF F

Function Key

OUT

Binary Input


LED

01233 Earth current prot. is BLOCKED (IEE BLOCKED)

Event Log On/Off

Information-No

IEC 60870-5-103

Type


Function


Description


F.No.

553

A Appendix


Log-Buffers


Data Unit (ASDU)


LED BI

BO

167

8

1

GI

01511 Thermal Overload Protection OFF (Th.Overload OFF)


OUT

ON OF F

*

LED

BO

167

11

1

GI

01512 Thermal Overload Protection BLOKKED (Th.Overload BLK)


OUT

ON OF F

ON OFF

LED

BO

167

12

1

GI

01513 Overload Protection ACTIVE (Overload ACT)


OUT

ON OF F

*

LED

BO

167

13

1

GI

01514 Failure temperature input (Fail.Temp.inp)


OUT

ON OF F

*

LED

BO

167

14

1

GI

01515 Overload Current Alarm (I alarm) (O/L I Alarm)


OUT

ON OF F

*

LED

BO

167

15

1

GI

01516 Thermal Overload Alarm (O/L Θ Alarm)


OUT

ON OF F

*

LED

BO

167

16

1

GI

01517 Thermal Overload picked up (O/L Th. pick.up)


OUT

ON OF F

*

LED

BO

167

17

1

GI

01519 Reset memory for thermal replica O/L (RM th.rep. O/L)


OUT

ON OF F

*

LED

BO

167

19

1

GI

01521 Thermal Overload TRIP (ThOverload TRIP)


OUT

*

ON

LED

BO

167

21

2

GI

01720 >BLOCK direction I>> stage (>BLOCK dir.)


SP

ON OF F

*

LED BI

BO

60

18

1

GI

01721 >BLOCK I>> (>BLOCK I>>)


SP

*

*

LED BI

BO

01722 >BLOCK I> (>BLOCK I>)


SP

*

*

LED BI

BO

01801 O/C fault detection stage I>> phase L1 (I>> Fault L1)


OUT

*

ON OFF

LED

BO

60

46

2

GI



OUT

*

ON OFF

LED

BO

60

47

2

GI



OUT

*

ON OFF

LED

BO

60

48

2

GI

01806 O/C I>> direction forward (I>> forward)


OUT

*

ON OFF

LED

BO

60

208

2

GI

01807 O/C I>> direction backward (I>> back- O/C I>> (with direcward) tion)

OUT

*

ON OFF

LED

BO

60

209

2

GI

01808 O/C prot. I>> picked up (I>> picked up)

OUT

*

ON OFF

LED

BO

60

210

2

GI

554


Chatter Blocking

*

Binary Output

ON OF F

Function Key

SP

Binary Input


LED

01508 >Failure temperature input (>Fail.Temp.inp)

Event Log On/Off

Information-No

IEC 60870-5-103

Type


Function


Description


F.No.

7UM62 Manual C53000-G1176-C149-3



Log-Buffers

Data Unit (ASDU)


2

GI

ON OFF

LED

BO

60

50

2

GI

*

ON OFF

LED

BO

60

51

2

GI

OUT

*

ON OFF

LED

BO

60

52

2

GI


OUT

*

ON

LED

BO

60

71

2

GI

01883 >BLOCK inverse O/C time protection (>BLOCK O/C Ip)


SP

*

*

LED BI

BO

01891 O/C protection Ip is switched OFF (O/ C Ip OFF)


OUT

ON OF F

*

LED

BO

60

180

1

GI

01892 O/C protection Ip is BLOCKED (O/C Ip BLOCKED)


OUT

ON OF F

ON OFF

LED

BO

60

181

1

GI

01893 O/C protection Ip is ACTIVE (O/C Ip ACTIVE)


OUT

ON OF F

*

LED

BO

60

182

1

GI

01896 O/C fault detection Ip phase L1 (O/C Ip Fault L1)


OUT

*

ON OFF

LED

BO

60

184

2

GI



OUT

*

ON OFF

LED

BO

60

185

2

GI



OUT

*

ON OFF

LED

BO

60

186

2

GI

01899 O/C Ip picked up (O/C Ip pick.up)


OUT

*

ON OFF

LED

BO

60

183

2

GI

01900 O/C Ip TRIP (O/C Ip TRIP)


OUT

*

ON

LED

BO

60

187

2

GI

01950 >O/C prot. : BLOCK undervoltage seal-in (>Useal-in BLK)


SP

ON OF F

*

LED BI

BO

60

200

1

GI

01955 O/C prot. stage I>> is switched OFF (I>> OFF)


OUT

ON OF F

*

LED

BO

60

205

1

GI

01956 O/C prot. stage I>> is BLOCKED (I>> BLOCKED)


OUT

ON OF F

ON OFF

LED

BO

60

206

1

GI

01957 O/C prot. stage I>> is ACTIVE (I>> ACTIVE)


OUT

ON OF F

*

LED

BO

60

207

1

GI

01965 O/C prot. stage I> is switched OFF (I> OFF)


OUT

ON OF F

*

LED

BO

60

215

1

GI

*

ON

01811 O/C fault detection stage I> phase L1 (I> Fault L1)


OUT

*



OUT



01815 O/C I> TRIP (I> TRIP)

7UM62 Manual C53000-G1176-C149-3

M

M

Chatter Blocking

211

OUT

Binary Output

60


Function Key

BO

01809 O/C I>> TRIP (I>> TRIP)

Binary Input

LED


M

Event Log On/Off

Information-No

IEC 60870-5-103

Type


LED

Function


Description


F.No.

555

A Appendix


Log-Buffers


Data Unit (ASDU)


LED

BO

60

216

1

GI

01967 O/C prot. stage I> is ACTIVE (I> ACTIVE)


OUT

ON OF F

*

LED

BO

60

217

1

GI

01970 O/C prot. undervoltage seal-in (U< seal in)


OUT

*

ON OFF

LED

BO

60

220

2

GI

03953 >BLOCK impedance protection (>Imp. BLOCK)


SP

*

*

LED BI

BO

03956 >Zone 1B extension for impedance prot. (>Extens. Z1B)


SP

ON OF F

*

LED BI

BO

28

222

1

GI

03958 >Imp. prot. : BLOCK undervoltage seal-in (>Useal-in BLK)


SP

ON OF F

*

LED BI

BO

28

30

1

GI

03961 Impedance protection is switched OFF (Imp. OFF)


OUT

ON OF F

*

LED

BO

28

226

1

GI

03962 Impedance protection is BLOCKED (Imp. BLOCKED)


OUT

ON OF F

ON OFF

LED

BO

28

227

1

GI

03963 Impedance protection is ACTIVE (Imp. ACTIVE)


OUT

ON OF F

*

LED

BO

28

228

1

GI

03966 Impedance protection picked up (Imp. picked up)


OUT

*

ON OFF

LED

BO

28

229

2

GI

03967 Imp.: Fault detection , phase L1 (Imp. Fault L1)


OUT

*

ON OFF

LED

BO

28

230

2

GI



OUT

*

ON OFF

LED

BO

28

231

2

GI



OUT

*

ON OFF

LED

BO

28

232

2

GI

03970 Imp.: O/C with undervoltage seal in (Imp. I> & U<)


OUT

*

ON OFF

LED

BO

28

233

2

GI

03976 Power swing detection (Power Swing)


OUT

*

ON OFF

LED

BO

03977 Imp.: Z1< TRIP (Imp.Z1< TRIP)


OUT

*

ON

M

LED

BO

28

240

2

GI

03978 Imp.: Z1B< TRIP (Imp.Z1B< TRIP)


OUT

*

ON

M

LED

BO

28

241

2

GI

03979 Imp.: Z2< TRIP (Imp. Z2< TRIP)


OUT

*

ON

M

LED

BO

28

242

2

GI

03980 Imp.: T3> TRIP (Imp.T3> TRIP)


OUT

*

ON

M

LED

BO

28

243

2

GI

04523 >Block external trip 1 (>BLOCK Ext 1)


SP

*

*

LED BI

BO

556

Chatter Blocking

ON OFF

Binary Output

ON OF F

Function Key

OUT

Binary Input


LED

01966 O/C prot. stage I> is BLOCKED (I> BLOCKED)

Event Log On/Off

Information-No

IEC 60870-5-103

Type


Function


Description


F.No.

