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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.
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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
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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
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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
Functional Description .......................................................................................................... 35
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
Functional Description .......................................................................................................... 36
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
Functional Description .......................................................................................................... 38
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
Functional Description .......................................................................................................... 42
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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
Functional Description .......................................................................................................... 48
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
Functional Description .......................................................................................................... 55
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
Functional Description .......................................................................................................... 65
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
Functional Description .......................................................................................................... 72
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
Functional Description .......................................................................................................... 98
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
Functional Description ........................................................................................................ 115
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
Functional Description ........................................................................................................ 119
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
Functional Description ........................................................................................................ 148
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
Functional Description ........................................................................................................ 151
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
Functional Description ........................................................................................................ 154
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
Functional Description ........................................................................................................ 159
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
Functional Description ........................................................................................................ 164
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
Functional Description ........................................................................................................ 167
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
Functional Description ........................................................................................................ 173
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
Functional Description ........................................................................................................ 177
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
Functional Description ........................................................................................................ 185
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
Functional Description ........................................................................................................ 189
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
Functional Description ........................................................................................................ 194
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
Functional Description ........................................................................................................ 201
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
Functional Description ........................................................................................................ 206
2.31.2 Setting Hints ....................................................................................................................... 211 2.31.2.1 Settings of the Sensitive Rotor Earth Fault Protection........................................................ 212
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2.31.2.2 Information for the Sensitive Earth Fault Protection ........................................................... 212 2.32
Motor Starting Time Supervision (ANSI 48) ....................................................................... 213
2.32.1
Functional Description ........................................................................................................ 213
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
Functional Description ........................................................................................................ 217
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
Functional Description ........................................................................................................ 225
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
Functional Description ........................................................................................................ 230
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
Functional Description ........................................................................................................ 234
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
Functional Description ........................................................................................................ 239
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
Functional Description ........................................................................................................ 254
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
Functional Description ........................................................................................................ 261
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
Functional Description ........................................................................................................ 267
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
Functional Description ........................................................................................................ 270
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
Functional Description ........................................................................................................ 279
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
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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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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) and/or falls below (df/dt> 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 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
-
-
Thermal Overload Protection
ANSI 49
-
-
-
-
Fixed
-
TD2
Negative Sequence Protection
ANSI 46
-
-
-
-
Fixed
-
-
Startup Overcurrent Protection
ANSI 51
-
-
-
-
Fixed
-
-
-
Fixed
-
-
Fixed
-
-
Differential Protection
ANSI 87
Earth Fault Differential Protection
ANSI 87GN/TN
U0 calculated
Selectable
-
-
Selectable
Fixed
-
Underexcitation (Loss-of-Field) Protection
ANSI 40
Fixed
-
-
-
Fixed
-
TD3
Reverse Power Protection
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
Impedance Protection
ANSI 21
Fixed
-
-
-
Fixed
-
-
Out-of-Step Protection
ANSI 78
Fixed
-
-
-
Fixed
-
-
Undervoltage Protection
ANSI 27
Fixed
-
-
-
-
-
-
Overvoltage Protection
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
Motor Starting Time Supervision
ANSI 48
-
-
-
-
Fixed
-
-
Restart Inhibit for Motors
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
Address 0120 DIFF. PROT. = 3-phase Transformer
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
Address 0120 DIFF. PROT. = 3-phase Transformer
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
Differential Protection
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
Thermal Overload Protection
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
Differential Protection
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
Underexcitation Protection
131
REVERSE POWER Disabled Enabled
Enabled
Reverse Power Protection
132
FORWARD POWER
Enabled
Forward Power Supervision
7UM62 Manual C53000-G1176-C149-3
Disabled Enabled
23
Functions
Addr.
Setting Title
Setting Options
Default Setting
Comments
133
IMPEDANCE PROT.
Disabled Enabled
Enabled
Impedance Protection
135
OUT-OF-STEP
Disabled Enabled
Enabled
Out-of-Step Protection
140
UNDERVOLTAGE
Disabled Enabled
Enabled
Undervoltage Protection
141
OVERVOLTAGE
Disabled Enabled
Enabled
Overvoltage Protection
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
Jump of Voltage Vector
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
Motor Starting Time Supervision
166
RESTART INHIBIT
Disabled Enabled
Enabled
Restart Inhibit for Motors
170
BREAKER FAILURE
Disabled Side 1 Side 2
Side 2
Breaker Failure Protection
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 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 B2 (Port B)
175
ANALOGOUTPUT D1
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 D1 (Port D)
7UM62 Manual C53000-G1176-C149-3
25
Functions
Addr.
