Schneider Electric Easergy P3T32 User Manual | Manualzz
Easergy P3T32
Transformer protection relay
User Manual
P3T/en M/J006
11/2022
www.schneider-electric.com
Table of Contents
Transformer protection relay
Table of Contents
1 About this manual........................................................................ 13
1.1 Purpose...........................................................................................................13
1.2 Related documents......................................................................................... 13
1.3 Abbreviations and terms................................................................................. 14
2 Product introduction..................................................................... 20
2.1 Warranty..........................................................................................................20
2.2 Product overview............................................................................................ 20
2.3 Product selection guide...................................................................................21
2.4 Access to device configuration....................................................................... 30
2.4.1 User accounts.......................................................................................30
2.4.2 Logging on via the front panel.............................................................. 30
2.4.3 Password management........................................................................ 31
2.4.4 Password restoring............................................................................... 32
2.5 Front panel......................................................................................................32
2.5.1 Push-buttons.........................................................................................33
2.5.2 LED indicators...................................................................................... 33
2.5.3 Configuring the LED names via Easergy Pro....................................... 34
2.5.4 Controlling the alarm screen.................................................................35
2.5.5 Accessing operating levels................................................................... 35
2.5.6 Adjusting the LCD contrast................................................................... 35
2.5.7 Testing the LEDs and LCD screen........................................................36
2.5.8 Controlling an object with selective control...........................................36
2.5.9 Controlling an object with direct control................................................ 36
2.5.10 Menus................................................................................................. 36
2.5.10.1 Moving in the menus ............................................................ 39
2.5.10.2 Local panel messages...........................................................39
2.6 Easergy Pro setting and configuration tool..................................................... 40
3 Mechanical structure.................................................................... 41
3.1 Modularity....................................................................................................... 41
3.2 Slot info and order code..................................................................................42
4 Measurement functions................................................................44
4.1 Primary, secondary and per unit scaling......................................................... 47
4.1.1 Frequency adaptation mode................................................................. 50
4.1.2 Current transformer ratio...................................................................... 50
4.1.3 Voltage transformer ratio...................................................................... 53
4.2 Measurements for protection functions...........................................................55
4.3 Measurements for arc flash detection function............................................... 56
4.4 RMS values.....................................................................................................58
4.5 Harmonics and total harmonic distortion (THD)..............................................58
4.6 Demand values............................................................................................... 59
4.7 Minimum and maximum values...................................................................... 61
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4.8 Maximum values of the last 31 days and 12 months...................................... 62
4.9 Memory management of measurements........................................................ 64
4.10 Power and current direction.......................................................................... 66
4.11 Symmetrical components.............................................................................. 67
5 Control functions.......................................................................... 68
5.1 Digital outputs................................................................................................. 68
5.2 Digital inputs................................................................................................... 72
5.3 Virtual inputs and outputs................................................................................78
5.4 Matrix.............................................................................................................. 83
5.4.1 Output matrix........................................................................................ 83
5.4.2 Blocking matrix..................................................................................... 84
5.4.3 LED matrix............................................................................................ 85
5.4.4 Object block matrix............................................................................... 87
5.5 Releasing latches............................................................................................88
5.5.1 Releasing latches using Easergy Pro................................................... 88
5.5.2 Releasing latches using buttons and local panel display......................88
5.5.3 Releasing latches using F1 or F2 buttons............................................ 89
5.6 Controllable objects........................................................................................ 90
5.6.1 Object control with digital inputs........................................................... 91
5.6.2 Local or remote selection......................................................................92
5.6.3 Object control with Close and Trip buttons........................................... 92
5.6.4 Object control with F1 and F2...............................................................93
5.7 Logic functions................................................................................................ 94
5.8 Local panel....................................................................................................102
5.8.1 Mimic view.......................................................................................... 102
5.8.2 Local panel configuration....................................................................105
6 Protection functions.................................................................... 111
6.1 Current transformer requirements for overcurrent elements......................... 111
6.1.1 CT requirements when settings are unknown.....................................112
6.1.2 Principle for calculating the saturation current in class P....................112
6.1.3 Examples of calculating the saturation current in class P................... 112
6.1.4 Principle for calculating the saturation current in class PX................. 113
6.1.5 Examples of calculating the saturation current in class PX................ 114
6.1.6 CT requirements for REF protection................................................... 114
6.2 Current transformer requirements for generator and transformer block
differential protection........................................................................................... 115
6.3 Current transformer requirements for transformer differential protection...... 116
6.4 Maximum number of protection stages in one application............................ 118
6.5 General features of protection stages........................................................... 118
6.6 Dependent operate time............................................................................... 125
6.6.1 Standard dependent delays using IEC, IEEE, IEEE2 and RI curves..128
6.6.2 Custom curves....................................................................................148
6.6.3 Programmable dependent time curves...............................................149
6.7 Volts/hertz overexcitation protection (ANSI 24)............................................ 150
6.8 Synchronism check (ANSI 25)...................................................................... 152
6.9 Undervoltage (ANSI 27)................................................................................156
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6.10 Negative sequence overcurrent (ANSI 46) ................................................ 159
6.11 Negative sequence overvoltage protection (ANSI 47)................................ 161
6.12 Thermal overload (ANSI 49 RMS).............................................................. 162
6.13 Breaker failure (ANSI 50BF)....................................................................... 166
6.14 Breaker failure 1 and 2 (ANSI 50BF).......................................................... 168
6.15 Switch-on-to-fault (ANSI 50HS) ................................................................. 174
6.16 Phase overcurrent (ANSI 50/51).................................................................176
6.17 Ground fault overcurrent (ANSI 50N/51N) ................................................. 181
6.17.1 Ground fault phase detection............................................................184
6.18 Capacitor bank unbalance (ANSI 51C) ......................................................185
6.18.1 Taking unbalance protection into use............................................... 188
6.19 Overvoltage (ANSI 59)................................................................................192
6.20 Neutral overvoltage (ANSI 59N)................................................................. 196
6.21 Restricted high-impedance ground fault (ANSI 64REF, 64BEF).................199
6.22 Restricted ground fault (ANSI 64REF) .......................................................200
6.23 Directional phase overcurrent (ANSI 67) ................................................... 205
6.24 Directional ground fault overcurrent (ANSI 67N)........................................ 213
6.24.1 Ground fault phase detection............................................................218
6.25 Second harmonic inrush detection (ANSI 68F2).........................................220
6.26 Fifth harmonic detection (ANSI 68H5)........................................................ 222
6.27 Overfrequency and underfrequency (ANSI 81) ..........................................223
6.28 Rate of change of frequency (ANSI 81R)................................................... 226
6.29 Lockout (ANSI 86).......................................................................................230
6.30 Differential overcurrent protection (ANSI 87T) ........................................... 232
6.31 Arc flash detection (AFD)............................................................................239
6.31.1 Arc flash detection, general principle................................................239
6.31.2 Arc flash detection menus................................................................ 239
6.31.3 Configuration example of arc flash detection....................................240
6.31.4 Arc flash detection characteristics.................................................... 244
6.32 Programmable stages (ANSI 99)................................................................ 245
7 Supporting functions.................................................................. 248
7.1 Event log....................................................................................................... 248
7.2 Disturbance recording...................................................................................250
7.2.1 Configuring the disturbance recorder................................................. 254
7.3 Cold load start and magnetizing inrush.........................................................255
7.4 System clock and synchronization................................................................257
7.5 Voltage sags and swells................................................................................264
7.6 Voltage interruptions..................................................................................... 267
7.7 Current transformer supervision (ANSI 60)...................................................269
7.8 Voltage transformer supervision (ANSI 60FL).............................................. 271
7.9 Circuit breaker wear......................................................................................273
7.10 Circuit breaker condition monitoring........................................................... 279
7.11 Energy pulse outputs...................................................................................282
7.12 Active and reactive energy..........................................................................285
7.13 Running hour counter................................................................................. 286
7.14 Timers......................................................................................................... 287
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7.15 Combined overcurrent status......................................................................289
7.16 Trip circuit supervision (ANSI 74) ...............................................................294
7.16.1 Trip circuit supervision with one digital input.....................................294
7.16.2 Trip circuit supervision with two digital inputs................................... 300
7.16.3 Trip circuit supervision with two combined digital inputs...................303
8 Communication and protocols....................................................305
8.1 Cybersecurity................................................................................................ 305
8.2 Communication ports.................................................................................... 305
8.2.1 Ethernet port....................................................................................... 309
8.2.2 Disabling the Ethernet communication............................................... 310
8.3 Storm protection............................................................................................313
8.4 Parallel Redundancy Protocol.......................................................................313
8.5 Communication protocols............................................................................. 314
8.5.1 Modbus RTU and Modbus TCP..........................................................315
8.5.2 Profibus DP.........................................................................................315
8.5.3 SPA-bus.............................................................................................. 316
8.5.4 IEC 60870-5-103 (IEC-103)................................................................316
8.5.5 DNP 3.0.............................................................................................. 317
8.5.6 IEC 60870-5-101 (IEC-101)................................................................317
8.5.7 IEC 61850...........................................................................................318
8.5.8 Ethernet/IP..........................................................................................318
8.5.9 IEC 60870-5-104 (IEC-104)................................................................319
8.6 IP filter...........................................................................................................319
8.6.1 Configuring the IP filter....................................................................... 320
8.6.2 Unexpected packets........................................................................... 322
8.6.3 Alarms.................................................................................................323
9 Applications and configuration examples...................................324
9.1 Arc flash detection........................................................................................ 324
9.2 Using CSH120 and CSH200 with IN2 0.2 A / 1 A core balance CT input......327
10 Installation................................................................................ 329
10.1 Safety in installation.................................................................................... 329
10.2 Checking the consignment..........................................................................331
10.3 Product identification...................................................................................331
10.4 Storage....................................................................................................... 332
10.5 Mounting..................................................................................................... 332
10.6 Connections................................................................................................ 336
10.6.1 Supply voltage cards........................................................................ 337
10.6.2 Analog measurement cards..............................................................339
10.6.2.1 Analog measurement card 1 (slot 8)................................... 339
10.6.2.2 Analog measurement card 2 (slot 8)................................... 341
10.6.2.3 Analog measurement card 1 (slot 4)................................... 343
10.6.3 I/O cards........................................................................................... 344
10.6.3.1 I/O card “B = 3BIO+2Arc”.................................................... 344
10.6.3.2 I/O card “C = F2BIO+1Arc”..................................................346
10.6.3.3 I/O card “D = 2IGBT”........................................................... 347
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10.6.3.4 I/O option card “D=4Arc”..................................................... 348
10.6.3.5 I/O card “G = 6DI+4DO”...................................................... 349
10.6.3.6 I/O card “H = 6DI + 4DO (NC)”............................................351
10.6.3.7 I/O card “I = 10DI”................................................................351
10.6.4 Arc flash sensor................................................................................ 353
10.6.4.1 Mounting the sensors to the switchgear..............................354
10.6.4.2 Connecting the sensors to the device................................. 356
10.6.5 Communication cards....................................................................... 357
10.6.5.1 COM 1 port..........................................................................363
10.6.5.2 COM 3 – COM 4 ports.........................................................363
10.6.6 Local port.......................................................................................... 368
10.6.7 Connection data................................................................................369
10.6.8 External option modules................................................................... 376
10.6.8.1 VSE-001 fiber-optic interface module..................................376
10.6.8.2 VSE-002 RS-485 interface module..................................... 377
10.6.8.3 VPA-3CG Profibus interface module................................... 379
10.6.8.4 VIO 12A RTD and analog input / output modules............... 380
10.6.9 Block diagrams................................................................................. 380
10.6.10 Connection examples..................................................................... 382
10.7 Arc flash detection system setup and testing..............................................383
10.7.1 Setting up the arc flash system.........................................................383
10.7.2 Commissioning and testing...............................................................384
10.7.2.1 Checking zones...................................................................385
10.7.2.2 Disconnecting trip circuits....................................................385
10.7.2.3 Sensor testingTesting.......................................................... 386
10.7.2.3.1 Testing the sensors.............................................387
10.7.2.3.2 Testing the sensor supervision........................... 387
10.7.2.3.3 Testing the binary I/O connectivity...................... 388
10.7.3 Test report ........................................................................................388
10.7.3.1 Filling in the test report........................................................ 388
10.7.3.2 Test report example.............................................................389
10.7.4 Troubleshooting................................................................................ 390
10.8 Voltage system configuration...................................................................... 390
10.8.1 Multiple channel voltage measurement ........................................... 391
10.9 CSH120 and CSH200 Core balance CTs................................................... 400
11 Test and environmental conditions........................................... 405
11.1 Disturbance tests.........................................................................................405
11.2 Electrical safety tests...................................................................................406
11.3 Mechanical tests..........................................................................................407
11.4 Environmental tests.....................................................................................407
11.5 Environmental conditions............................................................................ 408
11.6 Casing......................................................................................................... 409
12 Maintenance.............................................................................410
12.1 Preventive maintenance............................................................................. 410
12.2 Periodic testing............................................................................................411
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12.3 Hardware cleaning...................................................................................... 411
12.4 System status messages............................................................................ 411
12.5 Spare parts..................................................................................................411
12.6 Self-supervision...........................................................................................411
12.6.1 Diagnostics....................................................................................... 413
12.7 Arc flash detection system maintenance.................................................... 415
12.7.1 Visual inspection...............................................................................416
12.7.2 Hardware cleaning............................................................................416
12.7.3 Sensor condition and positioning check........................................... 417
13 Order codes and accessories.................................................. 418
13.1 Order codes................................................................................................ 418
13.2 Accessories.................................................................................................419
14 Firmware revision.....................................................................422
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Legal information
Transformer protection relay
Legal information
The Schneider Electric brand and any registered trademarks of Schneider Electric
Industries SAS referred to in this guide are the sole property of Schneider Electric
SA and its subsidiaries. They may not be used for any purpose without the
owner's permission, given in writing. This guide and its content are protected,
within the meaning of the French intellectual property code (Code de la propriété
intellectuelle français, referred to hereafter as "the Code"), under the laws of
copyright covering texts, drawings and models, as well as by trademark law. You
agree not to reproduce, other than for your own personal, noncommercial use as
defined in the Code, all or part of this guide on any medium whatsoever without
Schneider Electric's permission, given in writing. You also agree not to establish
any hypertext links to this guide or its content. Schneider Electric does not grant
any right or license for the personal and noncommercial use of the guide or its
content, except for a non-exclusive license to consult it on an "as is" basis, at your
own risk. All other rights are reserved.
Electrical equipment should be installed, operated, serviced and maintained only
by qualified personnel. No responsibility is assumed by Schneider Electric for any
consequences arising out of the use of this material.
As standards, specifications and designs change from time to time, please ask for
confirmation of the information given in this publication.
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Transformer protection relay
Safety information
Safety information
Important information
Read these instructions carefully and look at the equipment to become familiar
with the device before trying to install, operate, service or maintain it.
The following special messages may appear throughout this publication or on the
equipment to warn of potential hazards or to call attention to information that
clarifies or simplifies a procedure.
This is the safety alert symbol. It is used to alert you to potential
personal injury hazards. Obey all safety messages that follow
this symbol to avoid possible injury or death.
The addition of either symbol to a “Danger” or “Warning” safety
label indicates that an electrical hazard exists which will result
in personal injury if the instructions are not followed.
DANGER
DANGER indicates a hazardous situation which, if not avoided, will result
in death or serious injury.
WARNING
WARNING indicates a hazardous situation which, if not avoided, could
result in death or serious injury.
CAUTION
CAUTION indicates a hazardous situation which, if not avoided, could
result in minor or moderate injury.
NOTICE
NOTICE is used to address practices not related to physical injury.
Please note
Electrical equipment must only be installed, operated, serviced, and maintained
by qualified personnel. A qualified person is one who has skills and knowledge
related to the construction, installation, and operation of electrical equipment and
has received safety training to recognize and avoid the hazards involved.
No responsibility is assumed by Schneider Electric for any consequences arising
out of the use of this material.
Protective grounding
The user is responsible for compliance with all the existing international and
national electrical codes concerning protective grounding of any device.
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North America regulatory compliance
Transformer protection relay
North America regulatory compliance
Certificate number: 20190829-E215590
Issue date: 2019-August-29
UL certifies that the Easergy P3 products comply with the following standards:
•
•
•
•
•
P3T/en M/J006
UL 508 Industrial Control Equipment
CSA C22.2 No. 14-13 Industrial Control Equipment
IEEE C37.90-2005 Guide for Power System Protection Testing
IEEE C37.90.1-2012 Standard for Surge Withstand Capability (SWC) Tests
for Relays and Relay Systems Associated with Electrical Power Apparatus
IEEE C37.90.2-2004 Standard for Withstand Capability of Relay Systems to
Radiated Electromagnetic Interference from Trancievers
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Transformer protection relay
EU directive and UKCA regulations compliance
EU directive and UKCA regulations compliance
EU directive compliance
UKCA regulations compliance
Schneider Electric Limited
Telford, TF3 3BL
United Kingdom
EMC compliance
EMC compliance
2014/30/EU
SI 2016 No. 1091
Compliance with the European
The Electromagnetic Compatibility
Commission's EMC Directive. Product
Regulations:
Specific Standard was used to establish
• BS EN 60255-26 2013
conformity:
• EN 60255-26 2013
Product safety
Product safety
2014/35/EU
SI 2016 No. 1101
Compliance with the European
The Electrical Equipment (Safety)
Commission's Low Voltage Directive.
Regulations:
Product Specific Safety Standard was used • BS EN 60255-27 2014
to establish conformity:
• EN 60255-27 2014
RoHS directive
RoHS regulation
2011/65/EU (inclusive of Directive (EU)
SI 2012 No. 3032
2015/863) Compliance
The Restriction of the Use of Certain
Compliance with the European
Hazardous Substances in Electrical and
Commission's on the restriction of the use
Electronic Equipment Regulations
of certain hazardous substances in
• BS EN IEC 63000:2018
electrical and electronic equipment
• EN IEC 63000:2018 / IEC 63000:2016
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1 About this manual
Transformer protection relay
1 About this manual
1.1 Purpose
This document contains instructions on the installation, commissioning and
operation of Easergy P3T32.
This document is intended for persons who are experts on electrical power
engineering, and it covers the relay models as described by the order code.
Related topics
13.1 Order codes
1.2 Related documents
Table 1 - Related documents
Document
Identification1)
P3 Advanced Quick Start
P3x3x/EN QS/xxxx
Easergy Pro Setting and Configuration Tool P3eSetup/EN M/xxxx
User Manual
RTD and mA Output/Input Modules User
VVIO12A_EN_M_D002
Manual
Profibus Interface Module User Manual
VVPA3CG_EN_M_D004
IEC 61850 configuration instructions
P3APS19001EN
Rapid Spanning Tree Protocol (RSTP)
P3APS17002EN
EtherNet/IP configuration instructions
P3APS17003EN
Parallel Redundancy Protocol for Easergy
P3APS17004EN
P3 relays with dual-port 100 Mbps Ethernet
interface
Communication parameter protocol
P3TDS17005EN
mappings
Easergy P3 protection functions'
P3TDS17006EN
parameters and recorded values
P3T/en M/J006
IEC103 Interoperability List
P3TDS17009EN
DNP 3.0 Device Profile Document
P3TDS17010EN
13
Transformer protection relay
1 About this manual
Document
Identification1)
P3 Advanced Series facia label instruction
P3TDS17012EN
Restricted earth fault protection using an I0
P3APS17016EN
input of an Easergy P3 relay
1) xxxx
= revision number
1.3 Abbreviations and terms
Table 2 - Abbreviations and terms used in this manual
AC
Alternating current
AFD
Arc flash detection
ANSI
American National Standards Institute
A standardization organization
bps
Bits per second
CB
Circuit breaker
CBFP
Circuit breaker failure protection
CLPU
Cold load pickup
CM
Common mode
Controlling output
Heavy duty output rated for the circuit
breaker controlling
CPU
Central processing unit
cosφ
Active power divided by apparent power =
P/S
(See power factor PF.)
Negative sign indicates reverse power.
CT
Current transformer
CT primary
CTPRI. Nominal primary value of the IL
(high-voltage) current transformer
CT’ primary
CT’PRI. Nominal primary value of the I’L
(low-voltage) current transformer
CT secondary
CTSEC. Nominal secondary value of the IL
(high-voltage) current transformer
CT’ secondary
CTSEC. Nominal secondary value of the I’L
(low-voltage) current transformer
DC
14
Direct current
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1 About this manual
Transformer protection relay
Dead band
See hysteresis.
DI
Digital input
Digital output
Relay's output contact
DM
Differential mode
DMS
Distribution management system
DO
Digital output
Document file
Stores information about the relay settings,
events and fault logs
DSR
Data set ready
An RS232 signal. Input in front panel port of
Easergy P3 devices to disable rear panel
local port.
DST
Daylight saving time
Adjusting the official local time forward by
one hour for summer time.
DT
Definite time
DTR
Data terminal ready
An RS232 signal. Output and always true
(+8 Vdc) in front panel port of Easergy P3
relays.
Easergy P3 Standard
P3U10, P3U20 and P3U30 relays
Easergy P3 Advanced
P3F30, P3L30, P3M30/32, P3G30/32 and
P3T32 relays
eSetup Easergy Pro
Setting and configuration tool for Easergy
P3 protection relays, later called Easergy
Pro
ETAR T>
This measurement indicates the time to
allow a restart coming from the T> stage
(49F, 49M, 49G, 49T)
Eth packets per second limit
Use this to set the maximum transmitted
packet limit in each second by the Easergy
P3 device. The recommended setting is 75.
Event
A single occurrence in a power system
process. In the HMI, event is abbreviated
as “E” followed by an identification number.
For example, E15 refers to Event 15.
F2BIO
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Transformer protection relay
1 About this manual
fy
Frequency on the other side of the breaker.
This measurement is available when the
voltage scaling mode has synchrocheck
configured.
GOOSE
Generic object-oriented substation event
A specific definition of a type of generic
substation event, for peer-peer
communication.
Hysteresis
I.e. dead band
Used to avoid oscillation when comparing
two nearby values.
IDMT
Inverse definite minimum time
IMODE
Nominal current of the selected mode
In feeder mode, IMODE= VTPRIMARY. In
motor mode, IMODE= IMOT.
IMOT
Nominal current of the protected motor
INOM
Nominal current
Rating of CT primary or secondary
ISET
Start setting value I> (50/51)
ITN
Rated current of the transformer (protected
object)
IN(nom)
Nominal current of IN input in general
IEC
International Electrotechnical Commission
An international standardization
organisation
IEC-101
Communication protocol defined in
standard IEC 60870-5-101
IEC-103
Communication protocol defined in
standard IEC 60870-5-103
IEEE
Institute of Electrical and Electronics
Engineers
IRIG-B
Inter-Range Instrumentation Group time
code B
Standard for time transfer
IT
Instrument transformer (current or voltage
transformer): electrical device used to
isolate or transform voltage or current
levels
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Transformer protection relay
LAN
Local area network
Ethernet-based network for computers and
devices
Latching
Digital outputs and indication LEDs can be
latched, which means that they are not
released when the control signal is
releasing. Releasing of latched devices is
done with a separate action.
LCD
Liquid crystal display
LED
Light-emitting diode
NTP
Network Time Protocol for LAN and WWW
Operation delay
A setting in Easergy Pro that specifies the
total operate time from the fault occurrence
until the output contacts are operated.
The delay contains:
• start delay
• user-configurable operation delay
• output contact delay
OVF
Indication of the event overflow
P
Active power
Unit = [W]
PF
Power factor
The absolute value is equal to cosφ, but the
sign is 'IND' for inductive i.e. lagging current
and 'CAP' for capacitive i.e. leading current.
PLC
Programmable logic controller
PM
Nominal power of the prime mover
(Used by reverse/under power protection.)
POC signals
Binary signals that are transferred in the
communication channel of two P3L30 line
differential relays in both directions. POC
signals are used to transfer statuses of the
DI, VI, VO and logic outputs.
pu
Per unit
PU
Depending of the context, the per unit
refers to any nominal value.
For example, for overcurrent setting 1 pu =
1 x I GN .
P3T30
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Transformer protection relay
1 About this manual
Q
Reactive power
Unit = [var]
RELxxxxx
Short order code
RH
Relative humidity
RMS
Root mean square
RS232 or RS485 (EIA-232 or EIA-485)
Standard defining the electrical
characteristics of a serial communication
interface
RTU
Remote terminal unit
S
Apparent power
Unit = [VA]
SCADA
Supervisory control and data acquisition
SF
Alarm duty watchdog output is energized
when the auxiliary power supply is on and
the product status is operative. This output
is referenced as "service status output" in
the setting tool.
Signaling output
Alarm duty output rated, not suitable for
direct circuit breaker controlling
SNTP
Simple Network Time Protocol for LAN and
WWW
SOTF
Switch on to fault
Squelch limit
Noise filter used to force the measured low
signal level to zero
SPST
Single pole single throw
SPDT
Single pole double throw
Storm protection limit
Use this setting to limit broadcast
messages. For example, limit the storm to
3%, that is 0.03 * 100 Mbps = 30 kbps. This
means that only 30 kb (typically 45 packets)
of broadcast traffic per second is processed
by the Easergy P3 device.
TCP keepalive interval
Interval between keepalive messages.
Keepalive messages are used to keep the
connection active and to response faster to
a lost connection.
18
TCS
Trip circuit supervision
THD
Total harmonic distortion
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1 About this manual
Transformer protection relay
V
Voltage V
VNSEC
Voltage at input Vc at zero ohm ground
fault. (Used in voltage measurement mode
“2LL+VN”)
VA
Voltage input for VAB or VA depending on
the voltage measurement mode
VB
Voltage input for VBC or VB depending on
the voltage measurement mode
VC
Voltage input for VCA or VN depending on
the voltage measurement mode
VN
Neutral voltage
Rating of VT primary or secondary
VNOM
Nominal voltage
Rating of VT primary or secondary
UMI
User-machine interface
USB
Universal serial bus
UTC
Coordinated Universal Time
Used to be called GMT = Greenwich Mean
Time
VI
Virtual input
VO
Virtual output
VT
Voltage transformer
VTPRI
Nominal primary value of voltage
transformer
VTSEC
Nominal secondary value of voltage
transformer
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Transformer protection relay
2 Product introduction
2 Product introduction
2.1 Warranty
This product has a standard warranty of 10 years.
2.2 Product overview
The relay has a modular design, and it can be optimized to medium and big sized
transformers.
Main characteristic and options
•
•
•
•
•
The relay is a transformer protection relay for medium sized transformers in
power distribution.
The relay has optional arc flash communications and high speed outputs to
allow for simple arc flash system configuration.
Two alternative display options
◦ 128 x 128 LCD matrix
◦ 128 x 128 LCD matrix detachable
Power quality measurements and disturbance recorder enable capture of
transients
Wide range of communication protocols, for example:
◦ Modbus TCP/IP
◦ Profibus
◦ IEC61850
The following options depend on the order code:
•
•
•
•
•
•
•
power supply options
ground fault overcurrent input sensitivity
number of digital inputs
number of trip contacts
integrated arc-options (point sensors)
various possibilities with communication interfaces:
◦ high-speed outputs
◦ simple arc flash system communications (BIO)
◦ fiber loop
front panel protection of IP54
Protection functions
•
•
•
•
•
20
Universal, adaptive protection functions for user-configurable transformer
applications
Neutral overvoltage, overvoltage and frequency protection including
synchronism check for two breakers
Single-line diagram, measurements and alarms in the user-machine interface
(UMI)
User-configurable interlocking for primary object control
Optional arc flash detection utilizing point sensors and a fiber loop that can
provide system wide arc flash detection.
P3T/en M/J006
2 Product introduction
Transformer protection relay
Virtual injection
•
Current and voltage injection by manipulating the database of the product by
setting tool disturbance recorder file playback through the product's database
Robust hardware
•
•
•
User-selectable Ethernet, RS485 or RS232 -based communication interfaces
Designed for demanding industrial conditions with conformal-coated printed
circuit boards
Standard USB connection (type B) for Easergy P3 setting software
Common technology for cost efficiency
•
•
Powerful CPU supporting IEC 61850
Thanks to four setting groups, adaptation to various protection schemes is
convenient
User-machine interface (UMI)
•
•
•
•
•
Clear LCD display for alarms and events
Single-line diagram mimic with control, indication and live measurements
Programmable function keys and LEDs
Circuit breaker ON/OFF control
Common firmware platform with other Easergy P3 range protection relays
NOTE: If the device has been powered off for more than about one week, the
UMI language after starting is IEC but after about two minutes, it is
automatically updated to ANSI.
2.3 Product selection guide
The selection guide provides information on the Easergy P3 platform to aid in the
relay selection. It suggests Easergy P3 types suitable for your protection
requirements, based on your application characteristics. The most typical
applications are presented along with the associated Easergy P3 type.
P3T/en M/J006
21
Transformer protection relay
2 Product introduction
Table 3 - Applications
Easergy P3 Standard
Easergy P3 Advanced
4
3
1
Voltage
–
–
–
Feeder
P3F30
w.
directional
–
P3L30
w. line diff. &
P3U30
distance
with
Transformer
P3T32
directional
P3U10
o/c
P3U20
–
with
differential
with voltage
protection
Motor
P3M32
P3M30
with
differential
Generator
P3G32
P3G30
with
differential
Measuring
Phase current
1/5A CT (x3)
1/5A CT (x3) or
inputs
LPCT (x3)
Residual current
1/5A CT or 0.2/1A CT or CSH
1/5A CT (x3) or
LPCT
1/5A CT (x6)
(x3)2)
5/1A+1/0.2A or
5/1A+1/0.2A +
or 5/1A + CSH
5/1A+1/0.2A
CT
Voltage
VT (x1)
Arc flash sensor input
Digital I/O
Input
Output
Analog I/O
22
VT (x4) or LPVT
LPVT (x4)
(x4)2)
–
0 to 4 point
VT (x4)
0 to 4 point
sensor
sensor
6 to 16
2
8/10
14/16
6 to 36
5 + WD
5/8 + WD
11/8 + WD
10 to 21 + WD
10 to 13 + WD
Input
–
0 or 4 3)
0 or 4 3)
Output
–
0 or 4 3)
0 or 4 3)
–
0 or 8 or 123)
0 or 8 or 123)
Temperature sensor input
Front port
VT (x4) or
USB
USB
P3T/en M/J006
2 Product introduction
Nominal power supply
Transformer protection relay
Easergy P3 Standard
Easergy P3 Advanced
24 V dc or 24...48 V dc or 48...230 V ac/dc4)
24...48 V dc or 110...240 V ac/dc
-40...60°C (-40...140°F)
-40...60°C (-40...140°F)
Ambient temperature, in service
2) LPCT/LPVT
available for P3F30 and P3M30 only
external RTD module
4) Check the available power supply range from the device's serial number label.
3) Using
Table 4 - Communication & others
Easergy P3 Standard
Easergy P3 Advanced
4
3
1
Communication
Rear ports
RS-232
–
IRIG/B
RS-485
Protocols
–
■
■
■
■
■
■
■
Using external
Using external
I/O module
I/O module
■
■
Ethernet
–
■
IEC 61850 Ed1
–
■
■
■
■
IEC 60870-5-101
–
■
■
■
■
IEC 60870-5-103
–
■
■
■
■
DNP3 Over
–
■
■
■
■
Modbus serial
–
■
■
■
■
Modbus TCP/IP
–
■
■
■
■
Ethernet/IP
–
■
■
■
■
Profibus DP
–
■
■
■
■
SPAbus
–
■
■
■
■
RSTP
–
■
■
■
■
PRP
–
■
■
■
■
& Ed2
Ethernet
Redundancy
protocols
Others
Control
Logic
Cyber security
P3T/en M/J006
1 object
8 objects
8 objects
Mimic
Mimic
Mimic
Matrix
■
■
Logic equations
■
■
Password
Password
23
Transformer protection relay
2 Product introduction
Easergy P3 Standard
Easergy P3 Advanced
■
–
–
■
Withdrawability (Pluggable
connector)
Remote UMI
NOTE: The numbers in the following tables represent the amount of stages
available for each Easergy P3 type.
Table 5 - Protection functions for P3U
Protection functions
ANSI
code
Feeder
P3U10/20
Feeder P3U30
Motor P3U10/20
Motor P3U30
Fault locator
21FL
–
1
–
1
Synchronism check5)
25
–
2
–
2
Undervoltage
27
–
3
–
3
32L, 32R
–
2
–
2
37
1
1
1
1
38/49T
12
12
12
12
46
–
–
2
2
46BC
1
1
–
–
Incorrect phase sequence
47
–
–
1
1
Negative sequence
47
–
3
–
3
48/51LR
–
–
1
1
Thermal overload
49
1
1
1
1
Phase overcurrent
50/51
3
3
3
3
50N/51N
5
5
5
5
Breaker failure
50BF
1
1
1
1
SOTF
50HS
1
1
1
1
51C
2
2
2
2
51V
–
1
–
1
59
–
3
–
3
Capacitor overvoltage
59C
1
1
–
–
Neutral overvoltage
59N
3
3
3
3
Directional power
Phase undercurrent
RTD temperature
monitoring6)
Negative sequence
overcurrent (motor,
generator)
Cur. unbalance, broken
conductor
overvoltage protection
Motor start-up
supervision / Locked rotor
Ground fault overcurrent
Capacitor bank
unbalance7)
Voltage-dependent
overcurrent
Overvoltage
24
P3T/en M/J006
2 Product introduction
Protection functions
Transformer protection relay
ANSI
code
Feeder
P3U10/20
Feeder P3U30
Motor P3U10/20
Motor P3U30
CT supervision
60
1
1
1
1
VT supervision
60FL
–
1
–
1
64REF
1
1
1
1
Restricted ground fault
with external connection
(high impedance)
64BEF
Starts per hour
66
–
–
1
1
Directional phase
67
–
4
–
4
67N
3
3
3
3
Transient intermittent
67NI
1
1
–
–
Second harmonic inrush
68F2
1
1
1
1
68H5
1
1
1
1
78V
–
–
–
1
Auto-Recloser
79
5
5
–
–
Over or under frequency
81
–
2/2
–
2/2
81R
–
1
–
1
81U
–
2
–
2
Lockout
86
1
1
1
1
Programmable stages
99
8
8
8
8
Cold load pickup (CLPU)
–
1
1
1
1
Programmable curves
–
3
3
3
3
Setting groups 8)
–
4
4
4
4
overcurrent
Directional ground fault
o/c
detection
Fifth harmonic detection
Vector shift
Rate of change of
frequency
Under frequency
5) The
availability depends on the selected voltage measurement mode (in the Scaling setting view in Easergy Pro)
external RTD module
7) Capacitor bank unbalance protection is connected to the ground fault overcurrent input and shares two stages with the ground fault
overcurrent protection.
8) Not all protection functions have 4 setting groups. See details in the manual.
6) Using
Table 6 - Protection functions for Px3x
Protection functions
ANSI
code
P3F30
P3L30
P3M30
P3M32
P3G30
P3G32
P3T32
21
–
1
–
–
–
–
–
Under-impedance
21G
–
–
–
–
2
2
–
Fault locator
21FL
1
1
–
–
–
–
–
Overfluxing
24
–
–
–
–
1
1
1
Distance
P3T/en M/J006
25
Transformer protection relay
Protection functions
2 Product introduction
ANSI
code
P3F30
P3L30
P3M30
P3M32
P3G30
P3G32
P3T32
Synchronism check9)
25
2
2
2
2
2
2
2
Undervoltage
27
3
3
3
3
3
3
3
27P
–
–
–
–
2
2
–
32L, 32R
2
2
2
2
2
2
–
37
–
–
1
1
–
–
–
38/49T
12
12
12
12
12
12
12
40
–
–
–
–
1
1
–
21/40
–
–
–
–
2
2
–
46
–
–
2
2
2
2
2
46BC
1
1
–
–
–
–
–
Incorrect phase sequence
47
–
–
1
1
–
–
–
Negative sequence
47
3
3
3
3
3
3
3
48/51LR
–
–
1
1
–
–
–
Thermal overload
49
1
1
1
1
1
1
1
Phase overcurrent
50/51
3
3
3
3
3
3
3
50N/51N
5
5
5
5
5
5
5
Breaker failure
50BF
1
1
1
1
1
1
1
SOTF
50HS
1
1
1
1
1
1
1
51C
2
2
2
2
2
2
2
51V
1
1
–
–
1
1
–
59
3
3
3
3
3
3
3
Capacitor overvoltage
59C
1
1
–
–
–
–
–
Neutral overvoltage
59N
2
2
2
2
2
2
2
CT supervision
60
1
1
1
1
1
2
2
VT supervision
60FL
1
1
1
1
1
1
1
Positive sequence undervoltage
Directional power
Phase undercurrent
RTD temperature
monitoring10)
Loss of field
Under-reactance
Negative sequence
overcurrent (motor,
generator)
Cur. unbalance, broken
conductor
overvoltage protection
Excessive start time,
locked rotor
Ground fault overcurrent
Capacitor bank
unbalance11)
Voltage-dependent
overcurrent
Overvoltage
26
P3T/en M/J006
2 Product introduction
Transformer protection relay
Protection functions
ANSI
code
P3F30
P3L30
P3M30
P3M32
P3G30
P3G32
P3T32
Restricted ground fault
64REF
1
1
1
1
1
1
1
64REF
–
–
–
–
–
1
1
64S
–
–
–
–
1
1
–
Starts per hour
66
–
–
1
1
–
–
–
Directional phase
67
4
4
4
4
4
4
4
67N
3
3
3
3
3
3
3
Transient intermittent
67NI
1
1
–
–
–
–
–
Second harmonic inrush
68F2
1
1
1
1
1
1
1
Fifth harmonic detection
68H5
1
1
1
1
1
1
1
Pole slip
78PS
–
–
–
–
1
1
–
Auto-Recloser
79
5
5
–
–
–
–
–
Over or under frequency
81
2/2
2/2
2/2
2/2
2/2
2/2
2/2
81R
1
1
1
1
1
1
1
81U
2
2
2
2
2
2
2
Lockout
86
1
1
1
1
1
1
1
Line differential
87L
–
2
–
–
–
–
–
Machine differential
87M
–
–
–
2
–
2
–
Transformer differential
87T
–
–
–
–
–
–
2
Programmable stages
99
8
8
8
8
8
8
8
Arc flash detection (AFD)
–
8
8
8
8
8
8
8
Cold load pickup (CLPU)
–
1
1
1
1
1
1
1
Programmable curves
–
3
3
3
3
3
3
3
Setting groups 12)
–
4
4
4
4
4
4
4
with external connection
(high impedance)
Restricted ground fault
64BEF
(low impedance)
Stator ground fault
overcurrent
Directional ground fault
o/c
detection
Rate of change of
frequency
Under frequency
9) The
availability depends on the selected voltage measurement mode (in the Scaling setting view in Easergy Pro)
external RTD module
11) Capacitor bank unbalance protection is connected to the ground fault overcurrent input and shares two stages with the ground fault
overcurrent protection.
12) Not all protection functions have 4 setting groups. See details in the manual.
10) Using
P3T/en M/J006
27
Transformer protection relay
2 Product introduction
Table 7 - Control functions
Control functions
P3U10/
20
P3U30
P3F30
P3L30
P3M30
P3M32
P3G30
P3G32
P3T32
1/2
4
6
6
6
6
6
6
6
–
–
2
2
2
2
2
2
2
■
■
■
■
■
■
■
■
■
■
■
■
■
■
■
■
■
■
Local control with O/I keys
■
■
■
■
■
■
■
■
■
Local/remote function
■
■
■
■
■
■
■
■
■
Function keys
2
2
2
2
2
2
2
2
2
Custom logic (logic
■
■
■
■
■
■
■
■
■
■
■
■
■
■
■
■
■
■
P3U10/
20
P3U30
P3F30
P3L30
P3M30
P3M32
P3G30
P3G32
P3T32
RMS current values
■
■
■
■
■
■13)
■
■13)
■13)
RMS voltage values
■
■
■
■
■
■
■
■
■
RMS active, reactive and
–
■
■
■
■
■
■
■
■
Frequency
■
■
■
■
■
■
■
■
■
Fundamental frequency
■
■
■
■
■
■13)
■
■13)
■13)
–
■
■
■
■
■
■
■
■
–
■
■
■
■
■
■
■
■
Power factor
–
■
■
■
■
■
■
■
■
Energy values active and
–
■
■
■
■
■
■
■
■
–
■
■
■
■
■
■
■
■
■
■
■
■
■
■
■
■
■
Switchgear control and
monitoring
Switchgear monitoring
only
Programmable switchgear
interlocking
Local control on singleline diagram
equations)
Control with Smart App
Table 8 - Measurements
Measurement
apparent power
current values
Fundamental frequency
voltage values
Fundamental frequency
active, reactive and
apparent power values
reactive
Energy transmitted with
pulse outputs
Demand values: phase
currents
28
P3T/en M/J006
2 Product introduction
Measurement
Transformer protection relay
P3U10/
20
P3U30
P3F30
P3L30
P3M30
P3M32
P3G30
P3G32
P3T32
–
■
■
■
■
■
■
■
■
■
■
■
■
■
■
■
■
■
■
■
■
■
■
■
■
■
■
–
■
■
■
■
■
■
■
■
–
■
■
■
■
■
■
■
■
–
■
■
■
■
■
■
■
■
■
■
■
■
■
■
■
■
■
–
■
■
■
■
■
■
■
■
■
■
■
■
■
■
■
■
■
–
■
■
■
■
■
■
■
■
■
■
■
■
■
■13)
■
■13)
■13)
–
■
■
■
■
■
■
■
■
–
■
■
■
■
■
■
■
■
P3U10/
20
P3U30
P3F30
P3L30
P3M30
P3M32
P3G30
P3G32
P3T32
Sequence of event record
■
■
■
■
■
■
■
■
■
Disturbance record
■
■
■
■
■
■
■
■
■
Tripping context record
■
■
■
■
■
■
■
■
■
Demand values: active,
reactive, apparent power
and power factor
Min and max demand
values: phase currents
Min and max demand
values: RMS phase
currents
Min and max demand
values: active, reactive,
apparent power and
power factor
Maximum demand values
over the last 31 days and
12 months: active,
reactive, apparent power
Minimum demand values
over the last 31 days and
12 months: active,
reactive power
Max and min values:
currents
Max and min values:
voltages
Max and min values:
frequency
Max andmin values:
active, reactive, apparent
power and power factor
Harmonic values of phase
current and THD
Harmonic values of
voltage and THD
Voltage sags and swells
13) Function
available on both sets of CT inputs
Table 9 - Logs and records
Logs and Records
P3T/en M/J006
29
Transformer protection relay
2 Product introduction
Table 10 - Monitoring functions
P3U10/
20
P3U30
P3F30
P3L30
P3M30
P3M32
P3G30
P3G32
P3T32
1
1
1
1
1
1
1
1
1
Circuit breaker monitoring
1
1
1
1
1
1
1
1
1
Relay monitoring
■
■
■
■
■
■
■
■
■
Monitoring functions
Trip
circuit
supervision
(ANSI 74)
2.4 Access to device configuration
You can access the device configuration via:
• the Easergy Pro setting tool
• the device’s front panel
NOTE: There is a timeout mechanism for Telnet/Serial/Http connections.
When logging on via the front panel or web HMI, you are automatically logged
out after 15 minutes inactivity.
2.4.1 User accounts
By default, the Easergy P3 device has five user accounts.
Table 11 - User accounts
User account User name
Default
password
Use
User
0
Used for reading parameter
user
values, measurements, and
events, for example
Operator
operator
1
Used for controlling objects and
for changing the protection stages’
settings, for example
Configurator
conf
2
Needed during the device
commissioning. For example, the
scaling of the voltage and current
transformers can be set only with
this user account.
2.4.2 Logging on via the front panel
NOTE: To log on via the front panel, you need a password that consists of
letters, digits, or other characters in the scope of ASCII 0x21~0x7E.
1. Press
30
and
on the front panel. The Enter password view opens.
P3T/en M/J006
2 Product introduction
Transformer protection relay
Figure 1 - Enter password view
2. Enter the password for the desired access level.
Select a digit value using
, and if the password is longer than one digit,
move to the next digit position using
.
NOTE: There are 16 digit positions in the Enter password view. Enter the
password starting from the first digit position.
For example, if the password is 2, you can enter 2***, **2*, ***2, or 0002
to log on.
3. Press
to confirm the password.
Related topics
2.4.3 Password management
2.4.3 Password management
NOTICE
CYBERSECURITY HAZARD
To improve cybersecurity:
•
•
•
Change all passwords from their default values when taking the protection
device into use.
Change all passwords regularly.
Ensure a minimum level of password complexity according to common
password guidelines.
Failure to follow these instructions can increase the risk of unauthorized
access.
You can change the password for the operator or configurator user accounts in
the General > Device info setting view in Easergy Pro.
The password can contain letters, digits or other characters in the scope of ASCII
0x21~0x7E. However, the new password cannot be any of the default passwords
(digits 0–4 or 9999).
Follow these guidelines to improve the password complexity and thus device
security:
• Use a password of minimum 8 characters.
• Use alphabetic (uppercase and lowercase) and numeric characters in addition
to symbols.