7UM62 Manual C53000-G1176-C149-3



Log-Buffers


Data Unit (ASDU)


LED BI

BO

51

126

1

GI

04531 External trip 1 is switched OFF (Ext 1 OFF)


OUT

ON OF F

*

LED

BO

51

131

1

GI

04532 External trip 1 is BLOCKED (Ext 1 BLOCKED)


OUT

ON OF F

ON OFF

LED

BO

51

132

1

GI

04533 External trip 1 is ACTIVE (Ext 1 ACTIVE)


OUT

ON OF F

*

LED

BO

51

133

1

GI

04536 External trip 1: General picked up (Ext 1 picked up)


OUT

*

ON OFF

LED

BO

51

136

2

GI

04537 External trip 1: General TRIP (Ext 1 Gen.TRP)


OUT

*

ON

LED

BO

51

137

2

GI

04543 >BLOCK external trip 2 (>BLOCK Ext 2)


SP

*

*

LED BI

BO

04546 >Trigger external trip 2 (>Ext trip 2)


SP

ON OF F

*

LED BI

BO

51

146

1

GI



OUT

ON OF F

*

LED

BO

51

151

1

GI



OUT

ON OF F

ON OFF

LED

BO

51

152

1

GI



OUT

ON OF F

*

LED

BO

51

153

1

GI



OUT

*

ON OFF

LED

BO

51

156

2

GI



OUT

*

ON

LED

BO

51

157

2

GI



SP

*

*

LED BI

BO



SP

ON OF F

*

LED BI

BO

51

166

1

GI



OUT

ON OF F

*

LED

BO

51

171

1

GI



OUT

ON OF F

ON OFF

LED

BO

51

172

1

GI



OUT

ON OF F

*

LED

BO

51

173

1

GI

7UM62 Manual C53000-G1176-C149-3

Chatter Blocking

*

Binary Output

ON OF F

Function Key

SP

Binary Input


LED


Event Log On/Off

Information-No

IEC 60870-5-103

Type


Function


Description


F.No.

557

A Appendix


Log-Buffers


Data Unit (ASDU)


LED

BO

51

176

2

GI



OUT

*

ON

LED

BO

51

177

2

GI



SP

*

*

LED BI

BO



SP

ON OF F

*

LED BI

BO

51

186

1

GI



OUT

ON OF F

*

LED

BO

51

191

1

GI



OUT

ON OF F

ON OFF

LED

BO

51

192

1

GI



OUT

ON OF F

*

LED

BO

51

193

1

GI



OUT

*

ON OFF

LED

BO

51

196

2

GI



OUT

*

ON

LED

BO

51

197

2

GI

04822 >BLOCK Restart inhibit motor (>BLK Re. Inhib.)


SP

*

*

LED BI

BO

04823 >Emergency start rotor (>Emer. Start ΘR)


SP

ON OF F

*

LED BI

BO

168

51

1

GI

04824 Restart inhibit motor is switched OFF (Re. Inhibit OFF)


OUT

ON OF F

*

LED

BO

168

52

1

GI

04825 Restart inhibit motor is BLOCKED (Re. Inhibit BLK)


OUT

ON OF F

*

LED

BO

168

53

1

GI

04826 Restart inhibit motor is ACTIVE (Re. Inhibit ACT)


OUT

ON OF F

*

LED

BO

168

54

1

GI

04827 Restart inhibit motor TRIP (Re. Inhib. TRIP)


OUT

ON

*

LED

BO

168

55

1

GI

04828 >Reset thermal memory rotor (>RM th.rep. ΘR)


SP

ON OF F

*

LED BI

BO

04829 Reset thermal memory rotor (RM th.rep. ΘR)


OUT

ON OF F

*

LED

BO

168

50

1

GI

04830 Alarm restart inhibit motor (Re. Inhib.ALARM)


OUT

ON OF F

*

LED

BO

558

Chatter Blocking

ON OFF

Binary Output

*

Function Key

OUT

Binary Input


LED


Event Log On/Off

Information-No

IEC 60870-5-103

Type


Function


Description


F.No.

7UM62 Manual C53000-G1176-C149-3



Log-Buffers


Data Unit (ASDU)


LED

BO

71

2

1

GI

05010 >BLOCK fuse failure monitor (>FFM BLOCK)

Supervision

SP

ON OF F

ON OFF

LED BI

BO

71

7

1

GI

05011 >FFM extern undervoltage (>FFM U< extern)

Supervision

SP

ON OF F

*

LED BI

BO

71

8

1

GI

05012 Voltage UL1E at trip (UL1E:)

Power System Data 2

OUT

*

ON OFF

71

38

4


Power System Data 2

OUT

*

ON OFF

71

39

4


Power System Data 2

OUT

*

ON OFF

71

40

4

05015 Active power at trip (P:)

Power System Data 2

OUT

*

ON OFF

71

41

4

05016 Reactive power at trip (Q:)

Power System Data 2

OUT

*

ON OFF

71

42

4

05017 Frequency at trip (f:)

Power System Data 2

OUT

*

ON OFF

71

43

4

05053 >BLOCK out-of-step protection (>BLOCK O/S)


SP

*

*

LED BI

BO

05061 Out-of-step protection is switched OFF (O/S OFF)


OUT

ON OF F

*

LED BI

BO

70

56

1

GI

05062 Out-of-step protection is BLOCKED (O/S BLOCKED)


OUT

ON OF F

ON OFF

LED

BO

70

57

1

GI

05063 Out-of-step protection is ACTIVE (O/S ACTIVE)


OUT

ON OF F

*

LED

BO

70

58

1

GI

05067 Out-of-step pulse of characteristic 1 (O/S char. 1)


OUT

*

ON OFF

LED

BO

70

60

2

GI

05068 Out-of-step pulse of characteristic 2 (O/S char. 2)


OUT

*

ON OFF

LED

BO

70

61

2

GI

05069 Out-of-step characteristic 1 picked up (O/S det. char.1)


OUT

*

ON OFF

LED

BO

70

62

2

GI

05070 Out-of-step characteristic 2 picked up (O/S det. char.2)


OUT

*

ON OFF

LED

BO

70

63

2

GI

05071 Out-of-step TRIP characteristic 1 (O/S TRIP char.1)


OUT

*

ON

M

LED

BO

70

64

2

GI

05072 Out-of-step TRIP characteristic 2 (O/S TRIP char.2)


OUT

*

ON

M

LED

BO

70

65

2

GI

05083 >BLOCK reverse power protection (>Pr BLOCK)


SP

*

*

LED BI

BO

7UM62 Manual C53000-G1176-C149-3

Chatter Blocking

*

Binary Output

ON OF F

Function Key

OUT

Binary Input

Power System Data 1

LED

05002 Suitable measured quantities present (Operat. Cond.)

Event Log On/Off

Information-No

IEC 60870-5-103

Type


Function


Description


F.No.

559

A Appendix


Log-Buffers


Data Unit (ASDU)


LED BI

BO

70

77

1

GI

05091 Reverse power prot. is switched OFF (Pr OFF)


OUT

ON OF F

*

LED

BO

70

81

1

GI

05092 Reverse power protection is BLOKKED (Pr BLOCKED)


OUT

ON OF F

ON OFF

LED

BO

70

82

1

GI

05093 Reverse power protection is ACTIVE (Pr ACTIVE)


OUT

ON OF F

*

LED

BO

70

83

1

GI

05096 Reverse power: picked up (Pr picked up)


OUT

*

ON OFF

LED

BO

70

84

2

GI

05097 Reverse power: TRIP (Pr TRIP)


OUT

*

ON

M

LED

BO

70

85

2

GI

05098 Reverse power: TRIP with stop valve (Pr+SV TRIP)


OUT

*

ON

M

LED

BO

70

86

2

GI

05113 >BLOCK forward power supervision (>Pf BLOCK)


SP

*

*

LED BI

BO

05116 >BLOCK forw. power superv. Pf< stage (>Pf< BLOCK)


SP

ON OF F

*

LED BI

BO

70

102

1

GI

05117 >BLOCK forw. power superv. Pf> stage (>Pf> BLOCK)


SP

ON OF F

*

LED BI

BO

70

103

1

GI

05121 Forward power supervis. is switched OFF (Pf OFF)


OUT

ON OF F

*

LED

BO

70

106

1

GI

05122 Forward power supervision is BLOKKED (Pf BLOCKED)


OUT

ON OF F

ON OFF

LED

BO

70

107

1

GI

05123 Forward power supervision is ACTIVE (Pf ACTIVE)


OUT

ON OF F

*

LED

BO

70

108

1

GI

05126 Forward power: Pf< stage picked up (Pf< picked up)


OUT

*

ON OFF

LED

BO

70

109

2

GI

05127 Forward power: Pf> stage picked up (Pf> picked up)


OUT

*

ON OFF

LED

BO

70

110

2

GI

05128 Forward power: Pf< stage TRIP (Pf< TRIP)


OUT

*

ON

M

LED

BO

70

111

2

GI

05129 Forward power: Pf> stage TRIP (Pf> TRIP)


OUT

*

ON

M

LED

BO

70

112

2

GI

05143 >BLOCK I2 (Unbalance Load) (>BLOCK I2)


SP

*

*

LED BI

BO

560

Chatter Blocking

*

Binary Output

ON OF F

Function Key

SP

Binary Input


LED

05086 >Stop valve tripped (>SV tripped)

Event Log On/Off

Information-No

IEC 60870-5-103

Type


Function


Description


F.No.