Setting Title
Setting Options
Default Setting
Comments
176
ANALOGOUTPUT D2
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 D2 (Port D)
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
Trip Circuit Supervision
185
THRESHOLD
Disabled Enabled
Enabled
Threshold Supervision
186
EXT. TRIP 1
Disabled Enabled
Enabled
External Trip Function 1
187
EXT. TRIP 2
Disabled Enabled
Enabled
External Trip Function 2
188
EXT. TRIP 3
Disabled Enabled
Enabled
External Trip Function 3
189
EXT. TRIP 4
Disabled Enabled
Enabled
External Trip Function 4
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 U0 measured value (precisely: √3 U0)
–
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
Processing of UE input
Processing of UE input
–
UE connected to rotor
Processing of U0 measured value (precisely: √3 U0)
–
–
Processing of UE input
UE connected to neutral transformer
Processing of UE input
Processing of UE input
Processing of UE input
–
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
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
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 Solid Earthed
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
CT-Strpnt. Side2 in Direct. of Object
211
IN-PRI I-SIDE2
1..100000 A
500 A
CT Rated Primary Current Side 2
212
IN-SEC I-SIDE2
1A 5A
1A
CT Rated Secondary Current Side 2
213
FACTOR IEE2
1.0..100000.0
60.0
CT Ratio Prim./Sec. IEE2
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
Functional Description
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:
Primary fault current IL2 Side1
00578 IL3 S1:
Primary fault current IL3 Side1
00579 IL1 S2:
Primary fault current IL1 Side2
00580 IL2 S2:
Primary fault current IL2 Side2
00581 IL3 S2:
Primary fault current IL3 Side2
05012 UL1E:
Voltage UL1E at trip
05013 UL2E:
Voltage UL2E at trip
05014 UL3E:
Voltage UL3E at trip
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
Functional Description
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
Definite-Time Overcurrent Protection (I>, ANSI 50/51) with Undervoltage Seal-In
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
Definite-Time Overcurrent Protection (I>, ANSI 50/51) with Undervoltage Seal-In
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
O/C fault detection stage I> phase L2
01813 I> Fault L3
O/C fault detection stage I> phase 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
Functional Description
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 IL1IL3
IL2
UL3 – UL1
L2, L3 with IL2=IL1
IL2
UL3 – UL1
L2, L3 with IL2IL1
IL3
UL1 – UL2 UL1 – UL2
L3, L1 with IL3=IL1
IL1
UL2 – UL3
L3, L1 with IL3(IL2, IL3) IL1 L1, L2, L3 with IL2>(IL1, IL3) IL1
UL2 – UL3 UL2 – UL3
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
I>> Fault L2 FNo. 01803
I>> Fault L3 FNo. 01808
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
Definite-Time Overcurrent Protection (I>>, ANSI 50, 51, 67) with Direction Detection
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
Definite-Time Overcurrent Protection (I>>, ANSI 50, 51, 67) with Direction Detection
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 ON Block relay for trip commands
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
O/C fault detection stage I>> phase L2
01803 I>> Fault L3
O/C fault detection stage I>> phase 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
Inverse-Time Overcurrent Protection (ANSI 51V)
2.8.1
Functional Description
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
Inverse-Time Overcurrent Protection (ANSI 51V)
:
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
Inverse-Time Overcurrent Protection (ANSI 51V)
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
Inverse-Time Overcurrent Protection (ANSI 51V)
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 ON Block relay for trip commands
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
01897 O/C Ip Fault L2
O/C fault detection Ip phase L2
01898 O/C Ip Fault L3
O/C fault detection Ip phase L3
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
Thermal Overload Protection (ANSI 49)
2.9
Thermal Overload Protection (ANSI 49)
2.9.1
Functional Description
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
Thermal Overload Protection (ANSI 49)
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
Thermal Overload Protection (ANSI 49)
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
Thermal Overload Protection (ANSI 49)
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
Thermal Overload Protection (ANSI 49)
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
Thermal Overload Protection
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
Temperature Rise at Rated Sec. Curr.
7UM62 Manual C53000-G1176-C149-3
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
Temperature for Scaling
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
Unbalanced Load (Negative Sequence) Protection (ANSI 46)
2.10
Unbalanced Load (Negative Sequence) Protection (ANSI 46)
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
Unbalanced Load (Negative Sequence) Protection (ANSI 46)
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)
Current transformer:
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
Unbalanced Load (Negative Sequence) Protection (ANSI 46)
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
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7UM62 Manual C53000-G1176-C149-3
Startup Overcurrent Protection (ANSI 51)
2.11
Startup Overcurrent Protection (ANSI 51)
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
2.11.2 Setting Hints General
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.
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7UM62 Manual C53000-G1176-C149-3
Startup Overcurrent Protection (ANSI 51)
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.
7UM62 Manual C53000-G1176-C149-3
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 ON Block relay for trip commands
OFF
Startup O/C protection
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
05575 O/C Start L1 PU
Startup O/C phase L1 picked up
05576 O/C Start L2 PU
Startup O/C phase L2 picked up
05577 O/C Start L3 PU
Startup O/C phase L3 picked up
05578 O/C Start TRIP
Startup O/C protection TRIP
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7UM62 Manual C53000-G1176-C149-3
Differential Protection (ANSI 87G/87M/87T)
2.12
Differential Protection (ANSI 87G/87M/87T)
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
Differential Protection (ANSI 87G/87M/87T)
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
Differential Protection (ANSI 87G/87M/87T)
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
Differential Protection (ANSI 87G/87M/87T)
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
Fault characteristic
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
Differential Protection (ANSI 87G/87M/87T)
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
Fault characteristic
9 8 D
7 6
Trip area
5
Block area
C
4 3 2
Add-on stabilization
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.
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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
Fault characteristic
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
Add-on stabilization
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
Add-on Stabilization During Current Transformer Saturation
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
Differential Protection (ANSI 87G/87M/87T)
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
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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
Differential Protection (ANSI 87G/87M/87T)
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 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
Differential Protection (ANSI 87G/87M/87T)
2.12.2 Setting Hints General
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
Block area 2041 SLOPE 1
3 2 1
2021 I–DIFF>
a 1
Add-on stabilization
b 2
3
4
5
2044 BASE POINT 2 2042 2056 BASE POINT 1 EXF–STAB
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
Differential Protection (ANSI 87G/87M/87T)
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 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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Functions
− 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
Differential Protection (ANSI 87G/87M/87T)
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.
Tripping Characteristic
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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Functions
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
Block area 2041 SLOPE 1
3 2 1
2021 I–DIFF>
Add-on stabilization
b a 1
2
3
4
5
2044 BASE POINT 2 2042 2056 BASE POINT 1 EXF–STAB
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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Differential Protection (ANSI 87G/87M/87T)
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 ON Block relay for trip commands
OFF
Differential Protection
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
Slope 2 of Tripping Characteristic
2044A
BASE POINT 2
0.00..10.00 I/InO
2.50 I/InO
Base Point for Slope 2 of Charac.
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.