• Avoid character repetition, number or letter sequences and keyboard patterns.
P3T/en M/J006
31
Transformer protection relay
2 Product introduction
•
•
•
Do not use any personal information, such as birthday, name, etc.
Do not use the same password for different user accounts.
Do not reuse old passwords.
Also, all users must be aware of the best practices concerning passwords
including:
• not sharing personal passwords
• not displaying passwords during password entry
• not transmitting passwords in email or by other means
• not saving the passwords on PCs or other devices
• no written passwords on any supports
• regularly reminding users about the best practices concerning passwords
Related topics
2.4.2 Logging on via the front panel
2.4.4 Password restoring
If you have lost or forgotten all passwords, contact Schneider Electric to restore
the default passwords.
2.5 Front panel
Easergy P3T32 has a 128 x 128 LCD matrix display.
Figure 2 - Easergy P3T32 front panel
A
A
B
D
D
E
F
F
F1
A
I
F2
B
B
GJ
J GG
A. Power LED
B. CANCEL push-button
C. Navigation push-buttons
D. LCD
E. INFO push-button
32
B
GC
C
E
G
D
J
F
H
F. Service LED
G. Function push-buttons and LEDs showing their status
H. Local port
I. Object control buttons
J. User-configurable LEDs
P3T/en M/J006
2 Product introduction
Transformer protection relay
2.5.1 Push-buttons
Symbol
Function
HOME/CANCEL push-button for returning to the previous menu. To
return to the first menu item in the main menu, press the button for at
least 3 seconds.
INFO push-button for viewing additional information, for entering the
password view and for adjusting the LCD contrast.
Programmable function push-button.14)
Programmable function push-button.14)
ENTER push-button for activating or confirming a function.
UP navigation push-button for moving up in the menu or increasing a
numerical value.
DOWN navigation push-button for moving down in the menu or
decreasing a numerical value.
LEFT navigation push-button for moving backwards in a parallel menu
or selecting a digit in a numerical value.
RIGHT navigation push-button for moving forwards in a parallel menu or
selecting a digit in a numerical value.
Circuit breaker close push-button
Circuit breaker trip push-button
14) The
default names of the function buttons are Function button 1 and 2. You can change the names
of the buttons in the Control > Names for function buttons setting view.
2.5.2 LED indicators
The relay has 18 LEDs on the front panel:
•
•
•
two LEDs for function buttons (F1 and F2)
two LEDs represent the unit's general status (power and service)
14 user-configurable LEDs (A-N)
When the relay is powered, the power LED is green. During normal use, the
service LED is not active, it activates only when an error occurs or the relay is not
operating correctly. Should this happen, contact your local representative for
further guidance. The service LED and watchdog contact are assigned to work
together. Hardwire the status output into the substation's automation system for
alarm purposes.
The user-configurable LEDs may be red or green. You can configure them via
Easergy Pro.
P3T/en M/J006
33
Transformer protection relay
2 Product introduction
To customize the LED texts on the front panel for the user-configurable LEDs, the
text may be created using a template and then printed. The printed text may be
placed in the pockets beside the LEDs.
You can also customize the LED texts that are shown on the screen for active
LEDs via Easergy Pro.
Table 12 - LED indicators and their information
LED indicator
LED color
Meaning
Measure /
Remarks
Power LED lit
Green
The auxiliary power
Normal operation
has been switched
state
on
Service LED lit
Red
Internal fault.
The relay attempts
Operates in parallel
to reboot. If the
with the self-
service LED remains
supervision output
lit, call for
maintenance.
A–H LED lit
F1 or F2 LED lit
Green or red
Green
Application-related
Configurable in the
status indicators.
Matrix setting view
Corresponding
Depending on the
function key
function
pressed / activated
programmed to F1 /
F2
2.5.3 Configuring the LED names via Easergy Pro
1. Go to General > LED names.
2. To change a LED name, click the LED Description text and type a new
name. To save the new name, press Enter.
34
P3T/en M/J006
2 Product introduction
Transformer protection relay
Figure 3 - LED NAMES menu in Easergy Pro for LED configuration
2.5.4 Controlling the alarm screen
You can enable or disable the alarm screen either via the relay's local display or
using Easergy Pro:
•
•
On the local display, go to Events > Alarms.
In Easergy Pro, go to General > Local panel conf.
2.5.5 Accessing operating levels
1. On the front panel, press
and
2. Enter the password, and press
.
.
2.5.6 Adjusting the LCD contrast
Prerequisite: You have entered the correct password.
1. Press
, and adjust the contrast.
◦
To increase the contrast, press
◦
To decrease the contrast, press
2. To return to the main menu, press
.
.
.
NOTE: By nature, the LCD display changes its contrast depending on the
ambient temperature. The display may become dark or unreadable at low
temperatures. However, this condition does not affect the proper operation of
the protection or other functions.
P3T/en M/J006
35
Transformer protection relay
2 Product introduction
2.5.7 Testing the LEDs and LCD screen
You can start the test sequence in any main menu window.
To start the LED and LCD test:
1. Press
.
2. Press
.
The relay tests the LCD screen and the functionality of all LEDs.
2.5.8 Controlling an object with selective control
Prerequisite: You have logged in with the correct password and enabled selective
control in the Objects setting view.
When selective control is enabled, the control operation needs confirmation
(select before operate).
•
•
Press
to close an object.
–
Press
again to confirm.
–
Press
to cancel.
Press
to trip an object.
–
Press
again to confirm.
–
Press
to cancel.
2.5.9 Controlling an object with direct control
Prerequisite: You have logged in with the correct password and enabled direct
control in the Objects setting view.
When direct control is enabled, the control operation is done without confirmation.
•
Press
to close an object.
•
Press
to trip an object.
2.5.10 Menus
This section gives an overview of the menus that you can access via the device's
front panel.
The main menu
Press the right arrow to access more measurements in the main menu.
36
P3T/en M/J006
2 Product introduction
Transformer protection relay
Table 13 - Main menu
Menu name
Description
Active LEDs
User-configurable texts for active LEDs
Measurements
User-configurable measurements
Single line
Single line or Single line mimic,
measurements and control view. This is a
default start view. To return to this view
from any location, press the HOME/
CANCELL button for at least 3 seconds.
Info
Information about the relay: relay's name,
order code, date, time and firmware version
P
Power: power factor and frequency values
calculated by the relay. Press the right
arrow to view more measurements.
E
Energy: the amount of energy that has
passed through the protected line,
calculated by the relay from the currents
and voltages. Press the right arrow to view
more energy measurements.
I
Current: phase currents and demand
values of phase currents. Press the right
arrow to view more current measurements.
V
Line-to-line voltages. Press the right arrow
to view other voltage measurements.
Dema
Minimum and maximum phase current and
power demand values
Vmax
Minimum and maximum values of voltage
and frequency
Imax
Minimum and maximum current values
Pmax
Minimum and maximum power values
Month
Monthly maximum current and power
values
FL
Short-circuit locator applied to incomer or
feeder
P3T/en M/J006
Evnt
Event log: event codes and time stamps
DR
Disturbance recorder configuration settings
Runh
Running hour counter
37
Transformer protection relay
2 Product introduction
Menu name
Description
TIMR
Timers: programmable timers that you can
use to preset functions
DI
Digital input statuses and settings
DO
Digital output statuses and settings
Arc
Arc flash detection settings
Prot
Protection: settings and statuses for various
protection functions
50/51-1–50/51-4
Protection stage settings and statuses. The
availability of the menus are depends on
the activated protection stages.
AR
Auto-reclosure settings, statuses and
registers
OBJ
Objects: settings related to object status
data and object control (open/closed)
Lgic
Logic events and counters
CONF
General device setup: CT and VT scalings,
frequency adaptation, units, device info,
date, time, clock, etc.
Bus
Communication port settings
Slot
Slot info: card ID (CID) that is the name of
the card used by the relay firmware
Diag
38
Diagnosis: various diagnostic information
P3T/en M/J006
2 Product introduction
Transformer protection relay
2.5.10.1 Moving in the menus
Figure 4 - Moving in menus using the front panel
Main menu
Submenus
Arc detection settings
ARC
OK
I pick-up setting
OK
OK
•
To move in the main menu, press
or
.
•
To move in the submenus, press
•
While in the submenu, press
•
To enter a submenu, press
in the menu.
•
To edit a parameter value, press
and
•
Enter the password, and press
.
•
To go back to the previous menu, press
•
To go back to the first menu item in the main menu, press
seconds.
or
or
.
to jump to the root.
and use
or
for moving down or up
.
.
for at least three
NOTE: To enter the parameter edit mode, enter the password. When the
value is in edit mode, its background is dark.
2.5.10.2 Local panel messages
Table 14 - Local panel messages
Value is not editable:
The value can not be edited or password is
not given
Control disabled:
Object control disabled due to wrong
operating level
Change causes autoboot:
Notification that if the parameter is changed
the relay boots itself
P3T/en M/J006
39
Transformer protection relay
2 Product introduction
2.6 Easergy Pro setting and configuration tool
DANGER
HAZARD OF ELECTRIC SHOCK, EXPLOSION, OR ARC
FLASH
Only qualified personnel should operate this equipment.
Such work should be performed only after reading this
entire set of instructions and checking the technical
characteristics of the device.
Failure to follow this instruction will result in death or
serious injury.
Easergy Pro is a software tool for configuring Easergy P3 relays. It has a
graphical interface where the relay settings and parameters are grouped under
seven tabs:
•
•
•
•
•
•
•
General
Measurements
Inputs/outputs
Protection
Matrix
Logs
Communication
The contents of the tabs depend on the relay type and the selected application
mode.
Easergy Pro stores the relay configuration in a setting file. The configuration of
one physical relay is saved in one setting file. The configurations can be printed
out and saved for later use.
For more information, see the Easergy Pro user manual.
NOTE: Download the latest version of the software from se.com/ww/en/
product-range-download/64884-easergy-p3-protection-relays.
NOTICE
HAZARD OF EQUIPMENT DAMAGE
After writing new settings or configurations to a device, perform a test to verify
that the relay operates correctly with the new settings.
Failure to follow these instructions can result in unwanted shutdown of
the electrical installation.
40
P3T/en M/J006
3 Mechanical structure
Transformer protection relay
3 Mechanical structure
3.1 Modularity
The relay has a modular structure. The relay is built from hardware modules that
are installed into 10 different slots at the back of the relay. The location of the
slots is shown in Figure 5.
The type of the hardware modules is defined by the order code.
Figure 5 - Slot numbering and card options in the Easergy P3T32 rear panel and
an example of defining the pin address 1/C/1:1
A
B
1
2
3
4
5
6
7
9
10
8
C
D
A.
Card C
1
Supply voltage [V]
B.
Connector 2
2, 3
I/O card
C.
Pin 1
4, 5
I/O or analog
measurement card
D.
Protective grounding 6, 9
Communication or
I/O option card
7, 8, 10
Analog
measurement card
(I, V)
For complete availability information on the different option cards, see 13.2
Accessories.
10.6 Connections contains detailed information on each card.
P3T/en M/J006
41
Transformer protection relay
3 Mechanical structure
Example
Table 15 - Example of typical model Easergy P3T32-CGATA-AAENA-B2
SLOT
NAME
TYPE
Application
T32 = Transformer
protection relay
1
Supply voltage
Power C 110 – 240 V (80–
265 V ac/dc, 5 x DO heavy
duty, A1, SF)
2
I/O card I
G = 6DI+4DO (6 x DI, 4 x
DO)
3
I/O card II
A = None
4
I/O card III
T = 3xI (5/1A) + Io (5/1A) for
Transformer differential,
excludes I/O card in slot 5
5
I/O card IV
A = None
6
Option card I
A = None
7
Future option
A = None
8
Analog measurement card
E = 3L(5A)+4V+2IO (5/1A
(See application)
+1/0.2A)
Communication interface I
N = 2 x RJ (Ethernet RJ 100
9
Mbs, RSTP, PRP)
10
Future option
A = None
Display type
B = 128x128 (128 x 128
LCD matrix)
DI nominal voltage
2 = 110 V dc/ac
3.2 Slot info and order code
The relay's configuration can be checked via the front panel or Easergy Pro menu
called Slot or Slot info. “Card ID” is the name of the card used by the relay
firmware.
42
P3T/en M/J006
3 Mechanical structure
Transformer protection relay
Figure 6 - Hardware configuration example view from Easergy Pro configuration
tool
NOTE: See 13.1 Order codes for the relay ordering options.
P3T/en M/J006
43
Transformer protection relay
4 Measurement functions
4 Measurement functions
Easergy P3 has various amounts of analog inputs depending on the model in use.
#GID-TABLE-1-55631 introduces directly measured and calculated quantities for
the power system monitoring. Also see 2.3 Product selection guide.
The current scaling impacts the following functions:
• Protection stages
• Measurements
• Disturbance recorder
• Fault location calculation
Table 16 - Measurement functions in Easergy P3
Measurements
Specification
RMS phase
P3U10/20
P3U30
P3x3x
■
■
■
Measurement
range
Inaccuracy
0.025–50 x IN
I ≤ 1.5 x IN: ±0.5 %
current
of value or ±15 mA
I > 1.5 x IN: ±3 %
of value
RMS ground fault
■
■
■
0.003–10 x IN
overcurrent
I ≤ 1.5 xI0N: ±0.3
% of value or ±0.2
% of I0N
I > 1.5 xI0N: ±3 %
of value
RMS line-to-line
—
■
■
0.005–1.7 x VN
±0.5 % or ±0.3 V
—
■
■
0.005–1.7 x VN
±0.5 % or ±0.3 V
—
■
■
±0.1–1.5 x PN
±1 % for range
voltage15)
RMS phase-toneutral
voltage15)
RMS active power
(PF >0.5)
0.3–1.5xPN
±3 % for range
0.1–0.3xPN
RMS reactive
—
■
■
±0.1–1.5 x QN
power (PF >0.5)
±1 % for range
0.3–1.5xQN
±3 % for range
0.1–0.3xQN
RMS apparent
—
■
■
±0.1–1.5 x SN
power (PF >0.5)
±1 % for range
0.3–1.5xSN
±3 % for range
0.1–0.3xSN
Frequency
44
■
■
■
16 Hz – 75 Hz
±10 mHz
P3T/en M/J006
4 Measurement functions
Measurements
Specification
Fundamental
Transformer protection relay
P3U10/20
P3U30
P3x3x
■
■
■
Measurement
range
Inaccuracy
0.025-50 x IN
I ≤ 1.5 x IN: ±0.5 %
frequency current
of value or ±15 mA
values
I > 1.5 x IN: ±3 %
of value
Fundamental
—
■
■
0.005–1.7 x VN
±0.5 % or ±0.3 V
—
■
■
±0.1–1.5 x PN
±1 % for range
frequency voltage
values
Fundamental
frequency active,
0.3–1.5xPN
reactive and
±3 % for range
apparent power
0.1–0.3xPN
values
Fundamental
—
■
■
±0.1–1.5 x QN
frequency active
±1 % for range
0.3–1.5xQN
power values
±3 % for range
0.1–0.3xQN
Fundamental
—
■
■
±0.1–1.5 x SN
frequency reactive
±1 % for range
0.3–1.5xSN
power values
±3 % for range
0.1–0.3xSN
Power factor
—
■
■
0.02–1
±2° or ±0.02 for PF
> 0.5
Active energy
—
■
■
±1 % for range
0.3–1.5xEPN
Reactive energy
—
■
■
±1 %/1h for range
0.3–1.5xEQN
±3 %/1h for range
0.1–0.3xEQN
Energy transmitted
—
■
■
±1 %/1h for range
with pulse outputs
0.3–1.5xEPN
±3 %/1h for range
0.1–0.3xEPN
Demand values:
phase currents
■
■
■
0.025–50 x IN
I ≤ 1.5 x IN: ±0.5 %
of value or ±15 mA
I > 1.5 x IN ±3 % of
value
P3T/en M/J006
45
Transformer protection relay
Measurements
Specification
Active power
4 Measurement functions
P3U10/20
P3U30
P3x3x
—
■
■
Measurement
range
Inaccuracy
±0.1–1.5 x PN
±1 % for range
demand
0.3–1.5xPN
±3 % for range
0.1–0.3xPN
Reactive power
—
■
■
±0.1–1.5 x QN
demand
±1 % for range
0.3–1.5xQN
±3 % for range
0.1-0.3xQN
Apparent power
—
■
■
±0.1–1.5 x SN
demand
±1 % for range
0.3–1.5xSN
±3 % for range
0.1–0.3xSN
Power factor
—
■
■
±2° or ±0.02 for PF
demand
Min. and max.
> 0.5
■
■
■
0.025–50 x IN
demand values:
I ≤ 1.5 x IN: ±0.5 %
of value or ±15 mA
phase currents
I > 1.5 x IN ±3 % of
value
Min. and max.
■
■
■
demand values:
0.025–50 x IN
I ≤ 1.5 x IN: ±0.5 %
of value or ±15 mA
RMS phase
I > 1.5 x IN ±3 % of
currents
value
Min. and max.
—
■
■
±1 % for range
demand values:
0.3–1.5xPN, QN,
active, reactive,
SN
apparent power
±3 % for range
and power factor
0.1–0.3xPN, QN,
SN
Maximum demand
—
■
■
±1 % for range
values over the
0.3–1.5xPN, QN,
last 31 days and
SN
12 months: active,
reactive, apparent
±3 % for range
power
0.1–0.3xPN, QN,
SN
46
P3T/en M/J006
4 Measurement functions
Transformer protection relay
Measurements
Specification
P3U10/20
P3U30
P3x3x
Minimum demand
—
■
■
Measurement
range
Inaccuracy
±1 % for range
values over the
0.3–1.5xPN, QN,
last 31 days and
SN
12 months: active,
±3 % for range
reactive power
0.1–0.3xPN, QN,
SN
Max. and min.
■
■
■
0.025–50 x IN
values: currents
I ≤ 1.5 x IN: ±0.5 %
of value or ±15 mA
I > 1.5 x IN ±3 % of
value
Max. and min.
—
■
■
0.005–1.7 x VN
±0.5 % or ±0.3 V
■
■
■
16 Hz-75 Hz
±10 mHz
—
■
■
±0.1–1.5 x PN, QN, ±1 % for range
values: voltages
Max. and min.
values: frequency
Max. and min.
values: active,
SN
reactive, apparent
0.3–1.5xPN, QN,
SN
power and power
±3 % for range
factor
0.1–0.3xPN, QN,
SN
±2° or ±0.02 for PF
> 0.5
Harmonic values
■
■
■
2nd–15th
—
■
■
2nd–15th
—
■
■
0.005–1.7 x VN
of phase current
and THD
Harmonic values
of voltage and
THD
Voltage sags and
swells
15) The
±2° or ±0.02 for PF
> 0.5
RMS voltage measurement is dependent on the voltage scaling mode.
NOTE: The measurement display's refresh rate is 0.2 s.
4.1 Primary, secondary and per unit scaling
Many measurement values are shown as primary values although the device is
connected to secondary signals. Some measurement values are shown as
relative values – per unit or percent. Almost all start setting values use relative
scaling.
The scaling is done using the rated values of VTs and CTs depending on the
selected model order option.
P3T/en M/J006
47
Transformer protection relay
4 Measurement functions
Scaling settings
The scaling settings define the characteristics of measurement transformers
connected to the Easergy P3 protection device and determine the correct
adaptation and performance of the metering and protection functions. They are
accessed via:
• Easergy Pro or the web HMI in the General > Scaling view
• on local panel in the CT-VT view of the General menu
Table 17 - Phase current and ground fault overcurrent scaling parameters
Parameter
Description
CT' primary
Primary current value of the CT at the I’L (low-voltage) side (only
P3x32 devices).
In Easergy Pro, this parameter is CT primary (2).
CT' secondary
Secondary current value of the CT at the I’L (low-voltage) side
(only P3x32 devices).
In Easergy Pro, this parameter is CT secondary (2).
Nominal input (IL
Rated value of the phase current input. The given thermal
side)
withstand, burden and impedance are based on this value.
See Table 157 for details.
Nominal input (I'L
Rated value of the phase current input at I' side. The given
side)
thermal withstand, burden and impedance are based on this
value (only P3x32 devices). See Table 157 for details.
CT primary
CT secondary
Primary current value of the IL (high-voltage) current transformer
Secondary current value of the IL (high-voltage) current
transformer
IN1 CT primary
Primary current value of the ground fault IN1 overcurrent
transformer
IN1 CT secondary
Secondary current value of the ground fault IN1 overcurrent
transformer
Nominal IN1 input
Selectable nominal input rating for the ground fault overcurrent
input. Select either 5A or 1A depending on which Io input is used.
The given thermal withstand, burden and impedance are based
on this value.
See Table 157 for details.
IN2 CT primary
Primary current value of the ground fault IN2 overcurrent
transformer
IN2 CT secondary
Secondary current value of the IN2 overcurrent transformer
Nominal IN2 input
Selectable nominal input rating for the ground fault overcurrent
input. Select either 1A or 0.2A depending on which Io input is
used. The given thermal withstand, burden and impedance are
based on this value. See Table 157 for details.
48
P3T/en M/J006
4 Measurement functions
Transformer protection relay
Parameter
Description
IN3 CT primary
Primary current value of the ground fault IN3 overcurrent
transformer
IN3 CT secondary
Secondary current value of the ground fault IN3 overcurrent
transformer
VT primary
Primary voltage value of the voltage transformer
Nominal IN3 input
Selectable nominal input rating for the ground fault overcurrent
input. Select either 1A or 0.2A depending on which Io input is
used. The given thermal withstand, burden and impedance are
based on this value. See Table 157 for details.
VT secondary
Secondary voltage value of the voltage transformer
VT0 secondary
Secondary voltage value of the neutral voltage displacement
voltage transformer
Voltage
Indicates at which side of the protected object the voltage
measurement side
transformers are located.
Voltage
The device can be connected either to zero-sequence voltage,
measurement mode
line-to-line voltage or line-to-neutral voltage. Set the voltage
measurement mode according to the type of connection used.
Frequency adaptation Parameter used to set the system frequency. There are three
mode
modes available: manual, auto and fixed. For more information,
see 4.1.1 Frequency adaptation mode.
Adapted frequency
When the frequency adaption mode is set to manual, you can set
the frequency in the Adapted frequency field, and it is not be
updated even if the measured frequency is different.
Angle memory
Time setting for the directional overcurrent stage to keep the
duration
phase angle fixed if the system voltage collapses
I' 180 deg. angle turn
A setting to turn I' currents 180 degrees (only P3x32 devices)
Power direction
Direction of the power flow:
• “Outgoing” retains all the operation as it is in the existing
Easergy P3 platform.
• “Incoming” changes the sign of real and reactive power by
multiplying the said quantities by -1.
Transformer nominal
Nominal power of the transformer
power
IL side nominal
Nominal power system voltage at the IL side
voltage
I'L side nominal
Nominal power system voltage at I’L side
voltage
Connection group
P3T/en M/J006
Connection group of the power transformer
49
Transformer protection relay
4 Measurement functions
Parameter
Description
Io compensation
Zero-current compensation on the I’L side. If the transformer is
earthed on the IL side, this must be set.
I'o compensation
Zero-current compensation on the I’L side. If the transformer is
earthed on the IL side, this must be set.
The scaling equations presented in 4.1.2 Current transformer ratio and 4.1.3
Voltage transformer ratio are useful when doing secondary testing.
4.1.1 Frequency adaptation mode
You can set the system frequency in General > Scaling in Easergy Pro.
There are three frequency adaptation modes available:
•
•
Manual: When the adaption mode is set to manual, you can set the frequency
in the Adapted frequency field, and it will not be updated even if the
measured frequency is different. However, the relay monitors the system
frequency internally and adapts to the new frequency even if the frequency
has been set manually.
Auto: The network frequency is automatically updated when the relay has
measured the voltage for approximately 45 seconds. The Adapted frequency
field is updated even if it has been set previously. The frequency is measured
from the voltage signals.
Table 18 - Voltage signals
Voltage measurement
mode
Voltage
Voltage channel
2LL+VN, 2LL+VN/LNy, 2LL
VAB, VBC
V1, V2
VA, VB
V1, V2
LN+VN/y/z
VA
V1
LL+VN/y/z
VAB
V1
+VN/LLy
3LN, 3LN+VN, 3LN/LNy,
3LN/LLy
•
Fixed: The frequency is not updated based on the measured voltage and only
the set value is used. This mode is recommended to be used for the linedifferential function.
4.1.2 Current transformer ratio
NOTE: The rated value of the relay's current input, for example 5 A or 1 A,
does not have any effect on the scaling equations, but it defines the
measurement range and the maximum allowed continuous current. See Table
157 for details.
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Table 19 - Primary and secondary scaling
Current (CT)
Residual current calculated
secondary → primary
primary → secondary
I PRI = I SEC ⋅
CTPRI
CTSEC
I SEC = I PRI ⋅
CTSEC
CTPRI
For ground fault overcurrent to input IN, use the corresponding CTPRI and CTSEC
values. For ground fault stages using IN Calc signals, use the phase current CT
values for CTPRI and CTSEC.
Examples
1. Secondary to primary
CT = 500 / 5
Current to the relay's input is 4 A.
=> Primary current is IPRI = 4 x 500 / 5 = 400 A
2. Primary to secondary
CT = 500 / 5
The relay displays IPRI = 400 A
=> Injected current is ISEC = 400 x 5 / 500 = 4 A
Per unit [pu] scaling
For phase currents excluding ArcI>stage:
1 pu = 1 x IN = 100%, where IN is the rated current of the transformer.
The rated current for high-voltage side (HV) and low-voltages side (LV) are
calculated by the relay itself using Equation 1.
Equation 1
IN =
SN
3 ⋅V N
IN = The rated current 1 pu.
SN = Rated apparent power of the protected object
VN = Rated line-to-line voltage of the protected object
For ground fault overcurrents and ArcI> stage:
1 pu = 1 x CTSEC for secondary side and 1 pu = 1 x CTPRI for primary side.
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Phase current scaling
excluding ArcI> stage
Ground fault
overcurrent (3I0)
scaling and phase
current scaling for
ArcI> stage
secondary → per unit
per unit → secondary
I PU =
I SEC ⋅ CTPRI
CTSEC ⋅ I N
I SEC = I PU ⋅ CTSEC ⋅
I PU =
IN
CTPRI
I SEC
CTSEC
I SEC = I PU ⋅ CTSEC
Examples
1. Secondary to per unit for ArcI>
CT = 750 / 5
Current injected to the relay's inputs is 7 A.
Per unit current is IPU = 7 / 5 = 1.4 pu = 140%
2. Secondary to per unit for phase currents excluding ArcI>
CT = 750/5
IN = 525 A
Current injected to the relay's inputs is 7 A.
Per unit current is IPU = 7 x 750 / (5 x 525) = 2.00 pu = 2.00 x IN = 200%
Per unit current is IPU = 7 x 750 / (5 x 525) = 2.00 pu = 2.00 x ITN= 200%
3. Per unit to secondary for ArcI>
CT = 750 / 5
The relay setting is 2 pu = 200%.
Secondary current is ISEC = 2 x 5 = 10 A
4. Per unit to secondary for phase currents
CT = 750 / 5
IN = 525 A
The relay setting is 2 x IN = 2 pu = 200%.
The relay setting is 2 x ITN = 2 pu = 200%.
Secondary current is ISEC = 2 x 5 x 525 / 750 = 7 A
5. Secondary to per unit for earth fault overcurrent
Input is IN1.
CT0 = 50 / 1
Current injected to the relay's input is 30 mA.
Per unit current is IPU = 0.03 / 1 = 0.03 pu = 3%
6. Secondary to per unit for ground fault overcurrent
Input is IN1.
CT0 = 50 / 1
The relay setting is 0.03 pu = 3%.
Secondary current is ISEC = 0.03 x 1 = 30 mA
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7. Secondary to per unit for earth fault overcurrent
Input is IN Calc.
CT = 750 / 5
Currents injected to the relay's IA input is 0.5 A.
IB = IC = 0.
Per unit current is IPU = 0.5 / 5 = 0.1 pu = 10%
8. Secondary to per unit for earth fault overcurrent
Input is IN Calc.
CT = 750 / 5
The relay setting is 0.1 pu = 10%.
If IB = IC = 0, then secondary current to IA is ISEC = 0.1 x 5 = 0.5 A
4.1.3 Voltage transformer ratio
NOTE: Voltage transformer scaling is based on the line-to-line voltages in all
voltage measurements modes.
Table 20 - Primary/secondary scaling of line-to-line voltages
Line-to-line
voltage
measurement
(LL) with VT
secondary →
primary
primary →
secondary
Line-to-neutral
voltage
measurement
(LN) with VT
V PRI = V SEC ⋅
VTPRI V = 3 ⋅ V ⋅ VTPRI
PRI
SEC
VTSEC
VTSEC
V SEC = V PRI ⋅
VTSEC
VT
V
V SEC = PRI ⋅ SEC
VTPRI
3 VTPRI
Examples
1. Secondary to primary. Voltage measurement mode is "2LL+VN".
VT = 12000/110
Voltage connected to the relay's input VA or VB is 100 V.
=> Primary voltage is VPRI = 100x12000/110 = 10909 V.
2. Secondary to primary. Voltage measurement mode is "3LN”.
VT = 12000/110
Three phase symmetric voltages connected to the relay's inputs VA, VB
and VC are 57.7 V.
=> Primary voltage is VPRI = √3 x58x12000/110 = 10902 V
3. Primary to secondary. Voltage measurement mode is "2LL+VN".
VT = 12000/110
The relay displays VPRI = 10910 V.
=> Secondary voltage is VSEC = 10910x110/12000 = 100 V
4. Primary to secondary. Voltage measurement mode is "3LN”.
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VT = 12000/110
The relay displays VAB = VBC = VCA = 10910 V.
=> Symmetric secondary voltages at VA, VB and VC are VSEC = 10910/√3
x110/12000 = 57.7 V.
Per unit [pu] scaling of line-to-line voltages
One per unit = 1 pu = 1 x VN = 100%, where VN = rated voltage of the VT.
Line-to-line voltage scaling
Voltage measurement
Voltage measurement
mode = "2LL+VN", "1LL mode = "3LN"
+VN/LLy", "2LL/LLy",
"LL/LLy/LLz"
secondary → per unit
per unit → secondary
V PU =
V SEC VTPRI
⋅
VTSEC V N
V SEC = V PU ⋅ VTSEC ⋅
V PU = 3 ⋅
V SEC VTPRI
⋅
VTSEC V N
VT
V
VN
V SEC = V PU ⋅ SEC ⋅ N
VTPRI
3 VTPRI
Examples
1. Secondary to per unit. Voltage measurement mode is "2LL+VN".
VT = 12000/110
Voltage connected to the relay's input VA or VB is 110 V.
=> Per unit voltage is VPU = 110/110 = 1.00 pu = 1.00 x VN = 100%
2. Secondary to per unit. Voltage measurement mode is "3LN".
VT = 12000/110
Three symmetric phase-to-neutral voltages connected to the relay's inputs
VA, VB and VC are 63.5 V
=> Per unit voltage is VPU = √3 x 63.5/110 x 12000/11000 = 1.00 pu =
1.00xVN = 100%
3. Per unit to secondary. Voltage measurement mode is "2LL+VN".
VT = 12000/110
The relay displays 1.00 pu = 100%.
=> Secondary voltage is VSEC = 1.00 x 110 x 11000/12000 = 100.8 V
4. Per unit to secondary. Voltage measurement mode is "3LN".
VT = 12000/110
VN = 11000 V
The relay displays 1.00 pu = 100%.
=> Three symmetric phase-to-neutral voltages connected to the relay 's
inputs VA, VB and VC are VSEC = 1.00 x 110/√3 x 11000/12000 = 58.2 V
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Per unit [pu] scaling of neutral overvoltage
Neutral overvoltage (VN) scaling
Voltage measurement
Voltage measurement
mode = "2LL+VN", "1LL mode = "3LN"
+VN/LLy"
secondary → per unit
per unit →secondary
V PU =
V SEC
V 0 SEC
V SEC = V PU ⋅ V 0 SEC
V PU =
V a +V b +V
1
⋅
VTSEC
3
V a +V b +V
c
SEC
c
SEC
= 3 ⋅ V PU ⋅ VTSEC
Examples
1. Secondary to per unit. Voltage measurement mode is "2LL+VN".
V0SEC = 110 V (This is a configuration value corresponding to VN at full
ground fault.)
Voltage connected to the relay's input VC is 22 V.
=> Per unit voltage is VPU = 22/110 = 0.20 pu = 20%
2. Secondary to per unit. Voltage measurement mode is "3LN".
VT = 12000/110
Voltage connected to the relay's input VA is 38.1 V, while VA = VB = 0.
=> Per unit voltage is VPU = (38.1+0+0)/(√3 x110) = 0.20 pu = 20%
3. Per unit to secondary. Voltage measurement mode is "2LL+VN".
V0SEC = 110 V (This is a configuration value corresponding to VN at full
ground fault.)
The relay displays VN = 20%.
=> Secondary voltage at input VC is VSEC = 0.20 x 110 = 22 V
4. Per unit to secondary. Voltage measurement mode is "3LN".
VT = 12000/110
The relay displays VN = 20%.
=> If VB = VC = 0, then secondary voltages at VA is VSEC = √3 x 0.2 x 110 =
38.1 V
4.2 Measurements for protection functions
The relay uses root mean square (RMS) measurement for the protection stages if
not stated otherwise in the protection stage description.
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Figure 7 - Example of various current values of a transformer inrush current
Current (PU)
rms
5
f2/f1 (%)
100
50
f1
f2
0
0
-5
IB
-10
0.00
0.05
0.10
0.15
Time (s)
0.20
0.25
0.30
Relative 2nd harmoic f2/f1 (%)
Load = 0%
All the direct measurements are based on fundamental frequency values. The
exceptions are frequency and instantaneous current for arc flash detection. Most
protection functions are also based on the fundamental frequency values.
Figure 7 shows a current waveform and the corresponding fundamental
frequency component f1, second harmonic f2, and RMS value in a special case
where the current deviates significantly from a pure sine wave.
4.3 Measurements for arc flash detection function
The three-phase current measurement and ground fault current measurement for
arc flash detection are done with electronics. The electronics compares the
current levels to the start settings - THRESHOLDs - and gives a binary signals
“I>” or “IN1>” to the arc flash detection function if limit is exceeded. All the
frequency components of the currents are taken into account.
Signals “I>” or “IN>” are connected to a FPGA chip which implements the arc flash
detection function. The start settings are named “I> int” and “IN1> int” in the local
LCD panel or Easergy Pro views, these settings are used to set the THRESHOLD
levels for the electronics.
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Figure 8 - Measurement logic for the arc flash detection function
3xI
6xI + 3Io + 4U
f
A/D
3xI
Io
A
3xI
Io
B
Io>>
I>>
C
FPGA
D
A. Threshold
B. Comp.
P3T/en M/J006
C. Conf. memory
D. CPU
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Figure 9 - Measurement logic for the arc flash detection function
3xI
f
A/D
6xI + 3Io + 4V
3xI
Io
B
3xI
Io
A
Io>>
I>>
C
FPGA
D
A. Threshold
B. Comp.
C. Conf. memory
D. CPU
4.4 RMS values
RMS currents
The relay calculates the RMS value of each phase current. The minimum and
maximum RMS values are recorded and stored (see 4.7 Minimum and maximum
values).
I RMS = I f 1 + I f 2 + ... + I f 15
2
2
2
RMS voltages
The relay calculates the RMS value of each voltage input. The minimum and the
maximum of RMS values are recorded and stored (see 4.7 Minimum and
maximum values).
V RMS = V
2
f1
+V
2
f2
+ ... + V
2
f 15
4.5 Harmonics and total harmonic distortion (THD)
The relay calculates the the total harmonic distortions (THDs) as a percentage of
the currents and voltages values measured at the fundamental frequency. The
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relay calculates the harmonics from the 2nd to the 15th of phase currents and
voltages. (The 17th harmonic component is also shown partly in the value of the
15th harmonic component. This is due to the nature of digital sampling.)
The harmonic distortion is calculated:
Equation 2
15
∑f
i =2
THD =
2
i
h1
f1 = Fundamental value
f2– 15 = Harmonics
Example
f1 = 100 A,
THD =
f3 = 10 A,
f7 = 3 A,
f11 = 8 A
10 2 + 3 2 + 8 2
= 13.2%
100
For reference, the RMS value is:
RMS = 100 2 + 10 2 + 3 2 + 8 2 = 100.9 A
Another way to calculate the THD is to use the RMS value as reference instead of
the fundamental frequency value. In the example above, the result would then be
13.0 %.
4.6 Demand values
The device calculates average values (demand values) of phase currents IA, IB, IC
and power values S, P and Q.
The demand time is configurable from 10 to 60 minutes with the parameter
"Demand time".
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Figure 10 - Demand values
Table 21 - Demand value parameters
Parameter
Value
Unit
Description
Set16)
Time
10 – 30
min
Demand time (averaging time)
Set
Fundamental frequency values
IAda
A
Demand of phase current IA
IBda
A
Demand of phase current IB
ICda
A
Demand of phase current IC
Pda
kW
Demand of active power P
PFda
Demand of power factor PF
Qda
kvar
Demand of reactive power Q
Sda
kVA
Demand of apparent power S
IARMSda
A
Demand of RMS phase current IA
IBRMSda
A
Demand of RMS phase current IB
ICRMSda
A
Demand of RMS phase current IC
Prmsda
kW
Demand of RMS active power P
Qrmsda
kvar
Demand of RMS reactive power Q
Srmsda
kVA
Demand of RMS apparent power S
RMS values
16) Set
60
= An editable parameter (password needed)
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Transformer protection relay
4.7 Minimum and maximum values
Minimum and maximum values are registered with time stamps since the latest
manual clearing or since the relay has been restarted. The available registered
values are listed in Table 22.
Figure 11 - Minimum and maximum values
Table 22 - Minimum and maximum measurement values
Min & Max measurement
Description
IA, IB, IC
Phase current, fundamental frequency
value
IA RMS, IB RMS, IC RMS
Phase current, RMS value
IN1, IN2
Ground fault overcurrent, fundamental
value
VA, VB, VC, VD
Voltages, fundamental frequency values
VARMS, VBRMS, VCRMS, VDRMS
Line-to-neutral voltages, RMS value
VN
Neutral voltage displacement, fundamental
value
f
Frequency
P, Q, S
Active, reactive, apparent power
IA da, IBda, ICda
Demand values of phase currents
IAda, IBda, ICda (rms value)
Demand values of phase currents, rms
values
P.F.
Power factor
The clearing parameter "ClrMax" is common for all these values.
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Table 23 - Parameters
Parameter
Value
Description
Set17)
ClrMax
-; Clear
Reset all minimum
Set
and maximum
values
17) Set
= An editable parameter (password needed).
4.8 Maximum values of the last 31 days and 12 months
The maximum and minimum values of the last 31 days and the last 12 months
are stored in the relay's non-volatile memory. You can view them in the Logs >
Month max setting view in Easergy Pro.
NOTE: The saving process starts every 30 minutes and it takes a while. If the
relay's auxiliary supply power is switched off before all values have been
saved, the old values remain for the unsaved ones.
Corresponding time stamps are stored for the last 31 days. The registered values
are listed in Table 24.
Figure 12 - Maximum and minimum values of the past 31 days
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Figure 13 - Maximum and minimum values of the past 12 months
Table 24 - Maximum registered values of the last 31 days and 12 months
Max
12
months
Min
Descriptio
n
31
12
days
months
Measur
ement
IA, IB, IC
X
Phase
current
(fundamental
frequency
value)
IN1, IN2
X
Ground fault
overcurrent
S
X
Apparent
X
X
power
P
X
X
Active power
X
X
Q
X
X
Reactive
X
X
power
The timebase can be a value from one cycle to one minute. Also a demand value
can be used as the timebase and its value can be set between 10 and 60
minutes. The demand value menu is located under the Measurements view.
Table 25 - Parameters of the day and month registers
Parameter
Value
Timebase
Description
Set18)
Parameter to select
Set
the type of the
registered values
20 ms
Collect min & max of
one cycle values19)
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Parameter
Value
Description
200 ms
Collect min & max of
Set18)
200 ms average
values
1s
Collect min & max of
1 s average values
1 min
Collect min & max of
1 minute average
values
demand
Collect min & max of
demand values (4.6
Demand values)
ResetDays
Reset the 31 day
Set
registers
ResetMon
Reset the 12 month
Set
registers
18) Set
= An editable parameter (password needed)
is the fundamental frequency RMS value of one cycle updated every 20 ms.
19) This
4.9 Memory management of measurements
Table 26 - Memory management of measured and recorded values
Measurement
Online
RMS phase current
x
RMS ground fault overcurrent
x
RMS line-to-line voltage
x
RMS phase-to-neutral voltage
x
RMS active power
x
RMS reactive power
x
RMS apparent power
x
Frequency
x
Fundamental frequency current
x
Non-
Non-
volatile20)
volatile21)
values
Fundamental frequency voltage
x
values
Fundamental frequency active,
x
reactive and apparent power
values
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Measurement
Fundamental frequency active
Online
Non-
Non-
volatile20)
volatile21)
x
power values
Fundamental frequency reactive
x
power values
Power factor
x
Active energy
x
Reactive energy
x
Energy transmitted with pulse
x
outputs
Demand values: phase currents
x
Active power demand
x
Reactive power demand
x
Apparent power demand
x
Power factor demand
x
Min. and max. demand values:
x
phase currents
Min. and max. demand values:
x
RMS phase currents
Min. and max. demand values:
x
active, reactive, apparent power
and power factor
Max. demand values over the last
x
31 days and 12 months: active,
reactive, apparent power
Min. demand values over the last
x
31 days and 12 months: active,
reactive power
Max. and min. values: currents
x
Max. and min. values: voltages
x
Max. and min. values: frequency
x
Max. and min. values: active,
x
reactive, apparent power and
power factor
Harmonic values of phase current
x
and THD
Harmonic values of voltage and
x
THD
Voltage sags and swells
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Measurement
Online
Non-
Non-
volatile20)
volatile21)
Engine running counter
x
Events
x
Disturbance record
x
Protection stage fault values and
x
events
20) Capacitor-backed-up
for 5-10 days
21) FLASH
4.10 Power and current direction
Figure 14 shows the concept of three-phase current direction and sign of cosφ
and power factor PF (the absolute value is equal to cosφ, but the sign is 'IND' for
inductive i.e. lagging current and 'CAP' for capacitive i.e. leading current). Figure
15 shows the same concepts on a PQ power plane.
Figure 14 - Quadrants of voltage/current phasor plane
+90°
II
I
+cap
ind
cos = +
PF =
cos =
PF = +
V REF 0°
III
IV
I
cap
+ind
cos = +
PF = +
cos =
PF =
I:
Forward capacitive power, current is leading
II:
Reverse inductive power, current is leading
III:
Reverse capacitive power, current is lagging
IV:
Forward inductive power, current is lagging
Figure 15 - Quadrants of power plane
Q
II
cap
cos =
PF =
+90°
+ind
I
cos = +
PF = +
S
P 0°
III
ind
cos =
PF = +
66
+cap
IV
cos = +
PF =
P3T/en M/J006
4 Measurement functions
Transformer protection relay
I:
Forward inductive power, current is lagging
II:
Reverse capacitive power, current is lagging
III:
Reverse inductive power, current is leading
IV:
Forward capacitive power, current is leading
Table 27 - Power quadrants
Power
quadrant
Current
related to
voltage
Power
direction
cosφ
Power factor
PF
+ inductive
Lagging
Forward
+
+
+ capacitive
Leading
Forward
+
-
- inductive
Leading
Reverse
-
+
- capacitive
Lagging
Reverse
-
-
4.11 Symmetrical components
In a three-phase system, the voltage or current phasors may be divided into
symmetrical components.
•
•
•
Positive sequence 1
Negative sequence 2
Zero sequence 0
Symmetrical components are calculated according to the following equations:
S 0 
1 1
 S  = 1 1 a
 1 3
1 a 2
 S 2 
1   S A
2
a   S B
a   S C
S 0 = zero sequence component
S 1 = positive sequence component
S 2 = negative sequence component
1
3
a = 1∠120° = − + j
2
2
, a phase rotating constant
SA = phasor of phase A (phase current or voltage)
SB = phasor of phase B
SC = phasor of phase C
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5 Control functions
5.1 Digital outputs
The digital outputs are also called controlling outputs, signaling outputs and selfsupervision outputs. Trip contacts can be controlled by using the relay output
matrix or logic functions. Also forced control is possible. To use forced control,
you must enable it in the Device/Test > Relays setting view.
Any internal signal can be connected to the digital outputs in the Matrix > Arc
matrix - output setting views.
The Output matrix and Relays setting views represent the state (de-energized /
energized) of the digital output's coil. For example, a bright green vertical line in
the Output matrix and a logical "1" in the Relays view represent the energized
state of the coil. The same principle applies for both NO and NC type digital
outputs. The actual position (open / closed) of the digital outputs' contacts in coil's
de-energized and energized state depends on the type (NO / NC) of the digital
outputs. De-energized state of the coil corresponds to the normal state of the
contacts. A digital output can be configured as latched or non-latched. 5.5
Releasing latches describes releasing latches procedure.
The difference between trip contacts and signal contacts is the DC breaking
capacity. The contacts are single pole single throw (SPST) normal open (NO)
type, except signal relay A1 which has a changeover contact single pole double
throw (SPDT).
In addition to this, the relay has so called heavy duty outputs available in the
power supply modules C and D. For more details, see Table 157.
Programming matrix
1. Connected (single bullet)
2. Connected and latched (single bullet rounded with another circle)
3. Not connected (line crossing is empty)
Trip contacts can be connected to protection stages or other similar purpose in
the Output matrix setting view.
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Figure 16 - Output matrix view
Figure 17 - Trip contacts assigned directly to outputs of logical operators
NOTE: Logic outputs are assigned automatically in the output matrix as well
when logic is built.
Trip contact status can be viewed and forced to operate in the Relays setting
view. Logical "0" means that the output is not energized and logical "1" states that
the output is set active.
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Figure 18 - Relays view
Enable NO / NC outputs in the Polarity setting view for the signals shown.
Figure 19 - Polarity view
Default numbering of DI / DO
Every option card and slot has default numbering. Below is an example of model
P3x30 CGGII-AAEAA-BA showing the default numbering of digital outputs.
You can see the default digital output numbering and change the numbering of
the following option cards in the Inputs/Outputs > Relay config setting view: slot
2, 3, 4, 5: G, I.
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Figure 20 - Default numbering of digital outputs for model P3x30-CGGII-AAEAABA
C: T1, T9–12, A1, SF
G: T13-16
G: T17-20
I: –
I: –
Power supply card outputs are not visible in the Relay config setting view.
Figure 21 - Relay config setting view
Table 28 - Parameters of digital outputs
Parameter
T1 – Tx the available
parameter list
depends on the
Value
0
Unit
Description
Note
Status of trip controlling output
F22)
Status of alarm signalling output
F
1
number and type of
the I/O cards.
A1
0
1
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Parameter
Value
WD
Unit
Description
Note
0
Status of the WD relay
F
1
In Easergy Pro, it is called
"Service status output"
Force
On
Off
Set23)
Force flag for digital output
forcing for test purposes
Names for output relays (editable with Easergy Pro only)
Description
String of
Names for DO on Easergy Pro
max. 32
screens. Default is
characte
rs
Set
"Trip relay n", n=1 – x or
"Signal relay n", n=1
22) F
= Editable when force flag is on
= An editable parameter (password needed).
23) Set
5.2 Digital inputs
Digital inputs are available for control purposes. The number of available inputs
depends on the number and type of option cards.
The polarity normal open (NO) / normal closed (NC) and a delay can be
configured according to the application by using the front panel or Easergy Pro.
Digital inputs can be used in many operations. The status of the input can be
checked in the Output matrix and Digital inputs setting views. The digital inputs
make it possible to change group, block/enable/disable functions, to program
logics, indicate object status, etc.
The digital inputs require an external control voltage (ac or dc). The digital inputs
are activated after the activation voltage is exceeded. Deactivation follows when
the voltage drops below threshold limit. The activation voltage level of digital
inputs can be selected in the order code when such option cards are equipped.
Digital inputs can be connected, latched or unlatched to trip contacts or other
similar purpose in Output matrix setting view.
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Figure 22 - Output matrix view
Digital inputs can be assigned, latched or unlatched directly to inputs/outputs of
logical operators.
Figure 23 - Digital inputs assigned to outputs of logical operators
Digital inputs can be viewed, named and changed between NO/NC in the Digital
inputs and Names for digital inputs setting views.
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Figure 24 - Digital inputs view
If inputs are energized by using ac voltage, “mode” has to be selected as ac.
All essential information on digital inputs can be found in the same location in the
Digital inputs setting view. DI on/off events and alarm display (pop-up) can be
enabled and disabled in Digital inputs setting view. Individual operation counters
are located in the same view as well.
Label and description texts can be edited with Easergy Pro according to the
demand. Labels are the short parameter names used on the local panel and
descriptions are the longer names used by Easergy Pro.
The digital input activation thresholds are hardware-selectable.
Digital input delay determines the activation and de-activation delay for the input.
Figure 25shows how the digital input behaves when the delay is set to 1 second.
Figure 25 - Digital input’s behavior when delay is set to 1 second
1 s.
1 s.
1
0
VOLTAGE
1
DIGITAL INPUT
0
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Table 29 - Parameters of digital inputs
Parameter
Value
Mode
dc, ac
Unit
Description
Note
Used voltage of
Set24)
digital inputs
Input
DI1 – DIx
Number of
digital input. The
available
parameter list
depends on the
number and
type of the I/O
cards.
Slot
2–6
Card slot
number where
option card is
installed.
State
0, 1
Status of digital
input 1 – digital
input x.
Polarity
For normal open Set
NO
contacts (NO).
NC
Active edge is 0
>1
For normal
closed contacts
(NC)
Active edge is 1
>0
Delay
0.00 – 60.00
s
Definite delay
Set
for both on and
off transitions
On event
On
Active edge
Set
event enabled
Off
Active edge
event disabled
Off event
On
Inactive edge
Set
event enabled
Off
Inactive edge
event disabled
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Parameter
Value
Alarm display
no
Unit
Description
Note
No pop-up
Set
display
yes
Alarm pop-up
display is
activated at
active DI edge
Counters
0 – 65535
Cumulative
(Set)
active edge
counter
NAMES for DIGITAL INPUTS (editable with Easergy Pro only)
Label
String of max.
Short name for
10 characters
DIs on the local
Set
display
Default is "DI1 –
DIx". x is the
maximum
number of the
digital input.
Description
String of max.
Long name for
32 characters
DIs. Default is
Set
"Digital input 1 –
Digital input x".
x is the
maximum
number of the
digital input.
24) Set
= An editable parameter (password needed).
Every option card and slot has default numbering. After making any changes to
the numbering, read the settings from the relay after the relay has rebooted.
Below is an example of model P3x30-CGGII-AAEAA-BAAAA showing default
numbering of DI.
You can see the default digital input numbering and change the numbering of the
following option cards in the Inputs/Outputs > Digital inputs setting view: slot 2,
3, 4, 5: G, I.
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Figure 26 - Default numbering of digital inputs for model P3x30-CGGII-AAEAABA
C: G: DI1–6
G: DI7–12
I: DI13–22
I: DI23–32
Figure 27 - Digital inputs setting view
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5.3 Virtual inputs and outputs
There are virtual inputs and virtual outputs that can in many places be used like
their hardware equivalents except that they are located in the memory of the
relay. The virtual inputs act like normal digital inputs. The status of the virtual input
can be changed via the local display, communication bus and Easergy Pro. For
example setting groups can be changed using virtual inputs.
Virtual inputs can be used in many operations. The status of the input can be
checked in the Matrix > Output matrix and Control > Virtual inputs setting
views. The status is also visible on local mimic display, if so selected. Virtual
inputs can be selected to be operated with the function buttons F1 and F2, the
local mimic or simply by using the virtual input menu. Virtual inputs have similar
functions as digital inputs: they enable changing groups, block/enable/disable
functions, to program logics and other similar to digital inputs.
The activation and reset delay of the input is approximately 5 ms.
Table 30 - Virtual inputs and outputs
Number of inputs
20
Number of outputs
20
Activation time / Reset time
< 5 ms
Figure 28 - Virtual inputs and outputs can be used for many purpose in the
Output matrix setting view.
Figure 29 - Virtual inputs and outputs can be assigned directly to inputs/outputs of
logical operators
Notice the difference between latched and non-latched connection.
Virtual inputs and outputs can be used for many purposes in the Output matrix
setting view.
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Virtual inputs and outputs can be assigned, latched or unlatched, directly to
inputs/outputs of logical operators.
Virtual inputs
The virtual inputs can be viewed, named and controlled in the Control > Virtual
inputs setting view.
Figure 30 - Virtual inputs view
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Figure 31 - Names for virtual inputs view
Table 31 - Parameters of virtual inputs
Parameter
Value
VI1-VI20
0
Unit
1
Events
On
Description
Set25)
Status of virtual
input
Event enabling
Set
Off
Names for virtual inputs (editable with Easergy Pro only)
Label
String of max.
Short name for
10 characters
VIs on the local
Set
display
Default is "VIn",
n = 1–20
Description
String of max.
Long name for
32 characters
VIs. Default is
Set
"Virtual input n",
n = 1–20
25) Set
80
= An editable parameter (password needed).
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Virtual outputs
In Easergy Pro, the Virtual outputs setting view is located under Control.
Figure 32 - Virtual outputs view
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Figure 33 - Names for virtual outputs view
Table 32 - Parameters of virtual outputs
Parameter
VO1-VO20
Value
0
Unit
Description
Set26)
Status of virtual output
F
Event enabling
Set
1
Events
On
Off
NAMES for VIRTUAL OUTPUTS (editable with Easergy Pro only)
Label
String of
Short name for VOs on the local
max. 10
display
Set
characte
Description
rs
Default is "VOn", n=1-20
String of
Long name for VOs. Default is
Set
max. 32
characte
"Virtual output n", n=1-20
rs
26) Set
82
= An editable parameter (password needed). F = Editable when force flag is on.
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5.4 Matrix
The relay has several matrices that are used for configuring the relay:
•
Output matrix used to link protection stage signals, digital inputs, virtual
inputs, function buttons, object control, logic output, relay's internal alarms,
GOOSE signals and release latch signals to outputs, disturbance recorder trig