7UM62 Manual C53000-G1176-C149-3



Log-Buffers


Data Unit (ASDU)


70

128

1

GI

LED

BO

70

129

1

GI

*

LED

BO

70

131

1

GI

ON OF F

ON OFF

LED

BO

70

132

1

GI

OUT

ON OF F

*

LED

BO

70

133

1

GI


OUT

ON OF F

*

LED

BO

70

134

1

GI

05158 Reset memory of thermal replica I2 (RM th.rep. I2)


OUT

ON OF F

*

LED

BO

70

137

1

GI

05159 I2>> picked up (I2>> picked up)


OUT

*

ON OFF

LED

BO

70

138

2

GI

05160 Unbalanced load: TRIP of current stage (I2>> TRIP)


OUT

*

ON

LED

BO

70

139

2

GI

05161 Unbalanced load: TRIP of thermal stage (I2 Θ TRIP)


OUT

*

ON

LED

BO

70

140

2

GI

05165 I2> picked up (I2> picked up)


OUT

*

ON OFF

LED

BO

70

150

2

GI

05173 >BLOCK stator earth fault protection (>S/E/F BLOCK)


SP

*

*

LED BI

BO

05176 >Switch off earth current detec.(S/E/F) (>S/E/F Iee off)


SP

ON OF F

*

LED BI

BO

70

152

1

GI

05181 Stator earth fault prot. is switch OFF (S/E/F OFF)


OUT

ON OF F

*

LED

BO

70

156

1

GI

05182 Stator earth fault protection is BLOCK. (S/E/F BLOCKED)


OUT

ON OF F

ON OFF

LED

BO

70

157

1

GI

05145 >Reverse Phase Rotation (>Reverse Rot.)

Power System Data 1

SP

ON OF F

*

LED BI

BO

05146 >Reset memory for thermal replica I2 (>RM th.rep. I2)


SP

ON OF F

*

LED BI

BO

05147 Phase Rotation L1L2L3 (Rotation L1L2L3)

Power System Data 1

OUT

ON OF F

*

LED

05148 Phase Rotation L1L3L2 (Rotation L1L3L2)

Power System Data 1

OUT

ON OF F

*

05151 I2 switched OFF (I2 OFF)


OUT

ON OF F

05152 I2 is BLOCKED (I2 BLOCKED)


OUT

05153 I2 is ACTIVE (I2 ACTIVE)


05156 Unbalanced load: Current warning stage (I2> Warn)

7UM62 Manual C53000-G1176-C149-3

M

Chatter Blocking

BO

Binary Output

GI

Function Key

1

Binary Input

34

LED

71

Event Log On/Off

Information-No

IEC 60870-5-103

Type


Function


Description


F.No.

561

A Appendix


Log-Buffers


Data Unit (ASDU)


LED

BO

70

158

1

GI

05186 Stator earth fault: U0 picked up (U0> picked up)


OUT

*

ON OFF

LED

BO

70

159

2

GI

05187 Stator earth fault: U0 stage TRIP (U0> TRIP)


OUT

*

ON

LED

BO

70

160

2

GI

05188 Stator earth fault: I0 picked up (3I0> picked up)


OUT

*

ON OFF

LED

BO

70

168

2

GI

05189 Earth fault in phase L1 (Uearth L1)


OUT

*

ON OFF

LED

BO

70

169

2

GI



OUT

*

ON OFF

LED

BO

70

170

2

GI



OUT

*

ON OFF

LED

BO

70

171

2

GI

05193 Stator earth fault protection TRIP (S/E/ Stator Earth Fault F TRIP) Protection

OUT

*

ON

LED

BO

70

173

2

GI

05194 Stator earth fault: direction forward (SEF Dir Forward)


OUT

ON OF F

*

LED

BO

70

174

1

GI

05203 >BLOCK frequency protection (>BLOCK Freq.)


SP

*

*

LED BI

BO

05206 >BLOCK stage f1 (>BLOCK f1)


SP

ON OF F

*

LED BI

BO

70

177

1

GI



SP

ON OF F

*

LED BI

BO

70

178

1

GI



SP

ON OF F

*

LED BI

BO

70

179

1

GI



SP

ON OF F

*

LED BI

BO

70

180

1

GI

05211 Frequency protection is OFF (Freq. OFF)


OUT

ON OF F

*

LED

BO

70

181

1

GI

05212 Frequency protection is BLOCKED (Freq. BLOCKED)


OUT

ON OF F

ON OFF

LED

BO

70

182

1

GI

05213 Frequency protection is ACTIVE (Freq. ACTIVE)


OUT

ON OF F

*

LED

BO

70

183

1

GI

05214 Frequency protection undervoltage Blk (Freq UnderV Blk)


OUT

ON OF F

ON OFF

LED

BO

70

184

1

GI

05232 f1 picked up (f1 picked up)


OUT

*

ON OFF

LED

BO

70

230

2

GI

562

M

M

Chatter Blocking

*

Binary Output

ON OF F

Function Key

OUT

Binary Input


LED

05183 Stator earth fault protection is ACTIVE (S/E/F ACTIVE)

Event Log On/Off

Information-No

IEC 60870-5-103

Type


Function


Description


F.No.

7UM62 Manual C53000-G1176-C149-3



Log-Buffers


Data Unit (ASDU)


LED

BO

70

231

2

GI



OUT

*

ON OFF

LED

BO

70

232

2

GI



OUT

*

ON OFF

LED

BO

70

233

2

GI

05236 f1 TRIP (f1 TRIP)


OUT

*

ON

M

LED

BO

70

234

2

GI



OUT

*

ON

M

LED

BO

70

235

2

GI



OUT

*

ON

M

LED

BO

70

236

2

GI



OUT

*

ON

M

LED

BO

70

237

2

GI

05293 >BLOCK DC protection (>BLOCK DC Prot.)


SP

*

*

LED BI

BO

05301 DC protection is switched OFF (DC Prot. OFF)


OUT

ON OF F

*

LED

BO

71

181

1

GI

05302 DC protection is BLOCKED (DC Prot.BLOCKED)


OUT

ON OF F

ON OFF

LED

BO

71

182

1

GI

05303 DC protection is ACTIVE (DC Prot. ACTIVE)


OUT

ON OF F

*

LED

BO

71

183

1

GI

05306 DC protection picked up (DC Prot.pick.up)


OUT

*

ON OFF

LED

BO

71

186

2

GI

05307 DC protection TRIP (DC Prot. TRIP)


OUT

*

ON

LED

BO

71

187

2

GI

05308 Failure DC protection (Failure DC Prot)


OUT

ON OF F

*

LED

BO

71

184

1

GI

05323 >BLOCK underexcitation protection (>Exc. BLOCK)


SP

*

*

LED BI

BO

05327 >BLOCK underexc. prot. char. 3 (>Char. 3 BLK.)


SP

ON OF F

*

LED BI

BO

71

53

1

GI

05328 >Exc. voltage failure recognized (>Uexc fail.)


SP

ON OF F

*

LED BI

BO

71

54

1

GI



SP

ON OF F

*

LED BI

BO

71

64

1

GI



SP

ON OF F

*

LED BI

BO

71

65

1

GI

7UM62 Manual C53000-G1176-C149-3

Chatter Blocking

ON OFF

Binary Output

*

Function Key

OUT

Binary Input


LED


Event Log On/Off

Information-No

IEC 60870-5-103

Type


Function


Description


F.No.

563

A Appendix


Log-Buffers


Data Unit (ASDU)


LED

BO

71

55

1

GI

05332 Underexc. prot. is BLOCKED (Excit.BLOCKED)


OUT

ON OF F

ON OFF

LED

BO

71

56

1

GI

05333 Underexc. prot. is ACTIVE (Excit.ACTIVE)


OUT

ON OF F

*

LED

BO

71

57

1

GI

05334 Underexc. prot. blocked by U< (Exc. U< blk)


OUT

ON OF F

ON OFF

LED

BO

71

58

1

GI

05336 Exc. voltage failure recognized (Uexc failure)


OUT

*

ON OFF

LED

BO

71

59

2

GI

05337 Underexc. prot. picked up (Exc< pikked up)


OUT

*

ON OFF

LED

BO

71

60

2

GI

05343 Underexc. prot. char. 3 TRIP (Exc<3 TRIP)


OUT

*

ON

M

LED

BO

71

63

2

GI



OUT

*

ON

M

LED

BO

71

66

2

GI



OUT

*

ON

M

LED

BO

71

67

2

GI

05346 Underexc. prot. char.+Uexc< TRIP (Exc

OUT

*

ON

M

LED

BO

71

68

2

GI

05353 >BLOCK overexcitation protection (>U/f BLOCK)


SP

*

*

LED BI

BO

05357 >Reset memory of thermal replica U/f (>RM th.rep. U/f)


SP

ON OF F

*

LED BI

BO

05361 Overexcitation prot. is swiched OFF (U/f> OFF)


OUT

ON OF F

*

LED

BO

71

83

1

GI

05362 Overexcitation prot. is BLOCKED (U/ f> BLOCKED)


OUT

ON OF F

ON OFF

LED

BO

71

84

1

GI

05363 Overexcitation prot. is ACTIVE (U/f> ACTIVE)


OUT

ON OF F

*

LED

BO

71

85

1

GI

05367 Overexc. prot.: U/f warning stage (U/f> warn)


OUT

ON OF F

*

LED

BO

71

86

1

GI

05369 Reset memory of thermal replica U/f (RM th.rep. U/f)


OUT

ON OF F

*

LED

BO

71

88

1

GI

05370 Overexc. prot.: U/f> picked up (U/f> picked up)


OUT

*

ON OFF

LED

BO

71

89

2

GI

05371 Overexc. prot.: TRIP of U/f>> stage (U/f>> TRIP)


OUT

*

ON

LED

BO

71

90

2

GI

564

M

Chatter Blocking

*

Binary Output

ON OF F

Function Key

OUT

Binary Input


LED

05331 Underexc. prot. is switched OFF (Excit. OFF)

Event Log On/Off

Information-No

IEC 60870-5-103

Type


Function


Description


F.No.