7UM62 Manual C53000-G1176-C149-3
95
Functions
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
05645 Diff 2.Harm L2
Diff: Blocked by 2.Harmon. L2
05646 Diff 2.Harm L3
Diff: Blocked by 2.Harmon. L3
05647 Diff n.Harm L1
Diff: Blocked by n.Harmon. L1
05648 Diff n.Harm L2
Diff: Blocked by n.Harmon. L2
05649 Diff n.Harm L3
Diff: Blocked by n.Harmon. L3
05651 Diff Bl. exF.L1
Diff. prot.: Blocked by ext. fault L1
05652 Diff Bl. exF.L2
Diff. prot.: Blocked by ext. fault L2
05653 Diff Bl. exF.L3
Diff. prot.: Blocked by ext. fault.L3
05657 DiffCrosBlk2HM
Diff: Crossblock by 2.Harmonic
05658 DiffCrosBlknHM
Diff: Crossblock by n.Harmonic
05666 Diff in.char.L1
Diff: Increase of char. phase L1
05667 Diff in.char.L2
Diff: Increase of char. phase L2
05668 Diff in.char.L3
Diff: Increase of char. phase L3
05670 Diff I-Release
Diff: Curr-Release for Trip
05671 Diff TRIP
Differential protection TRIP
05672 Diff TRIP L1
Differential protection: TRIP L1
05673 Diff TRIP L2
Differential protection: TRIP L2
05674 Diff TRIP L3
Differential protection: TRIP L3
05681 Diff> L1
Diff. prot.: IDIFF> L1 (without Tdelay)
05682 Diff> L2
Diff. prot.: IDIFF> L2 (without Tdelay)
05683 Diff> L3
Diff. prot.: IDIFF> L3 (without Tdelay)
05684 Diff>> L1
Diff. prot: IDIFF>> L1 (without Tdelay)
05685 Diff>> L2
Diff. prot: IDIFF>> L2 (without Tdelay)
05686 Diff>> L3
Diff. prot: IDIFF>> L3 (without Tdelay)
05691 Diff> TRIP
Differential prot.: TRIP by IDIFF>
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7UM62 Manual C53000-G1176-C149-3
Differential Protection (ANSI 87G/87M/87T)
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:
Diff. current in phase L2 at trip
05703 Diff L3:
Diff. current in phase L3 at trip
05704 Res L1:
Restr. current in phase L1 at trip
05705 Res L2:
Restr. current in phase L2 at trip
05706 Res L3:
Restr. current in phase L3 at trip
7UM62 Manual C53000-G1176-C149-3
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Functions
2.13
Earth Current Differential Protection (ANSI 87GN, TN)
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
2.13.1 Functional Description Measuring Principle
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
Earth Current Differential Protection (ANSI 87GN, TN)
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
7UM62 Manual C53000-G1176-C149-3
99
Functions
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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7UM62 Manual C53000-G1176-C149-3
Earth Current Differential Protection (ANSI 87GN, TN)
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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Functions
• 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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7UM62 Manual C53000-G1176-C149-3
Earth Current Differential Protection (ANSI 87GN, TN)
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
2.13.2 Setting Hints General
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).
7UM62 Manual C53000-G1176-C149-3
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Functions
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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Earth Current Differential Protection (ANSI 87GN, TN)
2.13.2.1 Settings of the Earth Current Differential Protection Addr.
Setting Title
Setting Options
Default Setting
Comments
2101
REF PROT.
OFF ON Block relay for trip commands
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
7UM62 Manual C53000-G1176-C149-3
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Functions
2.14
Underexcitation (Loss-of-Field) Protection (ANSI 40)
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
Underexcitation (Loss-of-Field) Protection (ANSI 40)
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 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
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7UM62 Manual C53000-G1176-C149-3
Out-of-Step Protection (ANSI 78)
Addr.
Setting Title
Setting Options
Default Setting
Comments
3510
REP. CHAR. 2
1..8
4
Number of Power Swing: Characteristic 2
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.
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Undervoltage Protection (ANSI 27)
FNo. 06533
U< picked up
4002 U<
4003 T U<
&
FNo. 06539
FNo. 06506
U< TRIP
>BLOCK U<
Tripping matrix
FNo. 06537
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
2.20.2 Setting Hints General
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 ON Block relay for trip commands
OFF
Overvoltage Protection
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
Overvoltage Protection (ANSI 59)
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
Frequency Protection (ANSI 81)
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 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
2.21.2 Setting Hints General
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 fBLOCK 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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Overexcitation (Volt/Hertz) Protection (ANSI 24)
2.22
Overexcitation (Volt/Hertz) Protection (ANSI 24)
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
Overexcitation (Volt/Hertz) Protection (ANSI 24)
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
2.22.2 Setting Hints General
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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Overexcitation (Volt/Hertz) Protection (ANSI 24)
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 ON Block relay for trip commands
OFF
Overexcitation Protection (U/f)
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
U/f = 1.10 Time Delay
4308
t(U/f=1.15)
0..20000 sec
240 sec
U/f = 1.15 Time Delay
4309
t(U/f=1.20)
0..20000 sec
60 sec
U/f = 1.20 Time Delay
4310
t(U/f=1.25)
0..20000 sec
30 sec
U/f = 1.25 Time Delay
4311
t(U/f=1.30)
0..20000 sec
19 sec
U/f = 1.30 Time Delay
4312
t(U/f=1.35)
0..20000 sec
13 sec
U/f = 1.35 Time Delay
4313
t(U/f=1.40)
0..20000 sec
10 sec
U/f = 1.40 Time Delay
4314
T COOL DOWN
0..20000 sec
3600 sec
Time for Cooling Down
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
Inverse-Time Undervoltage Protection (ANSI 27)
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).
Tripping Characteristic
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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Inverse-Time Undervoltage Protection (ANSI 27)
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
Fuse Failure Monitor
Figure 2-77
Logic Diagram of the Inverse-Time Undervoltage Protection
2.23.2 Setting Hints General
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 UpBLOCK 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 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
2.24.2 Setting Hints General
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 >/ positive rate of freq. change
-df/dt< negative rate of freq. change
Mode of Threshold (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 (df2/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 (df3/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 (df4/dt >/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
Stage df2/dt picked up
05518 df3/dt pickup
Stage df3/dt picked up
05519 df4/dt pickup
Stage df4/dt picked up
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
Jump of Voltage Vector
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
Jump of Voltage Vector
2.25.1 Functional Description Measuring Principle
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).
7UM62 Manual C53000-G1176-C149-3
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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
OR
0
T
5585 VEC JUMP Range
4605 U MIN U1U MAX
Logic Diagram of the Vector Jump Detection
2.25.2 Setting Hints General
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
Jump of Voltage Vector
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 ON Block relay for trip commands
OFF
Jump of Voltage Vector
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
7UM62 Manual C53000-G1176-C149-3
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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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7UM62 Manual C53000-G1176-C149-3
90–%–Stator Earth Fault Protection (ANSI 59N, 64G, 67G)
2.26
90–%–Stator Earth Fault Protection (ANSI 59N, 64G, 67G)
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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7UM62 Manual C53000-G1176-C149-3
90–%–Stator Earth Fault Protection (ANSI 59N, 64G, 67G)
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
90–%–Stator Earth Fault Protection (ANSI 59N, 64G, 67G)
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
2.26.2 Setting Hints General
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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181
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
90–%–Stator Earth Fault Protection (ANSI 59N, 64G, 67G)
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 ON Block relay for trip commands
OFF
Stator Earth Fault Protection
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
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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
Earth fault in phase L2
05191 Uearth L3
Earth fault in phase 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
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Sensitive Earth Fault Protection (ANSI 51GN, 64R)
2.27
Sensitive Earth Fault Protection (ANSI 51GN, 64R)
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
Sensitive Earth Fault Protection (ANSI 51GN, 64R)
2.27.2 Setting Hints General
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 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 ON Block relay for trip commands
OFF
Sensitive Earth Current Protection
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
100–%–Stator Earth Fault Protection with 3rd Harmonics (ANSI 27/59TN 3rd Harm.)