input and virtual outputs
Block matrix used to block protection stages
LED matrix used to control LEDs on the front panel
Object block matrix used to inhibit object control
Auto-recloser matrix used to control auto-recloser
Arc matrix used to control current and light signals to arc stages and arc
stages to the high-speed outputs
•
•
•
•
•
Figure 34 - Blocking matrix and output matrix
Protection stages
I
V
n
Directly
measured
values
Calculate
S, P, Q,
cosφ, tanφ,
symmetric
components
etc.
n
Block matrix
n
Output matrix
START
TRIP
START
TRIP
START
TRIP
BLOCK
INPUT
BLOCK
INPUT
BLOCK
INPUT
n
User’s logic
I
N
P
U
T
S
OUTPUTS
Virtual
inputs
n
Digital
inputs
DI
n
optional
delay
and
inversion
n
Output relays
and indicators
Virtual
outputs
n
Output contacts
NOTE: Blocking matrix can not be used to block the arc flash detection
stages.
5.4.1 Output matrix
There are general-purpose LED indicators – "A", "B", "C" to ”N” – available for
customer-specific indications on the front panel. Their usage is define in a
separate LED matrix.
There are two LED indicators specified for keys F1 and F2. The triggering of the
disturbance recorder (DR) and virtual outputs are configurable in the output
matrix.
A digital output or indicator LED can be configured as latched or non-latched. A
non-latched relay follows the controlling signal. A latched relay remains activated
although the controlling signal releases.
There is a common "release all latches" signal to release all the latched relays.
This release signal resets all the latched digital outputs and indicators. The reset
signal can be given via a digital input, via front panel or remotely through
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communication. For instructions on how to release latches, see 5.5 Releasing
latches.
Trip and alarm relays together with virtual outputs can be assigned in the output
matrix. Also automatic triggering of disturbance recorder is done in the output
matrix.
Figure 35 - Output matrix example view
5.4.2 Blocking matrix
By means of a blocking matrix, the operation of any protection stage (except the
arc flash detection stages) can be blocked. The blocking signal can originate from
the digital inputs or it can be a start or trip signal from a protection stage or an
output signal from the user's programmable logic. In Figure 36, an active blocking
is indicated with a black dot (●) in the crossing point of a blocking signal and the
signal to be blocked.
All protection stages (except Arc stages) can be blocked in the block matrix
Figure 36 - Block matrix view
The Blocked status becomes visible only when the stage is about to activate.
Figure 37 - DI input blocking connection
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Figure 38 - Result for the I> stage when the DI is active and the stage exceeds its
current start value
NOTICE
RISK OF NUISANCE TRIPPING
•
•
The blocking matrix is dynamically controlled by selecting and deselecting
protection stages.
Activate the protection stages first, then store the settings in a relay. After
that, refresh the blocking matrix before configuring it.
Failure to follow these instructions can result in unwanted shutdown of
the electrical installation.
5.4.3 LED matrix
The LED matrix is used to link digital inputs, virtual inputs, function buttons,
protection stage outputs, object statuses, logic outputs, alarm signals and
GOOSE signals to various LEDs located on the front panel.
In the LED configuration setting view, each LED has three checkboxes with
which the behavior of the LED is configured.
Figure 39 - LED configuration
LEDs are assigned to control signals in the LED matrix setting view. It is not
possible to control LEDs directly with logics.
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Figure 40 - LED matrix
Normal setting
With no checkboxes selected, the assigned LED is active when the control signal
is active. After deactivation, the LED turns off. LED activation and deactivation
delay when controlled is approximately 10 ms.
Latch setting
A latched LED activates when the control signal activates but remains active
when the control signal deactivates. Latched LEDs are released using the
procedure described in 5.5 Releasing latches.
Blink setting
When the Blink setting is selected, the LED blinks when it is active.
Store setting
In the LED configuration setting view, you can configure the latched states of
LEDs to be stored after a restart. In Figure 39, storing has been configured for
LED A (green).
NOTE: To use the Store setting, Latch must also be selected.
Inputs for LEDs
Inputs for LEDs can be assigned in the LED matrix. All 14 LEDs can be assigned
as green or red. The connection can be normal, latched or blink-latched. In
addition to protection stages, there are lots of functions that can be assigned to
output LEDs. See Table 33.
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Table 33 - Inputs for LEDs A-N
Input
Detection, Arc and
program-mable stages
Digital/Virtual inputs
and function buttons
Object open/close,
object final trip and
object failure
LED mapping
Latch
LED A–N
Normal/ Latched/
green or red
BlinkLatch
Description
Different type of
Note
Set
detection stages can
be assigned to LEDs
LED A–N
green or red
LED A–N
green or red
Normal/ Latched/
All different type of
BlinkLatch
inputs can be assigned
Set
to LEDs
Normal/ Latched/
Information related to
BlinkLatch
objects and object
Set
control
information
Local control enabled
LED A–N
green or red
Normal/ Latched/
While remote/local
BlinkLatch
state is selected as
Set
local the “local control
enabled” is active
Logic output 1–20
LED A–N
green or red
Manual control
indication
COM 1–5 comm.
LED A–N
green or red
LED A–N
green or red
Setting error, seldiag
alarm, pwd open and
setting change
GOOSE NI1–64
LED A–N
green or red
LED A–N
green or red
GOOSEERR1–16
LED A–N
green or red
Normal/ Latched/
All logic outputs can be Set
BlinkLatch
assigned to LEDs at
the LED matrix
Normal/ Latched/
When the user has
BlinkLatch
controlled the
Set
objectives
Normal/ Latched/
When the
BlinkLatch
communication port 1 -
Set
5 is active
Normal/ Latched/
Self diagnostic signal
Set
Normal/ Latched/
IEC 61850 goose
Set
BlinkLatch
communication signal
Normal/ Latched/
IEC 61850 goose
BlinkLatch
communication signal
BlinkLatch
Set
5.4.4 Object block matrix
The object block matrix is used to link digital inputs, virtual inputs, function
buttons, protection stage outputs, logic outputs, alarm signals and GOOSE
signals to inhibit the control of objects, that is, circuit breakers, isolators and
grounding switches.
Typical signals to inhibit controlling of the objects like circuit breaker are:
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•
•
•
•
protection stage activation
statuses of other objects
interlocking made with logic
GOOSE signals
These and other signals are linked to objects in the object block matrix.
There are also event-type signals that do not block objects as they are on only for
a short time, for example "Object1" open and "Object1 close" signals.
5.5 Releasing latches
You can release latches using:
• Easergy Pro
• buttons and local panel display
• F1 or F2 buttons
5.5.1 Releasing latches using Easergy Pro
1. Connect Easergy Pro to the device.
2. From the Easergy Pro toolbar, select Device > Release all latches.
Figure 41 - Releasing all latches
Alternatively, go to Control > Release latches, and click the Release button.
Figure 42 - Release latches
5.5.2 Releasing latches using buttons and local panel display
Prerequisite: You have entered the correct password
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1. Press
2. Press
.
.
3. Select Release, and press
All latches are released.
.
5.5.3 Releasing latches using F1 or F2 buttons
You can use the function buttons F1 or F2 to release all latches after configuring
this function in Easergy Pro. You can make the configuration either under Control
> Release Latches or under Control > Function buttons.
•
To configure F1 to release latches under Control > Release latches:
a. In Easergy Pro, go to Control > Release latches.
b. Under Release latches, select F1 from the DI to release latches dropdown menu.
c. Set 1 s delay for Latch release signal pulse.
Figure 43 - Release latches view
•
After this, pressing the F1 button on the relay’s front panel releases all
latches.
To configure F1 to release latches under Control >Function buttons:
a. Under Function buttons, for F1, select PrgFncs from the Selected
control drop down menu.
b. Set 1 s delay for F1 pulse length.
c. Under Programmable functions for F1, select “On” from the Release all
latches drop-down menu.
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Figure 44 - Function buttons view
After this, pressing the F1 button on the relay's front panel releases all
latches.
NOTE: The latch release signal can be activated only if the latched
output is active.
5.6 Controllable objects
The relay allows controlling eight objects, that is, circuit breakers, disconnectors
and grounding switches by the "select before operate" or "direct control" principle.
Controlling is possible in the following ways:
•
•
•
•
•
•
•
through the object control buttons
through front panel and display using single-line diagram
through the function keys
through digital input
through remote communication
through Easergy Pro setting tool
through Smart APP
The connection of an object to specific controlling outputs is done via an output
matrix (object 1–8 open output, object 1–8 close output). There is also an output
signal “Object failed” that is activated if the control of an object is not completed.
Object states
Each object has the following states:
Setting
Value
Description
Object state
Undefined (00)
Actual state of the object
Open
Close
Undefined (11)
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Basic settings for objects
Each object has the following settings:
Setting
Value
DI for ‘obj open’
DI for ‘obj close’
None, any digital input,
virtual input or virtual output
DI for ‘obj ready’
Max ctrl pulse length
Description
Open information
Close information
Ready information
0.02–600 s
Pulse length for open and
close commands. Control
pulse stops once object
changes its state
Completion timeout
0.02–600 s
Timeout of ready indication
Object control
Open/Close
Direct object control
If changing the states takes longer than the time defined by the “Max ctrl pulse
length” setting, the object is inoperative and the “Object failure” matrix signal is
set. Also, an undefined event is generated. “Completion timeout” is only used for
the ready indication. If “DI for ‘obj ready’” is not set, the completion timeout has no
meaning.
Output signals of objects
Each object has two control signals in matrix:
Output signal
Description
Object x Open
Open control signal for the object
Object x Close
Close control signal for the object
These signals send control pulse when an object is controlled by digital input,
remote bus, auto-reclose etc.
5.6.1 Object control with digital inputs
Objects can be controlled with digital inputs, virtual inputs or virtual outputs. There
are four settings for each object:
Setting
Active
DI for remote open / close control
In remote state
DI for local open / close control
In local state
If the relay is in local control state, the remote control inputs are ignored and vice
versa. An object is controlled when a rising edge is detected from the selected
input. The length of digital input pulse should be at least 60 ms.
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5.6.2 Local or remote selection
In local mode, digital outputs can be controlled via the front panel but they cannot
be controlled via a remote serial communication interface.
In remote mode, digital outputs cannot be controlled via a front panel but they can
be controlled via a remote serial communication interface.
The local or remote mode can be selected by using the front panel or via one
selectable digital input. The digital input is normally used to change a whole
station to local or remote mode. You can select the L/R digital input in the Control
> Objects setting view in Easergy Pro.
Table 34 - Local or remote selection
Action
Control through Easergy Pro Control through
or SmartApp
communication protocol
Local/Remote
Local
Remote
Local
Remote
CB control
Yes
No
No
Yes
Setting or
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
No
No
Yes
switch status
configuration
changes
Communication
configuration
Virtual inputs 27) Yes
27) Virtual
inputs have a general parameter “Check L/R selection” for disabling the L/R check.
5.6.3 Object control with Close and Trip buttons
The relay also has dedicated control buttons for objects. Close stands for object
closing and Trip controls object open command internally. Control buttons are
configured in the Control > Objects setting view.
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Table 35 - Parameters of function keys
Parameter
Value
Object for
Obj1–Obj8
Unit
Description
Set
Set
control buttons
Button
closes selected
object if
password is
enabled
Button
opens selected
object if
password is
enabled
Mode for control Selective
Control
butons
operation needs
Direct
confirmation
(select-execute)
Control
operation is
done without
confirmation
5.6.4 Object control with F1 and F2
Objects can be controlled with the function buttons F1 and F2.
By default, the F1 and F2 buttons are configured to control F1 and F2 variables
that can further be assigned to control objects.
Table 36 - Parameters of F1 and F2
Parameter
Value
State
Pulse
length
F1
F1, V1-V20,
0.1
0600 s
ObjCtrl
Description
28)
controls F1,
V1-V20 or
ObjCtrl
parameters.
F2
F2, V1-V20,
0.1
ObjCtrl
0-600 s
controls F2,
V1-V20 and
ObjCtrl
parameters.
28) Pulse
length applies to values F1 and F2 only
You can configure the button funtions in the Control > Function buttons setting
view in Easergy Pro.
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Figure 45 - Function buttons view
If ObjCtrl has been selected under Selected control, the selected object is
shown under Selected object. Otherwise, this column is empty.
When selecting ObjCtrl, link the function button to the appropriate object in the
Control > Objects setting view.
Figure 46 - Ctrl object 2 view
5.7 Logic functions
The relay supports customer-defined programmable logic for boolean signals.
User-configurable logic can be used to create something that is not provided by
the relay as a default. You can see and modify the logic in the Control > Logic
setting view in the Easergy Pro setting tool.
Table 37 - Available logic functions and their memory use
Logic functions
No. of gates
reserved
AND
1
OR
1
XOR
1
AND+OR
2
Max. no. of input Max. no. of logic
gates
outputs
32
94
(An input gate can
include any number
20
of inputs.)
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Logic functions
No. of gates
reserved
CT (Count+Reset)
2
INVAND
2
INVOR
2
OR+AND
2
RS (Reset+Set)
2
RS_D (Set D+Load
4
Max. no. of input Max. no. of logic
gates
outputs
+Reset)
The consumed memory is dynamically shown on the configuration view in
percentage. The first value indicates the memory consumption of inputs, the
second value the memory consumption of gates and the third value the memory
consumption of outputs.
The logic is operational as long the memory consumption of the inputs, gates or
outputs remains individually below or equal to 100%.
Figure 47 - Logic and memory consumption
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Truth tables
Table 38 - Truth table
Gate
AND
Symbol
A
Y
&
A
Y
&
A
Y
&
Truth table
In
Out
A
Y
0
0
1
1
In
Out
A
Y
0
1
1
0
In
Out
A
B
Y
0
1
0
1
0
0
1
1
1
0
0
0
B
A
Y
&
B
AND+OR
A
Y
&
>1
B
96
In
Out
A
B
Y
0
1
1
1
0
1
1
1
0
0
0
1
In
Out
A
B
Y
0
0
0
1
1
1
1
0
1
0
1
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A
B
Reset
CT (Count+Reset)
Symbol
Count
Gate
Truth table
In
Out
Y
CT
A
B
Y
Cou
Rese Setti
nt
t
A
Y
¬&
B
INVOR
A
Y
¬>1
B
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ng
1
3
0
1
3
0
1
3
1
3
0
1
INVAND
Y
In
Out
A
B
Y
0
0
0
1
0
1
1
1
0
0
1
0
In
Out
A
B
Y
0
0
1
1
1
1
1
0
1
0
1
0
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Gate
Symbol
OR
Y
A
>1
B
Y
A
In
Out
A
B
Y
0
0
0
1
1
1
1
0
1
0
1
1
In
>1
B
A
B
Truth table
Out
A
B
Y
0
0
1
1
1
0
1
0
0
0
1
0
In
>1
Out
Y
A
B
C
Y
0
0
0
1
1
1
0
1
1
0
0
1
0
1
0
1
1
1
1
1
C
A
B
>1
Y
In
Out
A
B
C
Y
0
0
0
1
1
0
0
0
1
1
0
0
0
1
0
0
1
1
1
0
C
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Gate
OR+AND
Symbol
A
Y
&
>1
B
B
In
Out
A
B
Y
0
0
0
1
1
1
1
0
0
0
1
0
In
Set
A
Reset
RS (Reset+Set)
Truth table
RS
Out
Y
A
B
Y
Set
Reset
Y
1
0
1
0
0
129)
0
0
030)
X
1
031)
29) Output
= 1 (latched), if
previous state was 1, 0, 1.
30) Output = 0, if previous state
was X, 1, 0.
31) Output = 0, if RESET = 1
regardless of state of SET.
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Gate
Symbol
RS_D (Set+D+Load+Reset)
Truth table
C
D
Reset Load D Set
A
A
B
R
S
D
B
Set D
Y
C
D
Y
Loa Re
Stat
d
set
e
0
0
0
0
032)
1
X
X
0
1
1
X
X
1
0
0
1
0
0
0
0
1
1
0
1
0
1
1
1
033)
32) Initial
state
state remains 1 until
Reset is set active
33) The
X = Any state
If Set or D + Load are high,
the state returns to high if
Reset returns to low.
XOR
In
A
B
=1
Y
C
Out
A
B
C
Y
0
0
0
0
0
0
1
1
0
1
0
1
0
1
1
0
1
0
0
1
1
0
1
0
1
1
0
0
1
1
1
1
29) Output
= 1 (latched), if previous state was 1, 0, 1.
= 0, if previous state was X, 1, 0.
31) Output = 0, if RESET = 1 regardless of state of SET.
32) Initial state
33) The state remains 1 until Reset is set active
30) Output
Logic element properties
After you have selected the required logic gate in Easergy Pro, you can change
the function of the gate in the Element properties window by clicking the gate.
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Figure 48 - Logic element properties
Table 39 - Settings available for the logical gates depending on the selected
element
Property
Description
Element properties
Type
Change the logical function of the gate
Inverted
Inverts the output state of the logical gate
ON delay
Time delay to activate the output after
logical conditions are met
OFF delay
Time delay for how long the gate remain
active even the logical condition is reset
Count
Setting for counter (CT gate only)
Reverse
Use to reverse AND and OR gates (AND
+OR gate only)
Inputs
Normal - / +
Use to increase or decrease number of
inputs
Inverting - / +
Use to increase or decrease number of
inverted inputs. This setting is visible for
INVAND and INVOR gates only
Count
Use to increase or decrease number of
count inputs (CT gate only)
Reset
Use to increase or decrease number of
count inputs (CT gate only)
AND
Use to increase or decrease number of
inputs for AND gates (AND+OR gate only)
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Property
Description
OR
Use to increase or decrease number of
inputs for OR gates (AND+OR gate only)
Set
Use to increase or decrease number of Set
inputs (RS_D gate only)
D
Use to increase or decrease number of
Data inputs (RS_D gate only)
Load
Use to increase or decrease number of
Load inputs (RS_D gate only)
Reset
Use to increase or decrease number of
Reset inputs (RS_D gate only)
5.8 Local panel
Easergy P3T32 has one LCD matrix display.
All the main menus are located on the left side of the display. To get to a
submenu, move up and down the main menus.
Figure 49 - Local panel's main menu
5.8.1 Mimic view
The mimic view is set as the local panel's main view as default. You can modify
the mimic according to the application or disable it, if it is not needed, via the
Easergy Pro setting tool.
You can modify the mimic in the General > Mimic setting view in Easergy Pro
and disable the mimic view in the General > Local panel conf setting view.
NOTE: The mimic itself or the local mimic settings cannot be modified via the
local panel.
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Figure 50 - Mimic view
C
A
B
F
I
G
H
F
J
D
E
I
A. To clear an object or drawing, first point an
empty square (A) with the mouse. Then point the
object item with the mouse. The color of the object
item turns red. To clear the whole mimic, click on
the empty area.
B. Text tool
C. To move an existing drawing or object, point it
with the mouse. The color turns green. Hold down
the left mouse button and move the object.
D. Different type of configurable objects. The
object's number corresponds to the number in
Control > Objects.
E. Some predefined drawings.
F. The remote/local selection defines whether
certain actions are granted or not. In remote
state, it is not possible to locally enable or
disable auto-reclosing or to control objects. The
remote/local state can be changed in Control >
Objects.
G. Creates auto-reclosing on/off selection to
mimic.
H. Creates virtual input activation on the local
mimic view.
I. Describes the relay's location. Text comes
from the relay info menu.
J. Up to six configurable measurements.
Table 40 - Mimic functionality
Parameter
Value
Sublocation
Text field
Unit
Description
Set
Up to 9
Set
characters.
Fixed location.
Object 1–8
1–8
Double-click on
Set
top of the object
to change the
control number
between 1 and
8. Number 1
corresponds to
object 1 in
General >
Objects.
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Parameter
Value
Remote/Local
L
mode
R
Unit
Description
Set
Local / Remote
Set
control. R
stands for
remote. Remote
local state can
be changed in
General >
Objects as well.
Position can be
changed.
Auto reclosing
0
1
Possible to
Set
enable/disable
auto-reclosure
localy in local
mode (L) or
remotely in
remote mode
(R). Position
can be
changed.
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Parameter
Value
Measurement
display 1–6
Description
Set
IA–IC
Up to 6 freely
Set
IN
selectable
VAB, VBC,
Unit
measurements.
VCA, VA, VB,
VC, VN
f, P, Q, S,
P.F.
CosPhi
E+, Eq+, E-,
EqARStart,
ARFaill,
ARShot1–5
IFLT
Starts, Trips
IN Calc
IA–ICda, IL
Pda, Qda,
Sda
T
fSYNC,
VSYNC
IA-2–IC–2
dIL1–dIL3
dIA–IC
VAI1–VAI5
ExtAI1–634)
Virtual input 1–
12
0
1
Change the
Set
status of virtual
inputs while the
password is
enabled.
Position can be
changed.
34) Requires
serial communication interface and External IO protocol activated.
Set = Settable.
NOTE: The measurement view's data selection depends on the voltage
measurement mode selected in the General > Scaling setting view.
5.8.2 Local panel configuration
You can modify the local panel configuration in the General > Local panel conf
setting view in Easergy Pro.
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Figure 51 - Local panel configuration view
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Table 41 - Local panel configuration parameters
Parameter
Value
Display 1–5
ILA-C
Unit
Description
Set35)
20 (5 x 4) freely
Set37)
configurable
IN
measurement
VAB, VBC, VCA,
values can be
VA, VB, VC, VN
selected
f, P, Q, S, P.F.
CosPhi
E+, Eq+, E-, EqARStart,
ARFaill,
ARShot1–5
IFLT
Starts, Trips
IN Calc
Phase
currents
IA–Cda
IA–C max
IA–C min
IA–CdaMax
Pda, Qda,
Sda
T
fSYNC,
VSYNC
IA-2–IC-2
dIA–C
VAI1–5
ExtAI1–636)
SetGrp
Display contrast 50–210
Contrast can be
Set
changed in the
relay menu as
well.
Display
DI1–44, Arc1–3,
backlight control ArcF, BI, VI1–4,
LED1–14, VO1–
Activates the
Set37)
backlight of the
display.
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Parameter
Value
Unit
Description
Set35)
Panel reset
Value range:
min
Configurable
Set
timeout
0.0–2000.0
delay for the
front panel to
Default value:
return to the
15.0
default screen
when the front
panel is not
used.
When this value
is zero (0.0),
this timeout
never occurs.
Default screen
Value range:
Default screen
Mimic, Meas
for the front
disp1, Meas
panel.
disp2, Meas
Set
If the selected
disp3, Meas
screen would
disp4, Meas
result in a blank
disp5
screen, the title
Default value:
screen is used
Mimic
as the default
screen.
Backlight off
0.0–2000.0
timeout
min
Configurable
Set
delay for
backlight to
turns off when
the relay is not
used. Default
value is 60
minutes. When
value is zero
(0.0) backlight
stays on all the
time.
Enable alarm
screen
Selected
Unselected
Pop-up text box
Set
for events. popup events can
be checked
individually by
pressing enter,
but holding the
button for 2
seconds checks
all the events at
once.
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Parameter
Value
AR info for
Selected
mimic display
Unit
Description
Set35)
Auto reclosure
Set
status visible on
Unselected
top of the local
mimic view.
Sync I info for
mimic display
Selected
Synchro-check
Set
status visible on
Unselected
top of the local
mimic view.
Operates
together with
auto-reclosure.
Auto LED
release
Selected
Enables
Set
automatix LED
Unselected
release
functionality.
Auto LED
0.1–600
s
Default 1.5 s.
release enable
When new
time
LEDs are
Set
latched, the
previous active
latches are
released
automatically if
the set time has
passed.
Fault value
scaling
PU, Pri
Fault values per Set
unit or primary
scsaled.
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Parameter
Value
Local MIMIC
Selected
Unselected
Unit
Description
Set35)
Enable or
Set
disable the local
mimic (enabled
as default).
When selected,
the mimic is the
local panel's
default main
view. When
unselected, the
measurement
view is the
default main
view.
Event buffer
size
50–2000
Event buffer
Set38)
size. Default
setting is 200
events.
35) Set
= Settable
serial communication interface and External IO protocol activated.
37) Inputs vary according to the relay type.
38) The existing events are lost if the event buffer size is changed.
36) Requires
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Each protection stage can independently be enabled or disabled according to the
requirements of the intended application.
NOTE: When protection stages are enabled or disabled, the disturbance
recordings are deleted from the relay's memory. Therefore, before activating
or deactivating stages, store the recordings in your PC.
6.1 Current transformer requirements for overcurrent elements
The current transformer (CT) must be sized according to the rules described here
for definite time (DT) or inverse definite minimum time (IDMT) to avoid saturation
during steady-state short-circuit currents where accuracy is required.
The nominal CT primary and secondary must be selected according to the
maximum short-circuit secondary current to meet the thermal withstand specified
in Table 157.
The condition to be fulfilled by the CT saturation current (Isat) depends on the type
of overcurrent protection operate time.
Table 42 - Condition to be fulfilled by CT saturation current
Time delay
Condition to be fulfilled
DT
Isat > 1.5 x set point (Is)
IDMT
Isat > 1.5 x the curve value which is the smallest of these two values:
• Isc max., maximum installation short-circuit current
• 20 x Is (IDMT curve dynamic range)
Figure 52 - Overcurrent characteristics
A
B
t
t
Is
Isat
I
Is
Isat
I
C D
A. DT
C. Minimum (Isc max., 20 Is)
B. IDMT
D. 1.5 minimum (Isc max., 20 Is)
The method for calculating the saturation current depends on the CT accuracy
class.
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6.1.1 CT requirements when settings are unknown
If no other information about the settings is available, these characteristics are
suitable for most situations.
Class P accuracy class
Table 43 - CT requirements
Rated
secondary
current (Ins)
Rated burden Accuracy
class and
(VAct)
accuracy
limit factor
CT
secondary
resistance
(Rct)
Wiring
resistance
(Rw)
1A
2.5 VA
5P20
<3Ω
< 0.075 Ω
5A
7.5 VA
5P20
< 0.2 Ω
< 0.075 Ω
Class PX accuracy class
Vk / (Rct + Rw) > 30 x Ins
For 1 A: Vk > 30 x (Rct + Rw); for example: 30 x 3.9 = 117 V
For 5 A: Vk > 150 x (Rct + Rw); for example: 150 x 0.53 = 79.5 V
6.1.2 Principle for calculating the saturation current in class P
A class P CT is characterized by:
• Inp: rated primary current (in A)
•
Ins: rated secondary current (in A)
•
•
accuracy class, expressed by a percentage, 5P or 10P, followed by the
accuracy limit factor (ALF), whose usual values are 5, 10, 15, 20, 30
VAct: rated burden, whose usual values are 2.5/5/7.5/10/15/30 VA
•
Rct: maximum resistance of the secondary winding (in Ω)
The installation is characterized by the load resistance Rw at the CT secondary
(wiring + protection device). If the CT load complies with the rated burden, that is,
Rw x Ins2 <= VAct, the saturation current is higher than ALF x Inp.
If the resistance Rct is known, it is possible to calculate the actual CT ALF which
takes account of the actual CT load. The saturation current equals the actual ALF
x Inp.
Equation 3
Actual ALF = ALF ×
Rct × Ins2 + VAct
(Rct + Rw) × Ins2
6.1.3 Examples of calculating the saturation current in class P
The saturation current for a CT is calculated with:
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•
•
•
•
transformation ratio: 100 A/5 A
rated burden: 2.5 VA
accuracy class and accuracy-limit factor: 5P20
resistance of the secondary winding: 0.1 Ω
To have an ALF of at least 20, that is, a saturation current of 20 x Inp = 2 kA, the
load resistance Rw of the CT must be less than Equation 4.
Equation 4
Rw, max =
VAct
2.5
= 0.1Ω
2 =
Ins
52
This represents 12 m (39 ft) of wire with cross-section 2.5 mm² (AWG 14) for a
resistance per unit length of approximately 8 Ω/km (2.4 mΩ/ft). For an installation
with 50 m (164 ft) of wiring with section 2.5 mm² (AWG 14), Rw = 0.4 Ω.
As a result, the actual ALF is as presented in Equation 5.
Equation 5
Actual ALF = ALF ×
Rct × Ins2 + VAct
0.1 × 25 + 2.5
= 20×
=8
(Rct + Rw) × Ins2
(0.1 + 0.4) × 25
Therefore, the saturation current Isat = 8 x Inp = 800 A.
NOTE: The impedance of an Easergy P3 protection device's current inputs
(0.004 Ω) is often negligible compared to the wiring resistance.
6.1.4 Principle for calculating the saturation current in class PX
A class PX CT is characterized by:
• Inp: rated primary current (in A)
•
Ins: rated secondary current (in A)
•
Vk: rated knee-point voltage (in V)
•
Rct: maximum resistance of the secondary winding (in Ω)
The saturation current is calculated by the load resistance Rw at the CT
secondary (wiring + protection device) as shown in Equation 6.
Equation 6
Isat =
P3T/en M/J006
Inp
Vk
×
Rct + Rw Ins
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6.1.5 Examples of calculating the saturation current in class PX
Table 44 - Examples of calculating the saturation current in class PX
CT
Transformati
on ratio
Vk
Rct
Rw
Saturation
current
100 A/1 A
90 V
3.5 Ω
0.4 Ω
Isat = 90 / (3,5 +
0,4) / 1 x Inp =
23,08 x Inp
100 A/5 A
60 V
0.13 Ω
0.4 Ω
Isat = 60 / (0,13
+ 0,4) / 5 x Inp =
22,6 x Inp
6.1.6 CT requirements for REF protection
Two REF schemes are possible: the Low impedance REF and the High
impedance REF.
The Low impedance REF protection should be used with power networks X/R
only up to 15.
The formula for the CT requirements is
Vk > K * ISEC * (RCT + RB), where
ISEC = 1A or 5A, secondary ratio of the CT
‘K’ depends on X/R and the maximum through-fault current (three-phase fault
current) as defined in Table 45.
Table 45 - K factor
K value
Fault current (xIn)
<=7
<=10
<=15
X/R <= 10
45
60
70
X/R <= 15
55
70
80
X/R > 15
Not applicable; use the High Z REF.
For power system with an X/R ratio above 15, or when the above CT
requirements cannot be met, the high impedance REF protection shall be used
instead.
The CT requirements for high impedance REF are given in the Application Note
"P3APS17016EN_(HiZ-REF_87N)".
NOTE: The high impedance REF must use a different winding of the primary
CT than the Transformer Differential.
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6.2 Current transformer requirements for generator and
transformer block differential protection
NOTE: These current transformer (CT) requirements are applicable from
firmware version FW30.204 onward.
The CT requirements are based on the following settings:
Table 46 - CT settings
Parameter
Value
dI> pickup (Ibias < 0.5 Ign)
20% of In
Slope1
50%
Ibias for start of slope 2
2 x In
Slope2
150%
dI> 2nd harmonics block limit
10%
For maximum sub-synchronous through fault up to 7 In
P3G CT requirements from firmware 30.204 for generator differential protection
apply.
For maximum sub-synchronous through fault above 7 In
Class PX and class P CTs are recommended.
For maximum sub-synchronous through fault above 7 In and below 9 In, K = 25.
For maximum sub-synchronous through fault above 9 In, K = 30.
CT requirements for class PX
The minimum knee point voltage is Vk = K x Isr x (RCT + 2RL + Rr).
Vk = Minimum current transformer knee-point voltage
Isr = Secondary rated current (1A or 5A)
RCT = Resistance of current transformer secondary winding (Ω)
RL = Resistance of a single lead from relay to current transformer (Ω)
Rr = Resistance of all protective relays sharing the current transformer (Ω)
CT requirements for class P CT (5P10 for example)
The minimum rated burden is SVA > ((K / Kalf) x (RCT + Rba) – RCT) x Isr2
where kalf is the CT accuracy limit factor (i.e. 20 for 5P20, i.e. 10 for 5P10)
Rba = Actual burden = 2RL + Rr (Ω)
NOTE: The sub-synchronous value is ip.
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Figure 53 - Fault current
A
B
C
E
F
D
G
I
H
IEC 1263/2000
A. Current
F. Ip
B. Top envelope
C. d.c. component Id.c. of the short-circuit current
G. A
H. Bottom envelope
D. 2√2 I’k
I. Time
E. 2√2 Ik
6.3 Current transformer requirements for transformer differential
protection
This topic describes the current transformer requirements for transformer
differential protection applicable for star-star and star-delta transformers.
NOTE: These current transformer (CT) requirements are applicable from
firmware version FW30.204 onward.
For accuracy, class PX or class 5P CTs are recommended but TPY or 5PR can
also be used.
The CT requirements are based on the following settings based on the rated
current of the transformer “In”:
Table 47 - CT settings
Parameter
Value
dI> pickup (Ibias < 0.5 Ign)
20% of In
Slope1
50%
Ibias for start of slope 2
2 x In
Slope2
150%
dI> 2nd harmonics block limit
10%
The maximum through fault measured by the protection device must be limited to
15 In. Thus, choose the CT ratio carefully to meet this requirement. With a
through fault flowing from both sides, choose the highest one.
Determination of K for star-star transformers
For power network X/R up to 10 and for all the above-listed CT classes, K = 30.
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For power network X/R from 11 to 60:
• For TPX and class P CTs, K = 55
• For TPY and class PR CTs:
◦ For through faults up to 7 In, K = 30
◦ For through faults from 7 In to 15 In, K = 40
Table 48 - Determination of K for star-star transformers
Through fault current (up to)
7
X/R up to 10
15
30
TPX - 5P
TPY - 5PR
X/R up to 60
TPX - 5P
55
TPY - 5PR
30
40
Determination of K for star-delta transformers
For power network X/R up to 10 and for all above CT classes:
•
•
For through fault up to 7 In, K = 30
For through fault from 7 In to 15 In, K = 33
For power network X/R from 11 to 60,
•
•
For TPX and class P CTs, K = 55
◦ For through fault up to 5 In, K = 55
◦ For through fault from 5 In to 15 In, K = 70
For TPY and class PR CTs:
◦ For through fault up to 7 In, K = 30
◦ For through fault from 7 In to 15 In, K = 40
Table 49 - Determination of K for star-delta transformers
Through fault current (up to)
5
X/R up to 10
7
15
30
TPX - 5P
33
TPY - 5PR
X/R up to 60
TPX - 5P
TPY - 5PR
55
70
30
40
CT requirements for class PX and PY
K = 20
The minimum knee-point voltage is Vk = K x Isr x (RCT + 2RL + Rr).
Vk = Minimum current transformer knee-point voltage
Isr = Secondary rated current (1A or 5A)
RCT = Resistance of current transformer secondary winding (Ω)
RL = Resistance of a single lead from relay to current transformer (Ω)
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Rr = Resistance of all protective relays sharing the current transformer (Ω)
CT requirements for class P or PR CT ( for example 5P10)
K = 20
The minimum rated burden is SVA > ((K / Kalf) x (RCT + Rba) – RCT) x Isr2
where Kalf is the CT accuracy limit factor (20 for 5P20, 10 for 5P10)
Rba = Actual burden = 2 RL + Rr (Ω)
6.4 Maximum number of protection stages in one application
The relay limits the maximum number of enabled protection stages to about 30.
The exact number depends on the central processing unit's load consumption and
available memory as well as the type of the stages.
The individual protection stage and total load status can be found in the
Protection > Protection stage status setting view in the Easergy Pro setting
tool.
6.5 General features of protection stages
Setting groups
Setting groups are controlled by using digital inputs, function keys or virtual
inputs, via the front panel or custom logic. When none of the assigned inputs are
active, the setting group is defined by the parameter ‘SetGrp no control state’.
When controlled input activates, the corresponding setting group is activated as
well. If the control signal of the setting group is lost, the setting “Keep last” forces
the last active group into use. If multiple inputs are active at the same time, the
active setting group is defined by ‘SetGrp priority’. By using virtual I/O, the active
setting group can be controlled using the local panel display, any communication
protocol or the built-in programmable logic functions. All protection stages have
four setting groups.
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Figure 54 - Setting groups view
Example
Any digital input can be used to control setting groups but in this example, DI1,
DI2, DI3 and DI4 are chosen to control setting groups 1 to 4. This setting is done
with the parameter “Set group x DI control” where x refers to the desired setting
group.
Figure 55 - DI1, DI2, DI3, DI4 configured to control Groups 1 to 4 respectively
Use the 'SetGrp common change' parameter to force all protection stages to
group 1, 2, 3 or 4. The control becomes active if there is no local control in the
protection stage. You can activate this parameter using Easergy Pro.
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“SetGrp priority” is used to give a condition to a situation where two or more
digital inputs, controlling setting groups, are active at the same time. SetGrp
priority could have values “1 to 4” or “4 to 1”.
Figure 56 - SetGrp priority setting in the Valid Protection stages view
Assuming that DI2 and DI3 are active at the same time and SetGrp priority is set
to “1 to 4”, setting group 2 becomes active. If SetGrp priority is reversed, that is,
set to “4 to 1”, the setting group 3 becomes active.
Protection stage statuses
The status of a protection stage can be one of the followings:
•
Ok = ‘-‘
•
The stage is idle and is measuring the analog quantity for the protection. No
power system fault detected.
Blocked
•
The stage is detecting a fault but blocked for some reason.
Start
•
The stage is counting the operation delay.
Trip
The stage has tripped and the fault is still on.
The blocking reason may be an active signal via the block matrix from other
stages, the programmable logic or any digital input. Some stages also have builtin blocking logic. For more details about the block matrix, see 5.4.2 Blocking
matrix.
Protection stage counters
Each protection stage has start and trip counters that are incremented when the
stage starts or trips. The start and trip counters are reset on relay reboot.
Forcing start or trip condition for testing purposes
There is a "Forcing flag" parameter which, when activated, allows forcing the
status of any protection stage to be "start" or "trip" for half a second. By using this
forcing feature, current or voltage injection is not necessary to check the output
matrix configuration, to check the wiring from the digital outputs to the circuit
breaker and also to check that communication protocols are correctly transferring
event information to a SCADA system.
After testing, the forcing flag is automatically reset five minutes after the last local
panel push button activity.
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The force flag also enables forcing the digital outputs and the optional mA
outputs.
The force flag can be found in the Device/Test > Relays setting view.
Figure 57 - Force flag
Start and trip signals
Every protection stage has two internal binary output signals: start and trip. The
start signal is issued when a fault has been detected. The trip signal is issued
after the configured operation delay unless the fault disappears before the end of
the delay time.
The hysteresis, as indicated in the protection stage's characteristics data, means
that the signal is regarded as a fault until the signal drops below the start setting
determined by the hysteresis value.
hysteresis
Figure 58 - Behavior of a greater than comparator (for example, the hysteresis
(dead band) in overvoltage stages)
Hysteresis_GT
Start level
> Start
Output matrix
Using the output matrix, you can connect the internal start and trip signals to the
digital outputs and indicators. For more details, see 5.4.1 Output matrix.
Blocking
Any protection function, except for arc flash detection, can be blocked with
internal and external signals using the block matrix (5.4.2 Blocking matrix).
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Internal signals are for example logic outputs and start and trip signals from other
stages and external signals are for example digital and virtual inputs.
Some protection stages have also built-in blocking functions. For example underfrequency protection has built-in under-voltage blocking to avoid tripping when the
voltage is off.
When a protection stage is blocked, it does not start if a fault condition is
detected. If blocking is activated during the operation delay, the delay counting is
frozen until the blocking goes off or the start reason, that is the fault condition,
disappears. If the stage is already tripping, the blocking has no effect.
Dependent time operation
The operate time in the dependent time mode is dependent on the magnitude of
the injected signal. The bigger the signal, the faster the stage issues a trip signal
and vice versa. The tripping time calculation resets if the injected quantity drops
below the start level.
Definite time operation
Figure 59 - Dependent time and definite time operation curves
IDMT
DT
t (s)
If (A)
The operate time in the definite time mode is fixed by the Operation delay
setting. The timer starts when the protection stage activates and counts until the
set time has elapsed. After that, the stage issues a trip command. Should the
protection stage reset before the definite time operation has elapsed, then the
stage resets.
By default, the definite time delay cannot be set to zero because the value
contains processing time of the function and operate time of the output contact.
This means that the time indicated in the Definite time setting view is the actual
operate time of the function. Use the Accept zero delay setting in the protection
stage setting view to accept the zero setting for definite time function. In this case,
the minimum operate time of the function must be tested separately.
Overshoot time
Overshoot time is the time the protection device needs to notice that a fault has
been cleared during the operate time delay. This parameter is important when
grading the operate time delay settings between devices.
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Figure 60 - Overshoot time
RetardationTime
tFAULT
tRET < 50 ms
DELAY SETTING > tFAULT + tRET
TRIP CONTACTS
If the delay setting would be slightly shorter, an unselective trip might occur (the
dash line pulse).
For example, when there is a big fault in an outgoing feeder, it might start both the
incoming and outgoing feeder relay. However, the fault must be cleared by the
outgoing feeder relay and the incoming feeder relay must not trip. Although the
operating delay setting of the incoming feeder is more than at the outgoing feeder,
the incoming feeder might still trip if the operate time difference is not big enough.
The difference must be more than the overshoot time of the incoming feeder relay
plus the operate time of the outgoing feeder circuit breaker.
Figure 60 shows an overvoltage fault seen by the incoming feeder when the
outgoing feeder clears the fault. If the operation delay setting would be slightly
shorter or if the fault duration would be slightly longer than in the figure, an
unselective trip might happen (the dashed 40 ms pulse in the figure). In Easergy
P3 devices, the overshoot time is less than 50 ms.
Reset time
Figure 61 shows an example of reset time, that is, release delay when the relay is
clearing an overcurrent fault. When the relay’s trip contacts are closed, the circuit
breaker (CB) starts to open. After the CB contacts are open, the fault current still
flows through an arc between the opened contacts. The current is finally cut off
when the arc extinguishes at the next zero crossing of the current. This is the start
moment of the reset delay. After the reset delay the trip contacts and start contact
are opened unless latching is configured. The precise reset time depends on the
fault size; after a big fault, the reset time is longer. The reset time also depends
on the specific protection stage.
The maximum reset time for each stage is specified under the characteristics of
every protection function. For most stages, it is less than 95 ms.
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Figure 61 - Reset time
tSET
tCB
tRESET
TRIP CONTACTS
Reset time is the time it takes the trip or start relay contacts to open after the fault
has been cleared.
Hysteresis or dead band
When comparing a measured value against a start value, some amount of
hysteresis is needed to avoid oscillation near equilibrium situation. With zero
hysteresis, any noise in the measured signal or any noise in the measurement
itself would cause unwanted oscillation between fault-on and fault-off situations.
hysteresis
Figure 62 - Example behavior of an over-protection with hysteresis
Hysteresis_GT
Start level
> Start
Figure 63 - Example behavior of an under-protection with hysteresis
hysteresis
Hysteresis_LT
Start level
< Start
Time grading
When a fault occurs, the protection scheme only needs to trip circuit breakers
whose operation is required to isolate the fault. This selective tripping is also
called discrimination or protection coordination and is typically achived by time
grading. Protection systems in successive zones are arranged to operate in times
that are graded through the sequence of equipment so that upon the occurrence
of a fault, although a number of protections devices respond, only those relevant
to the faulty zone complete the tripping function.
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The recommended discrimination time between two Easergy P3 devices in an MV
network is 170–200 ms. This is based on the following facts:
• Tc: circuit breaker operating time, 60 ms
•
Tm: upstream protection overshoot time (retardation time), 50 ms
•
•
•
δt: time delay tolerance, 25 ms
m: safety margin, 10 ms
Δt: discrimination time, 170–200 ms
Figure 64 - Time grading
δt
TC
m
Tm
δt
time
Δt
Recorded values of the last eight faults
There is detailed information available on the last eight faults for each protection
stage. The recorded values are specific for the protection stages and can contain
information like time stamp, fault value, elapsed delay, fault current, fault voltage,
phase angle and setting group.
NOTE: The recorded values are lost if the relay power is switched off.
Squelch limit
Current inputs have a squelch limit (noise filter) at 0.005 x IN. When the
measured signal goes below this threshold level, the signal is forced to zero.
NOTE: If ICALC is used to measure the residual current, the squelch limit for
the ICALC signal is same as for the phase currents. The I0 setting range begins
at the level of phase currents' squelch limit. This can cause instability if the
minimum setting is used with the I0 CALC mode.
6.6 Dependent operate time
The dependent operate time – that is, the inverse definite minimum time (IDMT)
type of operation – is available for several protection functions. The common
principle, formula and graphic representations of the available dependent delay
types are described in this chapter.
Dependent delay means that the operate time depends on the measured real
time process values during a fault. For example, with an overcurrent stage using
dependent delay, a bigger a fault current gives faster operation. The alternative to
dependent delay is definite delay. With definite delay, a preset time is used and
the operate time does not depend on the size of a fault.
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Stage-specific dependent delay
Some protection functions have their own specific type of dependent delay.
Details of these dedicated dependent delays are described with the appropriate
protection function.
Operation modes
There are three operation modes to use the dependent time characteristics:
•
Standard delays
•
Using standard delay characteristics by selecting a curve family (IEC, IEEE,
IEEE2, RI) and a delay type (Normal inverse, Very inverse etc). See 6.6.1
Standard dependent delays using IEC, IEEE, IEEE2 and RI curves.
Standard delay formulae with free parameters
•
selecting a curve family (IEC, IEEE, IEEE2) and defining one's own
parameters for the selected delay formula. This mode is activated by setting
delay type to ‘Parameters’, and then editing the delay function parameters A –
E. See 6.6.2 Custom curves.
Fully programmable dependent delay characteristics
Building the characteristics by setting 16 [current, time] points. The relay
interpolates the values between given points with second degree polynomials.
This mode is activated by the setting curve family to ‘PrgN’'. There is a
maximum of three different programmable curves available at the same time.
Each programmed curve can be used by any number of protection stages.
See 6.6.3 Programmable dependent time curves.
CAUTION
HAZARD OF NON-OPERATION
When changing the dependent time (inverse curves) operation mode
settings manually through the device HMI, change both the Curve (Curve
delay family) and Type (Delay type) setting.
Failure to follow these instructions can result in injury or equipment
damage.
Dependent time limitation
The maximum dependent time is limited to 600 seconds.
Local panel graph
The relay shows a graph of the currently used dependent delay on the local panel
display. The up and down keys can be used for zooming. Also the delays at 20 x
ISET, 4 x ISET and 2 x ISET are shown.
Dependent time setting error signal
If there are any errors in the dependent delay configuration, the appropriate
protection stage uses the definite time delay.
There is a signal ‘Setting Error’ available in the output matrix that indicates
different situations:
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1. Settings are currently changed with Easergy Pro or local panel.
2. There is temporarily an illegal combination of curve points. For example, if
previous setting was IEC/NI and then curve family is changed to IEEE, this
causes a setting error because there is no NI type available for IEEE curves.
After changing valid delay type for IEEE mode (for example MI), the ‘Setting
Error’ signal releases.
3. There are errors in formula parameters A – E, and the relay is not able to
build the delay curve.
4. There are errors in the programmable curve configuration, and the relay is not
able to interpolate values between the given points.
Limitations
The maximum measured secondary phase current is 50 x IN and the maximum
directly measured ground fault current is 10 x I0N for ground fault overcurrent
input. The full scope of dependent delay curves goes up to 20 times the setting.
At a high setting, the maximum measurement capability limits the scope of
dependent curves according to Table 50.
Table 50 - Maximum measured secondary currents and settings for phase and
ground fault overcurrent inputs
Current input
Maximum measured
secondary current
Maximum secondary
scaled setting enabling
dependent delay times
up to full 20x setting
IA, IB, IC and IN Calc
250 A
12.5 A
IN1 = 5 A
50 A
2.5 A
IN1 = 1 A
10 A
0.5 A
IN1 = 0.2 A
2A
0.1 A
Example of limitation
CT = 750 / 5
CT0 = 100 / 1 (cable CT is used for ground fault overcurrent)
The CT0 is connected to a 1 A terminals of input IN.
The CT0 is connected to a 1 A terminals of input IN1.
For overcurrent stage 50/51 - 1, Table 50 gives 12.5 A. Thus, the maximum
setting the for 50/51 - 1 stage giving full dependent delay range is 12.5 A / 5 A =
2.5 xIN = 1875 APrimary.
For ground fault stage 50N/51N-1, Table 50 gives 0.5 A. Thus, the maximum
setting for the 50N/51N-1 stage giving full dependent delay range is 0.5 A / 1 A =
0.5 xI0N = 50 APrimary.
1. Example of limitation
CT0 = 100 / 1 (cable CT is used for ground fault overcurrent)
The CT0 is connected to a 1 A terminals of input IN1.
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6.6.1 Standard dependent delays using IEC, IEEE, IEEE2 and RI curves
The available standard dependent delays are divided in four categories called
dependent curve families: IEC, IEEE, IEEE2 and RI. Each category contains a set
of different delay types according to Table 51.
Dependent time setting error signal
The dependent time setting error signal activates if the delay category is changed
and the old delay type does not exist in the new category. See 6.6 Dependent
operate time for more details.
Limitations
The minimum definite time delay starts when the measured value is twenty times
the setting, at the latest. However, there are limitations at high setting values due
to the measurement range. See 6.6 Dependent operate time for more details.
Table 51 - Available standard delay families and the available delay types within
each family
Delay type
Curve family
DT
DT
Definite
IEC
IEEE
IEEE2
RI
X
time
NI
Normal
X
X
inverse
VI
Very
X
X
X
X
X
X
X
X
inverse
EI
Extremely
inverse
LTI
Long time
inverse
LTEI
Long time
X
extremely
inverse
LTVI
Long time
X
very
inverse
MI
Moderately
X
X
inverse
STI
Short time
X
inverse
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Delay type
Curve family
DT
STEI
IEC
IEEE
Short time
IEEE2
RI
X
extremely
inverse
RI
Old ASEA
X
type
RXIDG
Old ASEA
X
type
IEC dependent operate time
The operate time depends on the measured value and other parameters
according to Equation 7. Actually this equation can only be used to draw graphs
or when the measured value I is constant during the fault. A modified version is
implemented in the relay for real time usage.
Equation 7
t=
kA
 I