7UM62 Manual C53000-G1176-C149-3



Log-Buffers


Data Unit (ASDU)


LED

BO

71

91

2

GI

05373 Overexc. prot.: U/f>> picked up (U/f>> pick.up)


OUT

*

ON OFF

LED

BO

71

92

2

GI

05381 >BLOCK rotor earth fault prot. (1-3Hz) (>REF 1-3Hz BLK)


SP

*

*

LED BI

BO

05383 >BLOCK rotor earth fault prot. (R,fn) (>BLOCK R/E/F)


SP

*

*

LED BI

BO

05386 >Test rotor earth fault prot. (1-3Hz) (>Test REF 1-3Hz)


SP

ON OF F

*

LED BI

BO

71

116

1

GI

05387 REF protection (1-3Hz) is switched OFF (REF 1-3Hz OFF)


OUT

ON OF F

*

LED

BO

71

117

1

GI

05388 REF protection (1-3Hz) is BLOCKED (REF 1-3Hz BLK)


OUT

ON OF F

ON OFF

LED

BO

71

118

1

GI

05389 REF protection (1-3Hz) is ACTIVE (REF 1-3Hz ACT)


OUT

ON OF F

*

LED

BO

71

119

1

GI

05391 Rotor earth fault prot. (R,fn) swit. OFF (R/E/F OFF)


OUT

ON OF F

*

LED

BO

71

121

1

GI

05392 Rotor earth fault prot. (R,fn) BLOKKED (R/E/F BLOCKED)


OUT

ON OF F

ON OFF

LED

BO

71

122

1

GI

05393 Rotor earth fault prot. (R,fn) is ACTIVE (R/E/F AKTIVE)


OUT

ON OF F

*

LED

BO

71

123

1

GI

05394 Rot. earth flt. prot. (R,fn) block by U< (R/E/F U< block)


OUT

ON OF F

*

LED

BO

71

124

1

GI

05395 REF protection (1-3Hz) open circuit (REF 1-3Hz open)


OUT

ON OF F

*

LED

BO

71

125

1

GI

05396 Failure R/E/F protection Iee< (Fail. REF Iee<)


OUT

ON OF F

*

LED

BO

71

126

1

GI

05397 Rot. earth flt.prot. (R,fn) Re< warning (R/E/F warning)


OUT

ON OF F

*

LED

BO

71

127

1

GI

05398 Rot. earth flt.prot. (R,fn) Re<< pick.up (R/E/F picked up)


OUT

*

ON OFF

LED

BO

71

128

2

GI

05399 Rotor earth fault prot. (R,fn) Re<< TRIP (R/E/F TRIP)


OUT

*

ON

LED

BO

71

129

2

GI

05400 Failure rotor earth fault prot. (R,fn) (Failure R/E/F)


OUT

ON OF F

*

LED

BO

71

130

1

GI

7UM62 Manual C53000-G1176-C149-3

M

Chatter Blocking

ON

Binary Output

*

Function Key

OUT

Binary Input


LED

05372 Overexc. prot.: TRIP of th. stage (U/f> th.TRIP)

Event Log On/Off

Information-No

IEC 60870-5-103

Type


Function


Description


F.No.

565

A Appendix


Log-Buffers


Data Unit (ASDU)


LED

BO

71

131

1

GI

05403 REF prot. (1-3Hz): warning stage (Re<) (REF 1-3Hz Warn)


OUT

ON OF F

*

LED

BO

71

133

1

GI

05406 REF prot. (1-3Hz) Re<< picked up (REF 1-3Hz Fault)


OUT

*

ON OFF

LED

BO

71

136

2

GI

05407 REF prot. (1-3Hz) Re<< TRIP (REF 1- Rotor Earth Fault 3Hz Trip) Protection (1-3Hz)

OUT

*

ON

LED

BO

71

137

2

GI

05408 REF prot. (1-3Hz) test passed (Test REF PASSED)


OUT

ON OF F

*

LED

BO

71

138

1

GI

05409 REF prot. (1-3Hz) test NOT passed (Test REF Fail.)


OUT

ON OF F

*

LED

BO

71

139

1

GI

05410 REF (1-3Hz) 1 Measuring circuit open (1 Cir. open)


OUT

ON OF F

*

LED

BO

05411 REF (1-3Hz) 2 Measuring circuits open (2 Cir. open)


OUT

ON OF F

*

LED

BO

05473 >BLOCK Stator earth fault protection (>SEF100 BLOCK)

100% Stator-EarthFault Protection

SP

*

*

LED BI

BO

05476 >Failure 20Hz bias voltage (S/E/F) (>U20 failure)


SP

ON OF F

*

LED BI

BO

71

227

1

GI

05481 S/E/F 100% protection is switched OFF (SEF100 OFF)


OUT

ON OF F

*

LED

BO

71

228

1

GI

05482 Stator earth flt. prot. 100% is BLOKKED (SEF100 BLOCKED)


OUT

ON OF F

ON OFF

LED

BO

71

229

1

GI

05483 Stator earth flt. prot. 100% is ACTIVE (SEF100 ACTIVE)


OUT

ON OF F

*

LED

BO

71

230

1

GI

05486 Failure stator earth flt. prot. 100% (Failure SEF)


OUT

ON OF F

*

LED

BO

71

231

1

GI

05487 Stator earth flt. prot.100% Alarm stage (SEF100 Alarm)


OUT

ON OF F

*

LED

BO

71

232

1

GI

05488 Stator earth flt. prot.100%: picked up (SEF100 PICKUP)


OUT

*

ON OFF

LED

BO

71

233

2

GI

05489 Stator earth flt. prot.100%: TRIP (SEF100 TRIP)


OUT

*

ON

LED

BO

71

234

2

GI

05503 >BLOCK Rate-of-frequency-change prot. (>df/dt block)

Rate-of-frequencychange protection

SP

*

*

LED BI

BO

566

Chatter Blocking

*

Binary Output

ON OF F

Function Key

OUT

Binary Input


LED

05401 Failure REF protection (1-3Hz) (Fail REF 1-3Hz)

Event Log On/Off

Information-No

IEC 60870-5-103

Type


Function


Description


F.No.

7UM62 Manual C53000-G1176-C149-3



Log-Buffers


Data Unit (ASDU)


LED BI

BO

72

1

1

GI

05505 >BLOCK df2/dt stage (>df2/dt block)


SP

ON OF F

*

LED BI

BO

72

2

1

GI



SP

ON OF F

*

LED BI

BO

72

3

1

GI



SP

ON OF F

*

LED BI

BO

72

4

1

GI

05511 df/dt is switched OFF (df/dt OFF)


OUT

ON OF F

*

LED

BO

72

5

1

GI

05512 df/dt is BLOCKED (df/dt BLOCKED)


OUT

ON OF F

ON OFF

LED

BO

72

6

1

GI

05513 df/dt is ACTIVE (df/dt ACTIVE)


OUT

ON OF F

*

LED

BO

72

7

1

GI

05514 df/dt is blocked by undervoltage (df/dt U< block)


OUT

ON OF F

ON OFF

LED

BO

72

8

1

GI

05516 Stage df1/dt picked up (df1/dt pickup)


OUT

*

ON OFF

LED

BO

72

9

2

GI



OUT

*

ON OFF

LED

BO

72

10

2

GI



OUT

*

ON OFF

LED

BO

72

11

2

GI



OUT

*

ON OFF

LED

BO

72

12

2

GI

05520 Stage df1/dt TRIP (df1/dt TRIP)


OUT

*

ON

LED

BO

72

13

2

GI



OUT

*

ON

LED

BO

72

14

2

GI



OUT

*

ON

LED

BO

72

15

2

GI



OUT

*

ON

LED

BO

72

16

2

GI

05533 >BLOCK inadvertent energ. prot. (>BLOCK I.En.)


SP

*

*

LED BI

BO

05541 Inadvert. Energ. prot. is swiched OFF (I.En. OFF)


OUT

ON OF F

*

LED

BO

72

31

1

GI

05542 Inadvert. Energ. prot. is BLOCKED (I.En. BLOCKED)


OUT

ON OF F

ON OFF

LED

BO

72

32

1

GI

7UM62 Manual C53000-G1176-C149-3

Chatter Blocking

*

Binary Output

ON OF F

Function Key

SP

Binary Input


LED


Event Log On/Off

Information-No

IEC 60870-5-103

Type


Function


Description


F.No.