2.28.1 Functional Description General
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).
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
100–%–Stator Earth Fault Protection with 3rd Harmonics (ANSI 27/59TN 3rd Harm.)
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
2.28.2 Setting Hints General
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
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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 ON Block relay for trip commands
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
100–%–Stator Earth Fault Protection with 3rd Harmonics (ANSI 27/59TN 3rd Harm.)
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
100–% Stator Earth Fault Protection with 20 Hz Voltage Injection (ANSI 64G - 100%)
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>
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
100–% Stator Earth Fault Protection with 20 Hz Voltage Injection (ANSI 64G - 100%)
2.29.2 Setting Hints General
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
Earthing transformer
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 = 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
100–% Stator Earth Fault Protection with 20 Hz Voltage Injection (ANSI 64G - 100%)
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 ON Block relay for trip commands
OFF
100% Stator-Earth-Fault Protection
5302
R< SEF ALARM
20..700 Ohm
100 Ohm
Pickup Value of Alarm Stage Rsef<
5303
R> 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
Rotor Earth Fault Protection R, fn (ANSI 64R)
2.30
Rotor Earth Fault Protection R, fn (ANSI 64R)
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 RERM 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
2.33.2 Setting Hints General
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 for Motors (ANSI 66, 49Rotor)
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
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7UM62 Manual C53000-G1176-C149-3
Restart Inhibit for Motors (ANSI 66, 49Rotor)
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 ON Block relay for trip commands
OFF
Restart Inhibit for Motors
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
Maximum Permissible Starting Time
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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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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Breaker Failure Protection (ANSI 50BF)
2.34
Breaker Failure Protection (ANSI 50BF)
2.34.1 Functional Description General
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
Breaker Failure Protection (ANSI 50BF)
Device-internal protective functions I>TRIP
U>>TRIP
Masking
HW model of relays
BO 12 binary output (Relay R12), potential-free
fint. 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
2.34.2 Setting Hints General
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.
7UM62 Manual C53000-G1176-C149-3
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 ON Block relay for trip commands
OFF
Breaker Failure Protection
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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Breaker Failure Protection (ANSI 50BF)
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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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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7UM62 Manual C53000-G1176-C149-3
Inadvertent Energization (ANSI 50, 27)
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)
2.35.2 Setting Hints General
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 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 ON Block relay for trip commands
OFF
Inadvertent Energisation
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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Inadvertent Energization (ANSI 50, 27)
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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233
Functions
2.36
DC Voltage/DC Current Protection (ANSI 59NDC/51NDC)
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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7UM62 Manual C53000-G1176-C149-3
DC Voltage/DC Current Protection (ANSI 59NDC/51NDC)
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).
Earthing transformer
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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235
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
2.36.2 Setting Hints General
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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7UM62 Manual C53000-G1176-C149-3
DC Voltage/DC Current Protection (ANSI 59NDC/51NDC)
The DC voltage/DC current protection can be set to operate for overvoltage or undervoltage (address 7203 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 ON Block relay for trip commands
OFF
DC Voltage/Current Protection
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 >/<
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.
2.37.2 Setting Hints General
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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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 %
20 mA (B2) correspond to
7304
MIN VALUE (B2)
0.0..5.0 mA
1.0 mA
Output value (B2) valid from
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 %
20 mA (D2) correspond to
7308
MIN VALUE (D2)
0.0..5.0 mA
1.0 mA
Output value (D2) valid from
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Measured Value Monitoring Functions
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
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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.
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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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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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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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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
see Figure 2-59 in Section 2.17.1.2
Gen. trip
Imp. I>+U<
see Figure 2-61 in Section 2.17.1.3
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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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
Jumper setting for measuring transducer 2 does not match parameter 0296
DOK2) drops Relay goes out of service ”ERROR” LED Annunciation ”Err. TD2 jumper” out
Jumper setting for measuring transducer 3 does not match parameter 0297
DOK2) drops Relay goes out of service ”ERROR” LED Annunciation ”Err. TD3 jumper” out
Current sum Side 1
Internal (measured value acquisition)
Annunciation
Current sum Side 2
Internal (measured value acquisition)
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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Measured Value Monitoring Functions
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
Internal (measured value acquisition)
Annunciation
External (power system or voltage transformer)
Annunciation
Voltage phase sequence
External (power system or connection)
Annunciation
Current phase sequence Side 1
External (power system or connection)
Annunciation
Current phase sequence Side 2
External (power system or connection)
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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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
Current Balance Monitor Side 2
8107
BAL. FACT. I S2
0.10..0.90
0.50
Balance Factor for Current Monitor S2
8108
SUM.thres. U
10..200 V
10 V
Summation Thres. for Volt. Monitoring
250
7UM62 Manual C53000-G1176-C149-3
Measured Value Monitoring Functions
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
Summated Cur. Mon. Threshold on Side 2
8113
ΣI FACTOR S2
0.10
Summated Current Mon. Factor on Side 2
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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Functions
F.No.
Alarm
Comments
00194 Error neutralCT
Error: Neutral CT different from MLFB
00212 Err. TD1 jumper
Err: TD1 jumper different from setting
00213 Err. TD2 jumper
Err: TD2 jumper different from setting
00214 Err. TD3 jumper
Err: TD3 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
Measured Value Monitoring Functions
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
Trip Circuit Supervision
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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Trip Circuit Supervision
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+
7UM62 FNo. 06852 >TripC trip rel
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
Note: In the figure the circuit breaker is shown closed.
Figure 2-123 Principle of Trip Circuit Monitor with two Binary Inputs (Connected to Common Potential)
7UM62 Manual C53000-G1176-C149-3
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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
Trip Circuit Supervision
USt
L+
7UM62 FNo. 06852 >TripC trip rel
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
Note: In the figure the circuit breaker is shown closed.
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.