 I START
B

 − 1

t = Operation delay in seconds
k = User’s multiplier Inv. time coefficient k
I = Measured value
ISTART = Start setting
A, B = Constants parameters according to Table 52.
There are three different dependent delay types according to IEC 60255-3,
Normal inverse (NI), Extremely inverse (EI), Very inverse (VI) and a VI extension.
In addition, there is a de facto standard Long time inverse (LTI).
Table 52 - Constants for IEC dependent delay equation
Parameter
Delay type
A
B
0.14
0.02
80
2
NI
Normal inverse
EI
Extremely inverse
VI
Very inverse
13.5
1
LTI
Long time inverse
120
1
Example of the delay type "Normal inverse (NI)":
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k = 0.50
I = 4 pu (constant current)
IPICKUP = 2 pu
A = 0.14
B = 0.02
Equation 8
t=
0.50 ⋅ 0.14
4
 
2
0.02
= 5. 0
−1
The operate time in this example is five seconds. The same result can be read
from Figure 65.
Figure 65 - IEC normal inverse delay
IEC NI
A
B
A. Delay (s)
130
inverseDelayIEC_NI
B. I / Iset
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Figure 66 - IEC extremely inverse delay
IEC EI
A
B
A. Delay (s)
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B. I / Iset
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Figure 67 - IEC very inverse delay
IEC VI
A
B
A. Delay (s)
132
inverseDelayIEC_VI
B. I / Iset
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Figure 68 - IEC long time inverse delay
IEC LTI
A
B
A. Delay (s)
inverseDelayIEC_LTI
B. I / Iset
IEEE/ANSI dependent operate time
There are three different delay types according to IEEE Std C37.112-1996 (MI, VI,
EI) and many de facto versions according to Table 53. The IEEE standard defines
dependent delay for both trip and release operations. However, in the Easergy P3
relay only the trip time is dependent according to the standard but the reset time
is constant.
The operate delay depends on the measured value and other parameters
according to Equation 9. Actually, this equation can only be used to draw graphs
or when the measured value I is constant during the fault. A modified version is
implemented in the relay for real-time usage.
Equation 9




A


t=k 
+ B
C
  I  − 1

  I START 



t = Operation delay in seconds
k = User’s multiplier
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I = Measured value
ISTART = Start setting
A,B,C = Constant parameter according to Table 53
Table 53 - Constants for IEEE/ANSI inverse delay equation
Delay type
LTI
Long time
Parameter
A
B
C
0.086
0.185
0.02
28.55
0.712
2
64.07
0.250
2
0.0515
0.1140
0.02
inverse
LTVI
Long time very
inverse
LTEI
Long time
extremely
inverse
MI
Moderately
inverse
VI
Very inverse
19.61
0.491
2
EI
Extremely
28.2
0.1217
2
0.16758
0.11858
0.02
1.281
0.005
2
inverse
STI
Short time
inverse
STEI
Short time
extremely
inverse
Example of the delay type "Moderately inverse (MI)":
k = 0.50
I = 4 pu
IPICKUP = 2 pu
A = 0.0515
B = 0.114
C = 0.02
Equation 10




0.0515

t = 0.50 ⋅
+ 0.1140 = 1.9

  4  0.02

  −1
  2 

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The operate time in this example is 1.9 seconds. The same result can be read
from Figure 72.
Figure 69 - ANSI/IEEE long time inverse delay
IEEE LTI
A
B
A. Delay (s)
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B. I / Iset
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Figure 70 - ANSI/IEEE long time very inverse delay
IEEE LTVI
A
B
A. Delay (s)
136
inverseDelayIEEE1_LTVI
B. I / Iset
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Figure 71 - ANSI/IEEE long time extremely inverse delay
IEEE LTEI
A
B
A. Delay (s)
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B. I / Iset
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Figure 72 - ANSI/IEEE moderately inverse delay
IEEE MI
A
B
A. Delay (s)
138
inverseDelayIEEE1_MI
B. I / Iset
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Figure 73 - ANSI/IEEE short time inverse delay
IEEE STI
A
B
A. Delay (s)
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B. I / Iset
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Figure 74 - ANSI/IEEE short time extremely inverse delay
IEEE STEI
A
B
A. Delay (s)
inverseDelayIEEE1 STEI
B. I / Iset
IEEE2 dependent operate time
Before the year 1996 and ANSI standard C37.112 microprocessor relays were
using equations approximating the behavior of various induction disc type relays.
A quite popular approximation is Equation 11 which in Easergy P3 relays is called
IEEE2. Another name could be IAC because the old General Electric IAC relays
have been modeled using the same equation.
There are four different delay types according to Table 54. The old
electromechanical induction disc relays have dependent delay for both trip and
release operations. However, in Easergy P3 relays, only the trip time is
dependent and the reset time is constant.
The operate delay depends on the measured value and other parameters
according to Equation 11. Actually, this equation can only be used to draw graphs
or when the measured value I is constant during the fault. A modified version is
implemented in the relay for real-time usage.
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Equation 11




B
D
E


+
+
t = k A +
2
3
 I



− C   I − C   I − C  

I
 

 I START
  I START

 START
 

t = Operation delay in seconds
k = User’s multiplier
I = Measured value
ISTART = User’s start setting
A, B, C, D = Constant parameter according to Table 54.
Table 54 - Constants for IEEE2 inverse delay equation
Parameter
Delay type
MI
Moderately
A
B
C
D
E
0.1735
0.6791
0.8
-0.08
0.1271
0.0274
2.2614
0.3
-4.1899
9.1272
0.0615
0.7989
0.34
-0.284
4.0505
0.0399
0.2294
0.5
3.0094
0.7222
inverse
NI
Normally
inverse
VI
Very
inverse
EI
Extremely
inverse
Example of the delay type "Moderately inverse (MI)":
k = 0.50
I = 4 pu
ISTART = 2 pu
A = 0.1735
B = 0.6791
C = 0.8
D = -0.08
E = 0.127
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Equation 12




0.6791
0.127 
− 0.08
t = 0.5 ⋅ 0.1735 +
= 0.38
+
+
2
3


4
 4
4



 − 0.8   − 0.8 
 − 0.8  

2
 2

2
 

The operate time in this example is 0.38 seconds. The same result can be read
from Figure 75.
Figure 75 - IEEE2 moderately inverse delay
IEEE2 MI
A
B
A. Delay (s)
142
inverseDelayIEEE2_MI
B. I / Iset
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Figure 76 - IEEE2 normal inverse delay
IEEE2 NI
A
B
A. Delay (s)
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B. I / Iset
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Figure 77 - IEEE2 very inverse delay
IEEE2 VI
A
B
A. Delay (s)
144
inverseDelayIEEE2_VI
B. I / Iset
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Figure 78 - IEEE2 extremely inverse delay
IEEE2 EI
A
B
A. Delay (s)
inverseDelayIEEE2_EI
B. I / Iset
RI and RXIDG type dependent operate time
These two dependent delay types have their origin in old ASEA (nowadays ABB)
ground fault relays.
The operate delay of types RI and RXIDG depends on the measured value and
other parameters according to Equation 13 and Equation 14. Actually, these
equations can only be used to draw graphs or when the measured value I is
constant during the fault. Modified versions are implemented in the relay for realtime usage.
Equation 14
Equation 13
t RI =
k
0.339 −
0.236
 I

 I START
t RXIDG = 5.8 − 1.35 ln



I
k I START
t = Operate delay in seconds
k = User’s multiplier
I = Measured value
ISTART = Start setting
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Example of the delay type RI
k = 0.50
I = 4 pu
ISTART = 2 pu
Equation 15
t RI =
0.5
= 2.3
0.236
0.339 −
4
 
2
The operate time in this example is 2.3 seconds. The same result can be read
from Figure 79.
Example of the delay type RXIDG
k = 0.50
I = 4 pu
ISTART = 2 pu
Equation 16
t RXIDG = 5.8 − 1.35 ln
4
= 3.9
0.5 ⋅ 2
The operate time in this example is 3.9 seconds. The same result can be read
from Figure 80.
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Figure 79 - RI dependent delay
RI
A
B
A. Delay (s)
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B. I / Iset
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Figure 80 - RXIDG dependent delay
A
B
A. Delay (s)
B. I / Iset
6.6.2 Custom curves
This mode is activated by the setting delay type to ‘Parameters’, and then editing
the delay function constants, that is, the parameters A – E. The idea is to use the
standard equations with one’s own constants instead of the standardized
constants as in the previous chapter.
Example of the GE-IAC51 delay type:
k = 0.50
I = 4 pu
ISTART = 2 pu
A = 0.2078
B = 0.8630
C = 0.8000
D = - 0.4180
E = 0.1947
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Equation 17




− 0.4180
0.1947 
0.8630

+
+
t = 0.5 ⋅ 0.2078 +
= 0.37
2
3


 4
4
4



 − 0.8   − 0.8 

 − 0.8  
 2
2


2
 
The operate time in this example is 0.37 seconds.
The resulting time/current characteristic of this example matches quite well the
characteristic of the old electromechanical IAC51 induction disc relay.
Dependent time setting error signal
The dependent time setting error signal actives if interpolation with the given
parameters is not possible. See 6.6 Dependent operate time for more details.
Limitations
The minimum definite time delay starts at the latest when the measured value is
twenty times the setting. However, there are limitations at high setting values due
to the measurement range. See 6.6 Dependent operate time for more details.
6.6.3 Programmable dependent time curves
Programming dependent time curves requires Easergy Pro setting tool and
rebooting the unit.
The [current, time] curve points are programmed using Easergy Pro PC program.
There are some rules for defining the curve points:
• the configuration must begin from the topmost line
• the line order must be as follows: the smallest current (longest operate time)
on the top and the largest current (shortest operate time) on the bottom
• all unused lines (on the bottom) should be filled with [1.00 0.00s]
Here is an example configuration of curve points:
P3T/en M/J006
Point
Current I/ISTART
Operate delay
1
1.00
10.00 s
2
2.00
6.50 s
3
5.00
4.00 s
4
10.00
3.00 s
5
20.00
2.00 s
6
40.00
1.00 s
7
1.00
0.00 s
8
1.00
0.00 s
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Transformer protection relay
6 Protection functions
Point
Current I/ISTART
Operate delay
9
1.00
0.00 s
10
1.00
0.00 s
11
1.00
0.00 s
12
1.00
0.00 s
13
1.00
0.00 s
14
1.00
0.00 s
15
1.00
0.00 s
16
1.00
0.00 s
Dependent time setting error signal
The dependent time setting error signal activates if interpolation with the given
points fails. See 6.6 Dependent operate time for more details.
Limitations
The minimum definite time delay starts at the latest when the measured value is
twenty times the setting. However, there are limitations at high setting values due
to the measurement range. See 6.6 Dependent operate time for more details.
6.7 Volts/hertz overexcitation protection (ANSI 24)
The saturation of any inductive network components like transformers, inductors,
motors and generators depends on the voltage and frequency. The lower the
frequency, the lower is the voltage at which the saturation begins.
The volts/hertz overexcitation protection stage is sensitive to the voltage/
frequency ratio instead of voltage only. Figure 81 shows the difference between
volts/hertz and a standard overvoltage function. The highest of the three line-toline voltages is used regardless of the voltage measurement mode (10.8 Voltage
system configuration). By using line-to-line voltages, any line-to-neutral
overvoltages during ground faults have no effect. (The ground fault protection
functions take care of ground faults.)
The used net frequency is automatically adopted according to the local network
frequency.
Overexcitation protection is needed for generators that are excitated even during
startup and shutdown. If such a generator is connected to a unit transformer, also
the unit transformer needs volts/hertz overexcitation protection. Another
application is sensitive overvoltage protection of modern transformers with no flux
density margin in networks with unstable frequency.
This figure shows the difference between volts/hertz and normal overvoltage
protection. The volts/hertz characteristics on the left depend on the frequency,
while the standard overvoltage function on the right is insensitive to frequency.
The network frequency, 50 Hz or 60 Hz, is automatically adopted by the relay.
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Figure 81 - Difference between volts/hertz and normal overvoltage protection
V f> set t in g
2.0
18
1.8
Measured voltage (PU)
Measured voltage (PU)
1.8
1.6
V f> set t in g
2.0
TRIP AREA
140 %
1.4
1.2
100 %
1.0
0.8
ok area
0.6
0.4
0.2
1.6
14
1.4
IP
1.2
0
%
0%
EA
AR
TR
10
0%
1.0
0.8
0.6
ea
0.4
r
ok a
0.2
30 35 40 45 50 55 60 65
30 36 42 48 54 60 66 72
Frequency (Hz )
30 35 40 45 50 55 60 65
30 36 42 48 54 60 66 72
OverVoltFreqChar
Frequency (Hz )
VoltPerHerz
Setting groups
There are four setting groups available for each stage.
Characteristics
Table 55 - Volts/hertz over-excitation protection 24–1
Start setting range
100–200%
Operating time
0.3–300.0 s
Start time
Typically 200 ms
Reset time
< 450 ms
Reset ratio
0.995
Inaccuracy:
- Starting
V< 0.5% unit
f < 0.05 Hz
- Operating time at definite time function
P3T/en M/J006
±1% or ±150 ms
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6.8 Synchronism check (ANSI 25)
Description
The relay includes a function that checks the synchronism before giving or
enabling the circuit breaker close command. The function monitors the voltage
amplitude, frequency and phase angle difference between two voltages. Since
there are two stages available, it is possible to monitor three voltages. The
voltages can be busbar and line or busbar and busbar (bus coupler).
Figure 82 - Synchronism check function
Close
cmd
Side 1
Side 2
Request
V1= V2
f1 = f2
φ1 = φ2
&
V1
V2
Timeout Settings
&
Sync Voltage
mode mode
≥1
&
Sync fail
&
CB close
Register
event
Sync OK
Bypass
The synchronism check stage includes two separate synchronism criteria that can
be used separately or combined:
•
•
voltage only
voltage, frequency, and phase
The voltage check simply compares voltage conditions of the supervised objects.
The supervised object is considered dead (not energized) when the measured
voltage is below the Vdead setting limit. Similarly, the supervised object is
considered live (energized) when the measured voltage is above the Vlive setting
limit. Based on the measured voltage conditions and the selected voltage check
criteria, synchronism is declared.
When the network sections to be connected are part of the same network, the
frequency and phase are the same. Therefore, the voltage check criteria is safe to
use without frequency and phase check.
The frequency and phase check compares the voltages, frequency and phase of
the supervised objects. Synchronism is declared if the voltages are above the
Vlive limit and all three difference criteria are within the given limits. This
synchronism check is dynamic by nature, and the object close command is given
at a certain moment of time, depending on the selected mode of operation.
When two networks are running at slightly different frequencies, there is also a
phase difference between these two networks. Because of the different frequency,
the phase angle tends to rotate. The time for one cycle depends on the frequency
difference. The stress for electrical components is lowest when two networks are
connected at zero phase difference.
In the “Sync” mode, the circuit breaker closing is aimed at the moment of zero
phase difference. Therefore, the close command is advanced by the time defined
by the CB close time setting. In the “Async” mode, the circuit breaker closing is
152
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6 Protection functions
Transformer protection relay
aimed at the moment when the synchronism conditions are met, that is, when the
phase difference is within the given phase difference limit.
When two network sections to be connected are from different sources or
generators, the voltage criteria alone is not safe, so also frequency and phase
check must be used.
When two networks with different frequencies are to be connected, the request
timeout setting must be long enough to allow the synchronism criteria to be met.
For example, if the frequency difference is 0.1 Hz, the synchronism criteria is met
only once in ten seconds.
The synchronism check stage starts from an object close command that
generates a request to close the selected circuit breaker (as per CONTROL
SETTINGS view) when the synchronism conditions are met. The synchronism
check stage provides a "request" signal that is active from the stage start until the
synchronism conditions are met or the request timeout has elapsed. When the
synchronism conditions are not met within the request timeout, a “fail” pulse is
generated. The fail pulse has a fixed length of 200 ms. When the synchronism
conditions are met in a timely manner, the object close command is initiated for
the selected object. This signal is purely internal and not available outside the
synchronism check stage. When the synchronism conditions are met, the “OK”
signal is always active. The activation of the bypass input bybasses the
synchronism check and declares synchronism at all times.
The request, OK, and fail signals are available in the output matrix.
The synchronized circuit breaker close execution order is shown in Figure 83.
Figure 83 - Synchronism check execution order
1
A
4
2
B
5
3
C
A. Synchronism check stage
B. Object
C. Circuit breaker (physical) as selected in the CB Object 1 or CB Object 2 setting in the
CONTROL SETTINGS view of the synchro-check stage.
NOTE: A synchronisim check is made only if a CB is selected in the
CONTROL SETTING view.
P3T/en M/J006
1.
Object close command from mimic, digital inputs or communication protocol
2.
Synchronism declared
3.
Circuit breaker close command
4.
Sync fail signal if request timeout elapsed before synchronism conditions met
5.
Object fail signal if CB failed to operate
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6 Protection functions
Figure 84 - Synchronism check function principle
B
A
1
2
3
C
1.
Sync request
2.
Sync OK
3.
Object close command
D
A. The object close command given (mimic or bus) actually only makes a sync request.
B. The sync request ends when the synchronism conditions are met and CB command is given or
if the request timeout elapsed.
C. If the request timeout elapsed before synchronism conditions are met, sync fail pulse is
generated.
D. Normal object close operation
The synchronism check function is available when one of the following analog
measurement modules and a suitable measuring mode are in use:
Table 56 - Voltage measuring modes
Voltage measuring mode
Number of synchrocheck stages
3LN+LLy
1
3LN+LNy
1
2LL+VN+LLy
1
2LL+VN+LNy
1
LL+VN+LLy+LLz
2
LN+VN+LNy+LNz
2
Connections for synchronism check
The voltage used for checking the synchronism is always line-to-line voltage VAB
even when VA is measured. The sychronism check stage 1 always compares VAB
with VABy. The compared voltages for the stage 2 can be selected (VAB/VABy,
VAB/VABz, VABy/VABz). See 10.8 Voltage system configuration.
NOTE: To perform its operation, the synchronism check stage 2 converts the
voltages LNy and LNz to line-to-line voltage VAB. As such, the measured
voltage for LNy and LNz must be VA-N.
NOTE: The wiring of the secondary circuits of voltage transformers to the
relay terminal depends on the selected voltage measuring mode.
See the synchronism check stage's connection diagrams in See 10.8 Voltage
system configuration.
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Characteristics
Table 57 - Synchronism check function (25)
Input signal
V1 – V4
Synchronism check mode (SMODE)
Off; Async; Sync 39) 40) 41)
Voltage check mode (VMODE)
DD; DL; LD; DD/DL; DD/LD; DL/LD;
DD/DL/LD 42) 43) 44) 45)
CB closing time
0.04–0.6 s
VDEAD limit setting
10–120% VN
VLIVE limit setting
10–120% VN
Frequency difference
0.01–1.00 Hz
Voltage difference
1–60% VN
Phase angle difference
2°–90°
Request timeout
0.1–600.0 s
Stage operation range
46.0–64.0 Hz
Reset ratio (V)
0.97
Inaccuracy:
- voltage
±3% VN
- frequency
±20 mHz
- phase angle
±2° (when Δf < 0.2 Hz, else ±5°)
- operate time
±1% or ±30 ms
39) Off
– Frequency and phase criteria not in use
– dF, dU and d angle criteria are used. Circuit breaker close is aimed at the moment when
the phase angle is within phase angle difference limit. Slip frequency dF determines how much the
close command needs to be advanced to make the actual connection at the moment when the phase
angle is within the phase angle limit
41) Sync mode – d , d and d angle criteria are used. Circuit breaker close is aimed at the moment
F U
when the phase angle becomes zero. Slip frequency dF determines how much the close command
needs to be advanced to make the actual connection at zero phase angle.
42) The first letter refers to the reference voltage and the second letter to the comparison voltage.
43) D means that the side must be “dead” when closing (dead = The voltage is below the dead voltage
limit setting).
44) L means that the side must be “live” when closing (live = The voltage is higher than the live voltage
limit setting).
45) Example: DL mode for stage 1: The U12 side must be “dead” and the U12y side must be “live”.
40) Async
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6.9 Undervoltage (ANSI 27)
Description
Undervoltage protection is used to detect voltage dips or sense abnormally low
voltages to trip or trigger load shedding or load transfer. The function measures
the three line-to-line voltages, and whenever the smallest of them drops below the
start setting of a particular stage, this stage starts and a start signal is issued. If
the fault situation remains on longer than the operate time delay setting, a trip
signal is issued.
Blocking during voltage transformer fuse failure
As all the protection stages, the undervoltage function can be blocked with any
internal or external signal using the block matrix. For example if the secondary
voltage of one of the measuring transformers disappears because of a fuse failure
(See the voltage transformer supervision function in 7.8 Voltage transformer
supervision (ANSI 60FL)). The blocking signal can also be a signal from the
custom logic (see 5.7 Logic functions).
Low-voltage self blocking
The stages can be blocked with a separate low-limit setting. With this setting, the
particular stage is blocked when the biggest of the three line-to-line voltages
drops below the given limit. The idea is to avoid unwanted tripping when the
voltage is switched off. If the operate time is less than 0.08 s, the blocking level
setting should not be less than 15% for the blocking action to be fast enough. The
self blocking can be disabled by setting the low-voltage block limit equal to zero.
Figure 85 - Example of low-voltage self blocking
A
K
K
I
K
B
C
H
D
J
G
J
J
L
L
F
E
A. VLLmax = max (VAB, VBC, VCA)
B. Deadband
C. V< setting
D. Block limit
E. V< undervoltage state
F. Time
G. The maximum of the three line-to-line voltages VLLmax is below the block limit. This is not
regarded as an undervoltage situation.
H. The voltage VLLmax is above the block limit but below the start level. This is an undervoltage
situation.
I. The voltage is OK because it is above the start limit.
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6 Protection functions
Transformer protection relay
J. This is an undervoltage situation.
K. The voltage is OK.
L. The voltage VLLmax is under the block limit and this is not regarded as an undervoltage situation.
Three independent stages
There are three separately adjustable stages: 27-1, 27-2 and 27-3. All these
stages can be configured for the definite time (DT) operation characteristic.
Setting groups
There are four setting groups available for all stages.
Characteristics
Table 58 - Undervoltage (27–1)
Input signal
VA – VC
Start value
20–120% VN (step 1%)
Definite time characteristic:
- Operate time
0.0846) – 300.00 s (step 0.02)
Hysteresis (reset ratio)
1.001–1.200 (0.1–20.0%, step 0.1%)
Self-blocking value of the undervoltage
0–80% VN
Start time
Typically 60 ms
Release delay
0.06–300.00 s (step 0.02 s)
Reset time
< 95 ms
Overshoot time
< 50 ms
Reset ratio (Block limit)
0.5 V or 1.03 (3%)
Reset ratio
1.03 (depends on the hysteresis setting)
Inaccuracy:
- Starting
±3% of the set value
- Blocking
±3% of set value or ±0.5 V
- Operate time
±1% or ±30 ms
46) This
is the instantaneous time, that is, the minimum total operate time including the fault detection
time and the operate time of the trip contacts. Use the Accept zero delay setting in the protection
stage setting view in Easergy Pro to accept the zero operate time setting for the DT function.
Table 59 - Undervoltage (27–2)
P3T/en M/J006
Input signal
VA – VC
Start value
20–120% VN (step 1%)
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Transformer protection relay
6 Protection functions
Definite time characteristic:
- Operate time
0.0647) – 300.00 s (step 0.02)
Hysteresis (reset ratio)
1.001–1.200 (0.1–20.0%, step 0.1%)
Self-blocking value of the undervoltage
0–80% VN
Start time
Typically 60 ms
Reset time
< 95 ms
Overshoot time
< 50 ms
Reset ratio (Block limit)
0.5 V or 1.03 (3%)
Reset ratio
1.03 (depends on the hysteresis setting)
Inaccuracy:
- Starting
±3% of the set value
- Blocking
±3% of set value or ±0.5 V
- Operate time
±1% or ±30 ms
47) This
is the instantaneous time, that is, the minimum total operate time including the fault detection
time and the operate time of the trip contacts. Use the Accept zero delay setting in the protection
stage setting view in Easergy Pro to accept the zero operate time setting for the DT function.
Table 60 - Undervoltage (27–3)
Input signal
VA – VC
Start value
20–120% VN (step 1%)
Definite time characteristic:
- Operate time
0.0448) – 300.00 s (step 0.01)
Hysteresis (reset ratio)
1.001–1.200 (0.1–20.0%, step 0.1%)
Self-blocking value of the undervoltage
0–80% VN
Start time
Typically 30 ms
Reset time
< 95 ms
Overshoot time
< 50 ms
Reset ratio (Block limit)
0.5 V or 1.03 (3%)
Reset ratio
1.03 (depends on the hysteresis setting)
Inaccuracy:
- Starting
±3% of the set value
- Blocking
±3% of set value or ±0.5 V
- Operate time
±1% or ±25 ms
48) This
is the instantaneous time, that is, the minimum total operate time including the fault detection
time and the operate time of the trip contacts. Use the Accept zero delay setting in the protection
stage setting view in Easergy Pro to accept the zero operate time setting for the DT function.
158
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Transformer protection relay
6.10 Negative sequence overcurrent (ANSI 46)
Description
Negative sequence overcurrent protects against unbalanced phase currents and
single phasing. The protection is based on the negative sequence current. Both
definite time and dependent time characteristics are available. The dependent
delay is based on Equation 18. Only the base frequency components of the
phase currents are used to calculate the negative sequence value I2.
The negative sequence overcurrent protection is based on the negative sequence
of the base frequency phase currents. Both definite time and dependent time
characteristics are available.
Dependent time delay
The dependent time delay is based on the following equation:
Equation 18
T=
K1
2


 I 2  − K 22
I 
 TN 
T = Operate time
K1 = Delay multiplier
I2 = Measured and calculated negative sequence phase current of fundamental
frequency
ITN = Rated current of the transformer
K2 = Start setting I2 > in pu. The maximum allowed degree of unbalance.
Example
K1 = 15 s
I2 = 22.9 % = 0.229 x ITN
K2 = 5 % = 0.05 x ITN
t=
15
2
 0.229 
2
 − 0.05