567

A Appendix


Log-Buffers


Data Unit (ASDU)


LED

BO

72

33

1

GI

05546 Release of the current stage (I.En. release)


OUT

ON OF F

*

LED

BO

72

34

1

GI

05547 Inadvert. Energ. prot.: picked up (I.En. picked up)


OUT

*

ON OFF

LED

BO

72

35

2

GI

05548 Inadvert. Energ. prot.: TRIP (I.En. TRIP)


OUT

*

ON

LED

BO

72

36

2

GI

05553 >BLOCK SEF with 3.Harmonic (>SEF 3H BLOCK)


SP

*

*

LED BI

BO

05561 SEF with 3.Harm. is switched OFF (SEF 3H OFF)


OUT

ON OF F

*

LED

BO

72

51

1

GI

05562 SEF with 3.Harm. is BLOCKED (SEF 3H BLOCK)


OUT

ON OF F

ON OFF

LED

BO

72

52

1

GI

05563 SEF with 3.Harm. is ACTIVE (SEF 3H ACTIVE)


OUT

ON OF F

*

LED

BO

72

53

1

GI

05567 SEF with 3.Harm.: picked up (SEF 3H pick.up)


OUT

*

ON OFF

LED

BO

72

54

2

GI

05568 SEF with 3.Harm.: TRIP (SEF 3H TRIP)


OUT

*

ON

LED

BO

72

55

2

GI

05571 >BLOCK startup O/C protection (>BLOCK O/C St)


SP

*

*

LED BI

BO

05572 Startup O/C protection is switched OFF (O/C Start OFF)


OUT

ON OF F

*

LED

BO

72

62

1

GI

05573 Startup O/C protection is BLOCKED (O/C Start BLK)


OUT

ON OF F

ON OFF

LED

BO

72

63

1

GI

05574 Startup O/C protection is ACTIVE (O/ C Start ACT)


OUT

ON OF F

*

LED

BO

72

64

1

GI

05575 Startup O/C phase L1 picked up (O/C Start L1 PU)


OUT

*

ON OFF

LED

BO

72

65

2

GI



OUT

*

ON OFF

LED

BO

72

66

2

GI



OUT

*

ON OFF

LED

BO

72

67

2

GI

05578 Startup O/C protection TRIP (O/C Start TRIP)


OUT

*

ON

LED

BO

72

68

2

GI

568

M

M

Chatter Blocking

*

Binary Output

ON OF F

Function Key

OUT

Binary Input


LED

05543 Inadvert. Energ. prot. is ACTIVE (I.En. ACTIVE)

Event Log On/Off

Information-No

IEC 60870-5-103

Type


Function


Description


F.No.

7UM62 Manual C53000-G1176-C149-3




Data Unit (ASDU)


*

LED BI

BO

05582 Vector Jump is switched OFF (VEC JUMP OFF)


OUT

ON OF F

*

LED

BO

72

72

1

GI

05583 Vector Jump is BLOCKED (VEC JMP BLOCKED)


OUT

ON OF F

ON OFF

LED

BO

72

73

1

GI

05584 Vector Jump is ACTIVE (VEC JUMP ACTIVE)


OUT

ON OF F

*

LED

BO

72

74

1

GI

05585 Vector Jump not in measurement range (VEC JUMP Range)


OUT

ON OF F

*

LED

BO

72

75

1

GI

05586 Vector Jump picked up (VEC JUMP pickup)


OUT

*

ON OFF

LED

BO

72

76

2

GI

05587 Vector Jump TRIP (VEC JUMP TRIP)


OUT

*

ON

LED

BO

72

77

2

GI

05603 >BLOCK differential protection (>Diff BLOCK)


SP

*

*

LED BI

BO

05615 Differential protection is switched OFF (Diff OFF)


OUT

ON OF F

*

LED

BO

75

15

1

GI

05616 Differential protection is BLOCKED (Diff BLOCKED)


OUT

ON OF F

ON OFF

LED

BO

75

16

1

GI

05617 Differential protection is ACTIVE (Diff ACTIVE)


OUT

ON OF F

*

LED

BO

75

17

1

GI

05620 Diff: adverse Adaption factor CT (Diff Adap.fact.)


OUT

ON

*

LED

BO

05631 Differential protection picked up (Diff picked up)


OUT

*

ON OFF

LED

BO

75

31

2

GI

05644 Diff: Blocked by 2.Harmon. L1 (Diff 2.Harm L1)


OUT

*

ON OFF

LED

BO

75

44

2

GI



OUT

*

ON OFF

LED

BO

75

45

2

GI



OUT

*

ON OFF

LED

BO

75

46

2

GI

05647 Diff: Blocked by n.Harmon. L1 (Diff n.Harm L1)


OUT

*

ON OFF

LED

BO

75

47

2

GI



OUT

*

ON OFF

LED

BO

75

48

2

GI



OUT

*

ON OFF

LED

BO

75

49

2

GI

05651 Diff. prot.: Blocked by ext. fault L1 (Diff Bl. exF.L1)


OUT

*

ON OFF

LED

BO

75

51

2

GI

7UM62 Manual C53000-G1176-C149-3

M

Chatter Blocking

*

Binary Output

SP

Function Key


Binary Input

05581 >BLOCK Vector Jump (>VEC JUMP block)

LED

Information-No

IEC 60870-5-103

Type


Log-Buffers


Function


Description

Event Log On/Off

F.No.

569

A Appendix


Log-Buffers


Data Unit (ASDU)


LED

BO

75

52

2

GI

05653 Diff. prot.: Blocked by ext. fault.L3 (Diff Bl. exF.L3)


OUT

*

ON OFF

LED

BO

75

53

2

GI

05657 Diff: Crossblock by 2.Harmonic (DiffCrosBlk2HM)


OUT

*

ON OFF

LED

BO

05658 Diff: Crossblock by n.Harmonic (DiffCrosBlknHM)


OUT

*

ON OFF

LED

BO

05666 Diff: Increase of char. phase L1 (Diff in.char.L1)


OUT

ON OF F

ON OFF

LED

BO



OUT

ON OF F

ON OFF

LED

BO



OUT

ON OF F

ON OFF

LED

BO

05670 Diff: Curr-Release for Trip (Diff IRelease)


OUT

*

ON OFF

LED

BO

05671 Differential protection TRIP (Diff TRIP)


OUT

*

*

LED

BO

75

71

1

GI

05672 Differential protection: TRIP L1 (Diff TRIP L1)


OUT

*

*

LED

BO

75

72

1

GI



OUT

*

*

LED

BO

75

73

1

GI



OUT

*

*

LED

BO

75

74

1

GI

05681 Diff. prot.: IDIFF> L1 (without Tdelay) (Diff> L1)


OUT

*

ON OFF

LED

BO

75

81

2

GI



OUT

*

ON OFF

LED

BO

75

82

2

GI



OUT

*

ON OFF

LED

BO

75

83

2

GI

05684 Diff. prot: IDIFF>> L1 (without Tdelay) (Diff>> L1)


OUT

*

ON OFF

LED

BO

75

84

2

GI



OUT

*

ON OFF

LED

BO

75

85

2

GI



OUT

*

ON OFF

LED

BO

75

86

2

GI

05691 Differential prot.: TRIP by IDIFF> (Diff> TRIP)


OUT

*

ON

M

LED

BO

75

91

2

GI

05692 Differential prot.: TRIP by IDIFF>> (Diff>> TRIP)


OUT

*

ON

M

LED

BO

75

92

2

GI

05701 Diff. current in phase L1 at trip (Diff L1:)


OUT

*

ON OFF

75

101

4

570

Chatter Blocking

ON OFF

Binary Output

*

Function Key

OUT

Binary Input


LED

05652 Diff. prot.: Blocked by ext. fault L2 (Diff Bl. exF.L2)

Event Log On/Off

Information-No

IEC 60870-5-103

Type


Function


Description


F.No.

7UM62 Manual C53000-G1176-C149-3



IEC 60870-5-103

Information-No

Data Unit (ASDU)

ON OFF

75

102

4



OUT

*

ON OFF

75

103

4

05704 Restr. current in phase L1 at trip (Res L1:)


OUT

*

ON OFF

75

104

4



OUT

*

ON OFF

75

105

4



OUT

*

ON OFF

75

106

4

05713 Diff. prot: Adaptation factor CT side 1 (Diff CT-S1:)


OUT

ON OF F

05714 Diff. prot: Adaptation factor CT side 2 (Diff CT-S2:)


OUT

ON OF F

05803 >BLOCK restricted earth fault prot. (>BLOCK REF)


SP

*

*

LED BI

BO

05811 Restricted earth fault is switched OFF (REF OFF)


OUT

ON OF F

*

LED

BO

76

11

1

GI

05812 Restricted earth fault is BLOCKED (REF BLOCKED)


OUT

ON OF F

ON OFF

LED

BO

76

12

1

GI

05813 Restricted earth fault is ACTIVE (REF ACTIVE)


OUT

ON OF F

*

LED

BO

76

13

1

GI

05817 REF protection picked up (REF picked up)


OUT

*

ON OFF

LED

BO

76

17

2

GI

05821 REF protection TRIP (REF TRIP)


OUT

*

ON

LED

BO

76

21

2

GI

05836 REF: adverse Adaption factor CT (REF Adap.fact.)


OUT

ON

*

LED

BO

05840 REF is blocked by phase current (REF I> blocked)


OUT

ON OF F

*

LED

BO

76

40

1

GI

05841 REF Release by U0> (REF U0> releas.)


OUT

ON OF F

*

LED

BO

76

41

1

GI

05847 I0-Diff at REF-Trip (I0-Diff:)


OUT

*

ON OFF

76

47

4

05848 I0-Restraint at REF-Trip (I0-Res:)


OUT

*

ON OFF

76

48

4

06503 >BLOCK undervoltage protection (>BLOCK U/V)


SP

*

*

7UM62 Manual C53000-G1176-C149-3

LED BI

Chatter Blocking

*

Binary Output

OUT

Function Key


Binary Input


LED

Type


Log-Buffers




Function


Description

Event Log On/Off

F.No.