7UM62 Manual C53000-G1176-C149-3
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
Trip Circuit Supervision
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)
7UM62 Manual C53000-G1176-C149-3
259
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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7UM62 Manual C53000-G1176-C149-3
Threshold Supervision
2.40
Threshold Supervision
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
Threshold Supervision
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.
2.40.2 Setting Hints General
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.
7UM62 Manual C53000-G1176-C149-3
263
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
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
Threshold Supervision
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
Measured Value for Threshold MV3>
8506
THRESHOLD MV3> -200..200 %
100 %
Pickup Value of Measured Value MV3>
8507
MEAS. VALUE 4<
Disabled
Measured Value for Threshold MV4<
8508
THRESHOLD MV4< -200..200 %
100 %
Pickup Value of Measured Value MV4<
7UM62 Manual C53000-G1176-C149-3
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
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
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
Measured Value for Threshold MV5>
THRESHOLD MV5> -200..200 %
100 %
Pickup Value of Measured Value MV5>
8511
MEAS. VALUE 6<
Disabled
Measured Value for Threshold MV6<
8512
THRESHOLD MV6< -200..200 %
100 %
Pickup Value of Measured Value MV6<
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
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>
Measured Value MV3> picked up
07963 Meas. Value4<
Measured Value MV4< picked up
07964 Meas. Value5>
Measured Value MV5> picked up
07965 Meas. Value6<
Measured Value MV6< picked up
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2.41
External Trip Coupling
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
2.41.2 Setting Hints General
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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2.41.2.1 Settings Addr.
Setting Title
Setting Options
Default Setting
Comments
8601
EXTERN TRIP 1
OFF ON Block relay for trip commands
OFF
External Trip Function 1
8602
T DELAY
0.00..60.00 sec; ∞
1.00 sec
Ext. Trip 1 Time Delay
8701
EXTERN TRIP 2
OFF ON Block relay for trip commands
OFF
External Trip Function 2
8702
T DELAY
0.00..60.00 sec; ∞
1.00 sec
Ext. Trip 2 Time Delay
8801
EXTERN TRIP 3
OFF ON Block relay for trip commands
OFF
External Trip Function 3
8802
T DELAY
0.00..60.00 sec; ∞
1.00 sec
Ext. Trip 3 Time Delay
8901
EXTERN TRIP 4
OFF ON Block relay for trip commands
OFF
External Trip Function 4
8902
T DELAY
0.00..60.00 sec; ∞
1.00 sec
Ext. Trip 4 Time Delay
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
>Trigger external trip 2
04551 Ext 2 OFF
External trip 2 is switched OFF
04552 Ext 2 BLOCKED
External trip 2 is BLOCKED
04553 Ext 2 ACTIVE
External trip 2 is ACTIVE
04556 Ext 2 picked up
External trip 2: General picked up
04557 Ext 2 Gen.TRP
External trip 2: General TRIP
04563 >BLOCK Ext 3
>BLOCK external trip 3
04566 >Ext trip 3
>Trigger external trip 3
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External Trip Coupling
F.No.
Alarm
Comments
04571 Ext 3 OFF
External trip 3 is switched OFF
04572 Ext 3 BLOCKED
External trip 3 is BLOCKED
04573 Ext 3 ACTIVE
External trip 3 is ACTIVE
04576 Ext 3 picked up
External trip 3: General picked up
04577 Ext 3 Gen.TRP
External trip 3: General TRIP
04583 >BLOCK Ext 4
>BLOCK external trip 4
04586 >Ext trip 4
>Trigger external trip 4
04591 Ext 4 OFF
External trip 4 is switched OFF
04592 Ext 4 BLOCKED
External trip 4 is BLOCKED
04593 Ext 4 ACTIVE
External trip 4 is ACTIVE
04596 Ext 4 picked up
External trip 4: General picked up
04597 Ext 4 Gen.TRP
External trip 4: General TRIP
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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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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
2.42.2 Setting Hints General
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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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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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
RTD 1: Temperature Stage 1 Pickup
9015
RTD 1 STAGE 2
-50..250 °C; ∞
120 °C
RTD 1: Temperature Stage 2 Pickup
9016
RTD 1 STAGE 2
-58..482 °F; ∞
248 °F
RTD 1: Temperature Stage 2 Pickup
9021A
RTD 2 TYPE
not connected Pt 100 Ohm Ni 120 Ohm Ni 100 Ohm
not connected
RTD 2: Type
9022A
RTD 2 LOCATION
Oil Ambient Winding Bearing Other
Other
RTD 2: Location
9023
RTD 2 STAGE 1
-50..250 °C; ∞
100 °C
RTD 2: Temperature Stage 1 Pickup
9024
RTD 2 STAGE 1
-58..482 °F; ∞
212 °F
RTD 2: Temperature Stage 1 Pickup
9025
RTD 2 STAGE 2
-50..250 °C; ∞
120 °C
RTD 2: Temperature Stage 2 Pickup
9026
RTD 2 STAGE 2
-58..482 °F; ∞
248 °F
RTD 2: Temperature Stage 2 Pickup
9031A
RTD 3 TYPE
not connected Pt 100 Ohm Ni 120 Ohm Ni 100 Ohm
not connected
RTD 3: Type
9032A
RTD 3 LOCATION
Oil Ambient Winding Bearing Other
Other
RTD 3: Location
9033
RTD 3 STAGE 1
-50..250 °C; ∞
100 °C
RTD 3: Temperature Stage 1 Pickup
9034
RTD 3 STAGE 1
-58..482 °F; ∞
212 °F
RTD 3: Temperature Stage 1 Pickup
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Addr.