 1 
= 300.4
The operate time in this example is five minutes.
More stages (definite time delay only)
If more than one definite time delay stages are needed for negative sequence
overcurrent protection, the freely programmable stages can be used (6.32
Programmable stages (ANSI 99)).
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Figure 86 - Dependent operation delay of negative sequence overcurrent I2 >
(ANSI 46). The longest delay is limited to 1000 seconds (=16min 40s).
CurrentUnbalanceChar
2000
1000
K 2 = 40 %
K2 = 2 %
500
K 2 = 70 %
200
K1 = 50 s
100
A
50
K2 = 2 %
20
K 2 = 40 %
K 2 = 70 %
10
5
K1 = 1 s
2
1
0
20
40
60
80
100
B
A. Operate time (s)
B. Negative sequence current I2%
Setting groups
There are four setting groups available.
Characteristics
Table 61 - Negative sequence overcurrent I2 > 46–1
Input signal
IA – IC
Start value
2–70% (step 1%)
Definite time characteristic:
- Operate time
1.0–600.0 s (step 0.1 s)
Dependent time characteristic:
- 1 characteristic curve
Inv
- Time multiplier
1–50 s (step 1)
- Upper limit for dependent time
1000 s
Start time
Typically 300 ms
Reset time
< 450 ms
Reset ratio
0.95
Inaccuracy:
- Starting
±1% - unit
- Operate time
±5% or ±200 ms
NOTE: The stage is operational when all secondary currents are above 250
mA.
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6.11 Negative sequence overvoltage protection (ANSI 47)
Description
This protection stage can be used to detect voltage unbalance and phase
reversal situations. It calculates the fundamental frequency value of the negative
sequence component V2 based on the measured voltages (for calculation of V2,
see 4.11 Symmetrical components).
Whenever the negative sequence voltage V2 raises above the user's start setting
of a particular stage, this stage starts, and a start signal is issued. If the fault
situation remains on longer than the user's operate time delay setting, a trip signal
is issued.
Blocking during VT fuse failure
Like all the protection stages, the negative sequence overvoltage can be blocked
with any internal or external signal using the block matrix, for example, if the
secondary voltage of one of the measuring transformers disappears because of a
fuse failure (See VT supervision function in 7.8 Voltage transformer supervision
(ANSI 60FL)).
The blocking signal can also be a signal from the user's logic (see 5.7 Logic
functions).
Three independent stages
There are three separately adjustable stages: 47-1, 47-2, and 47-3. Both stages
can be configured for the definite time (DT) operation characteristic.
Setting groups
There are four settings groups available for all stages. Switching between setting
groups can be controlled by digital inputs, virtual inputs (mimic display,
communication, logic) and manually.
Characteristics
Table 62 - Negative sequence overvoltage protection (47)
Start value: 47-1, 47-2, 47-3
2–120%
Operate time
0.08–300 s
Reset ratio
0.95
Inaccuracy:
P3T/en M/J006
- Starting
±1% - unit
- Operate time
±5% or ±200 ms
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6.12 Thermal overload (ANSI 49 RMS)
Description
The thermal overload function protects the transformer against excessive
temperatures.
Thermal model
The temperature is calculated using RMS values of phase currents and a thermal
model according IEC60255-149. The RMS values are calculated using harmonic
components up to the 15th.
Trip time:
I2 − I
t = τ ⋅ ln 2 P2
I −a
2
Alarm (alarm 60% = 0.6):
a = k ⋅ kΘ ⋅ I TN ⋅ alarm
Trip:
a = k ⋅ kΘ ⋅ I TN
Reset time:
t = τ ⋅ Cτ ⋅ ln
2
IP
2
a − I2
Trip release:
a = 0.95 × k × I TN
Start release (alarm 60% = 0.6):
a = 0.95 × k × I TN × alarm
T = Operate time
= Thermal time constant tau (setting value). Unit: minute
ln = Natural logarithm function
I =Measured RMS phase current (the max. value of three phase currents)
k = Overload factor (Maximum continuous current), i.e. service factor (setting
value).
kΘ = Ambient temperature factor (permitted current due to tamb).
Ip = Preload current, I P = θ × k × I TN (If temperature rise is 120% -> θ = 1.2). This
parameter is the memory of the algorithm and corresponds to the actual
temperature rise.
ITN = The rated current of the transformer
Cτ = Relay cooling time constant (setting value)
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Time constant for cooling situation
If the transformer's fan is stopped, the cooling will be slower than with an active
fan. Therefore there is a coefficient Cτ for thermal constant available to be used
as cooling time constant, when current is less than 0.3 x ITN.
Heat capacitance, service factor and ambient temperature
The trip level is determined by the maximum allowed continuous current IMAX
corresponding to the 100% temperature rise ΘTRIP for example the heat
capacitance of the transformer. IMAX depends of the given service factor k and
ambient temperature ΘAMB and settings IMAX40 and IMAX70 according the following
equation.
I MAX = k ⋅ k Θ ⋅ I TN
The value of ambient temperature compensation factor kΘ depends on the
ambient temperature ΘAMB and settings IMAX40 and IMAX70. See Figure 87.
Ambient temperature is not in use when kΘ = 1. This is true when
• IMAX40 is 1.0
•
•
Samb is “n/a” (no ambient temperature sensor)
ΘAMB is +40 °C.
Figure 87 - Ambient temperature correction of the overload stage T>
k
1.2
1.0
0.8
IMAX40
IMAX70
0.6
50
60
70
80
(°C)
10
20
30
40
50
68
86
104 122 140 158 176 (°F)
AMB
Example of the thermal model behavior
Figure 87 shows an example of the thermal model behavior. In this example,
=
30 minutes, k = 1.06 and kΘ = 1 and the current has been zero for a long time
and thus the initial temperature rise is 0%. At time = 50 minutes, the current
changes to 0.85 x ITN and the temperature rise starts to approach value
(0.85/1.06)2 = 64% according to the time constant. At time = 300 min, the
temperature is nearly stable, and the current increases to 5% over the maximum
defined by the rated current and the service factor k. The temperature rise starts
to approach value 110%. At about 340 minutes, the temperature rise is 100% and
a trip follows.
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Initial temperature rise after restart
When the relay is switched on, an initial temperature rise of 70% is used.
Depending on the actual current, the calculated temperature rise then starts to
approach the final value.
Alarm function
The thermal overload stage is provided with a separately settable alarm function.
When the alarm limit is reached, the stage activates its start signal.
Figure 88 - Example of the thermal model behavior
thermbeh
Temperature rise
Θoverload
Θmax
Θalarm
Reset ratio=95%
Θp
Settings:
τ = 30 minutes
k = 1.06
Θalarm = 90%
Alarm
Trip
I/IN
IMAX = k*IN
1.6 min
IOVERLOAD = 1.05*IMAX
45 min
IP = 0.85*IN
100 min
200 min
300 min
400 min
500 min
Time
Setting groups
This stage has one setting group.
Characteristics
Table 63 - Thermal overload (49T)
164
Input signal
IA – IC
Maximum continuous current
0.1–2.40 x ITN
Alarm setting range
60–99% (step 1%)
Time constant τ
2–180 min (step 1)
Cooling time coefficient
1.0–10.0 x τ (step 0.1)
Max. overload at +40°C
70–120 %ITN (step 1)
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Transformer protection relay
Max. overload at +70°C
50–100 %ITN (step 1)
Ambient temperature
-55 – 125°C (step 1°)
Reset ratio (Start & trip)
0.95
Operate time inaccuracy
Relative inaccuracy ±5% or absolute
inaccuracy 1 s of the theoretical value
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6.13 Breaker failure (ANSI 50BF)
Description
The circuit breaker failure protection stage (CBFP) can be used to operate any
upstream circuit breaker (CB) if the programmed output matrix signals, selected
to control the main breaker, have not disappeared within a given time after the
initial command. The supervised output contact is defined by the “Monitored Trip
Relay” setting. An alternative output contact of the relay must be used for this
backup control selected in the Output matrix setting view.
The CBFP operation is based on the supervision of the signal to the selected
output contact and the time. The following output matrix signals, when
programmed into use, start the CBFP function:
• protection functions
• control functions
• supporting functions
• GOOSE signals (through communication)
If the signal is longer than the CBFP stage’s operate time, the stage activates
another output contact defined in the Output matrix setting view. The output
contact remains activated until the signal resets. The CBFP stage supervises all
the signals assigned to the same selected output contact.
In Figure 89, both the trip and CBFP start signals activate simultaneously (left
picture). If T> trip fails to control the CB through T1, the CBFP activates T3 after
the breaker failure operate time.
Figure 89 - Trip and CBFP start signals in the Output matrix view
NOTE: For the CBFP, always select the ”Connected” crossing symbol in the
Output matrix setting view.
166
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Characteristics
Table 64 - Breaker failure (50BF)
Relay to be supervised
T1–T4 (depending on the order code)
Definite time function:
- Operate time
0.1–10.0 s (step 0.1 s)
Inaccuracy:
- Operate time
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6.14 Breaker failure 1 and 2 (ANSI 50BF)
Easergy P3 has two identical Breaker failure 1 (ANSI 50BF) and Breaker failure 2
(ANSI 50BF) stages.
Description
Power system protection should always have some sort of backup protection
available. Backup protection is intended to operate when a power system fault is
not cleared or an abnormal condition is not detected in the required time because
of a failure or the inability of the primary protection to operate or failure of the
appropriate circuit breakers to trip. Backup protection may be local or remote.
Circuit breaker failure protection (CBFP) is part of the local backup protection.
CBFP provides a backup trip signal to an upstream circuit breaker (CB) when the
CB nearest to fault fails to clear fault current. The CB may fail to operate for
several reasons, for example burnt open coil or a flashover in the CB.
Figure 90 - CBFP implementation
A
B
C
A. CBFP trip
B. Normal trip
C. Re-trip
Two separate stages are provided to enable re-trip and CBFP trip commands.
The first stage can be used to give re-trip command (for example to control
second/backup open coil of the main CB) while the second stage can give
dedicated CBFP trip command to an upstream circuit breaker. Select the required
outputs for re-trip and CBFP trip through the output matrix.
168
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Block diagram
Figure 91 - Breaker failure 2 operation
A
I
IA
IB
Imax
>
&
&
IC
I0
>
&
≥
J
K
t
B
&
C
D
&
J
&
E
G
F
A. Condition 1
B. Condition 2
C. Condition 3
D. Condition 4
E. Block
F. Zero-current setting
H
G. Delay setting
H. Enable events setting
I. Start
J. Event register
K. Trip
CBFP operation
The CBFP function can be enabled and disabled with the Enable for BF2
selection. The CBFP function activates when any of the selected start signals
becomes and stays active.
The CBFP operation can be temporarily blocked by the stage block signal from
the block matrix. When the stage is blocked by the block signal, the stage timer
stops but it does not reset. The stage timer continues its operation when the block
signal is disabled. When the block signal is active, the stage output signals are
disabled.
The CBFP stage provides the following events:
• start on
• start off
• trip on
• trip off
Events can be activated via the Enable events setting view.
Condition selectors
The CBFP function has four condition selectors that can be used separately or all
together to activate and reset the CBFP function.
The four condition selectors are almost identical. The only difference is that
condition selectors 1 and 2 are for all protection functions that benefit from zerocurrent detection for resetting the CBFP as described in section Zero-current
detector, and selectors 3 and 4 are for all the protection functions that do not
benefit from zero-current detection for CBFP.
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Condition selector 4 can be used to support selectors 1, 2 and 3. For example, if
there are too many stages to be monitored in condition set 1, condition selector 4
can be used to monitor the output contacts. Monitoring digital inputs is also
possible if the backup protection is based on external current relay, for example.
The only CBFP reset criteria for condition set 4 are the monitored input and
output signals.
Figure 92 - Start signal and reset condition setting view for Condition 1
Separate zero-current detection with dedicated start settings exists for phase
overcurrent and ground fault overcurrent signals. Zero-current detection is
independent of the protection stages.
The condition criteria, available signals and reset conditions are listed in Table 65.
NOTE: The start signal can be selected for each condition in advance from
the pull-down menu even if the concerned stage is not enabled. For the CBFP
activation, the concerned stage must be enabled from the protection stage
menu and the stage has to start to activate the CBFP start signal.
Table 65 - CBFP condition selectors
Criteria
Start signal
Reset condition
Condition 1
50/51-1, 50/51-2, 50/51-3,
Reset by CB status: DI1 –
37, 46, 87M-1, 87M-2, 67-1,
DIx (1, F1, F2, VI1-20,
67-2, 67-3, 67-4, 49RMS,
VO1–20, GOOSE_NI1–64,
68F2, 21/40-1, 21/40-2,
POC1–16, Obj1-8Op
68F5, SOTF
Condition 2
Monitored stage: On/Off
50N/51N-1, 50N/51N-2,
Zero-current detection:
50N/51N-3, 50N/51N-4,
On/Off
50N/51N-5, 67N-1, 67N-2,
67N-3
170
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Criteria
Start signal
Reset condition
Condition 3
64S, 59-1, 59-2, 59-3, 27-1,
Reset by CB status: DI1 –
27-2, 27-3, 27P-1, 27P-2,
DIx (1, F1, F2, VI1-20,
59N-1, 59N-2, 32-1, 32-2,
VO1–20, GOOSE_NI1–64,
40, 21G-1, 21G-2,Pgr1-8,
POC1–16, Obj1-8Op
81U-1, 81U-2, 81-1,81-2,
81R, 24, Pslip
Condition 4
Monitored stage: On/Off
Outputs: A1, T1-Tx (1
Inputs: DI1 – DIx (1, F1, F2,
VI1-20, VO1 – 20,
GOOSE_NI1 – 64, POC1 –
16
Arc sensor 3- 10, ArcStg1-8,
I>int, Io>int
In addition to the selection of the start signal, the CBFP reset condition needs to
be selected.
If no reset conditions are selected, the stage uses Reset by monitored stage as
the reset condition. This prevents a situation where the stage never releases.
The reset condition Reset by CB status is useful if the current is already zero
when the CB is opened (for example unloaded CB).
When more than one selection criteria are selected, AND condition is used, for
example “zero current detection” AND “object open”. See Figure 91 for details.
Stage timer
The operate delay timer is started by a signal activated by the monitored stages
(condition selectors). The operate time delay is a settable parameter. When the
given time delay has elapsed, the stage provides a trip signal through the output
matrix and the event codes.
The timer delay can be set between 40 and 200 ms.
Zero-current detector
The zero-current detector is an undercurrent condition to reset the CBFP function
when all phase currents are below the start (pick-up) setting value. This separate
undercurrent condition is needed to properly detect successful CB operation. For
example, in a CB failure condition where one or more CB poles are partly
conducting when the CB is open, the fault current can be small enough to reset
the primary protection stage (for example overcurrent stage), in which case the
CBFP does not operate. When a separate undercurrent limit is used, CBFP reset
can be performed only when the fault current really is zero or near zero instead of
relying on the protection stage reset.
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Figure 93 - Zero-current detector setting view
The setting range of the zero-current detector is always associated with the CT
nominal value, even in case of motor and transformer protection. The setting
range minimum depends on the relay accuracy. Instead of zero, a small minimum
value can be accepted. See Table 66.
CBFP coordination
The CBFP delay setting has to be coordinated according to the CB operation time
and the reset time of protection stages monitored by the CBFP function as
described in Figure 94.
Figure 94 - CBFP coordination
B
C
A
E
F
G
D
H
I
J
A. Fault occurrence
B. Normal fault clearing time
C. Protection delay
D. CBFP stage start
E. CB operate time
172
F. Protection stage reset time + safety margin
G. CBFP trip
H. CBFP stage operate delay (CB operate time + protection stage
reset time + safety margin)
I. CB operate time
J. Total fault clearing time in case of failed CB operation but
successful CBFP operation
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Characteristics
Table 66 - Breaker failure 2 (ANSI 50BF)
Zero-current detection:
- Phase overcurrent
0.05–0.2 x In
- Ground fault overcurrent
Definite time function:
- Operate time
0.04–0.2 s
Inaccuracy:
- Operate time
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6.15 Switch-on-to-fault (ANSI 50HS)
Description
The switch-on-to-fault (SOTF) protection function offers fast protection when the
circuit breaker (CB) is closed manually against a faulty line. Overcurrent-based
protection does not clear the fault until the intended time delay has elapsed.
SOTF gives a trip signal without additional time delay if the CB is closed and a
fault is detected after closing the CB.
Figure 95 - Switch-on-to-fault function operates when the CB has detected open
and the fault current reaches start setting value
E
A
G
B
C
F
D
A. Start setting
B. Maximum of IA, IB, IC
C. Low limit 0.02 x IN
D. SOTF trip
E. Switch-on-to-fault does not activate if the CB has not been in open position before the fault.
Open CB detection is noticed from the highest phase current value which has to be under a fixed
low-limit threshold (0.02 x IN). Opening of the CB can be detected also with digital inputs (Dead
line detection input = DI1 – DIx, VI1 – VIx). The default detection input is based on the current
threshold, so the dead line detection input parameter has value “–“.
F. Dead line detection delay defines how long the CB has to be open so that the SOTF function is
active. If the set time delay is not fulfilled and the highest phase current value (maximum of IA, IB,
IC) rises over the start setting, the SOTF does not operate.
G.If the highest phase current value of IA, IB, IC goes successfully under the low limit and rises to a
value between the low limit and the start value, then if the highest phase current value rises over
the start setting value before the set SOTF active after CB closure time delay has elapsed, the
SOTF trips. If this time delay is exceeded, the SOTF does not trip even if the start setting value is
exceeded.
Setting groups
This stage has one setting group.
Characteristics
Table 67 - Switch-on-to-fault SOTF (50HS)
174
Current input
IL or I’L
Start value
1.00–3.00 x IN (step 0.01)
Dead line detection delay
0.00–60.00 s (step 0.01)
SOTF active after CB closure
0.10–60.00 s (step 0.01)
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Transformer protection relay
Operate time
< 30 ms (When IM/ISET ratio > 1.5)
Reset time
< 95 ms
Reset ratio
0.97
Inaccuracy
±3% of the set value or 5 mA secondary
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6.16 Phase overcurrent (ANSI 50/51)
Description
Phase overcurrent protection is used against short-circuit faults and heavy
overloads.
The overcurrent function measures the fundamental frequency component of the
phase currents. The protection is sensitive to the highest of the three phase
currents. Whenever this value exceeds the user's start setting of a particular
stage, this stage starts and a start signal is issued. If the fault situation remains on
longer than the operation delay setting, a trip signal is issued.
Block diagram
Figure 96 - Block diagram of the three-phase overcurrent stage 50/51-1
3vlsblock
Im1
Im2
Im3
MAX
>
ts
&
tr
H
&
A
t
J
>1
&
B
A. Block
B. Setting I>s
C. Delay
D. Definite / dependent time
E. Dependent time characteristics
176
I
C
D
E F
I
G
F. Multiplier
G. Enable events
H. Start
I. Register event
J. Trip
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Figure 97 - Block diagram of the three-phase overcurrent stage 50/51-2 and
50/51-3
3vIssblock
Im1
Im2
Im3
MAX
>
ts
tr
&
E
&
A
G
t
&
B
A. Block
B. Setting I>>s
C. Delay
D. Enable events
C
F
F
D
E. Start
F. Register event
G. Trip
Three independent stages
There are three separately adjustable overcurrent stages: 50/51-1, 50/51-2 and
50/51-3. The first stage 50/51-1 can be configured for definite time (DT) or
dependent operate time (IDMT) characteristic. The stages 50/51-2 and 50/51-3
have definite time operation characteristic. By using the definite delay type and
setting the delay to its minimum, an instantaneous (ANSI 50) operation is
obtained.
Figure 96 shows a functional block diagram of the 50/51-1 overcurrent stage with
definite time and dependent time operate time. Figure 97 shows a functional block
diagram of the 50/51-2 and 50/51-3 overcurrent stages with definite time
operation delay.
Dependent operate time
Dependent operate time means that the operate time depends on the amount the
measured current exceeds the start setting. The bigger the fault current is, the
faster is the operation. The dependent time delay types are described in 6.6
Dependent operate time. The relay shows the currently used dependent operate
time curve graph on the local panel display.
Dependent time limitation
The maximum measured secondary current is 50 x IN. This limits the scope of
dependent curves with high start settings. See 6.6 Dependent operate time for
more information.
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Include harmonics setting
The 50/51-1 and 50/51-2 (50/51) overcurrent protection stages have a setting
parameter to include harmonics. When this setting is activated, the overcurrent
stage calculates the sum of the base frequency and all measured harmonics. This
feature is used to determine the signal's true root mean square value to detect the
signal's real heating factor. The operate time is 5 ms more when harmonics are
included in the measurement. Activate the "Include harmonics" setting if the
overcurrent protection is used for thermal protection and the content of the
harmonics is known to exist in the power system.
Cold load and inrush current handling
See 7.3 Cold load start and magnetizing inrush.
Setting groups
There are four setting groups available for each stage.
Characteristics
Table 68 - Phase overcurrent stage 50/51-1 (50/51)
Input signal
IA – IC
Start value
0.05–5.00 x ITN (step 0.01)
Definite time function:
DT49)
- Operate time
0.04–300.00 s (step 0.01 s)
IDMT function:
- Delay curve family
(DT), IEC, IEEE, RI Prg
- Curve type
EI, VI, NI, LTI, MI…, depends on the
- Inv. time coefficient k
family50)
- RI curve
0.025–20.0
0.025–20.0
178
Start time
40 ms at 2 * Is pick-up value
Reset time
< 95 ms
Overshoot time
< 50 ms
Reset ratio
0.97
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Transient overreach, any τ
< 10%
Inaccuracy:
- Starting
±3% of the set value or 5 mA secondary
- Operate time at definite time function
±1% or ±25 ms
- Operate time at IDMT function
±5% or at least ±25ms
49) This
is the instantaneous time, that is, the minimum total operate time including the fault detection
time and the operate time of the trip contacts. Use the Accept zero delay setting in the protection
stage setting view in Easergy Pro to accept the zero operate time setting for the DT function.
50) EI = Extremely Inverse, NI = Normal Inverse, VI = Very Inverse, LTI = Long Time Inverse, MI=
Moderately Inverse
Table 69 - Phase overcurrent stage 50/51-2 (50/51)
Input signal
IA – IC
Start value
0.10 – 20.00 x ITN (step 0.01)
Definite time function:
DT51)
- Operate time
0.04 – 1800.00 s (step 0.01 s)
Start time
35 ms at 2 * Is pick-up value
Reset time
< 95 ms
Overshoot time
< 50 ms
Reset ratio
0.97
Transient overreach, any τ
< 10%
Inaccuracy:
- Starting
±3% of the set value or 5 mA secondary
±1% or ±25 ms
- operate time
51) This
is the instantaneous time, that is, the minimum total operate time including the fault detection
time and the operate time of the trip contacts. Use the Accept zero delay setting in the protection
stage setting view in Easergy Pro to accept the zero operate time setting for the DT function.
Table 70 - Phase overcurrent stage 50/51-3 (50/51)
Input signal
IA – IC
Start value
0.10–40.00 x ITN (step 0.01)
Definite time function:
DT52)
- Operate time
0.03–300.00 s (step 0.01 s)
Instant operate time:
P3T/en M/J006
IM / ISET ratio > 1.5
<30 ms
IM / ISET ratio 1.03 – 1.5
< 50 ms
Start time
20 ms at 2 * Is pick-up value
Reset time
< 95 ms
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Transformer protection relay
6 Protection functions
Overshoot time
< 50 ms
Reset ratio
0.97
Inaccuracy:
- Starting
±3% of the set value or 5 mA secondary
- Operate time DT (IM/ISET ratio > 1.5)
±1% or ±15 ms
- Operate time DT (IM/ISET ratio 1.03 – 1.5)
±1% or ±25 ms
52) This
is the instantaneous time, that is, the minimum total operate time including the fault detection
time and the operate time of the trip contacts. Use the Accept zero delay setting in the protection
stage setting view in Easergy Pro to accept the zero operate time setting for the DT function.
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6.17 Ground fault overcurrent (ANSI 50N/51N)
Description
The purpose of the nondirectional ground fault overcurrent protection is to detect
ground faults in low-impedance grounded networks. In high-impedance grounded
networks, compensated networks and isolated networks, nondirectional ground
fault overcurrent can be used as backup protection.
The nondirectional ground fault overcurrent function is sensitive to the
fundamental frequency component of the ground fault overcurrent 3IN. The
attenuation of the third harmonic is more than 60 dB. Whenever this fundamental
value exceeds the start setting of a particular stage, this stage starts and a start
signal is issued. If the fault situation remains on longer than the operate time
delay setting, a trip signal is issued.
Block diagram
Figure 98 - Block diagram of the ground fault stage overcurrent 50N/51N-1
i0s1
A
>
ts
&
tr
I
&
B
J
t
K
>1
&
C
D
E
F G
A. I0
G. Multiplier
B. Block
C. Setting I0>s
H. Enable events
I. Start
D. Delay
E. Definite / inverse time
J. Register event
K. Trip
J
H
F. Inverse time characteristics
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Figure 99 - Block diagram of the ground fault stages overcurrent 50N/51N-2, 50N/
51N-3, 50N/51N-4
I0ssblock
>
A
ts
tr
&
F
&
B
H
t
&
C
D
A. I0
E. Enable events
B. Block
C. Setting I0>>s
F. Start
G. Register event
D. Delay
H. Trip
G
G
E
Input signal selection
Each stage can be connected to supervise any of the following inputs and signals:
• Input IN1 for all networks other than solidly grounded.
•
Input IN2 for all networks other than solidly grounded.
•
Calculated signal IN Calc for solidly and low-impedance grounded networks. IN
Calc
= IA + IB + IC.
Four or six independent nondirectional ground fault overcurrent stages
There are four separately adjustable ground fault overcurrent stages: 50N/51N-1,
50N/51N-2, 50N/51N-3, and 50N/51N-4. The first stage 50N/51N-1 can be
configured for definite time (DT) or dependent time operation characteristic
(IDMT). The other stages have definite time operation characteristic. By using the
definite delay type and setting the delay to its minimum, an instantaneous (ANSI
50N) operation is obtained.
Dependent time limitation
The maximum measured secondary ground fault overcurrent is 10 x I0N and the
maximum measured phase current is 50 x IN. This limits the scope of dependent
curves with high start settings.
Setting groups
There are four setting groups available for each stage.
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Characteristics
Table 71 - Ground fault overcurrent 50N/51N-1 (50N/51N)
Input signal
IN1, IN2
IN Calc = (IA + IB + IC)
Definite time function:
DT53)
- Operate time
0.0453) –300.00 s (step 0.01 s)
IDMT function:
- Delay curve family
(DT), IEC, IEEE, RI Prg
- Curve type
EI, VI, NI, LTI, MI..., depends on the
- Inv. time coefficient k
family54)
0.025–20.0, except
0.50–20.0 for RXIDG, IEEE and IEEE2
Start time
45 ms at 2 * Is pick-up value
Reset time
< 95 ms
Reset ratio
0.95
Inaccuracy:
- Starting
- Starting (Peak mode)
±2% of the set value or ±0.3% of the rated
value
±5% of the set value or ±2% of the rated
value (Sine wave <65 Hz)
- Operate time at definite time function
- Operate time at IDMT function
±1% or ±25 ms
±5% or at least ±25 ms 53)
53) This
is the instantaneous time, that is, the minimum total operate time including the fault detection
time and the operate time of the trip contacts. Use the Accept zero delay setting in the protection
stage setting view in Easergy Pro to accept the zero operate time setting for the DT function.
54) EI = Extremely Inverse, NI = Normal Inverse, VI = Very Inverse, LTI = Long Time Inverse, MI=
Moderately Inverse
Table 72 - Ground fault overcurrent 50N/51N-2, 50N/51N-3, 50N/51N-4, 50N/
51N-5 (50N/51N)
Input signal
IN1, IN2
IN Calc = (IA + IB + IC)
Definite time function:
- Operate time
0.04 55) – 300.00 s (step 0.01 s)
Start time
Typically 45 ms (50N/51N-2, 50N/51N-3,
50N/51N-4)
30 ms at 2 * Is pick-up value (50N/51N-5)
Reset time
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Reset ratio
0.95
Inaccuracy:
- Starting
- Starting (Peak mode)
±2% of the set value or ±0.3% of the rated
value
±5% of the set value or ±2% of the rated
value (Sine wave <65 Hz)
- Operate time
±1% or ±25 ms
55) This
is the instantaneous time, that is, the minimum total operate time including the fault detection
time and the operate time of the trip contacts. Use the Accept zero delay setting in the protection
stage setting view in Easergy Pro to accept the zero operate time setting for the DT function.
6.17.1 Ground fault phase detection
The ground fault overcurrent stage (ANSI 50N/51N) and directional ground fault
overcurrent stage (ANSI 67N) have an inbuilt detection algorithm to detect a faulty
phase. This algorithm is meant to be used in radial-operated distribution
networks. The faulty phase detection can be used in solidly-grounded,
impedance-grounded or resonant-grounded networks.
Operation
The faulty phase detection starts from the ground fault stage trip. At the moment
of stage start, the phase currents measured prior to start are registered and
stored as prior-to-fault currents. At the moment of trip, phase currents are
registered again. Finally, faulty phase detection algorithm is performed by
comparing prior-to-fault currents to fault currents. The algorithm also uses positive
sequence current and negative sequence current to detect faulty phase.
The detection algorithm can be enabled and disabled by selecting or unselecting
a checkbox in the protection stage settings. Correct network grounding
configuration must be selected in the stage settings, too. In the ground fault
overcurrent stage settings, you can select between RES and CAP network
grounding configuration. This selection has no effect on the protection itself, only
on the faulty phase detection. In the directional ground fault overcurrent stage
settings, the detection algorithm uses the same network grounding type as
selected for protection. RES is used for solidly-grounded, impedance-grounded
and resonant-grounded networks. CAP is only used for isolated networks.
The detected faulty phase is registered in the protection stage fault log (and also
in the event list and alarm screen). Faulty phase is also indicated by a line alarm
and line fault signals in the output matrix.
Possible detections of faulty phases are A-N, B-N, C-N, AB-N, AC-N, BC-N, ABCN, and REV. If the relay protection coordination is incorrect, REV indication is
given in case of a relay sympathetic trip to a reverse fault.
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6.18 Capacitor bank unbalance (ANSI 51C)
NOTE: Configure the capacitor bank unbalance protection through the ground
fault overcurrent stages 50N/51N-3 and 50N/51N-4.
Description
The relay enables capacitor, filter and reactor bank protection with its five current
measurement inputs. The fifth input is typically useful for unbalance current
measurement of a double-wye connected ungrounded bank.
The unbalance protection is highly sensitive to internal faults of a bank because of
the sophisticated natural unbalance compensation. The location method enables
easy maintenance monitoring for a bank.
This protection scheme is specially used in double-wye-connected capacitor
banks. The unbalance current is measured with a dedicated current transformer
(like 5A/5A) between two starpoints of the bank.
As the capacitor elements are not identical and have acceptable tolerances, there
is a natural unbalance current between the starpoints of the capacitor banks. This
natural unbalance current can be compensated to tune the protection sensitive
against real faults inside the capacitor banks.
P3x3x_Capbank
Figure 100 - Typical capacitor bank protection application with Easergy P3 relays
8/E/1:1
8/E/1:2
8/E/1:3
8/E/1:4
8/E/1:5
8/E/1:6
8/E/1:7
8/E/1:8
IA
5A
IB
5A
IC
5A
I01 5A
I01 1A
8/E/1:9
8/E/1:10
8/E/1:11
I02 1A
I02 0,2A
8/E/1:12
Compensation method
The method of unbalance protection is to compensate for the natural unbalance
current. The compensation is triggered manually when commissioning. The
phasors of the unbalance current and one phase current are then recorded. This
is because one polarizing measurement is needed. When the phasor of the
unbalance current is always related to IA, the frequency changes or deviations
have no effect on the protection. After the recording, the measured unbalance
current corresponds to the zero-level and therefore, the setting of the stage can
be very sensitive.
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Compensation and location
The most sophisticated method is to use the compensation method described
above with an add-on feature that locates the branch of each faulty element (the
broken fuse).
This feature is implemented to the stage 50N/51N-4, while the other stage 50N/
51N-3 can still function as normal unbalance protection stage with the
compensation method. Normally, the 50N/51N-4 could be set as an alarming
stage while stage 50N/51N-3 trips the circuit breaker.
The stage 50N/51N-4 should be set based on the calculated unbalance current
change of one faulty element. You can calculate this using the following formula:
Equation 19
V L− N
V L− N
−
(2 ⋅ π ⋅ f ⋅ C1 ) −1 (2 ⋅ π ⋅ f ⋅ C2 ) −1
3I 0 =
3
C1 = Capacitor unit capacitance (μF)
C2 = Capacitor unit capacitance, after one element fails (μF)
However, the setting must be 10% smaller than the calculated value, since there
are some tolerances in the primary equipment as well as in the relay
measurement circuit. Then, the time setting of 50N/51N-4 is not used for tripping
purposes. The time setting specifies, how long the relay must wait until it is
certain that there is a faulty element in the bank. After this time has elapsed, the
stage 50N/51N-4 makes a new compensation automatically, and the measured
unbalance current for this stage is now zero. Note, the automatic compensation
does not affect the measured unbalance current of stage 50N/51N-3.
186
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Figure 101 - Natural unbalance compensation and a single capacitor fault
90
3I0
A
0
180
B
270
A. The natural unbalance is compensated for.
B. When the IN current increases above the set start value (normally 90% of a single capacitor
unit) according to the angle ratio between IN and IA, it is decided in which branch and phase the
fault occurred. The fault is memorised and compensation is completed automatically. After the set
amount of faults, the stage trips.
If there is an element failure in the bank, the algorithm checks the phase angle of
the unbalance current related to the phase angle of the phase current IA. Based
on this angle, the algorithm can increase the corresponding faulty elements
counter (there are six counters).
Figure 102 - How a failure in different branches of the bank affects the IN
measurement
Easergy P3
A
B
H
I
G
C
F
D
E
A. Branch 1
B. Branch 2
C. IA as reference
F. Phase 2 fault in branch 1
G. Phase 1 fault in branch 2
H. Phase 3 fault in branch 1
D. Phase 1 fault in branch 1
E. Phase 3 fault in branch 2
I. Phase 2 fault in branch 2
You can set for the stage 50N/51N-4 the allowed number of faulty elements. For
example, if set to three elements, the fourth fault element will issue the trip signal.
The fault location is used with internal fused capacitor and filter banks. There is
no need to use it with fuseless or external fused capacitor and filter banks, nor
with the reactor banks.
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Application example
An application example is presented below. Each capacitor unit has 12 elements
in parallel and four elements in series.
Figure 103 - 131.43 μF Y-Y connected capacitor bank with internal fuses
A
12kV
I
B
I0
A. 12 in parallel
B. Four in series
Characteristics
Table 73 - Capacitor bank unbalance50N/51N-3 and 50N/51N-4 (51C)
Operate time
0.04‑300 s (step 0.01)
Start time
Typically 30 ms
Reset time
<95 ms
Reset ratio
0.95
Inaccuracy:
- Starting
- Operate time
±2% of the set value or ±0.3% of the rated
value
±1% or ±25 ms
6.18.1 Taking unbalance protection into use
1. To enable the capacitor bank protection:
–
in Easergy Pro, in the Protection > 50N/51N-4 Unbalance setting view,
select Location for Compensation mode.
Figure 104 - Enabling unbalance protection
188
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–
via the Easergy P3 device's front panel: go to the 50N/51N-4 menu, scroll
right to 1 SET 50N/51N, and select Location for CMode.
2. To save the natural unbalance:
–
in Easergy Pro, in the Protection > 50N/51N-4 Unbalance setting view,
select Get for Save unbalance current.
Figure 105 - Saving the unbalance current
–
via the device's front panel: go to the 50N/51N-4 menu, scroll right to
SET2 50N/51N, and select Get for SaveBal.
NOTE: CMode has to be selected as Location before proceeding to
this step.
3. Set the start value for both branches.
Total capacitance of the bank is 131.43 μF. In each phase, there are three
capacitor units (1+2), so the capacitance of one unit is 43.81 μF. Failure of
one element inside the capacitor unit makes the total capacitance decrease to
41.92 μF (Ohm’s law). This value is important when calculating the start
value.
Equation 20
V L− N
V L− N
−
−1
(2 ⋅ π ⋅ f ⋅ C1 )
(2 ⋅ π ⋅ f ⋅ C 2 ) −1
3I 0 =
3
6928
6928
−
(2 ⋅ π ⋅ 50 ⋅ 43.81 ⋅ 10 −6 ) −1 (2 ⋅ π ⋅ 50 ⋅ 43.81 ⋅ 10 −6 ) −1
3I 0 =
3
3I 0 = 1.37 A
Failure of one element inside the bank on the left branch causes
approximately 1.37 ampere unbalance current at the star point. On the right
branch, there are two capacitor units in parallel, and therefore, a failure of one
element causes only 0.69 ampere unbalance. A different start value for each
branch is necessary. Set the start value to 80% of the calculated value.
4. Test the operation of the unbalance protection.
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Figure 106 - Testing the operation of the unbalance protection
0.80
0.60
A
0.40
B
0.20
0.00
C
A. Phase 2 fault in branch 2
B. IA as reference
C. Set operation delay
Conduct testing by injecting current to channels IA and IN1 of the relay. In the
example above, 0.69 A primary current is injected to the IN1 channel. IN1 is
leading the phase current IA by 60 degrees. This means the fault has to be on
the right branch and in phase 2. Compensation happens automatically after
the set operate time until the allowed total amount of failed units is exceeded
(Max. allowed faults). In this application, the fourth failed element would cause
the stage to trip.
NOTE: If branch 1 faults occur in branch 2, change the polarity of the IN
input. Clear the location counters when the commissioning of the relay
has been completed.
5. Clear the location counters by clicking the Clear button.
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Figure 107 - Clearing location counters
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6.19 Overvoltage (ANSI 59)
Description
Overvoltage protection is used to detect too high system voltages or to check that
there is sufficient voltage to authorize a source transfer.
The overvoltage function measures the fundamental frequency component of the
line-to-line voltages regardless of the voltage measurement mode (see 10.8
Voltage system configuration). By using line-to-line voltages any line-to-neutral
over-voltages during ground faults have no effect. (The ground fault protection
functions take care of ground faults.) Whenever any of these three line-to-line
voltages exceeds the start setting of a particular stage, this stage starts and a
start signal is issued. If the fault situation remains on longer than the operate time
delay setting, a trip signal is issued.
In solidly grounded, four-wire networks with loads between phase and neutral
voltages, overvoltage protection may be needed for line-to-neutral voltages, too.
In such applications, the programmable stages can be used. 6.32 Programmable
stages (ANSI 99).
Three independent stages
There are three separately adjustable stages: 59-1, 59-2, and 59-3. All the stages
can be configured for the definite time (DT) operation characteristic.
Configurable release delay
The 59–1 stage has a settable reset delay that enables detecting intermittent
faults. This means that the time counter of the protection function does not reset
immediately after the fault is cleared, but resets after the release delay has
elapsed. If the fault appears again before the release delay time has elapsed, the
delay counter continues from the previous value. This means that the function
eventually trips if faults are occurring often enough.
Configurable hysteresis
The dead band is 3% by default. This means that an overvoltage fault is regarded
as a fault until the voltage drops below 97% of the start setting. In a sensitive
alarm application, a smaller hysteresis is needed. For example, if the start setting
is about only 2% above the normal voltage level, the hysteresis must be less than
2%. Otherwise, the stage does not release after fault.
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Block diagram
Figure 108 - Block diagram of the three-phase overvoltage stages 59-1, 59-2, and
59-3
3vus
VmA
VmB
VmC
MAX
>
ts
tr
&
G
&
A
I
t
&
B C
A. Blocking
B. Setting U>s
C. Hysteresis
D. Release delay
E. Delay
D
E
H
H
F
F. Enable events
G. Start
H. Event register
I. Trip
Setting groups
There are four setting groups available for each stage.
Characteristics
Table 74 - Overvoltage stage 59–1 (59)
Input signal
VA – VC
Start value
50–150% VN (step 1%)
Definite time characteristic:
P3T/en M/J006
- operate time
0.0856)– 300.00 s (step 0.02)
Hysteresis
0.99–0.800 (0.1 – 20.0%, step 0.1%)
Start time
Typically 60 ms
Release delay
0.06–300.00 s (step 0.02)
Reset time
< 95 ms
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Overshoot time
< 50 ms
Inaccuracy:
- Starting
±3% of the set value
- operate time
±1% or ±30 ms
56) This
is the instantaneous time, that is, the minimum total operate time including the fault detection
time and the operate time of the trip contacts. Use the Accept zero delay setting in the protection
stage setting view in Easergy Pro to accept the zero operate time setting for the DT function.
Table 75 - Overvoltage stage 59–2 (59)
Input signal
VA – VC
Start value
50–150% VN (step 1%)
The measurement range is up to 160 V.
This limit is the maximum usable setting
when rated VT secondary is more than 100
V.
Definite time characteristic:
- Operate time
0.0657) – 300.00 s (step 0.02)
Hysteresis
0.99–0.800 (0.1–20.0%, step 0.1%)
Start time
Typically 60 ms
Reset time
< 95 ms
Overshoot time
< 50 ms
Inaccuracy:
- Starting
±3% of the set value
- Operate time
±1% or ±30 ms
57) This
is the instantaneous time, that is, the minimum total operate time including the fault detection
time and the operate time of the trip contacts. Use the Accept zero delay setting in the protection
stage setting view in Easergy Pro to accept the zero operate time setting for the DT function.
Table 76 - Overvoltage stage 59–3 (59)
Input signal
VA – VC
Start value
50–160% VN (step 1%)
The measurement range is up to 160 V.
This limit is the maximum usable setting
when rated VT secondary is more than 100
V.
Definite time characteristic:
194
- Operate time
0.0458) – 300.00 s (step 0.01)
Hysteresis
0.99–0.800 (0.1–20.0%, step 0.1%)
Start time
Typically 50 ms
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6 Protection functions
Transformer protection relay
Reset time
< 95 ms
Overshoot time
< 50 ms
Inaccuracy:
- Starting
±3% of the set value
- Operate time
±1% or ±25 ms
58) This
is the instantaneous time, that is, the minimum total operate time including the fault detection
time and the operate time of the trip contacts. Use the Accept zero delay setting in the protection
stage setting view in Easergy Pro to accept the zero operate time setting for the DT function.
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6.20 Neutral overvoltage (ANSI 59N)
Description
The neutral overvoltage protection is used as unselective backup for ground faults
and also for selective ground fault protections for motors having a unit transformer
between the motor and the busbar.
This function is sensitive to the fundamental frequency component of the neutral
overvoltage. The attenuation of the third harmonic is more than 60 dB. This is
essential because third harmonics exist between the neutral point and ground
also when there is no ground fault.
Whenever the measured value exceeds the start setting of a particular stage, this
stage starts and a start signal is issued. If the fault situation remains on longer
than the operate time delay setting, a trip signal is issued.
Measuring the neutral overvoltage
The neutral overvoltage is either measured with three voltage transformers (for
example broken delta connection), one voltage transformer between the motor's
neutral point and ground or calculated from the measured phase-to-neutral
voltages according to the selected voltage measurement mode (see 10.8 Voltage
system configuration):
•
•
When the voltage measurement mode is 3LN: the neutral displacement
voltage is calculated from the line-to-line voltages and therefore a separate
neutral displacement voltage transformer is not needed. The setting values
are relative to the configured voltage transformer (VT) voltage/√3
When the voltage measurement mode contains "+VN": The neutral
displacement voltage is measured with voltage transformer(s) for example
using a broken delta connection. The setting values are relative to the VTN
•
secondary voltage defined in configuration.
Connect the VN signal according to the connection diagram to achieve correct
polarization.
Two independent stages
There are two separately adjustable stages: 59N-1 and 59N-2. Both stages can
be configured for the definite time (DT) operation characteristic.
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Block diagram
Figure 109 - Block diagram of the neutral overvoltage stages 59N-1, 59N-2
U0sblock
>
A
ts
tr
&
G
&
B
I
t
&
C
D
A. U0
F. Enable events
B. Blocking
C. Setting U0>s
G. Start
H. Register event
D. Release delay
I. Trip
E
H
H
F
E. Delay
Setting groups
There are four setting groups available for both stages.
Characteristics
Table 77 - Neutral overvoltage stage 59N-1 (59N)
Input signal
VN
VN Calc = (VA + VB + VC)
Start value
1–60% V0N (step 1%)
Definite time function:
- Operate time
0.3–300.0 s (step 0.1 s)
Start time
Typically 200 ms
Reset time
< 450 ms
Reset ratio
0.97
Inaccuracy:
- Starting
- Starting VN Calc (3LN mode)
- Operate time
±2% of the set value or ±0.3% of the rated
value
±1 V
±1% or ±150 ms
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Table 78 - Neutral overvoltage stage 59N-2 (59N)
Input signal
VN
VN Calc = (VA + VB + VC)
Start value
1–60% V0N (step 1%)
Definite time function:
- Operate time
0.08–300.0 s (step 0.02 s)
Start time
Typically 60 ms
Reset time
<95 ms
Reset ratio
0.97
Inaccuracy:
- Starting
- Starting VN Calc (3LN mode)
- Operate time
±2% of the set value or ±0.3% of the rated
value
±1 V
±1% or ±30 ms
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6.21 Restricted high-impedance ground fault (ANSI 64REF,
64BEF)
The high-impedance REF/BEF protection function is based on an external
connection of a stabilizing resistor and a voltage limiting varistor connection to the
I0 input of Easergy P3 devices. The CT requirement, stabilizing resistor and
voltage limiting varistor calculations are explained in a separate Application Note
(P3APS17016EN).
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6.22 Restricted ground fault (ANSI 64REF)
Description
The restricted ground fault (REF) protection function is used to detect ground
faults in solidly-grounded or impedance-grounded power transformers, grounding
transformers and shunt reactors. REF protection can also be used to protect
rotating machines if the machine’s neutral point is grounded.
A traditional REF protection scheme is based on a high-impedance REF
protection principle. For implementation details, see separate document
“P3APS17016EN Restricted earth fault protection using an I0 input of an Easergy
P3 relay”. Modern REF protection operation is based on a low-impedance
principle that overcomes some drawbacks of the high-impedance REF principle.
Figure 110 to Figure 113 describe the basic low-impedance REF protection
schemes.
Figure 110 - Restricted ground fault protection of a solidly-grounded transformer
A
B
C
A
B
C
A (S2)
B (S2)
C (S2)
IN3 (S2)
C (S1)
B (S1)
A (S1)
64REF
IN3 (S1)
Figure 111 - Restricted ground fault protection of a transformer and neutral point
reactor
A
B
C
A
B
C
A (S2)
B (S2)
C (S2)
I 3 (S2)
N
C (S1)
B (S1)
A (S1)
64REF
I 3 (S1)
N
Figure 112 - Restricted ground fault protection of a shunt reactor
A
B
C
A
B
C
A (S2)
B (S2)
C (S2)
IN3 (S2)
C (S1)
B (S1)
A (S1)
64REF
IN3 (S1)
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Figure 113 - Restricted ground fault protection of a rotating machine
A
B
C
A (S2)
B (S2)
C (S2)
IN3 (S2)
C (S1)
B (S1)
A (S1)
64REF
IN3 (S1)
The REF protection principle has several advantages. It is very selective because
the protection zone is limited between the current transformers that are used for
the REF protection. Because of its selectivity, the REF protection requires no
additional time delay for protection coordination. Therefore, REF protection is
especially suitable for the protection of transformers and rotating machines
against internal ground faults. Because of the differential protection principle, it is
also very sensitive which makes it suitable for detecting faults located near the
neutral point of transformers and rotating machines.
Restricted ground fault protection principle
The REF protection function is based on the differential protection principle and is
sensitive to the fundamental frequency component of the measured currents.
Figure 114 depicts the differential protection principle applied to REF protection.
The protection zone is determined by the location of current transformers. The
direction of currents in REF protection are defined so that currents entering the
protection zone have positive direction and currents leaving the zone have
negative direction.
Figure 114 - Differential protection principle applied to REF protection
C
A
C
B
I
I
64REF
IN Calc = IA + IB + IC
IN Meas
A. Protection zone
B Protected object
C Positive direction
The function is based on the difference of the current measured at the neutral
point (IN Meas) and the calculated residual current (IN Calc). The function calculates
the differential current ID according to Equation 21. So the function is based on
the absolute value of ID that is a sum of the current vectors IN Meas and IN Calc.
NOTE: Nominal current of the IN Meas and IN Calc are current transformer
ratings.
Equation 21
ID = |IN Meas + IN Calc|
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During healthy conditions, the neutral point current (IN Meas) is near or equal to
zero and the same is true for the residual current or the calculated sum of the
phase currents IN Calc = 3I0 = IA+IB +IC. During healthy conditions, the differential
current ID is also close to zero and the REF protection stage does not start.
Figure 115 depicts through-fault conditions and a fault in the protected zone.
During a through-fault condition, a ground fault current flowing from the faulty
phase to earth returns to the system’s neutral point. Because of the convention of
current directions, the resulting neutral point current (IN Meas) and calculated
residual current (IN Calc) are flowing in opposite directions resulting in zero or very
small differential current ID according to Equation 21.
When a fault occurs inside the protection zone, the neutral point current flowing
into the protection zone has a positive current direction according to the current
direction convention. Depending on the network conditions, an additional fault
current may or may not flow into the zone along the line. This additional fault
current manifests itself as a residual current. Additional fault currents flowing into
the protection zone have a positive current direction, too. In other words, the
neutral point current and residual current are in a phase which results in a high
differential current ID according to Equation 21.
Figure 115 - Through-fault condition (left) and ground fault in protected zone
(right)
A
B
C
A
B
C
A
B
C
A
B
C
INCalc = IA + IB + IC
INCalc = IA + IB + IC
IN Meas
Id ≈ 0
IN Meas
Id > 0
During a through-fault or short-circuit fault outside the protection zone, the current
transformers may be exposed to very high currents. These high fault currents
may lead to different saturation of the phase current transformers resulting in an
erroneous residual current. To ensure correct operation of the protection stage, a
stabilization method is provided. Protection stage stabilisation is based on the
calculated bias current IB and programmable operating characteristics. The bias
current is calculated according to Equation 22.
Equation 22
IB=
|IA|+|IB|+|IC|
3
This bias current stabilization method is used in the dI0> stage. The dI0>> stage
does not consider the stabilization current IB and is purely based on the
differential current ID. Both the differential current ID and stabilization current IB
are current transformer ratings.
202
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Figure 116 - Restricted ground fault protection operating characteristics
A
B
N
K
I
C
L
D
J
M
E
H
F
G
A. ID/ IN
H. IB / IN