BO

571

A Appendix


Log-Buffers


Data Unit (ASDU)


LED BI

BO

74

6

1

GI

06508 >BLOCK undervoltage protection U<< (>BLOCK U<<)


SP

ON OF F

*

LED BI

BO

74

8

1

GI

06513 >BLOCK overvoltage protection (>BLOCK O/V)

Overvoltage Protec- SP tion

*

*

LED BI

BO

06516 >BLOCK overvoltage protection U> (>BLOCK U>)


ON OF F

*

LED BI

BO

74

20

1

GI

06517 >BLOCK overvoltage protection U>> (>BLOCK U>>)


ON OF F

*

LED BI

BO

74

21

1

GI

Chatter Blocking

*

Binary Output

ON OF F

Function Key

SP

Binary Input


LED

06506 >BLOCK undervoltage protection U< (>BLOCK U<)

Event Log On/Off

Information-No

IEC 60870-5-103

Type


Function


Description


F.No.

06520 >BLOCK inverse undervoltage protec- Inverse Undervoltion (>BLOCK Up<) tage Protection

SP

*

*

LED BI

BO

06522 Inv. Undervoltage prot. is switched OFF (Up< OFF)


OUT

ON OF F

*

LED

BO

74

95

1

GI

06523 Inv. Undervoltage protection is BLOKKED (Up< BLOCK)


OUT

ON OF F

ON OFF

LED

BO

74

96

1

GI

06524 Inv. Undervoltage protection is ACTIVE (Up< ACTIVE)


OUT

ON OF F

*

LED

BO

74

97

1

GI

06525 Inverse Undervoltage Up< picked up (Up< picked up)


OUT

*

ON OFF

LED

BO

74

98

2

GI

06526 Inv. Undervoltage Up<-char. picked up (Up< ch. pick.up)


OUT

*

ON OFF

LED

BO

74

99

2

GI

06527 Inverse Undervoltage Up< TRIP (Up< AUS)


OUT

*

ON

LED

BO

74

100

2

GI

06530 Undervoltage protection switched OFF (Undervolt. OFF)


OUT

ON OF F

*

LED

BO

74

30

1

GI

06531 Undervoltage protection is BLOCKED (Undervolt. BLK)


OUT

ON OF F

ON OFF

LED

BO

74

31

1

GI

06532 Undervoltage protection is ACTIVE (Undervolt. ACT)


OUT

ON OF F

*

LED

BO

74

32

1

GI

06533 Undervoltage U< picked up (U< pikked up)


OUT

*

ON OFF

LED

BO

74

33

2

GI

06537 Undervoltage U<< picked up (U<< pik- Undervoltage Proked up) tection

OUT

*

ON OFF

LED

BO

74

37

2

GI

06539 Undervoltage U< TRIP (U< TRIP)


OUT

*

ON

M

LED

BO

74

39

2

GI

06540 Undervoltage U<< TRIP (U<< TRIP)


OUT

*

ON

M

LED

BO

74

40

2

GI

572

7UM62 Manual C53000-G1176-C149-3



Log-Buffers


Data Unit (ASDU)


BO

74

65

1

GI

06566 Overvoltage protection is BLOCKED (Overvolt. BLK)

Overvoltage Protec- OUT tion

ON OF F

ON OFF

LED

BO

74

66

1

GI

06567 Overvoltage protection is ACTIVE (Overvolt. ACT)


ON OF F

*

LED

BO

74

67

1

GI

06568 Overvoltage U> picked up (U> picked up)


*

ON OFF

LED

BO

74

68

2

GI

06570 Overvoltage U> TRIP (U> TRIP)


*

ON

LED

BO

74

70

2

GI

06571 Overvoltage U>> picked up (U>> pikked up)


*

ON OFF

LED

BO

74

71

2

GI

06573 Overvoltage U>> TRIP (U>> TRIP)


*

ON

LED

BO

74

73

2

GI

06575 Voltage Transformer Fuse Failure (VT Fuse Failure)

Supervision

OUT

ON OF F

*

LED

BO

74

74

1

GI

06801 >BLOCK Motor Starting Supervision (>BLK START-SUP)


SP

*

*

LED BI

BO

06805 >Rotor is locked (>Rotor locked)


SP

ON OF F

*

LED BI

BO

06811 Starting time supervision switched OFF (START-SUP OFF)


OUT

ON OF F

*

LED

BO

169

51

1

GI

06812 Starting time supervision is BLOCKED (START-SUP BLK)


OUT

ON OF F

ON OFF

LED

BO

169

52

1

GI

06813 Starting time supervision is ACTIVE (START-SUP ACT)


OUT

ON OF F

*

LED

BO

169

53

1

GI

06821 Starting time supervision TRIP (START-SUP TRIP)


OUT

*

ON

LED

BO

169

54

2

GI

06822 Rotor is LOCKED after Locked Rotor Time (Rotor locked)


OUT

*

ON

LED

BO

169

55

2

GI

06823 Starting time supervision picked up (START-SUP PU)


OUT

ON OF F

*

LED

BO

169

56

1

GI

06851 >BLOCK Trip circuit supervision (>BLOCK TripC)

Trip Circuit Supervi- SP sion

*

*

LED BI

BO

06852 >Trip circuit supervision: trip relay (>TripC trip rel)


ON OF F

*

LED BI

BO

170

51

1

GI

7UM62 Manual C53000-G1176-C149-3

M

M

Chatter Blocking

LED

Binary Output

*

Function Key

ON OF F

Binary Input


LED

06565 Overvoltage protection switched OFF (Overvolt. OFF)

Event Log On/Off

Information-No

IEC 60870-5-103

Type


Function


Description


F.No.

573

A Appendix


Log-Buffers


Data Unit (ASDU)


BO

170

52

1

GI

06861 Trip circuit supervision OFF (TripC OFF)

Trip Circuit Supervi- OUT sion

ON OF F

*

LED

BO

170

53

1

GI

06862 Trip circuit supervision is BLOCKED (TripC BLOCKED)


ON OF F

ON OFF

LED

BO

153

16

1

GI

06863 Trip circuit supervision is ACTIVE (TripC ACTIVE)


ON OF F

*

LED

BO

153

17

1

GI

06864 Trip Circuit blk. Bin. input is not set (TripC ProgFail)


ON OF F

*

LED

BO

170

54

1

GI

06865 Failure Trip Circuit (FAIL: Trip cir.)


ON OF F

*

LED

BO

170

55

1

GI

07960 Measured Value MV1> picked up (Meas. Value1>)


OUT

*

*

LED

BO

07961 Measured Value MV2< picked up (Meas. Value2<)


OUT

*

*

LED

BO



OUT

*

*

LED

BO



OUT

*

*

LED

BO



OUT

*

*

LED

BO



OUT

*

*

LED

BO

14101 Fail: RTD (broken wire/shorted) (Fail: RTD)

RTD-Box

OUT

ON OF F

*

LED

BO

14111 Fail: RTD 1 (broken wire/shorted) (Fail: RTD 1)

RTD-Box

OUT

ON OF F

*

LED

BO

14112 RTD 1 Temperature stage 1 picked up (RTD 1 St.1 p.up)

RTD-Box

OUT

ON OF F

*

LED

BO


RTD-Box

OUT

ON OF F

*

LED

BO


RTD-Box

OUT

ON OF F

*

LED

BO


RTD-Box

OUT

ON OF F

*

LED

BO

574

Chatter Blocking

LED BI

Binary Output

*

Function Key

ON OF F

Binary Input


LED

06853 >Trip circuit supervision: breaker relay (>TripC brk rel.)

Event Log On/Off

Information-No

IEC 60870-5-103

Type


Function


Description


F.No.