Setting Title
Setting Options
Default Setting
Comments
9035
RTD 3 STAGE 2
-50..250 °C; ∞
120 °C
RTD 3: Temperature Stage 2 Pickup
9036
RTD 3 STAGE 2
-58..482 °F; ∞
248 °F
RTD 3: Temperature Stage 2 Pickup
9041A
RTD 4 TYPE
not connected Pt 100 Ohm Ni 120 Ohm Ni 100 Ohm
not connected
RTD 4: Type
9042A
RTD 4 LOCATION
Oil Ambient Winding Bearing Other
Other
RTD 4: Location
9043
RTD 4 STAGE 1
-50..250 °C; ∞
100 °C
RTD 4: Temperature Stage 1 Pickup
9044
RTD 4 STAGE 1
-58..482 °F; ∞
212 °F
RTD 4: Temperature Stage 1 Pickup
9045
RTD 4 STAGE 2
-50..250 °C; ∞
120 °C
RTD 4: Temperature Stage 2 Pickup
9046
RTD 4 STAGE 2
-58..482 °F; ∞
248 °F
RTD 4: Temperature Stage 2 Pickup
9051A
RTD 5 TYPE
not connected Pt 100 Ohm Ni 120 Ohm Ni 100 Ohm
not connected
RTD 5: Type
9052A
RTD 5 LOCATION
Oil Ambient Winding Bearing Other
Other
RTD 5: Location
9053
RTD 5 STAGE 1
-50..250 °C; ∞
100 °C
RTD 5: Temperature Stage 1 Pickup
9054
RTD 5 STAGE 1
-58..482 °F; ∞
212 °F
RTD 5: Temperature Stage 1 Pickup
9055
RTD 5 STAGE 2
-50..250 °C; ∞
120 °C
RTD 5: Temperature Stage 2 Pickup
9056
RTD 5 STAGE 2
-58..482 °F; ∞
248 °F
RTD 5: Temperature Stage 2 Pickup
9061A
RTD 6 TYPE
not connected Pt 100 Ohm Ni 120 Ohm Ni 100 Ohm
not connected
RTD 6: Type
9062A
RTD 6 LOCATION
Oil Ambient Winding Bearing Other
Other
RTD 6: Location
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Addr.
Setting Title
Setting Options
Default Setting
Comments
9063
RTD 6 STAGE 1
-50..250 °C; ∞
100 °C
RTD 6: Temperature Stage 1 Pickup
9064
RTD 6 STAGE 1
-58..482 °F; ∞
212 °F
RTD 6: Temperature Stage 1 Pickup
9065
RTD 6 STAGE 2
-50..250 °C; ∞
120 °C
RTD 6: Temperature Stage 2 Pickup
9066
RTD 6 STAGE 2
-58..482 °F; ∞
248 °F
RTD 6: Temperature Stage 2 Pickup
9071A
RTD 7 TYPE
not connected Pt 100 Ohm Ni 120 Ohm Ni 100 Ohm
not connected
RTD 7: Type
9072A
RTD 7 LOCATION
Oil Ambient Winding Bearing Other
Other
RTD 7: Location
9073
RTD 7 STAGE 1
-50..250 °C; ∞
100 °C
RTD 7: Temperature Stage 1 Pickup
9074
RTD 7 STAGE 1
-58..482 °F; ∞
212 °F
RTD 7: Temperature Stage 1 Pickup
9075
RTD 7 STAGE 2
-50..250 °C; ∞
120 °C
RTD 7: Temperature Stage 2 Pickup
9076
RTD 7 STAGE 2
-58..482 °F; ∞
248 °F
RTD 7: Temperature Stage 2 Pickup
9081A
RTD 8 TYPE
not connected Pt 100 Ohm Ni 120 Ohm Ni 100 Ohm
not connected
RTD 8: Type
9082A
RTD 8 LOCATION
Oil Ambient Winding Bearing Other
Other
RTD 8: Location
9083
RTD 8 STAGE 1
-50..250 °C; ∞
100 °C
RTD 8: Temperature Stage 1 Pickup
9084
RTD 8 STAGE 1
-58..482 °F; ∞
212 °F
RTD 8: Temperature Stage 1 Pickup
9085
RTD 8 STAGE 2
-50..250 °C; ∞
120 °C
RTD 8: Temperature Stage 2 Pickup
9086
RTD 8 STAGE 2
-58..482 °F; ∞
248 °F
RTD 8: Temperature Stage 2 Pickup
9091A
RTD 9 TYPE
not connected Pt 100 Ohm Ni 120 Ohm Ni 100 Ohm
not connected
RTD 9: Type
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Addr.
Setting Title
Setting Options
Default Setting
Comments
9092A
RTD 9 LOCATION
Oil Ambient Winding Bearing Other
Other
RTD 9: Location
9093
RTD 9 STAGE 1
-50..250 °C; ∞
100 °C
RTD 9: Temperature Stage 1 Pickup
9094
RTD 9 STAGE 1
-58..482 °F; ∞
212 °F
RTD 9: Temperature Stage 1 Pickup
9095
RTD 9 STAGE 2
-50..250 °C; ∞
120 °C
RTD 9: Temperature Stage 2 Pickup
9096
RTD 9 STAGE 2
-58..482 °F; ∞
248 °F
RTD 9: Temperature Stage 2 Pickup
9101A
RTD10 TYPE
not connected Pt 100 Ohm Ni 120 Ohm Ni 100 Ohm
not connected
RTD10: Type
9102A
RTD10 LOCATION
Oil Ambient Winding Bearing Other
Other
RTD10: Location
9103
RTD10 STAGE 1
-50..250 °C; ∞
100 °C
RTD10: Temperature Stage 1 Pickup
9104
RTD10 STAGE 1
-58..482 °F; ∞
212 °F
RTD10: Temperature Stage 1 Pickup
9105
RTD10 STAGE 2
-50..250 °C; ∞
120 °C
RTD10: Temperature Stage 2 Pickup
9106
RTD10 STAGE 2
-58..482 °F; ∞
248 °F
RTD10: Temperature Stage 2 Pickup
9111A
RTD11 TYPE
not connected Pt 100 Ohm Ni 120 Ohm Ni 100 Ohm
not connected
RTD11: Type
9112A
RTD11 LOCATION
Oil Ambient Winding Bearing Other
Other
RTD11: Location
9113
RTD11 STAGE 1
-50..250 °C; ∞
100 °C
RTD11: Temperature Stage 1 Pickup
9114
RTD11 STAGE 1
-58..482 °F; ∞
212 °F
RTD11: Temperature Stage 1 Pickup
9115
RTD11 STAGE 2
-50..250 °C; ∞
120 °C
RTD11: Temperature Stage 2 Pickup
9116
RTD11 STAGE 2
-58..482 °F; ∞
248 °F
RTD11: Temperature Stage 2 Pickup
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Temperature Detection by Thermoboxes
Addr.