B. 2 x IN
I. Single-end-feed limit
C. IN
J. ISTART
D. 50% IN
K. Maximum setting
E. 5% IN
L. Slope 1
F. IN
M. Minimum setting
G. 3 x IN
N. Slope 2
Additional stabilization can be activated by selecting the directional blocking
feature. When directional blocking is used, the trip command is issued only when
the measured neutral current and calculated residual current are less than ±88°
apart. Normal second harmonic blocking and cold-load blocking can be used to
block the stage via the blocking matrix.
Figure 117 - Block diagram of REF protection stage
A
B
I
C
&
J
&
K
D
>
E
A. Block
B. IN3
P3T/en M/J006
F
G
H
G. Δ I> setting
H. Enable events
C. INCalc
I. Diff & bias calculation
D. I’NCalc
J. Trip
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E. Reverse blocking
F. INCalc / I’NCalc selection
K. Register event
Characteristics
Table 79 - Restricted ground fault overcurrent (64REF)
64-1
64-2
Input signals
-
-
- Measured ground fault
IN3
IN3
-
-
IN Calc or I’N Calc
IN Calc or I’N Calc
Start value
-
-
- dIo>
5–50 % of IN
5–50 % of In
Ibias for start of slope 1
0.5 x IN
-
Slope 1
5–100 %
-
Ibias for start of slope 2
1–3 x IN
-
Slope 2
100–200 %
-
Directional blocking
On/off
-
Operate time (ID > 1.2 x
< 60 ms
-
< 50 ms
< 50 ms
Reset time
< 95 ms
< 95 ms
Reset ratio
0.95
0.95
Inaccuracy of starting
±3% of set value or 0.02 x In ±3 % of the set value or ±0.5
overcurrent input
- Calculated ground fault
overcurrent source
ISET)
Operate time (ID > 3.5 x
ISET)
when currents are < 200 mA % of the rated value
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6.23 Directional phase overcurrent (ANSI 67)
Description
The directional phase overcurrent protection can be used for directional shortcircuit protection. Typical applications are:
•
•
•
•
Short-circuit protection of two parallel cables or overhead lines in a radial
network.
Short-circuit protection of a looped network with single feeding point.
Short-circuit protection of a two-way feeder, which usually supplies loads but
is used in special cases as an incoming feeder.
Directional ground-fault overcurrent protection in low-impedance grounded
networks. In this case, the relay is recommended to connect for line-to-neutral
(3LN) voltage measurement instead of line-to-line (2LL+U0) voltage
measurement. In low-impedance grounded network, residual voltage U0 may
be too low for reliable measurement. See 10.8 Voltage system configuration.
NOTE: For networks where the maximum possible ground-fault current is
lower than the overcurrent setting value, use the directional ground-fault (67N)
stages.
The directional phase overcurrent function measures the fundamental frequency
component of the phase current. The protection is sensitive to the highest threephase current. Whenever this value exceeds the configured start setting and, if
the polarization quantity is within the configured sector setting of a particular
stage, a start signal is issued. If the fault remains on longer than the time defined
by the operation delay setting, a trip signal is issued.
For line-to-line and three-phase faults, the fault direction is determined with
positive-sequence polarization using the angles between the positive sequences
of currents and voltages.
For line-to-neutral faults, the fault direction is determined with cross-polarization
using fault-phase current and a healthy line-to-line voltage.
For details on power direction, see 4.10 Power and current direction.
Voltage memory
An adjustable 0.2...3.2 s cyclic buffer that stores the phase-to-ground voltages is
used as the voltage memory. The stored phase angle information is used as
direction reference if all the line-to-line voltages drop below 1% during a fault. The
voltage memory can be adjusted by setting the Angle memory duration
parameter in the Scalings setting view in Easergy Pro.
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Block diagrams
Figure 118 - Block diagram of directional phase overcurrent stage Iϕ > and Iϕ >>
3vlsblock_Idir>_Idir>>
K
U1
I1
Im1
Im2
Im3
U1
I1
MAX
>
ts
&
tr
H
&
A
I
t
J
>1
&
B
C
D
E F
I
G
G. Enable events
H. Start
I. Register event
J. Trip
K. Directional discrimination by U1/I1 angle
A. Block
B. Setting I>s
C. Delay
D. Definite / dependent time
E. Dependent time characteristics
F. Multiplier
Figure 119 - Block diagram of directional phase overcurrent stage Iϕ >>> and Iϕ
>>>>
3vlsblock_Idir>>>_Idir>>>>
K
U1
I1
Im1
Im2
Im3
U1
I1
MAX
>
ts
tr
&
H
&
A
J
t
&
B
A. Block
B. Setting I>>>s
C. Delay
G. Enable events
206
C
I
I
G
H. Start
I. Register event
J. Trip
K. Directional discrimination by U1/I1 angle
P3T/en M/J006
6 Protection functions
Transformer protection relay
Operation
The directional phase overcurrent uses positive-sequence polarization methods
for faults that do not involve ground, that is, line-to-line faults and three-phase
faults. For faults that involve ground, the cross-polarization method is used.
The function has two conditions as shown in the block diagram. One is the current
threshold and the other is the fault direction or fault angle. If both conditions are
true, the stage starts and trips after the set trip delay. Whenever the highest threephase current exceeds the set value, there is an overcurrent condition.
The directional condition of the fault is different depending on whether ground is
involved in the fault or not.
For faults that do not involve ground, the fault direction or fault angle is
determined as an angle between the positive sequences of current and voltage.
The angle reference for the positive-sequence current is the positive-sequence
voltage that is rotated by the base-angle setting (also called relay characteristics
angle). The actual trip area is ± 88° from the base-angle setting. If the positivesequence current vector falls into the trip area, there is a directional condition.
The magnitude of the positive-sequence current has no impact on the overcurrent
condition or the directional condition.
If the current threshold and directional conditions are true, the stage starts and
trips after the set trip delay.
For faults that involve ground, the fault direction or fault angle is determined as an
angle between the healthy line-to-line voltage and the faulted phase current. The
angle reference for the faulted phase current is opposite to the healthy line-to-line
voltage that is rotated by the base-angle setting plus 90° to the positive direction.
The actual trip area is ± 88° from the base angle setting plus 90°. If the fault
current vector falls into the trip area, there is a directional condition. If both
conditions are true, the stage starts and trips after the set trip delay. If the current
threshold and directional conditions are true, the stage starts and trips after the
set trip delay.
A typical characteristic for the directional phase overcurrent protection for line-toline faults is shown in Figure 120. The base angle setting is -30°. The stage starts
if the maximum of the three-phase currents exceeds the current threshold and if
the tip of the positive-sequence current phasor gets into the grey area.
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Figure 120 - Example of the directional phase overcurrent protection area for lineto-line fault
+90°
Reverse
Forward
+88°
0°
U1
-88°
Angle offset setting= -30° (RCA)
-90°
ldir_angle1
A typical characteristic for the directional phase overcurrent protection for line-toground faults is shown in Figure 121. The base angle setting is -30°. The stage
starts if the maximum of the three-phase currents exceeds the current threshold
and if the tip of the fault current phasor gets into the grey area.
Figure 121 - Example of the directional phase overcurrent protection area for lineto-ground fault , RCA internally rotated +90o CCW during ground fault
+90°
+60°
Forward
+88°
-88°
0°
U1
Angle offset setting= -30° (RCA)
Reverse
-90°
ldir_angle2
Three modes are available:
• directional
• non-directional
• directional + backup
In the non-directional mode, the stage acts like an ordinary overcurrent 50/51
stage.
The directional + backup mode works like the directional mode, but it has nondirectional backup protection that is used if a close-up fault forces all voltages to
about zero. After the angle memory hold time, the direction would be lost.
208
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Transformer protection relay
The directional + backup mode is required when the operate time is set longer
than the voltage memory setting or no other non-directional backup protection is
used.
In Figure 122, the grey area is the trip area.
Figure 122 - Difference between directional and non-directional mode
+90°
-ind.
2°
+90°
+cap.
-ind.
DIRECTIONAL
+cap.
NON-DIRECTIONAL
SET
VALUE
SET
VALUE
0°
+res.
BASE ANGLE= 0°
-res.
-res.
TRIP AREA
-cap.
0°
+res.
TRIP AREA
-cap.
+ind.
-90°
+ind.
-90°
An example of the bidirectional operation characteristic is shown in Figure 123.
The stage on the right side in this example is stage Iφ> and on the left side Iφ>>.
The base angle setting of Iφ> is 0° and the base angle of Iφ>> is set to -180°.
Figure 123 - Bidirectional application with two stages 67-1 and 67-2
+90°
ind.
4°
+cap.
67-2 TRIP AREA
SET
VA LUE
SET
VA LUE
res.
0°
+res.
BASE ANGLE = °
BASE ANGLE = 180°
67-1 TRIP AREA
cap.
+ind.
90°
ldir_modeBiDir
15%
When any of the three-phase currents exceeds the setting value and, in
directional mode, the phase angle including the base angle is within the active
±88° wide sector, the stage starts and issues a start signal. If this fault remains on
longer than the time defined by the delay setting, a trip signal is issued.
Four independent stages
There are four separately adjustable stages available: 67-1, 67-2, 67-3, and 67-4.
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Dependent operate time
Stages 67-1 and 67-2 can be configured for definite time (DT) or dependent time
characteristic. See 6.6 Dependent operate time for details on the available
dependent delays.
Stages 67-3 and 67-4 have definite time operation delay. The relay shows a
scaleable graph of the configured delay on the local panel display.
Dependent time limitation
The maximum measured secondary current is 50 x IN. This limits the scope of
dependent curves with high start settings. See 6.6 Dependent operate time for
more information.
Cold load and inrush current handling
See 7.3 Cold load start and magnetizing inrush.
Setting groups
There are four setting groups available for each stage.
Characteristics
Table 80 - Directional phase overcurrent 67-1, 67-2 (67)
Characteristic
Value
Input signal
IA – IC
VA – V C
Start value
0.10...4.00 xIN or x IMOT (step 0.01)
Mode
Directional/Directional+BackUp
Minimum voltage for the direction solving
2 VSECONDARY
Base angle setting range
-180°...+179°
Operate angle
±88°
Definite time function:
DT59)
- Operate time
0.04...300.00 s (step 0.01)
IDMT function:
- Delay curve family
(DT), IEC, IEEE, RI Prg
- Curve type
EI, VI, NI, LTI, MI…depends on the
- Inv. time coefficient k
family60)
0.025...20.0, except
0.50...20.0 for RXIDG, IEEE and IEEE2
210
Start time
Typically 30 ms
Reset time
<95 ms
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6 Protection functions
Transformer protection relay
Characteristic
Value
Overshoot time
<50 ms
Reset ratio
0.95
Reset ratio (angle)
2°
Transient overreach, any τ
<10%
Angle memory duration
0.2...3.2 s
Inaccuracy:
- Starting (rated value IN= 1...5 A)
±3% of the set value or ±0.5% of the rated
value
- Angle
±2° V>5 V
±30° V = 0.1...5.0 V
- Operate time at DT function
±1% or ±25 ms
- Operate time at IDMT function
±5% or at least ±30 ms59)
59) This
is the instantaneous time, that is, the minimum total operate time including the fault detection
time and the operate time of the trip contacts. Use the Accept zero delay setting in the protection
stage setting view in Easergy Pro to accept the zero operate time setting for the DT function.
60) EI = Extremely Inverse, NI = Normal Inverse, VI = Very Inverse, LTI = Long Time Inverse, MI=
Moderately Inverse
Table 81 - Directional phase overcurrent 67–3, 67–4 (67)
Characteristic
Value
Input signal
IA – IC
Va – VC
P3T/en M/J006
Start value
0.10...20.00 x IMODE (step 0.01)
Mode
Directional/Directional+BackUp
Minimum voltage for the direction solving
2 VSECONDARY
Base angle setting range
-180°...+179°
Operate angle
±88°
Definite time function:
DT61)
- Operate time
0.04...300.00 s (step 0.01)
Start time
Typically 30 ms
Reset time
<95 ms
Overshoot time
<50 ms
Reset ratio
0.95
Reset ratio (angle)
2°
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Transformer protection relay
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Characteristic
Value
Transient overreach, any τ
<10%
Angle memory duration
0.2...3.2 s
Inaccuracy:
- Starting (rated value IN= 1...5 A)
±3% of the set value or ±0.5% of the rated
value
- Angle
±2° V>5 V
±30° V = 0.1...5.0 V
- Operate time at DT function
±1% or ±25 ms
61) This
is the instantaneous time, that is, the minimum total operate time including the fault detection
time and the operate time of the trip contacts. Use the Accept zero delay setting in the protection
stage setting view in Easergy Pro to accept the zero operate time setting for the DT function.
212
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6.24 Directional ground fault overcurrent (ANSI 67N)
Description
The directional ground fault overcurrent is used in networks or motors where a
selective and sensitive ground fault protection is needed and in applications with
varying network structure and length.
The ground fault protection is adapted for various network ground systems.
The function is sensitive to the fundamental frequency component of the ground
fault overcurrent and neutral voltage displacement voltage and the phase angle
between them. The attenuation of the third harmonic is more than 60 dB.
Whenever the size of IN and VN and the phase angle between IN and VN fulfils the
start criteria, the stage starts and a start signal is issued. If the fault situation
remains on longer than the operate time delay setting, a trip signal is issued.
Polarization
The neutral overvoltage, used for polarization, is measured by energizing input
VN, that is, the angle reference for IN. Connect the VN signal according to the
connection diagram. Alternatively, the VN can be calculated from the line-to-line
voltages internally depending on the selected voltage measurement mode (see
10.8 Voltage system configuration):
•
3LN/LLY, 3LN/LNY and 3LN/VN: the zero sequence voltage is calculated from
•
the line-to-line voltages and therefore any separate zero sequence voltage
transformers are not needed. The setting values are relative to the configured
voltage transformer (VT) voltage/√3.
3LN+VN, 2LL+VN, 2LL+VN+LLy, 2LL+VN+LNy, LL+VN+LLy+LLz, and LN+VN
+LNy+LNz: the neutral overvoltage is measured with voltage transformer(s)
for example using a broken delta connection. The setting values are relative
to the VTN secondary voltage defined in the configuration.
•
•
3LN: the zero sequence voltage is calculated from the line-to-line voltages
and therefore any separate zero sequence voltage transformers are not
needed. The setting values are relative to the configured voltage transformer
(VT) voltage/√3.
3LN+VN and 2LL+VN: the zero sequence voltage is measured with voltage
transformer(s) for example using a broken delta connection. The setting
values are relative to the VTN secondary voltage defined in configuration.
Modes for different network types
The available modes are:
• ResCap
This mode consists of two sub modes, Res and Cap. A digital signal can be
used to dynamically switch between these two submodes. When the digital
input is active (DI = 1), Cap mode is in use and when the digital input is
inactive (DI = 0), Res mode is in use. This feature can be used with
compensated networks when the Petersen coil is temporarily switched off.
◦ Res
The stage is sensitive to the resistive component of the selected IN signal.
This mode is used with compensated networks (resonant grounding) and
networks grounded with a high resistance. Compensation is usually
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◦
done with a Petersen coil between the neutral point of the main
transformer and ground. In this context, high resistance means that the
fault current is limited to be less than the rated phase current. The trip
area is a half plane as drawn in Figure 126. The base angle is usually set
to zero degrees.
Cap
The stage is sensitive to the capacitive component of the selected IN
•
signal. This mode is used with ungrounded networks. The trip area is a
half plane as drawn in Figure 126. The base angle is usually set to zero
degrees.
Sector
•
This mode is used with networks grounded with a small resistance. In this
context, "small" means that a fault current may be more than the rated phase
currents. The trip area has a shape of a sector as drawn in Figure 127. The
base angle is usually set to zero degrees or slightly on the lagging inductive
side (negative angle).
Undir
This mode makes the stage equal to the non directional stage 50N/51N-1.
The phase angle and VN amplitude setting are discarded. Only the amplitude
of the selected IN input is supervised.
Input signal selection
Each stage can be connected to supervise any of the following inputs and signals:
•
Input IN1 for all networks other than solidly grounded.
•
Input IN2 for all networks other than solidly grounded.
•
Calculated signal IN Calc for solidly and low-impedance grounded networks. IN
Calc
= IA + IB + IC = 3IN.
Intermittent ground fault detection
Short ground faults make the protection start but does not cause a trip. A short
fault means one cycle or more. For shorter than 1 ms transient type of intermittent
ground faults in compensated networks, there is a dedicated stage I0INT> 67NI.
When starting happens often enough, such intermittent faults can be cleared
using the intermittent time setting.
When a new start happens within the set intermittent time, the operation delay
counter is not cleared between adjacent faults and finally the stage trips.
Two independent stages
There are two separately adjustable stages: 67N-1 and 67N-2. Both stages can
be configured for definite time delay (DT) or dependent time delay operate time.
Dependent operate time
Accomplished dependent delays are available for all stages 67N-1 and 67N-2.
The relay shows a scalable graph of the configured delay on the local panel
display.
214
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Dependent time limitation
The maximum measured secondary ground fault overcurrent is 10 x I0N and the
maximum measured phase current is 50 x IN. This limits the scope of dependent
curves with high start settings.
Block diagram
Figure 125 - Block diagram of the directional ground fault overcurrent stages
67N-1, 67N-2
I0fiisblock
A
Isinφ
&
>
Icosφ
I
&
B
C
>
K
t
&
D
E
F
G
J
H
A. I0
G. Delay
B. Block
C. V0
H. Enable events
I. Start
D. Choise Icosφ (Res) / Isinφ (Cap)
J. Register event
K. Trip
E. Setting Iφ > s
F. Setting I0 > s
J
Iosin φ
Figure 126 - Operation characteristics of the directional ground fault protection in
Res and Cap mode
67N-1
I0
-V0
67N-1
Iocos φ
Res mode can be used with compensated networks.
P3T/en M/J006
Cap mode is used with ungrounded networks.
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Figure 127 - Operation characteristics examples of the directional ground fault
stages in the sector mode
+90º
Angle offset = -15º
Sector = ±70º
+90º
Angle offset = +32º
Sector = ±120º
+55º
TRIP AREA
70º
I0φ>
+32º
120º
-V0
70º
I0
+152º
0º
120º
I0φ>
-V0
0º
-15º
I0
TRIP AREA
-88º
-85º
IoDir_SectorAdj
The drawn IN phasor is inside the trip area.
The angle offset and half sector size are user’s
parameters.
Setting groups
There are four setting groups available for each stage.
Characteristics
Table 82 - Directional ground fault overcurrent 67N-1, 67N-2 (67N)
Input signal
IN, VN
IN Calc = ( IA + IB + IC)
Start voltage
1–100% V0N (step 1%)
Mode
Non-directional/Sector/ResCap
Base angle setting range
-180°–179°
Operate angle
±88°
Definite time function:
- Operate time
0.1062) – 300.00 s (step 0.02 s)
IDMT function:
- Delay curve family
(DT), IEC, IEEE, RI Prg
- Curve type
EI, VI, NI, LTI, MI…, depends on the
- Inv. time coefficient k
family63)
0.025–20.0, except
0.50–20.0 for RI, IEEE and IEEE2
216
Start time
Typically 60 ms
Reset time
< 95 ms
Reset ratio
0.95
Reset ratio (angle)
2°
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Transformer protection relay
Inaccuracy:
- Starting VN & IN (rated value IN= 1–5A)
±3% of the set value or ±0.3% of the rated
value
- Starting VN & IN (Peak Mode when, rated
±5% of the set value or ±2% of the rated
value I0n= 1–10A)
value (Sine wave <65 Hz)
- Starting VN & IN (IN Calc)
±3% of the set value or ±0.5% of the rated
value
- Angle
±2° when V> 1V and IN> 5% of I0N or > 50
mA
else ±20°
- Operate time at definite time function
±1% or ±30 ms
- Operate time at IDMT function
±5% or at least ±30 ms62)
62) This
is the instantaneous time, that is, the minimum total operate time including the fault detection
time and the operate time of the trip contacts. Use the Accept zero delay setting in the protection
stage setting view in Easergy Pro to accept the zero operate time setting for the DT function.
63) EI = Extremely Inverse, NI = Normal Inverse, VI = Very Inverse, LTI = Long Time Inverse, MI=
Moderately Inverse
Table 83 - Directional ground fault overcurrent 67N-3 (67N)
Input signal
IN, VN
IN Calc = ( IA + IB + IC)
Start voltage
1–100% V0N (step 1%)
Mode
Non-directional/Sector/ResCap
Base angle setting range
-180° – 179°
Operation angle
±88°
Definite time function:
- Operate time
0.1064)– 300.00 s (step 0.02 s)
IDMT function:
- Delay curve family
(DT), IEC, IEEE, RI Prg
- Curve type
EI, VI, NI, LTI, MI…, depends on the
- Inv. time coefficient k
family65)
0.05–20.0, except
0.50–20.0 for RI, IEEE and IEEE2
P3T/en M/J006
Start time
Typically 60 ms
Reset time
< 95 ms
Reset ratio
0.95
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Transformer protection relay
6 Protection functions
Reset ratio (angle)
2°
Inaccuracy:
- Starting VN & IN (rated value In= 1 – 5A)
±3% of the set value or ±0.3% of the rated
value
- Starting VN & IN (Peak Mode when, rated
±5% of the set value or ±2% of the rated
value I0n= 1 – 10A)
value (Sine wave <65 Hz)
- Starting VN & IN (IN Calc)
±3% of the set value or ±0.5% of the rated
value
- Angle
±2° when V> 1V and IN> 5% of I0N or > 50
mA
else ±20°
- Operate time at definite time function
±1% or ±30 ms
- Operate time at IDMT function
±5% or at least ±30 ms64)
64) This
is the instantaneous time, that is, the minimum total operate time including the fault detection
time and the operate time of the trip contacts. Use the Accept zero delay setting in the protection
stage setting view in Easergy Pro to accept the zero operate time setting for the DT function.
65) EI = Extremely Inverse, NI = Normal Inverse, VI = Very Inverse, LTI = Long Time Inverse, MI=
Moderately Inverse
6.24.1 Ground fault phase detection
The ground fault overcurrent stage (ANSI 50N/51N) and directional ground fault
overcurrent stage (ANSI 67N) have an inbuilt detection algorithm to detect a faulty
phase. This algorithm is meant to be used in radial-operated distribution
networks. The faulty phase detection can be used in solidly-grounded,
impedance-grounded or resonant-grounded networks.
Operation
The faulty phase detection starts from the ground fault stage trip. At the moment
of stage start, the phase currents measured prior to start are registered and
stored as prior-to-fault currents. At the moment of trip, phase currents are
registered again. Finally, faulty phase detection algorithm is performed by
comparing prior-to-fault currents to fault currents. The algorithm also uses positive
sequence current and negative sequence current to detect faulty phase.
The detection algorithm can be enabled and disabled by selecting or unselecting
a checkbox in the protection stage settings. Correct network grounding
configuration must be selected in the stage settings, too. In the ground fault
overcurrent stage settings, you can select between RES and CAP network
grounding configuration. This selection has no effect on the protection itself, only
on the faulty phase detection. In the directional ground fault overcurrent stage
settings, the detection algorithm uses the same network grounding type as
selected for protection. RES is used for solidly-grounded, impedance-grounded
and resonant-grounded networks. CAP is only used for isolated networks.
218
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The detected faulty phase is registered in the protection stage fault log (and also
in the event list and alarm screen). Faulty phase is also indicated by a line alarm
and line fault signals in the output matrix.
Possible detections of faulty phases are A-N, B-N, C-N, AB-N, AC-N, BC-N, ABCN, and REV. If the relay protection coordination is incorrect, REV indication is
given in case of a relay sympathetic trip to a reverse fault.
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6.25 Second harmonic inrush detection (ANSI 68F2)
Description
This stage can be used to block other stages and to indicate possible primary
faults in the power distribution network. The ratio between the second harmonic
component and the fundamental frequency component is measured on all the
phase currents. When the ratio in any phase exceeds the setting value, the stage
gives a start signal. After a settable delay, the stage gives a trip signal.
The start and trip signals can be used for blocking the other stages.
The trip delay is irrelevant if only the start signal is used for blocking.
The trip delay of the stages to be blocked must be more than 60 ms to ensure a
proper blocking.
Block diagram
Figure 128 - Block diagram of the second harmonic inrush detection stage
2ndHarm
Im1
Im2
Im3
MAX
>
ts
tr
&
E
&
A
G
t
&
B
A. Block
B. Setting 2nd harmonics
C. Delay
D. Enable events
C
F
F
D
E. Start
F. Register event
G. Trip
Characteristics
Table 84 - Second harmonic inrush detection (68F2)
Current input
IL or I’L
Input signal
IA – IC
Settings:
- Start value
10–100 % (step 1%)
- Operate time
0.03–300.00 s (step 0.01 s)
Inaccuracy:
- Starting
220
±1% - unit
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6 Protection functions
Transformer protection relay
NOTE: The amplitude of second harmonic content has to be at least 2% of
the nominal of CT. If the nominal current is 5 A, the 100 Hz component needs
to exceed 100 mA.
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6.26 Fifth harmonic detection (ANSI 68H5)
Description
Overexcitation of a transformer creates odd harmonics. The fifth harmonic
detection stage can be used detect overexcitation. This stage can also be used to
block some other stages.
The ratio between the fifth harmonic component and the fundamental frequency
component is measured on all the phase currents. When the ratio in any phase
exceeds the setting value, the stage activates a start signal. After a settable delay,
the stage operates and activates a trip signal.
The trip delay of the stages to be blocked must be more than 60 ms to ensure a
proper blocking.
Characteristics
Table 85 - Fifth harmonic detection (68H5)
Current input
IL or I’L
Input signal
IA – IC
Settings:
- Setting range over exicitation
10–100% (step 1%)
- Operate time
0.03–300.00 s (step 0.01 s)
Inaccuracy:
- Starting
222
±2%- unit
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6 Protection functions
Transformer protection relay
6.27 Overfrequency and underfrequency (ANSI 81)
Description
Frequency protection is used for load sharing and shedding, loss of power system
detection and as a backup protection for overspeeding.
The frequency function measures the frequency from the two first voltage inputs.
At least one of these two inputs must have a voltage connected to be able to
measure the frequency. Whenever the frequency crosses the start setting of a
particular stage, this stage starts, and a start signal is issued. If the fault remains
on longer than the operating delay setting, a trip signal is issued. For situations
where no voltage is present, an adapted frequency is used.
Protection mode for 81–1 and 81–2 stages
These two stages can be configured either for overfrequency or for
underfrequency.
Undervoltage self-blocking of underfrequency stages
The underfrequency stages are blocked when the biggest of the three line-to-line
voltages is below the low-voltage block limit setting. With this common setting,
LVBlk, all stages in underfrequency mode are blocked when the voltage drops
below the given limit. The idea is to avoid purposeless alarms when the voltage is
off.
Initial self-blocking of underfrequency stages
When the biggest of the three line-to-line voltages has been below the block limit,
the underfrequency stages are blocked until the start setting has been reached.
Five independent frequency stages
There are five separately adjustable frequency stages: 81–1, 81–2, 81U–1,
81U-2, 81U-3. The two first stages can be configured for either overfrequency or
underfrequency usage. So totally five underfrequency stages can be in use
simultaneously. Using the programmable stages even more can be implemented
(chapter 6.32 Programmable stages (ANSI 99)). All the stages have definite
operate time delay (DT).
Setting groups
There are four setting groups available for each stage.
Characteristics
Table 86 - Overfrequency and underfrequency 81–1, 81–2 (81H/81L)
P3T/en M/J006
Input signal
VA – VC
Frequency measuring area
16.0–75.0 Hz
Current and voltage meas. range
45.0–65.0 Hz
Frequency stage setting range
40.0–70.0 Hz (step 0.01)
223
Transformer protection relay
6 Protection functions
Low-voltage blocking
10–100% Vn
Definite time function:
-Operate time
0.0866) – 300.0 s (step 0.02 s)
Start time (overfrequency)
< 100 ms
Start time (underfrequency)
< 80 ms (slope change)
Reset time
<120 ms
Reset ratio (LV block)
Instant (no hysteresis)
Inaccuracy:
- Starting
±20 mHz
- Starting (LV block)
3% of the set value or ±0.5 V
- operate time
±1% or ±30 ms
66) This
is the instantaneous time, that is, the minimum total operate time including the fault detection
time and the operate time of the trip contacts. Use the Accept zero delay setting in the protection
stage setting view in Easergy Pro to accept the zero operate time setting for the DT function.
NOTE: If the relay restarts for some reason, there is no trip even if the
frequency is below the set limit during the start-up (Start and trip is blocked).
To cancel this block, frequency has to rise above the set limit.
Table 87 - Underfrequency 81U–1, 81U–2, 81U–3 (81L)
Input signal
VA – Vc
Frequency measuring area
16.0–75.0 Hz
Current and voltage meas. range
45.0–65.0 Hz
Frequency stage setting range
40.0–64.0 Hz
Low-voltage blocking
10–100% Vn
Definite time function:
224
- operate time
0.0867) – 300.0 s (step 0.02 s)
Undervoltage blocking
2–100 %
Start time
< 80 ms (slope change)
Reset time
< 120 ms
Reset ratio
1.002
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Transformer protection relay
Reset ratio (LV block)
Instant (no hysteresis)
Inaccuracy:
- Starting
±20 mHz
- starting (LV block)
3% of the set value or ±0.5 V
- operate time
±1% or ±30 ms
67) This
is the instantaneous time, that is, the minimum total operate time including the fault detection
time and the operate time of the trip contacts. Use the Accept zero delay setting in the protection
stage setting view in Easergy Pro to accept the zero operate time setting for the DT function.
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6.28 Rate of change of frequency (ANSI 81R)
Description
The rate of change of frequency (ROCOF or df/dt) function is used for fast load
shedding, to speed up operate time in overfrequency and underfrequency
situations and to detect loss of grid. For example, a centralized dedicated load
shedding relay can be omitted and replaced with distributed load shedding, if all
outgoing feeders are equipped with Easergy P3 relays.
NOTE: Use ROCOF for load shedding only. Do not use it for loss of mains
detection.
Frequency behavior during load switching
Load switching and fault situations may generate change in frequency. A load
drop may increase the frequency and increasing load may decrease the
frequency, at least for a while. The frequency may also oscillate after the initial
change. After a while, the control system of any local generator may drive the
frequency back to the original value. However, in case of a heavy short-circuit
fault or if the new load exceeds the generating capacity, the average frequency
keeps on decreasing.
Figure 129 - An example of definite time df/dt operate time. At 0.6 s, which is the
delay setting, the average slope exceeds the setting 0.5 Hz/s and a trip signal is
generated.
FREQUENCY
(Hz)
ROCOF1_v3
1.
0
Hz
/s
0.5
H
2.0
0.7
Hz
5H
/s
z/s
z/s
Settings:
df/dt = 0.5 Hz/s
t = 0.60 s
tMin = 0.60 s
TIME
(s)
START
TRIP
ROCOF implementation
The ROCOF function is sensitive to the absolute average value of the time
derivate of the measured frequency |df/dt|. Whenever the measured frequency
slope |df/dt| exceeds the setting value for 80 ms time, the ROCOF stage starts
and issues a start signal after an additional 60 ms delay. If the average |df/dt|,
since the start moment, still exceeds the setting, when the operation delay has
elapsed, a trip signal is issued. In this definite time mode the second delay
parameter "minimum delay, tMIN" must be equal to the operation delay parameter
"t".
If the frequency is stable for about 80 ms and the time t has already elapsed
without a trip, the stage resets.
226
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ROCOF and overfrequency and underfrequency stages
One difference between the overfrequency and underfrequency and the df/dt
function is the speed. Often a df/dt function can predict an overfrequency or
underfrequency situation and is thus faster than a simple overfrequency or
underfrequency function. However, in most cases, standard overfrequency and
underfrequency stages must be used together with ROCOF to ensure tripping
also if the frequency drift is slower than the slope setting of ROCOF.
Definite operate time characteristics
Figure 129 shows an example where the df/dt start value is 0.5 Hz/s and the
delay settings are t = 0.60 s and tMIN = 0.60 s. Equal times t = tMIN gives a definite
time delay characteristic. Although the frequency slope fluctuates, the stage does
not release but continues to calculate the average slope since the initial start. At
the defined operate time, t = 0.6 s, the average slope is 0.75 Hz/s. This exceeds
the setting, and the stage trips.
At slope settings less than 0.7 Hz/s, the fastest possible operate time is limited
according to the Figure 130.
Figure 130 - At very sensitive slope settings the fastest possible operate time is
limited.
Fastest possible operation time setting (s)
ROCOF5_v3
Slope setting df/dt (Hz/s)
Dependent operate time characteristics
By setting the second delay parameter tMIN smaller than the operate time delay t,
a dependent type of operate time characteristic is achieved.
Figure 132 shows one example, where the frequency behavior is the same as in
the first figure, but the tMIN setting is 0.15 s instead of being equal to t. The
operate time depends on the measured average slope according to the following
equation:
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Equation 23
t TRIP =
s SET ⋅ t SET
s
tTRIP = Resulting operate time (seconds).
sSET = df/dt i.e. slope setting (hertz/seconds).
tSET = Operate time setting t (seconds).
s = Measured average frequency slope (hertz/seconds).
The minimum operate time is always limited by the setting parameter tMIN. In the
example, the fastest operate time, 0.15 s, is achieved when the slope is 2 Hz/s or
more. The leftmost curve in Figure 131 shows the dependent characteristics with
the same settings as in Figure 132.
Figure 131 - Three examples of possible dependent df/dt operate time
characteristics. The slope and operation delay settings define the knee points on
the left. A common setting for tMin has been used in these three examples. This
minimum delay parameter defines the knee point positions on the right.
Slope and delay settings
0.5 Hz/s 1 Hz/s 1.5 Hz/s
Operation time (s)
ROCOF6_v3
Setting for minimum delay
tMin= 0.15 s
Measured slope |df/dt| (Hz/s)
228
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Figure 132 - An example of dependent df/dt operate time. The time to trip will be
0.3 s, although the setting is 0.6 s, because the average slope 1 Hz/s is steeper
than the setting value 0.5 Hz/s.
FREQUENCY
(Hz)
ROCOF3_v3
50.0
0
1.
Settings:
df/dt = 0.5 Hz/s
t = 0.60 s
tMin = 0.15s
s
z/
H
0.5
2.0
Hz/
Hz
0.00
0.15
/s
Hz
/s
s
49.7
0.7
5
0.30
0.45
0.60
TIME
(s)
START
TRIP
Settings groups
There are four setting groups available.
Characteristics
Table 88 - Rate of change of frequency 81R (81R)
Start setting df/dt
0.2–10.0 Hz/s (step 0.1 Hz/s)
Definite time delay (t> and tMin> are equal):
- Operate time t>
0.1468) – 10.00 s (step 0.02 s)
Dependent time delay (t> is more than
tMin>):
0.1468) – 10.00 s (step 0.02 s)
- Minimum operate time tMin>
Start time
Typically 140 ms
Reset time
150 ms
Overshoot time
< 90 ms
Reset ratio
1
Inaccuracy:
- Starting
10% of set value or ±0.1 Hz/s
- Operate time(overshoot ≥ 0.2 Hz/s)
±35 ms, when area is 0.2 – 1.0 Hz/s
68) This
is the instantaneous time, that is, the minimum total operate time including the fault detection
time and the operate time of the trip contacts. Use the Accept zero delay setting in the protection
stage setting view in Easergy Pro to accept the zero operate time setting for the DT function.
NOTE: ROCOF stage is using the same low voltage blocking limit as the
frequency stages.
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6.29 Lockout (ANSI 86)
Description
The lockout feature, also called latching, can be programmed for outputs in the
Output matrix setting view. Any protection stage start or trip, digital input, logic
output, alarm and GOOSE signal connected to the following outputs can be
latched when required:
•
•
•
output contacts T1 – T7, A1
LEDs on the front panel
virtual outputs VO1- VO20
Figure 133 - The lockout programmed for LED A and 50/51-2 trip signals
In Figure 133, the latched signal is identified with a dot and circle in the matrix
signal line crossing.
The lockout can be released through the display or via the Easergy Pro. See
Chapter 4 Control functions.
Storing latch states
In the General > Release latches setting view, select the Store latch state
setting to configure latched states of relay outputs, virtual outputs, binary outputs
(BO) and high-speed outputs (HSO) to be stored. If some of these outputs are
latched and in “on” state, and the device is restarted, their status is set back to
“on” after restart.
Figure 134 - Store latch setting view
230
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In the LED configuration setting view, you can configure the latched states of
LEDs to be stored after a restart. In this example, storing has been configured for
LED A (green).
Figure 135 - LED configuration example
NOTE: To use the Store setting, Latch must also be selected.
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6.30 Differential overcurrent protection (ANSI 87T)
Description
The differential overcurrent protection comprises of two separately adjustable
stages: 87-1 and 87-2.
The differential protection is based on the winding currents' difference between I-1
and I-2 side. In transformer applications, the current calculation depends on
transformer connection group. For example, in a Yy0 connection, the measured
currents are also winding currents, see Figure 136.
Figure 136 - Winding currents in connection group Yy0
WindingCurrent1
IA
IB
IA winding
I’A winding
IB winding
I’B winding
IC winding
I’C winding
IC
I’C
I’B
I’A
In the second example, if the transformer IL side is connected to open delta for
example Dy11, then the winding currents are calculated on the delta side (IL
side), see Figure 137.
Figure 137 - Winding currents in connection group Dy11
WindingCurrent2
IA
IB
IA winding
I’A winding
IB winding
I’B winding
IC winding
I’C winding
IC
I’C
I’B
I’A
Equation 24 - Winding current calculation in delta side, Dy11 connection
(
IAW = IA − IB
)
3
(
IBW = IB − IC
)
3
(
ICW = IC − IA
)
3
232
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Equation 25 - Winding currents in star side, Dy11 connection
I ' AW = I ' A
I' BW = I' B
I ' CW = I ' C
Equation 26 - Bias current
Ib =
IW + I ' W
2
Equation 27 - Differential current
I d = IW + I ' W
Bias current calculation is only used in protection stage 87–1>. Bias current
describes the average current flow in the transformer. Bias and differential
currents are calculated individually for each phase.
If the transformer is grounded, for example having the connection group Dyn11,
then zero current must be compensated before differential and bias current
calculation. Zero current compensation can be selected individually for the IL and
I’L side.
Table 89 describes the connection group and zero current compensation for
different connection groups. If the protection area is only generator, then the
connection group setting is always Yy0, see Table 89. Also the settings of Vn and
V’n are set to be the same, for example generator nominal voltage.
Table 89 - Zero-current compensation in transformer applications
Transformator
P3T/en M/J006
Relay setting
Connection
group
ConnGrp
Io cmps
I'o cmps
YNy0
Yy0
ON
OFF
YNyn0
Yy0
ON
ON
Yy0
Yy0
OFF
OFF
Yyn0
Yy0
OFF
ON
YNy6
Yy6
ON
OFF
YNyn6
Yy6
ON
ON
Yy6
Yy6
OFF
OFF
Yyn6
Yy6
OFF
ON
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Transformator
Relay setting
Connection
group
ConnGrp
Io cmps
I'o cmps
Yd1
Yd1
OFF
OFF
YNd1
Yd1
ON
OFF
Yd5
Yd5
OFF
OFF
YNd5
Yd5
ON
OFF
Yd7
Yd7
OFF
OFF
YNd7
Yd7
ON
OFF
Yd11
Yd11
OFF
OFF
YNd11
Yd11
ON
OFF
Dy1
Dy1
OFF
OFF
Dyn1
Dy1
OFF
ON
Dy5
Dy5
OFF
OFF
Dyn5
Dy5
OFF
ON
Dy7
Dy7
OFF
OFF
Dyn7
Dy7
OFF
ON
Dy11
Dy11
OFF
OFF
Dyn11
Dy11
OFF
ON
NOTE: Connect the high-voltage side currents to IL terminals.
Table 90 - Zero-current compensation in generator applications
Genarator only
No grounding
234
Relay setting
ConnGrp
Io cmps
I'o cmps
Yy0
OFF
OFF
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Figure 138 - Block diagram of the differential overcurrent stage ΔI>
difflslohko
IL1
IL2
IL3
H
I
M
I'L1
I'L2
I'L3
H
J
M
K
>1
&
N
&
O
M
>
L
>
A
B
C
D
E F
A. Conngrp setting
I. I0 compensation
B. I0 cmps
J. I’0 compensation
C. I’0 cmps
K. 2nd harmonics / Fund
D. 5th harmonics setting
E. 2nd harmonics setting
L. 5th harmonics / Fund
M. Diff & bias calculation
F. Δ I> setting
G. Enable events
H. Y/D
N. Trip
O. Register event
G
The stage ΔI> can be configured to operate as shown in Figure 139. This dual
slope characteristic allows more differential current at higher currents before
tripping.
Figure 139 - Example of differential overcurrent characteristics
A
M
B
N
K
I
L
J
0.5
C
0.1
H
D
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E
F
A. ID/ITN
H. IBIAS
B. Minimum trip area
C. ISTART
I. Maximum setting
G
J. Slope 1
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D. 0.5 x IN / IBIAS1
K. Slope 2
E. IN
L. Minimum setting
F. IBIAS2
M. Default setting
G. 3 x IN
N. Setting area
Table 91 - Settings
Parameter
Value
Default
IStart
5...50% IN
0.25
Slope 1
5...100%
50%
IBIAS2
1.00...3.00 x IN
2.00
Slope 2
100...200%
150%
The stage also includes second harmonic blocking. The second harmonic is
calculated from differential currents. Harmonic ratio is:
100 x If2_Winding / If1_Winding [%].
The fast differential overcurrent stage 87–1 does not include slope characteristics
or second harmonics blocking.
Current transformer supervision
The current transformer supervision (CTS) feature is used to detect a failure of
one or more of the phase current inputs to the relay. Failure of a phase current
transformer (CT) or an open circuit of the interconnecting wiring can result in
incorrect operation of any current-operated element. Additionally, interruption in
the current circuit generates dangerous CT secondary voltages.
Figure 140 - Current transformer supervision settings
The differential CTS method uses the ratio between positive and negative
sequence currents at both sides of the protected transformer to determine a CT
failure. This algorithm is inbuilt in the dI> stage. When this ratio is small (zero),
one of the following four conditions is present:
•
•
•
•
The system is unloaded – both I2 and I1 are zero.
The system is loaded but balanced – I2 is zero.
The system has a three-phase fault – I2 is zero.
There is a three-phase CT failure – unlikely to happen.
When the ratio is non-zero, one of the following two conditions is present:
•
•
236
The system has an asymmetric fault – both I2 and I1 are non-zero.
There is a 1 or 2 phase CT fault – both I2 and I1 are non-zero.
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The I2 to I1 ratio is calculated at both sides of the protected transformer. With this
information, we can assume that:
•
•
If the ratio is non-zero at both sides, there is a real fault in the network and the
CTS should not operate.
If the ratio is non-zero only at one side, there is a change of CT failure and the
CTS should operate.
Another criterion for CTS is to check whether the differential system is loaded or
not. For this purpose, the positive sequence current I1 is checked at both sides of
the protected transformer.
If load current is detected only at one side, it is assumed that there is an internal
fault condition and CTS is prevented from operating, but if load current is detected
at both line ends, CTS operation is permitted.
Another criterion for CTS is to check whether the differential system is loaded or
not. For this purpose, the positive sequence current I1 is checked at both ends. If
load current is detected only at one end, it is assumed that there is an internal
fault condition and CTS is prevented from operating, but if load current is detected
at both line ends, CTS operation is permitted.
There are three modes of operation:
•
•
•
indication mode: CTS alarm is raised but there is no effect on tripping
restrain mode: an alarm is raised and the differential current percentage
setting value increased by 100 (for example 30 % + 100 % = 130 %). The new
value is theoretically the maximum amount of differential current that a CT
failure can produce in a normal full-load condition.
block mode: an alarm is raised and differential protection is prevented from
tripping
The differential CTS block mode is not recommended for two reasons:
•
•
If there is a real fault during a CT failure, the differential protection would not
protect the line at all.
Blocking the protection could slow down the operate time of the differential
protection because of transients in the beginning of the fault on the protected
line.
Setting groups
This stage has one setting group.
Characteristics
Table 92 - Differential overcurrent stage 87T-1
P3T/en M/J006
Start value
5–50 % IN
Bias current for start of slope 1
0.50 x IN
Slope 1
5–100 %
Bias current for start of slope 2
1.00–3.00 x IN
Slope 2
100–200 %
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6 Protection functions
Second harmonic blocking
5–30 %, or disable
Fifth harmonic blocking
20–50 %, or disable
Reset time
< 95 ms
Reset ratio
0.95
Inaccuracy:
- Second harmonic blocking
±2% - unit
- Fifth harmonic blocking
±3% - unit
- Starting
±3% of set value or 0.02 x IN when currents
are < 200 mA
- Operate time (ID > 1.2 x ISET)
< 60 ms
- Operate time (ID > 3.5 x ISET)
< 50 ms
Table 93 - Differential overcurrent stage 87T-2
Start value
5.0 – 40.0 x IN
Reset time
< 95 ms
Reset ratio
0.95
Inaccuracy:
238
- Starting
±3% of set value or ±0.5% of rated value
- Operate time (ID > 3.5 x ISET)
< 40 ms
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6.31 Arc flash detection (AFD)
DANGER
HAZARD OF ELECTRIC SHOCK, EXPLOSION, OR ARC FLASH
Information on this product is offered as a tool for conducting arc flash
hazard analysis. It is intended for use only by qualified persons who are
knowledgeable about power system studies, power distribution equipment,
and equipment installation practices. It is not intended as a substitute for the
engineering judgement and adequate review necessary for such activities.
Failure to follow this instruction will result in death or serious injury.
6.31.1 Arc flash detection, general principle
The arc flash detection contains 8 arc stages that can be used to trip for example
the circuit breakers. Arc stages are activated with overcurrent and light signals (or
light signals alone). The allocation of different current and light signals to arc
stages is defined in arc flash detection matrices: current, light and output matrix.
The matrices are programmed via the arc flash detection menus. Available matrix
signals depend on the order code (see 13.1 Order codes).
The available signal inputs and outputs for arc flash detection depend on the
relay's hardware configuration.
6.31.2 Arc flash detection menus
The arc flash detection menus are located in the main menu under ARC. The
ARC menu can be viewed either on the front panel or by using Easergy Pro.
Arc protection
Table 94 - Arc protection parameter group
Item
Default
Range
Description
I>int. start setting
1.00 xln
0.50–8.00 x ln
Phase A, B, C
overcurrent start
level
Io>int. start setting
1.00 xln
0.10–5.00 x ln
Residual overcurrent
start level
Install arc sensors
-
-, Install
Installs all connected
sensors
Installation state
Ready
Installing, Ready
Installation state
Link Arc selfdiag to
On
On, Off
Links Arc protection
SF relay
selfsupervision
signal to SF relay
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Item
Default
Range
Description
Stage Enabled
On or Off
On, Off
Enables the arc
protection stage
Trip delay [ms]
0
0–255
Trip delay for the arc
protection stage
Min. hold time
2
2–255
[10ms]
Minimum trip pulse
length for the arc
protection stage
(Overshoot time
<35ms)
Loop Sensor’s
737
100–900
sensitivity
Sensitivity setting for
fibre loop sensor
WARNING
HAZARD OF DELAYED OPERATION
Do not use the arc stage delay for primary trip. This delay is intended, with
the separate arc stage, for the circuit breaker failure scheme only
Failure to follow these instructions can result in death, serious injury,
or equipment damage.
6.31.3 Configuration example of arc flash detection
Installing the arc flash sensors and I/O units
1. Go to Protection > Arc protection.
2. Under Settings, click the Install arc sensors drop-down list and select
Install.
3. Wait until the Installation state shows Ready. The communication between
the system components is created.
4. The installed sensors and units can be viewed at the bottom of the Arc
protection group view.
Figure 141 - Installed arc sensors
On the Easergy Pro group list, select Arc protection.
5. Click the Arc Stages 1, 2, and select Stage 1 and 2 'On'.
6. Click the Trip delay[ms] value, set it to for example '0' and press Enter.
7. Click the DI block value, set it to for example '-' and press Enter.
240
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Configuring the current start values
The General > Scaling setting view contains the primary and secondary values
of the CT. However, the Arc protection menu calculates the primary value only
after the I start setting value is given.
For example:
1. Go to General > Scaling.
2. Click the CT primary value, set it to for example 1200 A, and press Enter.
3. Click the CT secondary value, set it to for example 5 A, and press Enter.
4. On the Easergy Pro group list, select Protection > Arc protection.
5. Define the I start setting value for the relay.
6. Define the Io start setting in a similar manner.
Figure 142 - Example of setting the current transformer scaling values
Figure 143 - Example of defining the I start setting value
Configuring the current matrix
Define the current signals that are received in the arc flash detection system’s
relay. Connect currents to Arc stages in the matrix.
For example:
The arc flash fault current is measured from the incoming feeder, and the current
signal is linked to Arc stage 1 in the current matrix.
1. Go to Matrix > Arc matrix - Current
2. In the matrix, select the connection point of Arc stage 1 and I>int.
3. On the Communication menu, select Write Changed Settings To Device.
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Figure 144 - Configuring the current matrix – an example
Configuring the light matrix
Define what light sensor signals are received in the detection system. Connect
the light signals to the arc stages in the matrix.
For example:
1. Go to Matrix > Arc matrix - Light.
2. In the matrix, select the connection point of Arc sensor 1 and Arc stage 2.
3. Select the connection point of Arc sensor 2 and Arc stage 2.
4. On the Communication menu, select Write Changed Settings To Device.
Figure 145 - Configuring the light arc matrix
Configuring the output matrix
Define the trip relays that the current and light signals affect.
For example:
242
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1. Go to Matrix > Arc matrix - Output.
2. In the matrix, select the connection point of Arc stage 1 and T1.
3. Select the connection points of Latched and T1 and T9.
4. Select the connection point of Arc stage 2 and T9.
5. On the Communication menu, select Write Changed Settings To Device.
NOTE: It is recommended to use latched outputs for the trip outputs.
Arc output matrix includes only outputs which are directly controlled by FPGA.
Figure 146 - Configuring the output matrix - an example
Configuring the arc events
Define which arc events are written to the event list in this application.
For example:
1. Go to Logs > Event enabling - Arc.
2. In the matrix, enable both ‘Act On’ event and ‘Act Off’’ event for Arc sensor
1, Arc stage 1, and Arc stage 2.
3. On the Communication menu, select Write Changed Settings To Device.
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Figure 147 - Configuring the arc events – an example
6.31.4 Arc flash detection characteristics
The operation of the arc detection depends on the setting value of the I> int and
I01> int current limits.
The arc current limits cannot be set, unless the relay is provided with the optional
arc protection card.
Table 95 - Arc flash detection characteristics
Start current:
Phase currents
0.50–8.00 x IN (step 0.01)
Residual current
0.10–5.00 x IN (step 0.01)
Operate time
High break trip relays (T1, T9–T12)
- Light only
≤9 ms
- 4 x Iset and light
≤9 ms
Trip relays (T2, T3 and T4)
- Light only
≤7 ms
- 4 x Iset and light
≤7 ms
Semiconductor outputs (HSO1 – HSO2)
- Light only
≤2 ms
- 4 x Iset and light
≤2 ms
- Arc stage delay
0 – 255 ms
Inaccuracy:
244
Current
±5% of the set value
Delayed operation time
+≤10 ms of the set value