7UM62 Manual C53000-G1176-C149-3



RTD-Box

OUT

ON OF F

*

LED

BO


RTD-Box

OUT

ON OF F

*

LED

BO


RTD-Box

OUT

ON OF F

*

LED

BO


RTD-Box

OUT

ON OF F

*

LED

BO


RTD-Box

OUT

ON OF F

*

LED

BO


RTD-Box

OUT

ON OF F

*

LED

BO


RTD-Box

OUT

ON OF F

*

LED

BO


RTD-Box

OUT

ON OF F

*

LED

BO


RTD-Box

OUT

ON OF F

*

LED

BO


RTD-Box

OUT

ON OF F

*

LED

BO


RTD-Box

OUT

ON OF F

*

LED

BO


RTD-Box

OUT

ON OF F

*

LED

BO


RTD-Box

OUT

ON OF F

*

LED

BO


RTD-Box

OUT

ON OF F

*

LED

BO


RTD-Box

OUT

ON OF F

*

LED

BO


RTD-Box

OUT

ON OF F

*

LED

BO

7UM62 Manual C53000-G1176-C149-3


Data Unit (ASDU)

Information-No

IEC 60870-5-103

Type

Chatter Blocking

Binary Output

Function Key

Binary Input



Log-Buffers

LED



Function


Description

Event Log On/Off

F.No.

575

A Appendix


RTD-Box

OUT

ON OF F

*

LED

BO


RTD-Box

OUT

ON OF F

*

LED

BO


RTD-Box

OUT

ON OF F

*

LED

BO


RTD-Box

OUT

ON OF F

*

LED

BO


RTD-Box

OUT

ON OF F

*

LED

BO


RTD-Box

OUT

ON OF F

*

LED

BO

14201 Fail: RTD10 (broken wire/shorted) (Fail: RTD10)

RTD-Box

OUT

ON OF F

*

LED

BO

14202 RTD10 Temperature stage 1 picked up (RTD10 St.1 p.up)

RTD-Box

OUT

ON OF F

*

LED

BO


RTD-Box

OUT

ON OF F

*

LED

BO


RTD-Box

OUT

ON OF F

*

LED

BO


RTD-Box

OUT

ON OF F

*

LED

BO


RTD-Box

OUT

ON OF F

*

LED

BO


RTD-Box

OUT

ON OF F

*

LED

BO


RTD-Box

OUT

ON OF F

*

LED

BO


RTD-Box

OUT

ON OF F

*

LED

BO

30607 Accumulation of interrupted curr. L1 S1 (ΣIL1 S1:)

Statistics

OUT


Statistics

OUT

576


Data Unit (ASDU)

Information-No

IEC 60870-5-103

Type

Chatter Blocking

Binary Output

Function Key

Binary Input



Log-Buffers

LED



Function


Description

Event Log On/Off

F.No.

7UM62 Manual C53000-G1176-C149-3



Log-Buffers


Data Unit (ASDU)


OUT


Statistics

OUT


Statistics

OUT

>Back Light on (>Light on)

Device

SP

ON OF F

*

LED BI

BO

Clock Synchronization (SynchClock)

Device

IntSP_ Ev

*

*

LED

BO

Control Authority (Cntrl Auth)

Control Authorization

IntSP

ON OF F

*

LED

101

85

1

GI

Controlmode LOCAL (ModeLOCAL)


IntSP

ON OF F

*

LED

101

86

1

GI

Controlmode REMOTE (ModeREMOTE)


IntSP

ON OF F

*

LED

Error Systeminterface (SysIntErr.)

Protocol

IntSP

ON OF F

*

LED

BO

Fault Recording Start (FltRecSta)


IntSP

ON OF F

*

LED

BO

Group A (Group A)

Change Group

IntSP

ON OF F

*

LED

BO

70

23

1

GI

Group B (Group B)

Change Group

IntSP

ON OF F

*

LED

BO

70

24

1

GI

Hardware Test Mode (HWTestMod)

Device

IntSP

ON OF F

*

LED

BO

Stop data transmission (DataStop)

Device

IntSP

ON OF F

*

LED

BO

70

20

1

GI

Test mode (Test mode)

Device

IntSP

ON OF F

*

LED

BO

70

21

1

GI

Unlock data transmission via BI (UnlockDT)

Device

IntSP

7UM62 Manual C53000-G1176-C149-3

Chatter Blocking

Statistics

Binary Output


Function Key

OUT

Binary Input

Statistics

LED


Event Log On/Off

Information-No

IEC 60870-5-103

Type


Function


Description


F.No.

577

A Appendix

A.14 List of Measured Values

Position

CFC

Control Display

Default Display


Data Unit (ASDU)

IEC 60870-5-103

Compatibility

Function

Information-No

Description

Function type

F.No.

00605

I1 (positive sequence) (I1 =)

Measurement

134

147

priv

9

5

CFC

CD

DD

00606

I2 (negative sequence) (I2 =)

Measurement

134

147

priv

9

6

CFC

CD

DD

00621

U L1-E (UL1E=)

Measurement

134

147

priv

9

7

CFC

CD

DD

00622

U L2-E (UL2E=)

Measurement

134

147

priv

9

8

CFC

CD

DD

00623

U L3-E (UL3E=)

Measurement

134

147

priv

9

9

CFC

CD

DD

00624

U L12 (UL12=)

Measurement

CFC

CD

DD

00625

U L23 (UL23=)

Measurement

CFC

CD

DD

00626

U L31 (UL31=)

Measurement

CFC

CD

DD

00627

Displacement voltage UE (UE =)

Measurement

134

147

priv

9

10

CFC

CD

DD

00629

U1 (positive sequence) (U1 =)

Measurement

134

147

priv

9

11

CFC

CD

DD

00630

U2 (negative sequence) (U2 =)

Measurement

CFC

CD

DD

00639

UE 3rd Harmonic Voltage Minimum (UE3h min=)


CFC

CD

DD

00640

UE 3rd Harmonic Voltage Maximum (UE3h max=)


CFC

CD

DD

00641

P (active power) (P =)

Measurement

134

147

priv

9

12

CFC

CD

DD

00642

Q (reactive power) (Q =)

Measurement

134

147

priv

9

13

CFC

CD

DD

00644

Frequency (Freq=)

Measurement

134

147

priv

9

15

CFC

CD

DD

00645

S (apparent power) (S =)

Measurement

CFC

CD

DD

00650

UE 3rd harmonic (UE3h =)

Measurement

CFC

CD

DD

00660

Remaining Time for Switch ON (T Rem.=)

Thermal Measurement

CFC

CD

DD

00661

Threshold of Restart Inhibit (Θ REST. =)

Thermal Measurement

CFC

CD

DD

578

7UM62 Manual C53000-G1176-C149-3


IEC 60870-5-103

CFC

CD

DD

00693

REF(R,fn): Total Resistance (R total) (Rtot =)

Measurement

CFC

CD

DD

00696

REF(R,fn): Total Reactance (X total) (Xtot =)

Measurement

CFC

CD

DD

00697

REF(R,fn): Phase Angle of Z total (ϕ Ztot=)

Measurement

CFC

CD

DD

00700

REF(R,fn): Fault Resistance (R earth) (Re =)

Measurement

134

148

priv

9

5

CFC

CD

DD

00721

Operat. meas. current L1 side 1 [%] is (IL1S1=)

Measurement

134

148

priv

9

1

CFC

CD

DD

00722


Measurement

134

148

priv

9

2

CFC

CD

DD

00723


Measurement

134

148

priv

9

3

CFC

CD

DD

00724


Measurement

134

147

priv

9

1

CFC

CD

DD

00725


Measurement

134

147

priv

9

2

CFC

CD

DD

00726


Measurement

134

147

priv

9

3

CFC

CD

DD

00755

REF(1-3Hz): Freq. of square-wave gen. (fgen =)

Measurement

CFC

CD

DD

00757

REF(1-3Hz): Volt. of square-wave gen. (Ugen =)

Measurement

CFC

CD

DD

00758

REF(1-3Hz): Curr. of rotor meas. circuit (Imeas. =)

Measurement

CFC

CD

DD

00759

REF(1-3 Hz): Charge at polarity rev.(Qc) (Qc =)

Measurement

CFC

CD

DD

00760

SEF100%: Prim. stator earth resistance (RSEFp=)

Measurement

CFC

CD

DD

00761

REF(1-3Hz): Fault Resistance (R earth) (R earth=)

Measurement

CFC

CD

DD

00762

SEF100%: Bias volt. for stator circuit (U SEF=)

Measurement

CFC

CD

DD

00763

SEF100%: Earth curr. in stator circuit (I SEF=)

Measurement

CFC

CD

DD

00764

SEF100%: Stator earth resistance (R SEF=)

Measurement

134

148

priv

9

7

CFC

CD

DD

00765

(U/Un) / (f/fn) (U/f =)

Measurement

134

147

priv

9

16

CFC

CD

DD

00766

Calculated temperature (U/f) (U/f th. =)

Thermal Measurement

CFC

CD

DD

00801

Temperat. rise for warning and trip (Θ /Θtrip =)

Thermal Measurement

CFC

CD

DD

7UM62 Manual C53000-G1176-C149-3

134

148

priv

9

Position

Measurement

Compatibility

DC Current (I DC =)

Information-No

00662

Function type

Default Display

Configurable in Matrix Control Display

Function

CFC

Description

Data Unit (ASDU)

F.No.