Setting Title
Setting Options
Default Setting
Comments
9121A
RTD12 TYPE
not connected Pt 100 Ohm Ni 120 Ohm Ni 100 Ohm
not connected
RTD12: Type
9122A
RTD12 LOCATION
Oil Ambient Winding Bearing Other
Other
RTD12: Location
9123
RTD12 STAGE 1
-50..250 °C; ∞
100 °C
RTD12: Temperature Stage 1 Pickup
9124
RTD12 STAGE 1
-58..482 °F; ∞
212 °F
RTD12: Temperature Stage 1 Pickup
9125
RTD12 STAGE 2
-50..250 °C; ∞
120 °C
RTD12: Temperature Stage 2 Pickup
9126
RTD12 STAGE 2
-58..482 °F; ∞
248 °F
RTD12: Temperature Stage 2 Pickup
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
RTD 1 Temperature stage 2 picked up
14121 Fail: RTD 2
Fail: RTD 2 (broken wire/shorted)
14122 RTD 2 St.1 p.up
RTD 2 Temperature stage 1 picked up
14123 RTD 2 St.2 p.up
RTD 2 Temperature stage 2 picked up
14131 Fail: RTD 3
Fail: RTD 3 (broken wire/shorted)
14132 RTD 3 St.1 p.up
RTD 3 Temperature stage 1 picked up
14133 RTD 3 St.2 p.up
RTD 3 Temperature stage 2 picked up
14141 Fail: RTD 4
Fail: RTD 4 (broken wire/shorted)
14142 RTD 4 St.1 p.up
RTD 4 Temperature stage 1 picked up
14143 RTD 4 St.2 p.up
RTD 4 Temperature stage 2 picked up
14151 Fail: RTD 5
Fail: RTD 5 (broken wire/shorted)
14152 RTD 5 St.1 p.up
RTD 5 Temperature stage 1 picked up
14153 RTD 5 St.2 p.up
RTD 5 Temperature stage 2 picked up
14161 Fail: RTD 6
Fail: RTD 6 (broken wire/shorted)
14162 RTD 6 St.1 p.up
RTD 6 Temperature stage 1 picked up
14163 RTD 6 St.2 p.up
RTD 6 Temperature stage 2 picked up
14171 Fail: RTD 7
Fail: RTD 7 (broken wire/shorted)
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F.No.
Alarm
Comments
14172 RTD 7 St.1 p.up
RTD 7 Temperature stage 1 picked up
14173 RTD 7 St.2 p.up
RTD 7 Temperature stage 2 picked up
14181 Fail: RTD 8
Fail: RTD 8 (broken wire/shorted)
14182 RTD 8 St.1 p.up
RTD 8 Temperature stage 1 picked up
14183 RTD 8 St.2 p.up
RTD 8 Temperature stage 2 picked up
14191 Fail: RTD 9
Fail: RTD 9 (broken wire/shorted)
14192 RTD 9 St.1 p.up
RTD 9 Temperature stage 1 picked up
14193 RTD 9 St.2 p.up
RTD 9 Temperature stage 2 picked up
14201 Fail: RTD10
Fail: RTD10 (broken wire/shorted)
14202 RTD10 St.1 p.up
RTD10 Temperature stage 1 picked up
14203 RTD10 St.2 p.up
RTD10 Temperature stage 2 picked up
14211 Fail: RTD11
Fail: RTD11 (broken wire/shorted)
14212 RTD11 St.1 p.up
RTD11 Temperature stage 1 picked up
14213 RTD11 St.2 p.up
RTD11 Temperature stage 2 picked up
14221 Fail: RTD12
Fail: RTD12 (broken wire/shorted)
14222 RTD12 St.1 p.up
RTD12 Temperature stage 1 picked up
14223 RTD12 St.2 p.up
RTD12 Temperature stage 2 picked up
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Inversion of Phase Sequence (Phase Sequence Reversal)
2.43
Inversion of Phase Sequence (Phase Sequence Reversal)
2.43.1 Functional Description General
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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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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Protection Function Logic
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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Functions
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
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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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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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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
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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.
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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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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
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UN–VT PRIMARY = ----------------------------------------------------------- ⋅ U LL sec UN–VT SECONDARY
U prim. -------------------------------------------------------------- ⋅ 100 UN GEN/MOTOR ⁄ ( 3 ) U prim. ---------------------------------------------- ⋅ 100 UN GEN/MOTOR
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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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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
Normalized overload protection measured values of the stator winding for phase L2
− ΘS/ΘSTripL3
Normalized overload protection measured values of the stator winding for phase L3
− 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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− 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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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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Functions
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.
296
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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Breaker Control
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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Functions
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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Functions
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
Interlocked *2) - switching authority LOCAL
Interlocked *2) - switching authority LOCAL
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
310
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
Annunciations Measured values
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
3 Installation and Commissioning
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
3.1 Installation and Connections
SIPROTEC
SIEMENS RUN
ERROR
MAIN MENU
7UM622
01/04
Annunciations Measured values
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.
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3 Installation and Commissioning
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
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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.
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3 Installation and Commissioning
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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3.1 Installation and Connections
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".
Measuring Transducers
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“.
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3 Installation and Commissioning
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:
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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).
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3 Installation and Commissioning
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
3.1 Installation and Connections
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)
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3 Installation and Commissioning
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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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.
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3 Installation and Commissioning
+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
3.1 Installation and Connections
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)
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3 Installation and Commissioning
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
3.1 Installation and Connections
The layout of the p.c.b for the C–I/O–2 board is shown in Figure 3-10.
X41 3 2 1
C–I/O–2 Input/ Output Board
(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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3 Installation and Commissioning
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)
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C–I/O–6 Input/ Output Board
The layout of the p.c.b for the C–I/O–6 board is shown in Figure 3-11.
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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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)
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3.1 Installation and Connections
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.
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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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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.
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3 Installation and Commissioning
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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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.
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3 Installation and Commissioning
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
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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/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
A/A’ (RxD/TxD–N)
A/A’ (RxD/TxD–N)
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
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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
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3 Installation and Commissioning
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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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.
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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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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 ]
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= 1316 A
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3 Installation and Commissioning
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
IPickup ------------------ = 0.760 ⋅ IDIFF > I N Relay
Single-phase
kVG = √3
IPickup ------------------ = 1.52 ⋅ IDIFF > I N Relay
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”).
Undervoltage Protection
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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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.
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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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3.2 Checking Connections and System (Plant) Integration
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 Commissioning
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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3.3 Commissioning
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> = 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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3.4 Primary Commissioning Tests with the Generator
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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3.4 Primary Commissioning Tests with the Generator
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
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∼
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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3.4 Primary Commissioning Tests with the Generator
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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3 Installation and Commissioning
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.