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6.32 Programmable stages (ANSI 99)
Description
For special applications the user can built own detection stages by selecting the
supervised signal and the comparison mode.
The following parameters are available:
•
•
•
•
•
•
•
•
•
•
•
Priority: Protection task execution cycle. If operate times less than 80
milliseconds are needed, select 10 ms. For operate times under one second,
20 ms is recommended. For longer operation times and THD signals, 100 ms
is recommended.
Time-base for input value A: ”Instant” is the latest available value of the
measurement. The other ones are average values of the measurement during
the given time. The average values are calculated for different purposes all
the time, for example, the 200 ms value is used to update the local display.
NOTE: Pay attention to selecting these timing values. For example,
having a short operate time but 1 minute time base does not necessarily
give the expected result. Using long time bases gives the possibility to use
a filtered value to avoid unnecessary operations.
Coupling A: The selected supervised signal in “>” and “<” mode. The
available signals are shown in the table below.
Coupling B: The selected supervised signal in "Diff" and "AbsDiff" mode. This
selection becomes available once "Diff" or "AbsDiff" is chosen for Coupling A.
Compare condition: Compare mode. ‘>’ for over or ‘<’ for under comparison,
“Diff” and “AbsDiff” for comparing Coupling A and Coupling B.
AbsDiff | d |: Coupling A – coupling B. The stage activates if the difference is
greater than the start setting.
Diff d: Coupling A – coupling B. The stage activates if the sign is positive and
the difference greater than the start setting.
Start: Limit of the stage. The available setting range and the unit depend on
the selected signal.
Operation delay: Definite time operation delay
Hysteresis: Dead band (hysteresis). For more information, see 6.5 General
features of protection stages.
No Compare limit for mode < : Only used with compare mode under (‘<’).
This is the limit to start the comparison. Signal values under NoCmp are not
regarded as fault.
Table 96 - Available signals to be supervised by the programmable stages
P3T/en M/J006
IA, IB, IC
Phase currents (RMS values)
VAB, VBC, VCA
Line-to-line voltages
IN
Ground fault overcurrent
VA, VB, VC
Line-to-neutral voltages
VN
Neutral displacement voltage
f
Frequency
P
Active power
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Q
Reactive power
S
Apparent power
Cos Phi
Cosine φ
IN Calc
Phasor sum IA + IB + IC
I1
Positive sequence current
I2
Negative sequence current
I2/I1
Relative negative sequence current
I2/In
Negative sequence current in pu
V1
Positive sequence overvoltage
V2
Negative sequence overvoltage
V2/V1
Relative negative sequence voltage
IAVG
Average (IA + IB + IC) / 3
Tan Phi
Tangent φ [= tan(arccosφ)]
PRMS
Active power RMS value
QRMS
Reactive power RMS value
SRMS
Apparent power RMS value
THDILA
Total harmonic distortion of IA
THDILB
Total harmonic distortion of IB
THDILC
Total harmonic distortion of IC
THDUA
Total harmonic distortion of input VA
THDUB
Total harmonic distortion of input VB
THDUC
Total harmonic distortion of input VC
fy
Frequency behind circuit breaker
fz
Frequency behind 2nd circuit breaker
IA RMS
IA RMS for average sampling
IB RMS
IB RMS for average sampling
IC RMS
IC RMS for average sampling
ILmin, ILmax
Minimum and maximum of phase currents
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VLNmin, VLNmax
Minimum and maximum of line-to-neutral
voltages
VAI1, VAI2, VAI3, VAI4, VAI5
Virtual analog inputs 1, 2, 3, 4, 5 (GOOSE)
Signals available depending on slot 8 options.
Eight independent stages
The relay has eight independent programmable stages. Each programmable
stage can be enabled or disabled to fit the intended application.
Setting groups
There are four settings groups available.
See 6.5 General features of protection stages for more details.
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7.1 Event log
The event log is a buffer of event codes and time stamps including date and time.
For example, each start-on, start-off, trip-on or trip-off of any detection stage has
a unique event number code. Such a code and the corresponding time stamp is
called an event.
As an example, a typical event of programmable stage trip event is shown in
Table 97.
Table 97 - Example of Pgr1 stage trip on event and its visibility in local panel and
communication protocols
EVENT
Description
Local panel
Communication
protocols
Code: 01E02
Channel 1, event 2
Yes
Yes
Prg1 trip on
Event text
Yes
No
2.7 x In
Fault value
Yes
No
2007-01-31
Date
Yes
Yes
08:35:13.413
Time
Yes
Yes
Events are the major data for a SCADA system. SCADA systems are reading
events using any of the available communication protocols. The Event log can
also be scanned using the front panel or Easergy Pro. With Easergy Pro, the
events can be stored to a file especially if the relay is not connected to any
SCADA system.
Only the latest event can be read when using communication protocols or
Easergy Pro. Every reading increments the internal read pointer to the event
buffer. (In case of communication interruptions, the latest event can be reread any
number of times using another parameter.) On the local panel, scanning the event
buffer back and forth is possible.
Event enabling/masking
An uninteresting event can be masked, which prevents it to be written in the event
buffer. By default, there is room for 200 latest events in the buffer. The event
buffer size can be modified from 50 to 2000. The existing events are lost if the
event buffer size is changed.
You can make this modification in the Local panel conf setting view.
An indication screen (popup screen) can also be enabled in this same menu in
Easergy Pro. The oldest event is overwritten when a new event occurs. The
shown resolution of a time stamp is one millisecond, but the actual resolution
depends on the particular function creating the event. For example, most
detection stages create events with 5 ms, 10 ms or 20 ms resolution. The
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absolute accuracy of all time stamps depends on the relay's time synchronization.
See 7.4 System clock and synchronization for system clock synchronizing.
Event buffer overflow
The normal procedure is to poll events from the relay all the time. If this is not
done, the event buffer could reach its limits. In that case, the oldest event is
deleted and the newest displayed with OVF (overflow) code on the front panel.
Table 98 - Setting parameters for events
Parameter
Value
Count
ClrEv
Description
Note
Number of events
-
Clear event buffer
Set
Order of the event
Set
Clear
Order
Old-New
New-Old
FVScal
buffer for local
display
Scaling of event fault Set
value
Display
Alarms
PU
Per unit scaling
Pri
Primary scaling
On
Indication dispaly is
Off
Set
enabled
No indication display
Sync
Controls event time
format
On
Off
Event time shown
normally if relay is
synchronized
Event time is shown
in brakets if relay is
not synchronized
FORMAT OF EVENTS ON THE LOCAL DISPLAY
Code: CHENN
CH = event channel, NN=event code
(channel number is not shown in case
channel is zero)
Event description
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Parameter
Value
yyyy-mm-dd
Description
Note
Date
(for available date formats, see 7.4 System
clock and synchronization)
hh:mm:ss.nnn
Time
7.2 Disturbance recording
The disturbance recorder (DR) can be used to record all the measured signals,
that is, currents, voltage and the status information of digital inputs (DI) and digital
outputs (DO). If the sample rate is slower than 1/10 ms, also the calculated
signals like active power, power factor, negative sequence overcurrent and so on
can be recorded. For a complete list of signals, see Table 99.
The available recording channels depend on the voltage measurement mode, too.
If a channel is added for recording and the added signal is not available because
of the used settings, the signal is automatically rejected from the recording
channel list.
NOTE: When protection stages are enabled or disabled or the recorder
signals or recording time changed, the disturbance recordings are deleted
from the relay's memory. Therefore, before activating or deactivating stages,
store the recordings on your PC.
Triggering the recording
The recording can be triggered by any start or trip signal from any protection
stage, by a digital input, logic output or GOOSE signals. The triggering signal is
selected in the output matrix (vertical signal DR). The recording can also be
triggered manually. All recordings are time-stamped.
Reading recordings
The recordings can be uploaded with Easergy Pro program. The recording is in
COMTRADE format. This also means that other programs can be used to view
and analyse the recordings made by the relay.
Number of channels
A maximum of 24 records can be stored. Up to 12 channels per record can be
stored. Both the digital inputs and the digital outputs (including all inputs and
outputs) use one channel out of the total of 12.
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Figure 148 - Recorder channels
Parameters
Table 99 - Disturbance recording parameters
Parameter
Value
Mode
Description
Note
Behavior in memory full situation:
Set69)
Saturated
No more recordings are accepted
Overflow
The oldest recording is overwritten
SR
P3T/en M/J006
Unit
Sample rate
32/cycle
Waveform
16/cycle
Waveform
8/cycle
Waveform
1/10ms
One cycle value70)
1/20ms
One cycle value 71)
1/200ms
Average
1/1s
Average
1/5s
Average
1/10s
Average
1/15s
Average
Set
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Parameter
Value
7 Supporting functions
Unit
Description
1/30s
Average
1/1min
Average
Note
Time
s
Recording length
Set
PreTrig
%
Amount of recording data before the trig moment
Set
MaxLen
s
Maximum time setting.
This value depends on the sample rate, number and type
of the selected channels and the configured recording
length.
ReadyRec
Readable recordings
Status
Status of recording
-
Not active
Run
Waiting a triggering
Trig
Recording
FULL
Memory is full in saturated mode
ManTrig
-, Trig
Manual triggering
ReadyRec
n/m
n = Available recordings / m = maximum number of
Set
recordings
The value of 'm' depends on the sample rate, number and
type of the selected channels and the configured
recording length.
69) Set
= An editable parameter (password needed).
is the fundamental frequency rms value of one cycle updated every 10 ms.
71) This is the fundamental frequency rms value of one cycle updated every 20 ms.
70) This
Table 100 - Disturbance recording parameters
Parameter
Value
ClrCh
-, Clear
AddCh
Unit
Description
Average
Waveform
Remove all channels
Add one channel. The maximum number of
channels used simultaneously is 12.
252
IA, IB, IC
Phase current
X
X
I’A, I’B, I’C
Phase current (lV side)
X
X
VAB, VBC, VCA
Line-to-line voltage
X
X
VA, VB, VC
Phase-to-neutral voltage
X
X
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Parameter
Value
Transformer protection relay
Unit
Description
Average
Waveform
VN
Neutral displacement voltage
X
X
f
Frequency
X
P, Q, S
Active, reactive, apparent power
X
P.F.
Power factor
X
CosPhi
cosφ
X
IN Calc
Phasor sum Io = (IA+IB+IC)/3
X
I1
Positive sequence current
X
I2
Negative sequence current
X
I2/I1
Relative current unbalance
X
I2/IN
Negative sequence overcurrent [x IN]
X
IAVG
Average (IA + IB + IC) / 3
X
DI
Digital inputs: DI1–20, F1, F2, BIOin, VI1-4, Arc1,
X
X
Arc2
DI_2
Digital inputs: DI21–40
X
X
DI_3
Virtual inputs: VI5–20, A1–A5, VO1–VO6
X
X
DO
Digital outputs: T1–15
X
X
DO_2
Rest of the outputs
X
X
DO_3
Virtual outputs, VO7–VO20
X
X
TanPhi
tanφ
X
THDIA,
Total harmonic distortion of IA, IB or IC
X
THDIB,
THDIC
X
P3T/en M/J006
Prms
Active power rms value
X
Qrms
Reactive power rms value
X
Srms
Apparent power rms value
X
fy
Frequency behind circuit breaker
X
fz
Frequency behind 2nd circuit breaker
X
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Parameter
Value
7 Supporting functions
Unit
Description
Average
IA, IB or IC RMS for average sampling
X
Arc 72)
Arc detection signals
X
Starts
Protection stage start signals
X
X
Trips
Protection stage trip signals
X
X
IARMS,
Waveform
IBRMS,
ICRMS
72) Arc
events are polled in every 5 ms.
Signal available depending on the slot 8 options.
NOTE: The selection of signals depends on the relay type, the used voltage
connection and the scaling mode.
Characteristics
Table 101 - Disturbance recording
Mode of recording
Saturated / Overflow
Sample rate:
-
- Waveform recording
32/cycle, 16/cycle, 8/cycle
- Trend curve recording
10, 20, 200 ms
1, 5, 10, 15, 30 s
1 min
Recording time (one record)
0.1 s–12 000 min (According recorder
setting)
Pre-trigger rate
0–100%
Number of selected channels
0–12
File format
IEEE Std C37.111-1999
The recording time and the number of records depend on the time setting and the
number of selected channels.
7.2.1 Configuring the disturbance recorder
NOTE: The DR configuration can only be edited when connected to the
device via Easergy Pro
1. To select the channels and sample rate for the disturbance recorder:
a. In Easergy Pro, go to General > Disturbance recorder.
b. Click the recorder channels you want to add.
c. Click the Sample rate drop-down list, and select the desired rate.
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2. To download the disturbance recorder file, select Tools > Download
disturbance records.
NOTE: The default (pre-configured) settings for DR are:
◦ all analog inputs supported by the device
◦ DI, DO
◦ Sampling rate: 32 s/c
◦ Recording length: 1 s'
◦ Output matrix: connection in every trip line to DR
Figure 149 - Configuring the disturbance recorder
3. To write the setting to the device, on the Easergy Pro toolbar, select Write
settings > Write all settings.
NOTE: To save the relay's configuration information for later use, also
save the Easergy Pro setting file on the PC. Use WaweWin or another
customer preferred tool to analyze disturbance recorder file.
4. To save the setting file on your PC:
a. On the Easergy Pro toolbar, click the Save icon. The Save a file window
opens.
b. Browse to the folder where you want to save the file. Type a descriptive
file name, and click Save.
NOTE: By default, the setting file *.epz is saved in the Easergy Pro
folder.
7.3 Cold load start and magnetizing inrush
Cold load start
A situation is regarded as cold load when all the three phase currents have been
below a given idle value and then at least one of the currents exceeds a given
start level within 80 ms. In such a case, the cold load detection signal is activated
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for the time set as Maximum time or until the measured signal returns below the
value set as Pickup current. This signal is available for the output matrix and
blocking matrix. Using virtual outputs of the output matrix setting group control is
possible.
Application for cold load detection
Right after closing a circuit breaker, a given amount of overload can be allowed
for a given limited time to take care of concurrent thermostat-controlled loads. The
cold load start function does this, for example, by selecting a more coarse setting
group for overcurrent stages. It is also possible to use the cold load detection
signal to block any set of protection stages for a given time.
Magnetizing inrush detection
Magnetizing inrush detection is quite similar to the cold load detection but it also
includes a condition for second harmonic content of the currents. When all phase
currents have been below a given idle value and then at least one of them
exceeds a given start level within 80 ms and the second harmonic ratio to
fundamental frequency, If2/If1, of at least one phase exceeds the given setting, the
inrush detection signal is activated. This signal is available for the output matrix
and blocking matrix. Using virtual outputs of the output matrix setting group
control is possible.
By setting the second harmonic start parameter for If2/If1 to zero, the inrush signal
will behave equally with the cold load start signal.
Application for inrush current detection
The inrush current of transformers usually exceeds the start setting of sensitive
overcurrent stages and contains a lot of even harmonics. Right after closing a
circuit breaker, the start and tripping of sensitive overcurrent stages can be
avoided by selecting a more coarse setting group for the appropriate overcurrent
stage with an inrush detect signal. It is also possible to use the detection signal to
block any set of protection stages for a given time.
NOTE: Inrush detection is based on the fundamental component calculation
which requires a full cycle of data for analyzing the harmonic content.
Therefore, when using the inrush blocking function, the cold load start starting
conditions are used for activating the inrush blocking when the current rise is
noticed. If a significant ratio of second harmonic components is found in the
signal after the first cycle, the blocking is continued. Otherwise, the secondharmonic-based blocking signal is released. Inrush blocking is recommended
to be used on time-delayed overcurrent stages while the non-blocked instant
overcurrent stage is set to 20 % higher than the expected inrush current. By
this scheme, a fast reaction time in short circuit faults during the energization
can be achieved while time-delayed stages are blocked by the inrush function.
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Figure 150 - Functionality of cold load / inrush current feature.
A
C
D
Pick-up
B
Idle
Cold load
A. No activation because the current has not been under the set IDLE current.
B. Current dropped under the IDLE current level but now it stays between the IDLE current and the
start current for over 80 ms.
C. No activation because the phase two lasted longer than 80 ms.
D. Now we have a cold load activation which lasts as long as the operate time was set or as long
as the current stays above the start setting.
Characteristics
Table 102 - Magnetizing inrush detection
Cold load settings:
- Current input
IL or I’L
- Idle current
0.01–0.50 x IN
- Start current
0.30–10.00 x IN
- Maximum time
0.0173) – 300.00 s (step 0.01 s)
Inrush settings:
- Start for 2nd harmonic
0–99%
73) This
is the instantaneous time, that is, the minimum total operate time including the fault detection
time and the operate time of the trip contacts. Use the Accept zero delay setting in the protection
stage setting view in Easergy Pro to accept the zero operate time setting for the DT function.
7.4 System clock and synchronization
Description
The relay's internal clock is used to time-stamp events and disturbance
recordings.
The system clock should be externally synchronised to get comparable event time
stamps for all the relays in the system.
The synchronizing is based on the difference of the internal time and the
synchronizing message or pulse. This deviation is filtered and the internal time is
corrected softly towards a zero deviation.
Time zone offsets
Time zone offset (or bias) can be provided to adjust the relay's local time. The
offset can be set as a Positive (+) or Negative (-) value within a range of -15.00 to
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+15.00 hours and a resolution of 0.01/h. Basically, resolution by a quarter of an
hour is enough.
Daylight saving time (DST)
The relay provides automatic daylight saving adjustments when configured. A
daylight saving time (summer time) adjustment can be configured separately and
in addition to a time zone offset.
Figure 151 - System clock view
Daylight time standards vary widely throughout the world. Traditional daylight/
summer time is configured as one (1) hour positive bias. The new US/Canada
DST standard, adopted in the spring of 2007 is one (1) hour positive bias, starting
at 2:00am on the second Sunday in March, and ending at 2:00am on the first
Sunday in November. In the European Union, daylight change times are defined
relative to the UTC time of day instead of local time of day (as in U.S.) European
customers, carefully check the local country rules for DST.
The daylight saving rules for Finland are the relay defaults (24-hour clock):
• Daylight saving time start: Last Sunday of March at 03.00
• Daylight saving time end: Last Sunday of October at 04.00
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Figure 152 - DST end and begin rules
To ensure proper hands-free year-around operation, automatic daylight time
adjustments must be configured using the “Enable DST” and not with the time
zone offset option.
Adapting the auto-adjust function
During tens of hours of synchronizing, the relay learns its average deviation and
starts to make small corrections by itself. The target is that when the next
synchronizing message is received, the deviation is already near zero.
Parameters "AAIntv" and "AvDrft" show the adapted correction time interval of this
±1 ms auto-adjust function.
Time drift correction without external sync
If any external synchronizing source is not available and the system clock has a
known steady drift, it is possible to roughly correct the clock deviation by editing
the parameters "AAIntv" and "AvDrft". The following equation can be used if the
previous "AAIntv" value has been zero.
AAIntv =
604.8
DriftInOneWeek
If the auto-adjust interval "AAIntv" has not been zero, but further trimming is still
needed, the following equation can be used to calculate a new auto-adjust
interval.
AAIntvNEW =
1
AAIntvPREVIOUS
1
DriftInOneWeek
+
604.8
The term DriftInOneWeek/604.8 may be replaced with the relative drift multiplied
by 1000 if some other period than one week has been used. For example, if the
drift has been 37 seconds in 14 days, the relative drift is 37*1000/(14*24*3600) =
0.0306 ms/s.
Example 1
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If there has been no external sync and the relay's clock is leading sixty-one
seconds a week and the parameter AAIntv has been zero, the parameters are set
as
AvDrft = Lead
AAIntv =
604.8
= 9.9 s
61
With these parameter values, the system clock corrects itself with –1 ms every
9.9 seconds which equals –61.091 s/week.
Example 2
If there is no external sync and the relay's clock has been lagging five seconds in
nine days and the AAIntv has been 9.9 s, leading, then the parameters are set as
AAIntv NEW =
1
= 10.6
1
5000
−
9.9 9 ⋅ 24 ⋅ 3600
AvDrft = Lead
When the internal time is roughly correct – the deviation is less than four seconds
– no synchronizing or auto-adjust turns the clock backwards. Instead, if the clock
is leading, it is softly slowed down to maintain causality.
Table 103 - System clock parameters
Parameter
Description
Note
Date
Current date
Set
Time
Current time
Set
Style
Date format
Set
SyncDI
Value
Unit
y-d-m
Year-Month-Day
d.m.y
Day.Month.Year
m/d/y
Month/Day/Year
Possible values
The digital input
depends on the
used for clock
types of I/O
synchronization.
74)
cards
-
DI not used for
synchronizing
Minute pulse
input
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Parameter
Value
TZone
-15.00 –
+15.00
Unit
75)
Description
Note
UTC time zone
Set
for SNTP
synchronization.
Note: This is a
decimal number.
For example for
state of Nepal
the time zone
5:45 is given as
5.75
DST
No; Yes
Daylight saving
Set
time for SNTP
SySrc
Clock
synchronization
source
Internal
No sync
recognized
since 200s
DI
Digital input
SNTP
Protocol sync
SpaBus
Protocol sync
ModBus
Protocol sync
ModBus TCP
Protocol sync
ProfibusDP
Protocol sync
IEC101
Protocol sync
IEC103
Protocol sync
DNP3
Protocol sync
IRIG-B003
IRIG timecode
B00376)
MsgCnt
0 – 65535,
0 – etc.
The number of
received
synchronization
messages or
pulses
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Parameter
Value
Unit
Description
Dev
±32767
ms
Latest time
Note
deviation
between the
system clock
and the
received
synchronization
SyOS
±10000.000
s
synchronization
Set
correction for
any constant
deviation in the
synchronizing
source
AAIntv
±1000
s
Adapted auto-
Set77)
adjust interval
for 1 ms
correction
AvDrft
Lead; Lag
Adapted
Set 77)
average clock
drift sign
FilDev
±125
ms
Filtered
synchronization
deviation
74) Set
the DI delay to its minimum and the polarity such that the leading edge is the synchronizing
edge.
75) A range of -11 h – +12 h would cover the whole ground but because the International Date Line
does not follow the 180° meridian, a more wide range is needed.
76) Relay needs to be equipped with suitable hardware option module to receive IRIG-B clock
synchronization signal. (13.2 Accessories).
77) If external synchronization is used, this parameter is set automatically.
Set = An editable parameter (password needed).
Synchronization with DI
The clock can be synchronized by reading minute pulses from digital inputs,
virtual inputs or virtual outputs. The sync source is selected with the SyncDI
setting. When a rising edge is detected from the selected input, the system clock
is adjusted to the nearest minute. The length of the digital input pulse should be at
least 50 ms. The delay of the selected digital input should be set to zero.
Synchronization correction
If the sync source has a known offset delay, it can be compensated with the
SyOS setting. This is useful for compensating hardware delays or transfer delays
of communication protocols. A positive value compensates a lagging external
sync and communication delays. A negative value compensates any leading
offset of the external synch source.
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Sync source
When the relay receives new sync message, the sync source display is updated.
If no new sync messages are received within the next 1.5 minutes, the relay
switches over to internal sync mode.
Sync source: IRIG-B003
IRIG-B003 synchronization is supported with a dedicated communication (See
13.2 Accessories).
IRIG-B003 input clock signal voltage level is TLLThe input clock signal originated
in the GPS receiver must be taken to multiple relays trough an IRIG-B distribution
module. This module acts as a centralized unit for a point-to-multiple point
connection.
NOTE: Daisy chain connection of IRIG-B signal inputs in multiple relays must
be avoided.
Figure 153 - Easergy P3 relays with IRIG-B synchronization capability
A
B
C
D
P3U
A. Antenna
B. GPS clock
P3x3x
C. IRIG-B signal from clock
D. IRIG-B distribution module
The recommended cable must be shielded and either of coaxial or twisted pair
type. Its length must not exceed 10 meters.
Deviation
The time deviation means how much the system clock time differs from the sync
source time. The time deviation is calculated after receiving a new sync message.
The filtered deviation means how much the system clock was really adjusted.
Filtering takes care of small deviation in sync messages.
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Auto-lag/lead
The relay synchronizes to the sync source, meaning that it starts automatically
leading or lagging to stay in perfect sync with the master. The learning process
takes a few days.
7.5 Voltage sags and swells
Description
The power quality of electrical networks has become increasingly important.
Sophisticated loads (for example computers) require an uninterruptible supply of
“clean” electricity. The Easergy P3T32 protection platform provides many power
quality functions that can be used to evaluate and monitor the quality and alarm
on the basis of the quality. One of the most important power quality functions is
voltage sag and swell monitoring.
Easergy P3T32 provides separate monitoring logs for sags and swells. The
voltage log is triggered if any voltage input either goes under the sag limit (V<) or
exceeds the swell limit (V>). There are four registers for both sags and swells in
the fault log. Each register contains start time, phase information, duration and
the minimum, average and maximum voltage values of each sag and swell event.
Furthermore, it contains the total number of sags and swells counters as well as
the total number of timers for sags and swells.
The voltage power quality functions are located under the submenu “V”.
Table 104 - Setting parameters of sags and swells monitoring
Parameter
Value
Unit
Default
Description
V>
20 – 150
%
110
Setting value of
swell limit
V<
10 – 120
%
90
Setting value of
sag limit
Delay
0.04 – 1.00
s
0.06
Delay for sag
and swell
detection
264
SagOn
On; Off
-
On
Sag on event
SagOff
On; Off
-
On
Sag off event
SwelOn
On; Off
-
On
Swell on event
SwelOf
On; Off
-
On
Swell off event
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Table 105 - Recorded values of sags and swells monitoring
Parameter
Recorded
Count
Value
Unit
Description
-
Cumulative sag
values
counter
Total
-
Cumulative sag
time counter
Count
-
Cumulative
swell counter
Total
-
Cumulative
swell time
counter
Sag / swell logs
Date
-
1–4
Date of the sag/
swell
Time
-
Time stamp of
the sag/swell
Type
-
Voltage inputs
that had the
sag/swell
Time
s
Duration of the
sag/swell
Min1
% VN
Minimum
voltage value
during the sag/
swell in the
input 1
Min2
% VN
Minimum
voltage value
during the sag/
swell in the
input 2
Min3
% VN
Minimum
voltage value
during the sag/
swell in the
input 3
Ave1
% VN
Average voltage
value during the
sag/swell in the
input 1
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Parameter
Value
Ave2
Unit
Description
% VN
Average voltage
value during the
sag/swell in the
input 2
Ave3
% VN
Average voltage
value during the
sag/swell in the
input 3
Max1
% VN
Maximum
voltage value
during the sag/
swell in the
input 1
Max2
% VN
Maximum
voltage value
during the sag/
swell in the
input 2
Max3
% VN
Maximum
voltage value
during the sag/
swell in the
input 3
Characteristics
Table 106 - Voltage sag & swell
Voltage sag limit
10 –120% VN (step 1%)
Voltage swell limit
20 –150% VN (step 1%)
Definite time function:
DT
- Operate time
0.08–1.00 s (step 0.02 s)
Low voltage blocking
0–50%
Reset time
< 60 ms
Reset ration:
266
- Sag
1.03
- Swell
0.97
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Block limit
0.5 V or 1.03 (3%)
Inaccuracy:
- Activation
±0.5 V or 3% of the set value
- Activation (block limit)
±5% of the set value
- Operate time at definite time function
±1% or ±30 ms
If one of the line-to-line voltages is below sag limit and above block limit but
another line-to-line voltage drops below block limit, blocking is disabled.
7.6 Voltage interruptions
Description
The relay includes a simple function to detect voltage interruptions. The function
calculates the number of voltage interruptions and the total time of the voltage-off
time within a given calendar period. The period is based on the relay's real-time
clock. The available periods are:
• 8 hours, 00:00–08:00, 08:00–16:00, 16:00–24:00
• one day, 00:00–24:00
• one week, Monday 00:00 – Sunday 24:00
• one month, the first day 00:00 – the last day 24:00
• one year, 1st January 00:00 – 31st December 24:00
After each period, the number of interruptions and the total interruption time are
stored as previous values. The interruption counter and the total time are cleared
for a new period. Previous values are overwritten.
Voltage interruption is based on the value of the positive sequence voltage V1 and
a limit value you can define. Whenever the measured V1 goes below the limit, the
interruption counter is increased, and the total time counter starts increasing.
The shortest recognized interruption time is 40 ms. If the voltage-off time is
shorter, it may be recognized depending on the relative depth of the voltage dip.
If the voltage has been significantly over the limit V1< and then there is a small
and short under-swing, it is not recognized (Figure 154).
Figure 154 - A short voltage interruption which is probably not recognized
A
V1<
10
A.Voltage V1
20
30
40
50
60
70
80
90
B
B. Time (ms)
On the other hand, if the limit V1< is high and the voltage has been near this limit,
and then there is a short but very deep dip, it is not recognized (Figure 155).
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Figure 155 - A short voltage interrupt that will be recognized
A
V1<
10
A.Voltage V1
20
30
40
50
60
70
80
90
B
B. Time (ms)
Table 107 - Setting parameters of the voltage sag measurement function
Parameter
Value
Unit
Default
Description
V1<
10.0–120.0
%
64
Setting value
Period
8h
-
Month
Length of the
observation
Day
period
Week
Month
Date
-
-
Date
Time
-
-
Time
Table 108 - Measured and recorded values of voltage sag measurement function
Parameter
Measured value Voltage
Value
Unit
Description
LOW;
-
Current voltage
status
OK
V1
%
Measured
positive
sequence
voltage
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Parameter
Recorded
Value
Count
Unit
Description
-
Number of
values
voltage sags
during the
current
observation
period
Prev
-
Number of
voltage sags
during the
previous
observation
period
Total
s
Total (summed)
time of voltage
sags during the
current
observation
period
Prev
s
Total (summed)
time of voltage
sags during the
previous
observation
period
Characteristics
Table 109 - Voltage interruptions
Voltage low limit (V1)
10–120% VN (step 1%)
Definite time function:
DT
- Operate time
< 60 ms (Fixed)
Reset time
< 60 ms
Reset ratio
1.03
Inaccuracy:
- Activation
3% of the set value
7.7 Current transformer supervision (ANSI 60)
Description
The relay supervises the current transformers (CTs) and the external wiring
between the relay terminals and the CTs. This is a safety function as well, since
an open secondary of a CT causes dangerous voltages.
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The CT supervision function measures phase currents. If one of the three phase
currents drops below the IMIN< setting while another phase current exceeds the
IMAX> setting, the function issues an alarm after the operation delay has elapsed.
Table 110 - Setting parameters of CT supervision
Parameter
Value
Unit
Default
Description
Imax>
0.0 – 10.0
xIn
2.0
Upper setting
for CT
supervision
current scaled
to primary
value,
calculated by
relay
Imin<
0.0 – 10.0
xIn
0.2
Lower setting
for CT
supervision
current scaled
to primary
value,
calculated by
relay
t>
0.02 – 600.0
s
0.10
Operation delay
CT on
On; Off
-
On
CT supervision
on event
CT off
On; Off
-
On
CT supervision
off event
Table 111 - Measured and recorded values of CT
Parameter
Measured value Φmax
Value
Unit
Description
A
Maximum of
phase currents
Φmin
A
Minimum of
phase currents
Display
Imax>, Imin<
A
Setting values
as primary
values
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Parameter
Recorded
Value
Date
Unit
Description
-
Date of CT
values
supervision
alarm
Time
-
Time of CT
supervision
alarm
Imax
A
Maximum phase
current
Imin
A
Minimum phase
current
Characteristics
Table 112 - Current transformer supervision
IMAX> setting
0.00 – 10.00 x IN (step 0.01)
IMIN< setting
0.00 – 10.00 x IN (step 0.01)
Definite time function:
DT
- Operate time
0.04 – 600.00 s (step 0.02 s)
Reset time
< 60 ms
Reset ratio IMAX>
0.97
Reset ratio IMIN<
1.03
Inaccuracy:
-
- Activation
±3% of the set value
- Operate time at definite time function
±1% or ±30 ms
7.8 Voltage transformer supervision (ANSI 60FL)
Description
The relay supervises the voltage transformers (VTs) and VT wiring between the
relay terminals and the VTs. If there is a fuse in the voltage transformer circuitry,
the blown fuse prevents or distorts the voltage measurement. Therefore, an alarm
should be issued. Furthermore, in some applications, protection functions using
voltage signals should be blocked to avoid false tripping.
The VT supervision function measures three line-to-line voltages and currents.
The negative sequence voltage V2 and the negative sequence current I2 are
calculated. If V2 exceed the V2> setting and at the same time, I2 is less than the
I2< setting, the function issues an alarm after the operation delay has elapsed.
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Table 113 - Setting parameters of VT supervision
Parameter
Value
Unit
Default
Description
V2>
0.0 – 200.0
% Vn
34.6
Upper setting
for VT
supervision
I2<
0.0 – 200.0
% In
100.0
Lower setting
for VT
supervision
t>
0.02 – 600.0
s
0.10
Operation delay
VT on
On; Off
-
On
VT supervision
on event
VT off
On; Off
-
On
VT supervision
off event
Table 114 - Measured and recorded values of VT supervision
Parameter
Measured value V2
Value
Unit
Description
%VN
Measured
negative
sequence
voltage
I2
%IN
Measured
negative
sequence
current
Recorded
Date
-
Date of VT
supervision
Values
alarm
Time
-
Time of VT
supervision
alarm
V2
%VN
Recorded
negative
sequence
voltage
I2
%IN
Recorded
negative
sequence
current
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Characteristics
Table 115 - Voltage transformer supervision
V2> setting
0.0 – 200.0% (step 0.1%)
I2< setting
0.0 – 200.0% (step 0.1%)
Definite time function:
DT
- Operate time
0.04 – 600.00 (step 0.02s)
Reset time
< 60 ms
Reset ratio
3% of the start value
Inaccuracy:
-
- Activation V2>
±1%-unit
- Activation I2<
±1%-unit
- Operate time at definite time function
±1% or ±30 ms
7.9 Circuit breaker wear
Description
Circuit breaker (CB) wear is a function that monitors CB wear by calculating how
much wear the CB can sustain. It raises an alarm about the need for CB
maintenance before the condition of the CB becomes critical.
This function records the peak symmetrical current78) from each phase79), and
uses that magnitude as the breaking current for that phase to estimate the
amount of wear on the CB. The function then calculates the estimated number of
cycles or trips remaining before the CB needs to be replaced or serviced.
Permissible cycle diagram
The permissible cycle diagram is usually available in the documentation of the CB
manufacturer. This diagram specifies the permissible number of cycles as a
function of the breaking current, that is, how much wear occurs in the CB when it
trips with a given breaking current. So the maximum number of cycles a CB can
trip with this breaking current is used as the measure of wear.
The condition monitoring function must be configured according to this diagram.
In the configuration, this diagram is called Breaker curve.
78)
79)
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The used peak current is the magnitude of the fundamental frequency component. This
magnitude does not include a possible DC component.
The current is sampled every 10 milliseconds, starting from the moment the monitored trip relay
is asserted and ending when the current of every phase has decreased below one quarter of
the phase’s breaking current or after 500 milliseconds have elapsed, whichever happens first.
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Figure 156 - Example permissible cycle diagram
100000
10000
A
1000
100
50
20
10
100 200
500 1000
10000
100000
B
A. Number of permitted operations
B. Breaking current (A)
Up to eight points can be selected from the diagram and entered to the device.
Each point specifies a breaking current and the associated maximum number of
permitted operations. The device assumes there is a straight line between each
two consecutive points in the log-log diagram (that is, uses logarithmic
interpolation between the points), and thus forms an approximation of the
permissible cycle diagram. It should be possible to accurately describe most
permissible cycle diagrams in this way.
The values in the example match the diagram in Figure 156.
Table 116 - An example of circuit breaker wear characteristics
Point
Interrupted current (kA)
Number of permitted
operations
1
0 (mechanical age)
10000
2
1.25 (rated current)
10000
3
31.0 (maximum breaking
80
current)
4
100
1
5
100
1
6
100
1
7
100
1
8
100
1
Alarm points
Two alarm points can be configured to notify about the approaching need for CB
maintenance.
The number of permissible CB cycles depends on the breaking current that is
interrupted by the CB. Larger currents lead to greater wear on the CB and thus to
fewer operating cycles.80)
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An alarm point specifies a breaking current and an associated number of
permissible cycles. An alarm is raised if the remaining number of permissible
cycles at the given breaking current falls below this limit.
The table in the Operations left setting view shows the number of operation
cycles left before the alarm points are reached. The number of remaining cycles
is tracked for each phase separately, and the alarm is raised when any phase
runs out of cycles.
Figure 157 - Operations left
The first alarm point can be set, for example, to the CB’s nominal current and the
second alarm point to a typical fault current.
When an alarm is raised, a signal is asserted in the output matrix. Also, an event
is created depending on the settings given in the Event enabling setting view.
Logarithmic interpolation
The permitted number of operations for the currents between the defined points is
logarithmically interpolated:
Equation 28
C=
a
In
C = permitted operations
I = interrupted current
a = constant according to Equation 29
n = constant according to Equation 30
Equation 29
a = C k I k2
80)
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Each cycle causes mechanical wear on the CB. In addition, large enough currents create arcs
inside the CB, which causes erosion of the electrical contacts for each phase. The larger the
current, the greater the erosion, and thus the greater the wear on the CB. A worn CB has fewer
cycles left at any breaking current.
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Equation 30
Ck
C k +1
n=
I
ln k +1
Ik
ln
ln = natural logarithm function
Ck, Ck+1 = permitted operations
k = rows 2–7 in Table 116
Ik, Ik+1 = corresponding current
k = rows 2–7 in Table 116
Example of the logarithmic interpolation
Alarm 2 current is set to 6 kA. The maximum number of operations is calculated
as follows.
The current 6 kA lies between points 2 and 3 in the table. That gives value for the
index k. Using
k=2
Ck = 10000
Ck+1 = 80
Ik+1 = 31 kA
Ik = 1.25 kA
and Equation 30 and Equation 29, the device calculates
Equation 31
10000
80 = 1.5038
n=
31000
ln
1250
ln
Equation 32
a = 10000 ⋅ 12501.5038 = 454 ⋅ 10 6
Using Equation 28, the device gets the number of permitted operations for current
6 kA.
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Equation 33
C=
454 ⋅ 10 6
= 945
60001.5038
Thus, the maximum number of current-breaking operations at 6 kA is 945. This
can be verified with the original CB curve in Figure 156. The figure shows that at
6 kA, the operation count is between 900 and 1000. In this case, a useful alarm
level for the operations left is 50, for example, which is about 5 percent of the
maximum.
Example of operation counter decrementing when the CB breaks a current
Alarm 2 is set to 6 kA. The CB failure protection supervises trip relay T1, and a
trip signal of an overcurrent stage detecting a two-phase fault is connected to this
trip relay T1. The interrupted phase currents are 12.5 kA, 12.5 kA and 1.5 kA. By
what number are Alarm2 counters decremented?
Using Equation 28 and values n and a from the previous example, the device gets
the number of permitted operations at 10 kA.
Equation 34
C10 kA =
454 ⋅ 10 6
= 313
125001.5038
At alarm level 2, 6 kA, the corresponding number of operations is calculated
according to:
Equation 35
∆=
C AlarmMax
C
∆A = ∆B =
945
=3
313
Thus, Alarm2 counters for phases A and B are decremented by 3. In phase A, the
current is less than the alarm limit current 6 kA. For such currents, the decrement
is 1.
ΔC= 1
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Table 117 - Local panel parameters of the CBWEAR function
Parameter
Value
Unit
Description
Set81)
CBWEAR STATUS
Operations left
for
Al1A
- Alarm 1, phase
Al1B
A
Al1C
- Alarm 1, phase
Al2A
B
Al2B
- Alarm 1, phase
Al2C
C
- Alarm 2, phase
A
- Alarm 2, phase
B
- Alarm 2, phase
C
Latest trip
Date
Time stamp of
the latest trip
time
operation
IA
A
IB
A
IC
A
Broken current
of phase A
Broken current
of phase B
Broken current
of phase C
CBWEAR SET
Alarm1
Current
0.00–100.00
kA
Alarm1 current
Set
level
Cycles
100000–1
Alarm1 limit for
Set
operations left
Alarm2
Current
0.00–100.00
kA
Alarm2 current
Set
level
Cycles
100000–1
Alarm2 limit for
Set
operations left
CBWEAR SET2
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Parameter
Value
Al1On
On; Off
Unit
Description
Set81)
'Alarm1 on'
Set
event enabling
Al1Off
On; Off
'Alarm1 off'
Set
event enabling
Al2On
On; Off
'Alarm2 on'
Set
event enabling
Al2Off
On; Off
'Alarm2 off'
Set
event enabling
Clear
-; Clear
Clearing of
Set
cycle counters
81) Set
= An editable parameter (password needed)
7.10 Circuit breaker condition monitoring
Description
Circuit breaker (CB) condition monitoring monitors the CB wear with the help of
the cumulative breaking current. It raises an alarm about the need for CB
maintenance before the CB’s condition becomes critical. This function has two
stages.
The approach to calculating the CB condition is different from the approach used
by the CB wear function described in 7.9 Circuit breaker wear. CB condition
monitoring also provides some additional features for integrating the device with
other Schneider Electric products. These functions are based on data analytics
for integration into EcoStruxure Asset Advisor cloud-based offers.
Cumulative breaking current
CB monitoring is activated when the monitored CB opens, and the breaking
current is added to the cumulative breaking current. This sum is calculated for
each phase separately. This way of estimating the wear on the CB is opposite to
the permissible cycles diagram used by the CB wear function. The permissible
cycles diagram describes how much more wear the CB can sustain, and this
approach describes how much wear the CB has accumulated.
To approximate the shape of the permissible cycles diagram, the cumulative
breaking current is also calculated for 5 different bins, so that each bin tracks
breaking currents within a given range (see Figure 158). If a phase's breaking
current is within the range of a given bin, this current is added to the phase’s
cumulative breaking current on that bin.
Each bin also has three counters (one for each phase). Each counter tracks the
number of times the CB has opened and something was added to the
corresponding sum on that bin (see Figure 158).
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Figure 158 - Cumulative breaking current
If all cumulative breaking currents for the bins are zero when the value of the CT
primary parameter is changed in the Scaling setting view, the breaking current
ranges for the bins are automatically set to their default values relative to the new
CT primary value. The lower limit for the first bin is set to zero and the upper limit
to two times the CT primary value. There is no upper limit for the fifth bin.
The cumulative breaking currents are tracked with greater precision than what is
visible on the setting tool, that is, there are hidden decimals stored for each sum.
A non-zero sum that is too small to be visible in the setting tool may prevent the
bin ranges from getting their default values when the CT primary value is
changed.
Each breaking current can be added to one bin.
The cumulative breaking currents can be read over the Modbus protocol as
floating-point values (IEEE 754, binary32). These values are represented in two
consecutive holding registers, so that the register in the lower address contains
the MSB 16 bits. To change the sum by writing a floating-point value, the MSB 16
bits must be written first.
The cumulative breaking currents can be cleared by writing value zero to them.
Counters for mechanical operations
This function includes a counter that tracks the number of times the monitored CB
is opened, and a second counter that tracks how many of those operations were
caused by a protection stage trip. This requires that one of the controllable
objects (see 5.6 Controllable objects) has been configured to represent the CB
and this object has been selected in the Monitored object parameter.
Internally, each object has its own open counter and the counter for the monitored
object is shown under Opening counts, Trip counts and Rack-out counter (see
Figure 159). These open counters are incremented even when this function has
been disabled. In contrast, the trip counter is incremented when the monitored
object is opened by a protection stage trip and this function is enabled. Thus, if
you change the monitored object, the open counter value switches to the counter
of the new object, but the trip counter continues from its current value. Both
counters' values can be changed.
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Figure 159 - Counters for mechanical operations
The number of times the monitored CB is racked out from the bay is tracked by its
own counter. This requires that a digital input is set up to indicate when the CB is
racked out82). This digital input is selected under Rack-out counter. Each digital
input has its own counter. The same counter is also found in the Digital inputs
setting view.
Operate times logs
This function records the completion times for the eight previous open, close, and
charge operations of the monitored CB. Each operate time is recorded with a
timestamp indicating when the operation was completed. This function also keeps
a cumulative moving average of 20 previous operate times for each of the three
categories.
The completion times are recorded even if this function has been disabled,
provided that the monitored object has been selected.
All three logs of completion times can be cleared by the Clear logs command.
Figure 160 - CB opening times
The charging times are recorded in seconds whereas the opening and closing
times are recorded in milliseconds.
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When the CB r is in the bay, this digital input has logical value false, and when the CB is racked
out, this input has logical value true.
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The operate times can be read over the Modbus protocol as floating-point values
(IEEE 754, binary32), so that a range of holding registers is used to represent all
operate times of a given category, from the newest to oldest. Each operate time is
represented in two consecutive holding registers, so that the register in the lower
address contains the MSB 16 bits.
Empty or unused cells in the log give value zero.
If an opening time or a closing time is greater than 300 milliseconds, this value is
given as NaN (not-a-number) when it is read as a floating-point value. Similarly,
charging times greater than 60 seconds are given as NaN.
7.11 Energy pulse outputs
Description
The relay can be configured to send a pulse whenever a certain amount of energy
has been imported or exported. The principle is presented in Figure 161. Each
time the energy level reaches the pulse size, a digital output is activated and the
relay is active as long as defined by a pulse duration setting.
Figure 161 - Principle of energy pulses
Configurable:
100 ms − 5 000 ms
Configurable:
10 – 10 000 kWh
kvarh
The relay has four energy pulse outputs. The output channels are:
•
•
•
•
active exported energy
reactive exported energy
active imported energy
reactive imported energy
Each channel can be connected to any combination of the digital outputs using
the output matrix. The parameters for the energy pulses can be found in the
ENERGY menu "E" under the submenus E-PULSE SIZES and E-PULSE
DURATION.
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Table 118 - Energy pulse output parameters
E-PULSE
Parameter
Value
Unit
Description
E+
10 – 10 000
kWh
Pulse size of
SIZES
active exported
energy
Eq+
10 – 10 000
kvarh
Pulse size of
reactive
exported energy
E-
10 – 10 000
kWh
Pulse size of
active imported
energy
Eq-
10 – 10 000
kvarh
Pulse size of
reactive
imported energy
E-PULSE
E+
100 – 5000
ms
Pulse length of
active exported
DURATION
energy
Eq+
100 – 5000
ms
Pulse length of
reactive
exported energy
E-
100 – 5000
ms
Pulse length of
active imported
energy
Eq-
100 – 5000
ms
Pulse length of
reactive
imported energy
Scaling examples
1. The average active exported power is 250 MW.
The peak active exported power is 400 MW.
The pulse size is 250 kWh.
The average pulse frequency is 250/0.250 = 1000 pulses/h.
The peak pulse frequency is 400/0.250 = 1600 pulses/h.
Set pulse length to 3600/1600 - 0.2 = 2.0 s or less.
The lifetime of the mechanical digital output is 50x106/1000 h = 6 a.
This is not a practical scaling example unless a digital output lifetime of about
six years is accepted.
2. The average active exported power is 100 MW.
The peak active exported power is 800 MW.
The pulse size is 400 kWh.
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The average pulse frequency is 100/0.400 = 250 pulses/h.
The peak pulse frequency is 800/0.400 = 2000 pulses/h.
Set pulse length to 3600/2000 - 0.2 = 1.6 s or less.
The lifetime of the mechanical digital output is 50x106/250 h = 23 a.
3. Average active exported power is 20 MW.
Peak active exported power is 70 MW.
Pulse size is 60 kWh.
The average pulse frequency is 25/0.060 = 416.7 pulses/h.
The peak pulse frequency is 70/0.060 = 1166.7 pulses/h.
Set pulse length to 3600/1167 - 0.2 = 2.8 s or less.
The lifetime of the mechanical digital output is 50x106/417 h = 14 a.
4. Average active exported power is 1900 kW.
Peak active exported power is 50 MW.
Pulse size is 10 kWh.
The average pulse frequency is 1900/10 = 190 pulses/h.
The peak pulse frequency is 50000/10 = 5000 pulses/h.
Set pulse length to 3600/5000 - 0.2 = 0.5 s or less.
The lifetime of the mechanical digital output is 50x106/190 h = 30 a.
Figure 162 - Application example of wiring the energy pulse outputs to a PLC
having common plus and using an external wetting voltage
Easergy P3
+
PLC
Active exported
energy pulses +E
Pulse counter input 1
Reactive exported
energy pulses +Eq
Pulse counter input 2
Active imported
energy pulses -E
Pulse counter input 3
Reactive imported
energy pulses -Eq
Pulse counter input 4
−
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Figure 163 - Application example of wiring the energy pulse outputs to a PLC
having common minus and using an external wetting voltage
Easergy P3
+
PLC
Active exported
energy pulses +E
Pulse counter input 1
Reactive exported
energy pulses +Eq
Pulse counter input 2
Active imported
energy pulses -E
Pulse counter input 3
Reactive imported
energy pulses -Eq
Pulse counter input 4
−
Figure 164 - Application example of wiring the energy pulse outputs to a PLC
having common minus and an internal wetting voltage.
Easergy P3
PLC
Active exported
energy pulses +E
Pulse counter input 1
Reactive exported
energy pulses +Eq
Pulse counter input 2
Active imported
energy pulses -E
Pulse counter input 3
Reactive imported
energy pulses -Eq
Pulse counter input 4
7.12 Active and reactive energy
The Easergy P3 protection device measures the following active and reactive
energy values, calculated based on the first three voltages and phase currents IA,