6

579

A Appendix

IEC 60870-5-103

CFC

CD

DD

00803

Temperature rise for phase L2 (Θ /ΘtripL2=)

Thermal Measurement

CFC

CD

DD

00804


Thermal Measurement

CFC

CD

DD

00805

Temperature of Rotor (ΘR/ΘRmax =)

Thermal Measurement

CFC

CD

DD

00828

Senstive Earth Current 1 (IEE1=)

Measurement

134

148

priv

9

4

CFC

CD

DD

00829

Senstive Earth Current 2 (IEE2=)

Measurement

134

147

priv

9

4

CFC

CD

DD

00831

3I0 (zero sequence) (3I0 =)

Measurement

CFC

CD

DD

00832

U0 (zero sequence) (U0 =)

Measurement

CFC

CD

DD

00857

Positive Sequence Minimum (I1 Min=)


CFC

CD

DD

00858

Positive Sequence Maximum (I1 Max=)


CFC

CD

DD

00874

U1 (positive sequence) Voltage Minimum (U1 Min =)


CFC

CD

DD

00875

U1 (positive sequence) Voltage Maximum (U1 Max =)


CFC

CD

DD

00876

Active Power Minimum (PMin=)


CFC

CD

DD

00877

Active Power Maximum (PMax=)


CFC

CD

DD

00878

Reactive Power Minimum (QMin=)


CFC

CD

DD

00879

Reactive Power Maximum (QMax=)


CFC

CD

DD

00882

Frequency Minimum (fMin=)


CFC

CD

DD

580

Position

Thermal Measurement

Compatibility


Information-No

00802

Function type

Default Display


Function

CFC

Description

Data Unit (ASDU)

F.No.

7UM62 Manual C53000-G1176-C149-3


IEC 60870-5-103

Energy

CD

DD

Pulsed Energy Wq (reactive) (Wq(puls))

Energy

CD

DD

00894

DC voltage (U DC =)

Measurement

CFC

CD

DD

00896

REF(R,fn): Injected Voltage (U RE) (U RE =)

Measurement

CFC

CD

DD

00897

REF(R,fn): Curr. in the Circuit (I RE) (I RE =)

Measurement

CFC

CD

DD

00901

Power Factor (PF =)

Measurement

CFC

CD

DD

00902

Power angle (PHI=)

Measurement

CFC

CD

DD

00903

Resistance (R=)

Measurement

CFC

CD

DD

00904

Reactance (X=)

Measurement

CFC

CD

DD

00909

Excitation voltage (Uexcit.=)

Measurement

CFC

CD

DD

00910

Calculated rotor temp. (unbal. load) (ThermRep.=)

Thermal Measurement

CFC

CD

DD

00911

Cooling medium temperature (AMB.TEMP =)

Thermal Measurement

CFC

CD

DD

00924

Wp Forward (Wp+=)

Energy

CD

DD

00925

Wq Forward (Wq+=)

Energy

CD

DD

00928

Wp Reverse (Wp-=)

Energy

CD

DD

00929

Wq Reverse (Wq-=)

Energy

CD

DD

00995

SEF100%: Phase angle in stator circuit (ϕ SEF=)

Measurement

CFC

CD

DD

00996

Transducer 1 (Td1=)

Measurement

CFC

CD

DD

00997

Transducer 2 (Td2=)

Measurement

CFC

CD

DD

00998

Transducer 3 (Td3=)

Measurement

CFC

CD

DD

01068

Temperature of RTD 1 (Θ RTD 1 =)

Thermal Measurement

134

146

priv

9

1

CFC

CD

DD

01069


Thermal Measurement

134

146

priv

9

2

CFC

CD

DD

01070


Thermal Measurement

134

146

priv

9

3

CFC

CD

DD


00888

Pulsed Energy Wp (active) (Wp(puls))

00889

7UM62 Manual C53000-G1176-C149-3

134

147

priv

9

Position

DD

Frequency Maximum (fMax=)

Compatibility

CD

00883

Information-No

CFC

Function type

Default Display


Function

CFC

Description

Data Unit (ASDU)

F.No.

14

581

A Appendix

Position

CFC

Control Display

Default Display


Data Unit (ASDU)

IEC 60870-5-103

Compatibility

Function

Information-No

Description

Function type

F.No.

01071


Thermal Measurement

134

146

priv

9

4

CFC

CD

DD

01072


Thermal Measurement

134

146

priv

9

5

CFC

CD

DD

01073


Thermal Measurement

134

146

priv

9

6

CFC

CD

DD

01074


Thermal Measurement

134

146

priv

9

7

CFC

CD

DD

01075


Thermal Measurement

134

146

priv

9

8

CFC

CD

DD

01076


Thermal Measurement

134

146

priv

9

9

CFC

CD

DD

01077

Temperature of RTD10 (Θ RTD10 =)

Thermal Measurement

134

146

priv

9

10

CFC

CD

DD

01078


Thermal Measurement

134

146

priv

9

11

CFC

CD

DD

01079


Thermal Measurement

134

146

priv

9

12

CFC

CD

DD

07740

Phase angle in phase IL1 side 1 (ϕIL1S1=)

Measurement

CFC

CD

DD

07741


Measurement

CFC

CD

DD

07742

IDiffL1(I/Inominal object [%]) (IDiffL1=)

Diff- and Rest. Measurement

CFC

CD

DD

07743



CFC

CD

DD

07744



CFC

CD

DD

07745

IRestL1(I/Inominal object [%]) (IRestL1=)


CFC

CD

DD

07746



CFC

CD

DD

07747



CFC

CD

DD

582

7UM62 Manual C53000-G1176-C149-3


IEC 60870-5-103

CFC

CD

DD

07750


Measurement

CFC

CD

DD

07759


Measurement

CFC

CD

DD

07760


Measurement

CFC

CD

DD

30654

I0-Diff REF (I/Inominal object [%]) (I0-Diff=)


CFC

DD

30655

I0-Rest REF (I/Inominal object [%]) (I0-Rest=)


CFC

DD

30659

3I0-1 REF (I/Inominal object [%]) (3I0-1 =)


CFC

DD

30660

3I0-2 REF (I/Inominal object [%]) (3I0-2 =)


CFC

DD

IL< under current (IL<)

Set Points (Measured Values)

CFC

Number of TRIPs (#of TRIPs=)

Statistics

Operating hours greater than (OpHour>)

7UM62 Manual C53000-G1176-C149-3

Position

Measurement

Compatibility


Information-No

07749

Function type

Default Display


Function

CFC

Description

Data Unit (ASDU)

F.No.

CD

DD

CD

DD

CD

DD

583

A Appendix

A.15 Protocol-Dependent Functions Protocol →

IEC 60870–5–103 Profibus DP

DNP3.0

Modbus ASCII/RTU Additional interface (optional)

Function ß Operational measured values

Yes

Yes

Yes

Yes

Yes

Metered values

Yes

Yes

Yes

Yes

Yes

Fault recording

Yes

No. Only via additional service interface

Remote relay setting

No. Only via additional service interface

No. Only via addi- No. Only via addi- No. Only via additional Yes tional service inter- tional service inter- service interface face face

User-defined messages and switching objects

Yes

Yes

Yes

Yes

Yes


Via protocol; DCF77/IRIG B; Interface; Binary input

Via DCF77/IRIG B; Interface; Binary input; protocol

Via protocol; DCF77/IRIG B; Interface; Binary input

Via DCF77/IRIG B; Interface; Binary input; protocol

–

No

Yes

No

Yes

• Measured value indica- Yes tion blocking

No

No

No

Yes

• Creating test messages

Yes

No

No

No

Yes

Physical mode

Asynchronous

Asynchronous

Asynchronous

Asynchronous

–

Transmission mode

Cyclically/Event

Cyclically

Cyclically/Event

Cyclically

–

Baudrate

4800 to 38400

Up to 1.5 MBaud

4800 to 19200

2400 to 19200

4800 to 115200

Type

RS232 RS485 Optical fibre

RS485 Optical fibre

RS485 Optical fibre

RS485 Optical fibre

RS232 RS485

Messages with time stamp Yes

No. Only via additional Yes service interface

Commissioning aids

• Double ring

n

584

7UM62 Manual C53000-G1176-C149-3

Corrections To

From

Siemens AG

Name:

Dept. PTD PA D DM D–13623 Berlin

Company/Dept.:

Germany Dear reader, printing errors can never be entirely eliminated: therefore, should you come across any when reading this manual, kindly enter them in this form together with any comments or suggestions for improvement that you may have. Corrections/Suggestions

7UM62 Manual C53000-G1176-C149-3

Address:

Phone no.:

Fax no.:

Subject to technical alteration

Siemens Aktiengesellschaft

Copying of this document and giving it to others and the use or communication of the contents thereof, are forbidden without express authority. Offenders are liable to the payment of damages. All rights are reserved in the event of the grant of a patent or the registration of a utility model or design. Order-no.: C53000-G1176-C149-3 Available from: LZF Fürth-Bislohe Printed in Germany/Imprimé en Allemagne AG 0702 0.1 FO 600 En

7UM62_iec

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