Frequency Protection
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 Primary Commissioning Tests with the Generator
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
7UM62 Manual C53000-G1176-C149-3
RB’
Equivalent Diagram and Vector Diagram
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3 Installation and Commissioning
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
Earthing transformer
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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3.4 Primary Commissioning Tests with the Generator
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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3 Installation and Commissioning
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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3.4 Primary Commissioning Tests with the Generator
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 %
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3 Installation and Commissioning
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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3.4 Primary Commissioning Tests with the Generator
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
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3 Installation and Commissioning
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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3.4 Primary Commissioning Tests with the Generator
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 Installation and Commissioning
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> (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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3 Installation and Commissioning
(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
7UM62 Manual C53000-G1176-C149-3
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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3 Installation and Commissioning
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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
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
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
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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
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
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
Measuring Transducers
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
4.1 General Device Data
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
– Transmission Speed
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
– Transmission Speed
Min. 4800 Bd, max. 38400 Bd Factory Setting: 38400 Bd
– Maximum Distance of Transmission
15 meters / 49 feet
RS485 – Connection for Flush Mounted Case
For Panel SurfaceMounted 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
– Transmission Speed
Min. 4800 Bd, max. 38400 Bd Factory Setting: 38400 Bd
– Maximum Distance of Transmission
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
4.1 General Device Data
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
– Transmission Speed
up to 19200 Baud
– Maximum Distance of Transmission
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
– Transmission Speed
up to 19200 Baud
– Maximum Distance of Transmission
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“
For Panel SurfaceMounted Case
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
– Transmission Speed
Up to 19200 Baud
– 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)
MODBUS Fibre Optical Link – Connection For Flush-Mounted Case For Panel SurfaceMounted Case
ST–Connector, Rear panel, mounting location “B“ On the case bottom
– Transmission Speed
Up to 19200 Baud
– 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)
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
4.1 General Device Data
– 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
1.4 V at IILow = 0.25 mA
1.9 V at IILow = 0.25 mA
IIHigh
4.5 mA to 9.4 mA
4.5 mA to 9.3 mA
4.5 mA to 8.7 mA
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 General Device Data
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 General Device Data
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
0.25 A to 100.00 A1) (Increments 0.05 A)1)
Delay Times T
50–1, 50–2,
0.00 s to 60.00 s (Increments 0.01 s) or ∞ (does not expire)
Undervoltage Seal–In
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)
Undervoltage Seal–In
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
, 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
1 % of setting value or 10 ms
Thermal Replica for 2 ≤ I2/I2 perm.≤ 20
5 % of reference (calculated) value + 1 % current tolerance, or 600 ms
Influencing Variables for Pickup
414
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%
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)
Inherent Operating Times
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
/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
Influencing Variables for Pickup
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%
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 % (see also Figure 4-7)
417
4 Technical Data
I diff --------- 10 IN
Fault characteristic
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)
Setting Ranges/ Resolutions
Pickup Characteristic
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)
Add-On Stabilization
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>>
0.00 s to 60.00 s or ∞ (ineffective)
(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
Influencing Variables for Pickup
Power Supply Direct Voltage 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
Frequency in Range 0.95 ≤ f/fN ≤ 1.05
1 % (see also Figure 4-11)
I diff --------- 10 IN
Fault characteristic
9 d
2031 8 I DIFF>>
7 6
Tripping
5
Blocking SLOPE 2
c
4 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
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)
Setting Ranges/ Resolution
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
(Increments 0.01 s) or ∞ (does not expire)
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
Inherent Operating Times
Pickup Times
Approx. 25 to 55 ms
Dropout Times
Approx. 60 ms
Dropout
Pickup Characteristic
Approx. 0.90
Dropout/Pickup Ratio
Approx. 0.95
Pickup Characteristic
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>
1 % of setting value or 0.5 V
Delay Times T
1 % of setting value 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 0.95 ≤ f/fN ≤ 1.05
≤1%
Harmonics – Up to 10 % 3rd Harmonics – Up to 10 % 5th Harmonics
≤1% ≤1%
Tolerances
Influencing Variables for Pickup
422
(Increments 0.01)
7UM62 Manual C53000-G1176-C149-3
4.10 Underexcitation (Loss-of-Field) Protection (ANSI 40)
4.10
Underexcitation (Loss-of-Field) Protection (ANSI 40)
Setting Ranges/ Resolutions
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
0.00 s to 60.00 s (Increments 0.01 s) or ∞ (does not expire)
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)
Inherent Operating Times
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
– – – – –
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%
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 Protection (ANSI 32R)
Setting Ranges/ Resolutions
Reverse Power
Pr>/SN
–0.50 % to –30.0 %(Increments 0.01 %)
Delay Times
T
0.00 s to 60.00 s (Increments 0.01 s) or ∞ (does not expire)
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
1 % of setting value or 10 ms
Inherent Operating Times
Pickup Times – Reverse Power Drop-Off Times
Influencing Variables for Pickup
424
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
>
0.00 s to 60.00 s (Increments 0.01 s) or ∞ (does not expire)
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)
Inherent Operating Times
– 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
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
50.0 V to 125.0 V (Increments 0.1 V) or 0 (ineffective)
(Increments 1 %)
Inherent Operating Times
– 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
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
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
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>
5 % of setting value or 100 mA1)
Release
U1<
1 % of setting value or 0.5 V
Delay Times
T
1 % of setting value or 10 ms
Tolerances
Influencing Variables
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
Frequency in Range 0.95 ≤ f/fN ≤ 1.05
1%
Harmonic currents – Up to 10 % 3. Harmonic – Up to 10 % 5. Harmonic
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
0.00 s to 60.00 s or ∞ (ineffective)
(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 – 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
Influencing Variables for Pickup
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
Frequency in Range 0.95 ≤ f/fN ≤ 1.05
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)
(Increments 1 °C) (Increments 1 °F)
Stage 2
–50 °C to 250 °C –58 °F to 482 °F or ∞ (No event)
(Increments 1 °C) (Increments 1 °F)
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
4.33 Additional Functions
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
4.33 Additional Functions
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>, dir.) (t=f(I) +U, t=f(I2)) (∆I) (1/xd) (–P) (P>, P, 3I0>, ∠U0, 3I0) (IEE>) (RE) (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, U) (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
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