IB, and IC measured according to the related current flow for an outgoing feeder:
•
•
•
•
E+: the accumulated active energy exported
E-: the accumulated active energy imported
Eq+: the accumulated reactive energy exported
Eq-: the accumulated reactive energy imported
The measurement is based on fundamental values or RMS values. You can
choose it with the Energy calculation mode setting in Easergy Pro.
Energy sign conversion
Independently of the power direction setting, the energy counter has an additional
setting for sign conversion. Use the Energy sign convention setting to define
positive and negative direction for export and import energy.
• The selection “Export – Positive power” results in positive power to
accumulate the export energy counter, while negative power accumulates the
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•
import energy counter. Similarly, positive reactive power accumulates the
exported reactive energy counter, while negative reactive accumulates the
imported reactive power counter.
The selection “Export – Negative power” results in negative power to
accumulate the export energy counter, while positive power accumulates the
import energy counter. Similarly, negative power accumulates the exported
reactive power counter, while positive reactive power accumulates the
imported reactive power counter.
Energy counter values available via communication protocols are impacted
according to selection.
Changing the energy sign conversion must reset the energy counter.
Table 119 - Energy calculation settings
Parameter
Description
Energy calculation mode
Fundamental: base frequency used for
energy calculation only
RMS: Base frequency and harmonics are
incorporated in the energy calculation
Energy sign convention
Export – positive power: positive power to
accumulate the export energy counter and
negative power to accumulate the import
energy counter
Export – negative power: negative power
to accumulate the export energy counter
and positive power to accumulate the
import energy counter
7.13 Running hour counter
Description
The running hour counter is typically used to monitor the service time of the motor
or appropriate feeder. This function calculates the total active time of the selected
digital input, virtual I/O function button, GOOSE signal, POC signal or output
matrix output signal. The resolution is ten seconds and the data is stored in the
non-volatile memory.
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Parameters
Table 120 - Running hour counter parameters
Parameter
Value
Unit
Description
Note
Runh
0...876000
h
Total active
(Set)83)
time, hours
Note: The label
text "Runh" can
be edited with
Easergy Pro.
Runs
0...3599
s
Total active
(Set)
time, seconds
Starts
0...65535
Activation
(Set)
counter
Status
Stop
Run
Started at
Current status
of the selected
digital signal
Date and time of
the last
activation
Stopped at
Date and time of
the last
inactivation
83) (Set)
= An informative value which can be edited as well.
7.14 Timers
Description
The Easergy P3 protection platform includes four settable timers that can be used
together with the user's programmable logic or to control setting groups and other
applications that require actions based on calendar time. Each timer has its own
settings. The selected on-time and off-time is set, after which the activation of the
timer can be set to be as daily or according to the day of the week (See the
setting parameters for details). The timer outputs are available for logic functions
and for the block and output matrix.
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Figure 165 - Timer output sequence in different modes
Monday
Tuesday
Wednesday
Thursday
Friday
Saturday
Sunday
(not in use)
Daily
Monday
Tuesday
Wednesday
Thursday
Friday
Saturday
Sunday
MTWTF
MTWTFS
SatSun
You can force any timer, which is in use, on or off. The forcing is done by writing a
new status value. No forcing flag is needed as in forcing for example the digital
outputs.
The forced time is valid until the next forcing or until the next reversing timed act
from the timer itself.
The status of each timer is stored in the non-volatile memory when the auxiliary
power is switched off. At startup, the status of each timer is recovered.
Table 121 - Setting parameters of timers
Parameter
Value
Description
TimerN
-
Timer status
-
Not in use
0
Output is inactive
1
Output is active
On
hh:mm:ss
Activation time of the timer
Off
hh:mm:ss
De-activation time of the
timer
Mode
For each four timers there
are 12 different modes
available:
-
The timer is off and not
running. The output is off i.e.
0 all the time.
Daily
The timer switches on and
off once every day.
Monday
The timer switches on and
off every Monday.
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Parameter
Value
Description
Tuesday
The timer switches on and
off every Tuesday.
Wednesday
The timer switches on and
off every Wednesday.
Thursday
The timer switches on and
off every Thursday.
Friday
The timer switches on and
off every Friday.
Saturday
The timer switches on and
off every Saturday.
Sunday
The timer switches on and
off every Sunday.
MTWTF
The timer switches on and
off every day except
Saturdays and Sundays
MTWTFS
The timer switches on and
off every day except
Sundays.
SatSun
The timer switches on and
off every Saturday and
Sunday.
7.15 Combined overcurrent status
Description
This function collects faults, fault types and registered fault currents of all enabled
overcurrent stages and shows them in the event log.
The combined overcurrent status can be used as an indication of faults.
Combined o/c indicates the amplitude of the last occurred fault. Also, a separate
indication of the fault type is informed during the start and the trip. Active phases
during the start and the trip are activated in the output matrix. After the fault is
switched off, the active signals release after the set delay “clearing delay“ has
passed. The combined o/c status referes to the following over current stages:
50/51-1, 50/51-2, 50/51-3, 67-1, 67-2, 67-3, 67-4.
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Table 122 - Line fault parameters
Parameter
Value
IFltLas
Unit
Description
Note
Current of the
(Set)
latest
overcurrent fault
LINE ALARM
AlrA
-
AlrB
0
AlrC
1
Start (=alarm)
status for each
phase.
0 = No start
since alarm
ClrDly
1 = Start is on
OCs
0
1
Combined
overcurrent start
status.
AlrL1 = AlrL2 =
AlrL3 = 0
AlrL1 = 1 or
AlrL2 = 1 or
AlrL3 = 1
LxAlarm
On
Off
'On' Event
Set
enabling for
AlrL1 – 3
Events are
enabled
Events are
disabled
LxAlarmOff
On
Off
'Off' Event
Set
enabling for
AlrL1...3
Events are
enabled
Events are
disabled
OCAlarm
On
Off
'On' Event
Set
enabling for
combined o/c
starts
Events are
enabled
Events are
disabled
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Parameter
Value
OCAlarmOff
-
Unit
Description
Note
'Off' Event
Set
enabling for
On
combined o/c
Off
starts
Events are
enabled
Events are
disabled
IncFltEvnt
-
Disabling
Set
several start
On
and trip events
Off
of the same
fault
Several events
are enabled 84)
Several events
of an increasing
fault is
disabled 85)
ClrDly
0 – 65535
s
Duration for
Set
active alarm
status AlrL1,
Alr2, AlrL3 and
OCs
84) Used
with IEC 60870-105-103 communication protocol. The alarm screen shows the latest fault
current if it is the biggest registered fault current, too. Not used with Spabus because Spabus masters
usually do not like to have unpaired On/Off events.
85) Used with SPA-bus protocol because most SPA-bus masters need an off-event for each
corresponding on-event.
Parameter
Value
Unit
Description
Note
LINE FAULT
FltL1
-
FltL2
0
FltL3
1
Fault (=trip)
status for each
phase.
0 = No fault
since fault
ClrDly
1 = Fault is on
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Parameter
Value
OCt
0
1
Unit
Description
Note
Combined
overcurrent trip
status.
FltL1 = FltL2 =
FltL3 = 0
FltL1 = 1 or
FltL2 = 1 or
FltL3 = 1
LxTrip
On
Off
'On' Event
Set
enabling for
FltL1 – 3
Events are
enabled
Events are
disabled
LxTripOff
On
Off
'Off' Event
Set
enabling for
FltL1...3
Events are
enabled
Events are
disabled
OCTrip
On
Off
'On' Event
Set
enabling for
combined o/c
trips
Events are
enabled
Events are
disabled
OCTripOff
On
Off
'Off' Event
Set
enabling for
combined o/c
starts
Events are
enabled
Events are
disabled
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Parameter
Value
IncFltEvnt
On
Off
Unit
Description
Note
Disabling
Set
several events
of the same
fault
Several events
are enabled 86)
Several events
of an increasing
fault is
disabled 87)
ClrDly
0 – 65535
Duration for
Set
active alarm
status FltL1,
Flt2, FltL3 and
OCt
86) Used
with IEC 60870-105-103 communication protocol. The alarm screen shows the latest fault
current if it is the biggest registered fault current, too. Not used with Spabus because Spabus masters
usually do not like to have unpaired On/Off events.
87) Used with SPA-bus protocol because most SPA-bus masters need an off-event for each
corresponding on-event.
Figure 166 - Combined o/c status
The fault that can be seen in the Figure 166 was 3.18 times to nominal and it
increased in to a two phase short circuit L1-L2. All signals those are stated as “1”
are also activated in the output matrix. After the fault disappears, the activated
signals release.
The combined overcurrent status can be found from Easergy Pro through
Protection > Protection stage status 2.
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7.16 Trip circuit supervision (ANSI 74)
Description
Trip circuit supervision is used to ensure that the wiring from the protective relay
to a circuit breaker (CB) is in order. Even though the trip circuit is unused most of
the time, keeping it in order is important so that the CB can be tripped whenever
the relay detects a fault in the network.
The digital inputs of the relay can be used for trip circuit monitoring.
Also the closing circuit can be supervised using the same principle.
NOTE: Apply trip circuit supervision using a digital input and its programmable
time delay.
NOTE: Change the Digital inputs’ Mode to AC in case trip circuit supervision
is applied to the ac control voltage.
7.16.1 Trip circuit supervision with one digital input
The benefits of this scheme are that only one digital inputs is needed and no extra
wiring from the relay to the circuit breaker (CB) is needed. Also, supervising a 24
Vdc trip circuit is possible.
The drawback is that an external resistor is needed to supervise the trip circuit on
both CB positions. If supervising during the closed position only is enough, the
resistor is not needed.
•
•
•
•
•
•
294
The digital input is connected parallel to the trip contacts (see Figure 167).
The digital input is configured as normal closed (NC).
The digital input delay is configured to be longer than the maximum fault time
to inhibit any superfluous trip circuit fault alarm when the trip contact is closed.
The digital input is connected to a relay in the output matrix giving out any trip
circuit alarm.
The trip relay must be configured as non-latched. Otherwise, a superfluous
trip circuit fault alarm follows after the trip contact operates, and the relay
remains closed because of latching.
By utilizing an auxiliary contact of the CB for the external resistor, also the
auxiliary contact in the trip circuit can be supervised.
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Figure 167 - Trip circuit supervision using a single digital input and an external
resistor R
+VAUX = 24 Vdc ... 240 Vdc
A
comm
B
C
D
0.5 s
E
G
52b
F
52a
-VAUX
H
CB
R
-VAUX
I
A. Digital input 1
B. Trip relay
C. Alarm relay for trip circuit failure
D. Trip circuit failure alarm
E. Relay compartment
F. Circuit breaker compartment
G. Close control
H. Open coil
I. Close coil
The circuit-breaker is in the closed position. The supervised circuitry in this CB
position is double-lined. The digital input is in active state when the trip circuit is
complete.
This is applicable to any digital inputs.
NOTE: The need for the external resistor R depends on the application and
circuit breaker manufacturer's specifications.
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Figure 168 - Alternative connection without using circuit breaker 52b auxiliary
contacts
+VAUX = 24 Vdc ... 240 Vdc
A
comm
B
C
D
0.5 s
E
F
G
52a
R
-VAUX
H
CB
-VAUX
I
A. Digital input 1
B. Trip relay
C. Alarm relay for trip circuit failure
D. Trip circuit failure alarm
E. Relay compartment
F. Circuit breaker compartment
G. Close control
H. Open coil
I. Close coil
Trip circuit supervision using a single digital input and an external resistor R. The
circuit breaker is in the closed position. The supervised circuitry in this CB
position is double-lined. The digital input is in active state when the trip circuit is
complete.
Alternative connection without using circuit breaker 52b auxiliary contacts. This is
applicable for any digital inputs.
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Figure 169 - Trip circuit supervision using a single digital input when the circuit
breaker is in open position
+VAUX = 24 Vdc ... 240 Vdc
A
B
C
D
0.5 s
E
G
52b
F
52a
-VAUX
H
CB
R
-VAUX
I
A. Digital input 1
B. Trip relay
C. Alarm relay for trip circuit failure
D. Trip circuit failure alarm
E. Relay compartment
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G. Close control
H. Open coil
I. Close coil
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Figure 170 - Alternative connection without using circuit breaker 52b auxiliary
contacts. Trip circuit supervision using a single digital input, when the circuit
breaker is in open position
+VAUX = 24 Vdc ... 240 Vdc
A
B
C
D
0.5 s
E
G
F
52a
R
-VAUX
H
CB
-VAUX
I
A. Digital input 1
B. Trip relay
C. Alarm relay for trip circuit failure
D. Trip circuit failure alarm
E. Relay compartment
F. Circuit breaker compartment
G. Close control
H. Open coil
I. Close coil
Figure 171 - Example of digital input DI7 configuration for trip circuit supervision
with one digital input
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Figure 172 - Example of output matrix configuration for trip circuit supervision with
one digital input
Example of dimensioning the external resistor R
VAUX = 110 Vdc - 20 % + 10%, Auxiliary voltage with tolerance
VDI = 18 Vdc, Threshold voltage of the digital input
IDI = 3 mA, Typical current needed to activate the digital input including a 1 mA
safety margin.
PCOIL = 50 W, Rated power of the open coil of the circuit breaker. If this value is
not known, 0 Ω can be used for the RCOIL.
VMIN = VAUX - 20 % = 88 V
VMAX = VAUX + 10 % = 121 V
RCOIL =V2AUX / PCOIL = 242 Ω.
The external resistance value is calculated using Equation 36:
Equation 36
R=
V MIN − V DI − I DI ⋅ RCoil
I DI
R = (88 – 18 – 0.003 x 242)/0.003 = 23.1 kΩ
In practice, the coil resistance has no effect.
By selecting the next smaller standard size, we get 22 kΩ.
The power rating for the external resistor is estimated using Equation 37 and
Equation 38.
The Equation 37 is for the CB open situation including a 100 % safety margin to
limit the maximum temperature of the resistor:
Equation 37
2
P = 2 ⋅ I DI
⋅R
P = 2 x 0.0032 x 22000 = 0.40 W
Select the next bigger standard size, for example 0.5 W.
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When the trip contacts are still closed and the CB is already open, the resistor
has to withstand much higher power (Equation 38) for this short time:
Equation 38
2
U MAX
P=
R
P = 1212 / 22000 = 0.67 W
A 0.5 W resistor is enough for this short time peak power, too. However, if the trip
relay is closed for longer than a few seconds, a 1 W resistor should be used.
7.16.2 Trip circuit supervision with two digital inputs
The benefit of this scheme is that no external resistor is needed.
The drawbacks are that two digital inputs (DIs) and two extra wires from the relay
to the CB compartment are needed. Additionally, the minimum allowed auxiliary
voltage is 48 V dc which is more than twice the threshold voltage of the digital
input because when the CB is in open position, the two digital inputs are in series.
When two DIs are connected in a series, the switching threshold value used with
one DI is too high. Therefore, a lower value must be selected: 24 V if the nominal
operation voltage for DI inputs is 110 V or 110 V if the nominal operation voltage
is 220 V.
•
•
•
•
•
•
The first digital input is connected parallel to the auxiliary contact of the circuit
breaker's open coil.
Another auxiliary contact is connected in series with the circuitry of the first
digital input. This makes it possible to supervise also the auxiliary contact in
the trip circuit.
The second digital input is connected in parallel with the trip contacts.
Both inputs are configured as normal closed (NC).
The user’s programmable logic is used to combine the digital input signals
with an AND port. The delay is configured to be longer than the maximum
fault time to inhibit any superfluous trip circuit fault alarm when the trip contact
is closed.
The output from the logic is connected to a relay in the output matrix giving
out any trip circuit alarm.
In Figure 173, the supervised circuitry in this CB position is double-lined. The
digital input is in active state when the trip circuit is complete. This is applicable
for all digital inputs.
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Figure 173 - Trip circuit supervision with two digital inputs and closed CB
+VAUX = 48 Vdc ... 240 Vdc
0
A
comm
B
C
&
D
0.5 s
E
G
52b
F
52a
-VAUX
H
CB
-VAUX
I
A. Digital input 1
B. Trip relay
C. Alarm relay for trip circuit failure
D. Trip circuit failure alarm
E. Relay compartment
F. Circuit breaker compartment
G. Close control
H. Open coil
I. Close coil
In Figure 174, the two digital inputs are in series.
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Figure 174 - Trip circuit supervision with two digital inputs and CB in open position
+VAUX = 48 Vdc ... 240 Vdc
1
A
comm
B
C
&
D
0.5 s
E
G
52b
F
52a
-VAUX
H
CB
-VAUX
I
A. Digital input 1
B. Trip relay
C. Alarm relay for trip circuit failure
D. Trip circuit failure alarm
E. Relay compartment
F. Circuit breaker compartment
G. Close control
H. Open coil
I. Close coil
Figure 175 - An example of digital input configuration for trip circuit supervision
with two digital inputs DI1 and DI2
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Figure 176 - An example of logic configuration for trip circuit supervision with two
digital inputs DI1 and DI2.
Figure 177 - An example of output matrix configuration for trip circuit supervision
with two digital inputs
7.16.3 Trip circuit supervision with two combined digital inputs
The trip circuit supervision scheme with two digital inputs 52a and 52b can be
implemented as illustrated in Figure 178. No external resistors are needed for this
scheme to function.
Figure 178 - Trip circuit supervision scheme
wire 1
Trip
relay(s)
CB open DI1
CB closed DI2
Easergy P3
wire 2a
wire 2b
Circuit breaker
Trip
coil
wire 3
When the trip circuit is OK under normal conditions, the status of inputs is
opposite (0,1) or (1,0). When the trip circuit is not OK (coil, wires, auxiliary contact
state or auxiliary voltage failure), both the logic inputs are in the same state, and
an alarm is issued after a delay. This delay is needed to prevent false signaling
during breaker opening events. The timing is set based on breaker operating time
and trip pulse length.
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Table 123 - TCS alarm output depending on the CB and its auxiliary contact
positions, and the possible wiring failure conditions
CB position
Conditions
CB open DI1
CB closed
DI2
TCS alarm
Closed
Trip circuit OK
Closed
Open
FALSE
Wire 1 failure88)
Open
Open
TRUE
Wire 2a
Open
Open
TRUE
Open
Open
TRUE
Trip circuit OK
Open
Closed
FALSE
Wire 1 failure88)
Open
Open
TRUE
Wire 2b
Open
Open
TRUE
Open
Open
TRUE
failure88)
Wire 3 or trip
coil
Open
failure88)
failure88)
Wire 3 or trip
coil
88) "failure"
failure88)
indicates that one or more of the components are permanently open circuit or short circuit
Figure 179 - Block diagram of trip circuit supervision (ANSI 74)
CB open DI1
=1
CB closed DI2
T
0
TCS alarm
T=2s
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Transformer protection relay
8 Communication and protocols
8.1 Cybersecurity
According to a classic model of information security, the three security goals are:
•
•
•
confidentiality (prevention of unauthorized disclosure of information)
integrity (prevention of unauthorized modification of information)
availability (ensuring that information is always available to authorized users)
These goals may be used as a starting point in designing security solutions for
electric power distribution.
We recommend that:
• Computer systems used to design or operate electric power distribution
systems are designed with the principle of least privilege, in other words, that
users only have those access rights that they needs to perform their duties.
• All workstations and servers have an effective antimalware solution, such as a
virus scanner.
• Computer systems are protected with adequate physical security measures to
prevent physical tampering of the devices or networks.
NOTICE
CYBERSECURITY HAZARD
To improve cybersecurity:
•
•
•
Change all passwords from their default values when taking the protection
device into use.
Change all passwords regularly.
Ensure a minimum level of password complexity according to common
password guidelines.
Failure to follow these instructions can increase the risk of unauthorized
access.
Related topics
2.4 Access to device configuration
8.2 Communication ports
The relay has one fixed communication port: a USB port on the front panel for
connection to Easergy Pro setting and configuration tool.
Optionally, the relay may have up to to two serial ports, COM 3 and COM 4, for
serial protocols (for example IEC 103) and one Ethernet port for Ethernet-based
communication protocols (for example IEC 61850).
The number of available serial ports depends on the type of the communication
option cards.
Each communication port can be individually enabled or disabled with the
Configurator access level via:
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•
•
the front panel of the Easergy P3 protection device
Easergy Pro
NOTE: By default and when the device comes from the factory, Ethernet
Protocol 1 is enabled and the default protocol is IEC-61850. Also Ethernet
Protocol 2 is enabled and the default protocol is Modbus TCPs.
Figure 180 - Ethernet protocol default setting
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Figure 181 - Ethernet, COM 1 and COM 2 ports
NOTE: It is possible to have up to 2 serial communication protocols
simultaneously in the same D9 and Ethernet connector but restriction is that
same protocol can be used only once.
The Protocol configuration setting view contains selection for the protocol, port
settings and message/error/timeout counters. Only serial communication
protocols are valid with RS-232 interface.
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Figure 182 - Protocol configuration setting view
Table 124 - Parameters
Parameter
Value
Protocol
Unit
Description
Note
Protocol
Set
selection for
COM port
None
-
SPA-bus
SPA-bus (slave)
ProfibusDP
Interface to
Profibus DB
module VPA
3CG (slave)
ModbusSlv
Modbus RTU
slave
IEC-103
IEC-60870-5-10
3 (slave)
ExternalIO
Modbus RTU
master for
external I/Omodules
IEC 101
IEC-608670-5-1
01
DNP3
308
DNP 3.0
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Parameter
Value
Unit
GetSet
Description
Note
Communicationi
protocola for
Easergy Pro
interface
Msg#
0–232 - 1
Message
Clr
counter since
the relay has
restarted or
since last
clearing
Errors
0–216 - 1
Protocol
Clr
interruption
since the relay
has restarted or
since last
clearing
Tout
0–216 - 1
Timeout
Clr
interruption
since the relay
has restarted or
since last
clearing
speed/DPS
Display of
1.
current
communication
parameters.
speed = bit/s
D = number of
data bits
P = parity: none,
even, odd
S = number of
stop bits
Set = An editable parameter (password needed)
Clr = Clearing to zero is possible
1. The communication parameters are set in the protocol specific menus. For the local
port command line interface the parameters are set in configuration menu.
8.2.1 Ethernet port
The Ethernet port is used for Ethernet protocols like IEC61850 and Modbus TCP.
The physical interface is described in 10.6 Connections.
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The parameters for the port can be set via the device's front panel or using
Easergy Pro. Two different protocols can be used simultaneously – both protocols
use the same IP address and MAC address (but different port number).
8.2.2 Disabling the Ethernet communication
NOTICE
CYBERSECURITY HAZARD
•
•
•
•
To improve cybersecurity, disable the Ethernet communication in
environments where effective antimalware solutions have not been taken
into use.
The device is not capable of transmitting data encrypted using Ethernet
protocols. If other users gain access to your network, transmitted information
can be disclosed or subject to tampering.
For transmitting data over an internal network, segment the network
physically or logically and restrict access using standard controls such as
firewalls and other relevant features supported by your device such as
IPTable whitelisting.
For transmitting data over an external network, encrypt protocol
transmissions over all external connections using an encrypted tunnel, TLS
wrapper or a similar solution.
Failure to follow these instructions can increase the risk of unauthorized
access.
1. To disable all Ethernet-based protocols:
a. In Easergy Pro, go to Communication > Protocol configuration.
b. Under Ethernet, disable the Ethernet port by unselecting the Enable
Ethernet communication checkbox.
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Figure 183 - Disabling the Ethernet port
This disables all the Ethernet-based protocols.
2. To disable Ethernet protocols separately:
a. Under Ethernet, select the Enable Ethernet communication checkbox.
b. Unselect the Enable... checkbox for the servers or protocols you want to
disable.
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Figure 184 - Disabling individual Ethernet-based protocols
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8.3 Storm protection
Storm protection limits the number of broadcast messages, for example, address
resolution protocol (ARP) messages that are forwarded to the central processing
unit (CPU) or to the protection device’s second Ethernet interface. Storm
protection may be necessary if the Ethernet network contains devices that may
send a big amount of ARP requests when starting up or during the normal
operation. If storm protection is not enabled, the protection devices can be
overloaded with the big number of ARP messages.
The storm protection limit defines how big percentage of the broadcast messages
are forwarded to the CPU.
Storm protection level 0.01% means 15 packets per second in a 100 Mbps
network. Broadcast traffic forwarded to CPU can be limited down to 15% for 100
Mbps. This is based on a theoretical maximum of 100 packets per second that the
CPU can receive and process.
Storm protection can be enabled in the Advanced Ethernet options setting view
with the Storm protection on Port1 and Storm protection on Port2
parameters.
Figure 185 - Storm protection properties
8.4 Parallel Redundancy Protocol
The Parallel Redundancy Protocol (PRP) implemented in Easergy P3 devices is
specified in the IEC62439-3 (Clause 4) standard and is available when a dualport, 100 Mbps Ethernet interface card is used.
PRP properties:
•
•
•
•
•
•
•
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Ethernet redundancy method independent of any industrial Ethernet protocol
or topology (tree, ring or mesh)
seamless switchover and recovery in case of failure (no delay)
continuous supervision of redundancy for better management of network
devices
suitable for hot swap - 24 hour/365 day operation in substations
allows mixing of devices with single and dual network interfaces on the same
local area network (LAN)
allows HMI devices (laptops, workstations) to be connected to the network
using standard Ethernet adapters
particularly suited for hard real-time systems such as substation automation,
high-speed drives and transportation
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For additional information, see application note Parallel Redundancy Protocol for
Easergy P3Ux and Easergy P3x3x relays with dual-port 100 Mbps Ethernet
interface (P3/EN ANCOM/A004).
Figure 186 - Redundancy protocol for Ethernet setting view
Figure 187 - Parallel Redundancy Protocol setting view
8.5 Communication protocols
The communication protocols enable the transfer of the following type of data:
•
•
•
•
314
events
status information
measurements
control commands
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•
•
•
clock synchronization
some settings through SPA bus, IEC-103, Modbus and IEC-61850 protocols
disturbance recordings through IEC-103, Modbus and IEC-61850 protocols
This product contains software developed by Viola Systems.
8.5.1 Modbus RTU and Modbus TCP
Modbus RTU and Modbus TCP protocols are often used in power plants and
industrial applications. The difference between these two protocols is the media.
Modbus TCP uses Ethernet and Modbus RTU uses RS-485, optic fibre, or
RS-232.
Easergy Pro shows a list of all available data items for Modbus. They are also
available as a zip file ("Communication parameter protocol mappings.zip").
The information available via Modbus RTU and Modbus TCP includes:
•
•
•
•
•
•
status values
control commands
measurement values
events
protection settings
disturbance recordings
The Modbus communication is activated via a menu selection with the parameter
"Protocol". See 8.2 Communication ports.
For more information on Modbus configuration, see the document
P3APS18025EN Modbus configuration instructions.
For the Ethernet interface configuration, see 8.2.1 Ethernet port.
8.5.2 Profibus DP
The Profibus DP protocol is widely used in the industry. An external VPA 3CG and
VX072 cables are required.
Device profile "continuous mode"
In this mode, the relay is sending a configured set of data parameters
continuously to the Profibus DP master. The benefit of this mode is the speed and
easy access to the data in the Profibus master. The drawback is the maximum
buffer size of 128 bytes, which limits the number of data items transferred to the
master. Some PLCs have their own limitation for the Profibus buffer size, which
may further limit the number of transferred data items.
Device profile "Request mode"
Using the request mode, it is possible to read all the available data from the
Easergy P3 relay and still use only a very short buffer for Profibus data transfer.
The drawback is the slower overall speed of the data transfer and the need of
increased data processing at the Profibus master as every data item must be
separately requested by the master.
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NOTE: In the request mode, it is not possible to read continuously only one
single data item. At least two different data items must be read in turn to get
updated data from the relay.
There is a separate manual for VPA 3CG for the continuous mode and request
mode. The manual is available for downloading on our website.
Available data
Easergy Pro shows the list of all available data items for both modes. A separate
document "Communication parameter protocol mappings.zip" is also available.
The Profibus DP communication is activated usually for remote port via a menu
selection with parameter "Protocol". See 8.2 Communication ports.
8.5.3 SPA-bus
The relay has full support for the SPA-bus protocol including reading and writing
the setting values. Also, reading multiple consecutive status data bits,
measurement values or setting values with one message is supported.
Several simultaneous instances of this protocol, using different physical ports, are
possible, but the events can be read by one single instance only.
There is a separate document "Communication parameter protocol mappings.zip"
of SPA-bus data items available.
8.5.4 IEC 60870-5-103 (IEC-103)
The IEC standard 60870-5-103 "Companion standard for the informative interface
of protection equipment" provides a standardized communication interface to a
primary system (master system).
The unbalanced transmission mode of the protocol is used, and the relay
functions as a secondary station (slave) in the communication. Data is transferred
to the primary system using the "data acquisition by polling" principle.
The IEC functionality includes application functions:
• station initialization
• general interrogation
• clock synchronization
• command transmission.
It is also possible to transfer parameter data and disturbance recordings via the
IEC 103 protocol interface.
The following application service data unit (ASDU) types can be used:
• ASDU 1: Time-tagged message
• ASDU 3: Measurands I
• ASDU 5: Identification message
• ASDU 6: Time synchronization
• ASDU 8: Termination of general interrogation
• ASDU 10: Generic data
The relay accepts:
• ASDU 6: Time synchronization
• ASDU 7: Initiation of general interrogation
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•
•
•
•
ASDU 10: Generic data
ASDU 20: General command
ASDU 21: Generic command
ASDU 23: Disturbance recorder file transfer
The data in a message frame is identified by:
• type identification
• function type
• information number.
These are fixed for data items in the compatible range of the protocol, for
example, the trip of I> function is identified by:
• type identification = 1
• function type = 160
• information number = 90
"Private range" function types are used for such data items that are not defined by
the standard (for example, the status of the digital inputs and the control of the
objects).
The function type and information number used in private range messages is
configurable. This enables flexible interfacing to different master systems.
For more information on IEC 60870-5-103 in Easergy P3 relays, see the "IEC 103
Interoperability List.pdf" and "Communication parameter protocol mappings.zip"
documents.
8.5.5 DNP 3.0
The relay supports communication using the DNP 3.0 protocol. The following
DNP 3.0 data types are supported:
• binary input
• binary input change
• double-bit input
• binary output
• analog input
• counters
8.5.6 IEC 60870-5-101 (IEC-101)
The IEC 60870-5-101 standard is derived from the IEC 60870-5 protocol standard
definition. In Easergy P3 relays, the IEC 60870-5-101 communication protocol is
available via menu selection. The relay works as a controlled outstation (slave)
unit in unbalanced mode.
The supported application functions include process data transmission, event
transmission, command transmission, general interrogation, clock
synchronization, transmission of integrated totals, and acquisition of transmission
delay.
For more information on IEC 60870-5-101 in Easergy P3 relays, see the
"Communication parameter protocol mappings.zip" document.
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8.5.7 IEC 61850
The IEC 61850 protocol is available with the optional communication module. It
can be used to read or write static data from the relay or to receive events and to
receive or send GOOSE messages from or to other relays.
The IEC 61850 server interface includes the following features:
•
•
•
•
•
•
•
•
•
•
•
•
configurable data model: selection of logical nodes corresponding to active
application functions
configurable pre-defined data sets
supported dynamic data sets created by clients
supported reporting function with buffered and unbuffered report control
blocks
support for changing selected setting parameters of the protection functions
sending analog values over GOOSE
supported control modes:
◦ direct with normal security
◦ direct with enhanced security
◦ select before operation with normal security
◦ select before operation with enhanced security
supported horizontal communication with GOOSE: configurable GOOSE
publisher data sets, configurable filters for GOOSE subscriber inputs, GOOSE
inputs available in the application logic matrix
32 data points can be published with GOOSE (two goose control blocks with
maximum 16 data points).
64 binary data points and five analog data points can be subscribed in
GOOSE (maximum five different MAC addresses).
The maximum number of clients is eight (the maximum number of BRCBs is
eight and the maximum number or URCBs is eight).
Both Ed1 and Ed2 are supported and can be selected with a parameter.
For additional information, see separate documents:
• IEC 61850 Edition 2 Certificate for Easergy P3
• Easergy P3 communication protocol parameter mapping
• IEC 61850 configuration instructions
Figure 188 - IEC 61850 default settings
8.5.8 Ethernet/IP
The relay supports communication using the Ethernet/IP protocol which is a part
of the Common Industrial Protocol (CIP) family. The Ethernet/IP protocol is
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available with the optional in-built Ethernet port. The protocol can be used to read
or write data from or to the relay using request / response communication or via
cyclic messages transporting data assigned to assemblies (sets of data).
For more detailed information and parameter lists for Ethernet/IP, refer to a
separate application note “EtherNet/IP configuration instructions.pdf”.
For the complete data model of Ethernet/IP, see the document “DeviceNet and
EtherNetIP data model.pdf” and "Communication parameter protocol
mappings.zip".
8.5.9 IEC 60870-5-104 (IEC-104)
NOTE: Consult Schneider Electric’s representative for the availability.
The IEC 60870-5-104 standard is derived from the IEC 60870-5 protocol standard
definition. It is a combination of the application layer of IEC 60870-5-101 and the
transport functions provided by a TCP/IP protocol stack.
In Easergy P3 relays, the IEC 60870-5-104 communication protocol is available
via menu selection on the Ethernet ports. The relay works as a controlled station
(server). The supported application functions include process data transmission,
event transmission, command transmission, general interrogation, clocksynchronization, and transmission of integrated totals. For more information on
IEC 60870-5-104 in Easergy P3 relays, see the "Communication parameter
protocol mappings" document (P3TDS17005).
8.6 IP filter
Easergy P3 devices contain a simple IP filter (IP firewall), which can be used to
filter incoming TCP/IP connections. This filtering applies only to Modbus TCP,
DNP3, and Ethernet/IP, and can be configured via Easergy Pro.
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Figure 189 - IP firewall setting view
The IP filter works based on configured rules. Incoming IP packets are compared
against the rules, and when a matching rule is found, the packet is handled using
the action specified for the rule. If none of the rules matches the packet, the
default action is taken on the packet. The IP filter records how many times a
packet has matched a rule. The number is shown in the Counter column.
On TCP connections, the rules are mostly applied only when a connection is
opened.
8.6.1 Configuring the IP filter
You can configure up to 10 rules for the IP filter via Easergy Pro and enable each
rule individually.
1. In Easergy Pro, go to Communication > Protocol configuration.
2. In the IP firewall setting view, select the Enable IP firewall checkbox to
enable the firewall.
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Figure 190 - IP firewall setting view
3. In the IP firewall setting view, create a rule.
a. In the Name column, give the rule a name (maximum 32 characters) that
describes its purpose .
b. In the IP address column, specify an IP address.
The IP address is used to filter the incoming IP packets based on the
(apparent) IP address of the source device. There are four options.
Table 125 - IP address for the IP filter
IP address
Description
Any
By writing a dash or value zero in this
column, the rule is set to match any
source IP address. The column shows
a dash.
Single IP address
If a single IP address (such as
192.168.0.10) is written here, the
packets (or connections) must originate
from this IP address to match the rule.
IP subnet
If all IP addresses in a subnet should
match this rule, write the subnet here
using the CIDR notation. For example,
notation 192.168.0.0/24 matches all IP
addresses in the range 192.168.0.0–
192.168.0.255.
IP address range
If a range of IP addresses (for
example, 192.168.0.20–192.168.0.30)
is written here, packets from these
addresses match the rule. Both end
points of this range are inclusive.
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NOTE: If the matching range of IP addresses can be expressed using
the CIDR notation, the range is expressed in this format, regardless of
how the range was entered into the configuration. As a result, the
presentation format of the configuration as it is read from the device
might not match the format in which it was entered. This may cause
problems with Easergy Pro because this tool expects the presentation
format to match exactly. To work around this issue, select the Reset
and read current view command in Easergy Pro after writing the
configuration. This is required to handle the large number of different
input formats supported.
c. In the Action column, specify an action for the rule.
There are four options.
Table 126 - Actions for IP filter
Action
Description
Allow
The packet is allowed to continue
normally. This means that the specified
source devices can use the specified
services on the P3 device.
Reject89)
The packet is blocked and the remote
peer is informed about this decision.
Drop
The packet is blocked without informing
the remote peer.
Cont.
The processing of the other rules
continues on this packet normally.
89) Because
of the implementation details in the Easergy P3 TCP/IP stack, rules that are
given the Reject action sometimes behave as if their action was Drop.
8.6.2 Unexpected packets
The IP filter also can also detect unexpected packets. For example, if a client
attempts to close a connection that does not exist, this is considered an
unexpected packet.
Certain techniques used by hackers produce unexpected packets, but such
packets may also appear on the network if some packets are lost or dropped
because of a malfunctioning network device. Some devices may also have
programming errors or bugs produce unexpected packets in their TCP/IP stack.
The unexpected packets feature attempts to distinguish between these two
sources based on the number of unexpected packets detected within a
configurable “recent period”. If the number of these packets is greater than the
configured limit, the selected alarm signal is triggered.
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Figure 191 - Unexpected packets setting view
Table 127 - Parameters for unexpected packages
Parameter
Description
Counter
Counts the number of unexpected packets
detected within the configured recent
period.
Limit
The limit after which an alarm is given
Recent period
The number of unexpected packets
counted within this period is compared to
the configured limit value
• Default value: 1 minute
• Maximum value: 65535 minutes (45 days)
Alarm
Select which CS alarm signal (CS Alarm
1/CS Alarm 2) is activated when the set
limit is exceeded. The alarms can be
assigned to other signals in the output
matrix.
8.6.3 Alarms
Active cybersecurity (CS) alarms can be viewed in the Alarms view. When an
alarm signal has been asserted, it remains active until it is cleared with the Clear
alarms command.
Figure 192 - Alarms
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9 Applications and configuration examples
This chapter describes the protection functions in different protection applications.
The relay can be used for line/feeder protection of medium voltage networks with
a grounded, low-resistance grounded, isolated or a compensated neutral point.
The relays have all the required functions to be applied as a backup relay in highvoltage networks or to a transformer differential relay. In addition, the relay
includes all the required functions to be applied as a motor protection relay for
rotating machines in industrial protection applications.
The relays provide a circuit breaker control function. Additional primary switching
relays (grounding switches and disconnector switches) can also be controlled
from the front panel or the control or SCADA/automation system. A
programmable logic function is also implemented in the relay for various
applications, for example interlockings schemes.
9.1 Arc flash detection
Figure 193 - Typical arc flash detection scheme with integrated arc flash option
card
T1
7
G
S1
6
A
T1
B
C
D
S2
S1
S1
S1
S1
T1
T1
T1
T1
T1
S2
S2
S2
S2
S2
S3
S1
E
S3
1
S3
2
S3
3
S3
4
S3
5
F
A. Incomer cable zone
B. Incomer circuit breaker zone
C. Busbar zone
E. Feeder cable zone
F. Light information via hard-wired BIO L> (feeder cable and circuit
breaker)
G. Light information via hard-wired BIO L> (incomer busbar and
circuit breaker)
D. Feeder circuit breaker zone
In this application example, the arc flash sensor for zone E is connected to device
1. If the sensor detects a fault and simultaneously, device 1 detects an
overcurrent signal, zone E is isolated by the outgoing feeder breaker.
The arc flash sensor for the second feeder zone E is connected to device 2, and it
operates the same way. The arc flash sensors for zones C and D are connected
to device 1, 2, 3, 4, or 5. If a sensor detects a fault in zone C or D, the light-only
signal is transferred to device 6 which also detects the overcurrent and then trips
the main circuit breaker.
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An arc flash fault in zone A or B does not necessarily activate the current
detection in device 6. However, arc flash detection can be achieved by using the
light-only principle. If an arc flash occurs in the cable termination or incomer
circuit breaker in zone A or B, the fault is cleared by an overcurrent signal.
WARNING
HAZARD OF UNWANTED OPERATION
Do not route the BIO line close to primary power circuits.
Failure to follow these instructions can result in death, serious injury,
or equipment damage.
Figure 194 - Arc flash detection application example – fiber
T1
7
E
S1
6
A
T1
B
C
T1
T1
T1
T1
T1
D
S1
1
S1
2
S1
S1
3
4
S1
5
F
A. Incomer cable zone
B. Busbar zone
C. Feeder circuit breaker zone
D. Feeder cable zone
E. Light information via optical BIO L> (incomer busbar and circuit
breaker)
F. Light information via optical BIO L> (feeder cable and circuit
breaker)
The fiber-loop arc flash sensor for zone D is connected to device 1. If the sensor
detects a fault and simultaneously, device 1 detects an overcurrent signal, zone D
is isolated by the outgoing feeder breaker.
For the other feeders, the fiber-loop arc flash sensors monitoring zone D are
connected to the appropriate feeder relays and they operate the same way as
feeder 1.
The fiber loop arc flash sensors for zones C, B and A are connected to device 6.
If a sensor detects a fault in zone C, B or A and simultaneously, device 6 detects
an overcurrent signal, the fault is cleared by the incoming breaker operation.
Device 7 measures the overcurrent and receives light detection signals from
zones A, B, and C. It trips the substation if device 6 is unable to measure the
overcurrent.
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WARNING
HAZARD OF UNWANTED OPERATION
Do not route the BIO line close to primary power circuits.
Failure to follow these instructions can result in death, serious injury,
or equipment damage.
Figure 195 - Arc flash detection application example – fiber connections
A
B
A
B
A. L > (BB & CB) via fibre-optic link
B. Feeder
C
C. Incomer
Figure 196 - Arc matrix – light
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Figure 197 - Arc matrix – output
9.2 Using CSH120 and CSH200 with IN2 0.2 A / 1 A core balance
CT input
General
The CSH120 and CSH200 core balance CTs are for direct ground fault
overcurrent measurement. The only difference between them is the diameter.
Because of their low-voltage insulation, they can only be used on cables.
These core balance CTs can be connected to the Easergy P3 protection device
range when 0.2 A IN input is used. This needs to be determined when ordering
the protection device (select 0.2 A for the ground fault current input in the order
code).
Settings in the Easergy P3 protection device
When CSH120 or CSH200 is connected to an Easergy P3 protection device, to
secure correct operation of the protection functions and measurement values, use
the following values in the Scaling setting view:
•
IN2 CT primary: 470 A
•
IN2 CT secondary: 1 A
•
Nominal IN2 input: 0.2 A
Figure 198 - Scalings view for I02 input
Lower scaling values
The device also allows selecting ten times lower scaling values. Set the values to:
• IN2 CT primary: 47 A
•
IN2 CT secondary: 0.1 A
•
Nominal IN2 input: 0.2 A
The minimum setting for the primary current is then 0.005 x 47 A = 0,235 A.
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Measuring specifications
When CSH120 or CSH200 is used with Easergy P3 protection devices the
measuring range is 0.2 A–300 A of primary current. The minimum setting for
primary current is 0.005xIN which in this case means 0.005 x 470 A = 2.35 A of
primary current.
Figure 199 - Ground fault overcurrent setting view
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10 Installation
10.1 Safety in installation
This page contains important safety instructions that must be followed precisely
before attempting to install, repair, service or maintain electrical equipment.
Carefully read and follow the safety instructions described below. Only qualified
personnel, equipped with appropriate individual protection equipment, may work
on or operate the equipment. Qualified personnel are individuals who:
• are familiar with the installation, commissioning, and operation of the
equipment and of the system to which it is being connected.
• are able to safely perform switching operations in accordance with accepted
safety engineering practices and are authorised to energize and de-energize
equipment and to isolate, ground, and label it.
• are trained in the care and use of safety apparatus in accordance with safety
engineering practices.
• are trained in emergency procedures (first aid).
DANGER
HAZARD OF ELECTRIC SHOCK, EXPLOSION, OR ARC FLASH BEFORE
PERFORMING ANY INTERVENTION:
•
•
•
•
•
Turn off all power supplying the protection device and the equipment in
which it is installed before working on it.
Always use a properly rated voltage sensing device to confirm that power
is off.
Replace all devices, doors, and covers before turning on power to this
equipment.
Apply appropriate personal protective equipment and follow safe electrical
work practices. See local regulation.
Do not install this product in ATEX class 0, 1 and 2 areas.
Failure to follow this instruction will result in death or serious injury.
DANGER
HAZARD OF FIRE
Insufficient tightening causes high contact resistance and overheat with
current, in extreme cases, even loose and ineffective connections and fire
hazard. Tighten all the electric connections with specified torque.
Failure to follow these instructions will result in death or serious
injury.
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WARNING
HAZARD OF UNEXPECTED OPERATION
Do not energize the primary circuit before this protection relay is properly
configured.
Failure to follow these instructions can result in death, serious injury,
or equipment damage.
CAUTION
HAZARD OF FIRE, DAMAGE TO ELECTRONICS OR MALFUNCTION
If you are authorized to withdraw the relay:
• Disconnect the power supply before removing or replacing a module or
the withdrawable part of the protection relay.
• Never touch electronic parts (electrostatic discharge).
• Before replacing the withdrawable part, visually check the cleanliness and
if there are any foreign objects in the case, the withdrawable part and the
connectors.
Failure to follow these instructions can result in injury or equipment
damage.
Protection Class I equipment
Before energizing the equipment it must be grounded using the protective
conductor terminal, if provided, or the appropriate termination of the supply plug in
the case of plug connected equipment.
The protective conductor (ground) connection must not be removed since the
protection against electric shock provided by the equipment would be lost.
When the protective (ground) conductor terminal (PCT) is also used to terminate
cable screens, etc., it is essential that the integrity of the protective (ground)
conductor is checked after the addition or removal of such functional ground
connections. For M4 stud PCTs the integrity of the protective (ground)
connections should be ensured by use of a locknut or similar.
The recommended minimum protective conductor (ground) wire size is 2.5 mm²
(AWG 14) (3.3 mm² (AWG 12) for North America) unless otherwise stated in the
technical data section of the equipment documentation, or otherwise required by
local or country wiring regulations.
The protective conductor (ground) connection must be low-inductance and as
short as possible. All connections to the equipment must have a defined potential.
Connections that are pre-wired, but not used, should preferably be grounded
when binary inputs and output relays are isolated. When binary inputs and output
relays are connected to common potential, the pre-wired but unused connections
should be connected to the common potential of the grouped connections.
NOTE: Use only copper conductors with minimum 75°C rating.
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10.2 Checking the consignment
Check that the unit packaging and the seal are intact at the receipt of the delivery.
Our products leave the factory in closed, sealed packaging. If the transport
packaging is open or the seal is broken, the confidentiality and authenticity of the
information contained in the products cannot be ensured.
10.3 Product identification
Each Easergy P3 relay is delivered in a separate package containing:
•
•
•
Easergy P3 protection relay with the necessary terminal connectors
Production testing certificate
Quick Start manual
Optional accessories are delivered in separate packages.
To identify an Easergy P3 protection relay, see the labels on the package and on
the side of the relay.
Serial number label
Figure 200 - Serial number label
1
2
3
4
8
9
Vn:
fn:
In:
Io1n:
Pmax:
P:
Vaux:
Made in Finland
100/110V
12 Mfg Date: 27.7.2017
50/60Hz
5 I n:
1/5A 13 MAC: 001AD3011FF1
1/5A
6 Io2n: 1/0.2A
5/1A
7 Io3n: 1/5A
35W
110 240 Vac/dc
I
Type: 10 P3G32-CGITA-KAFNA-BA
14 VID: P3G32-001017
S/N: 11 EB173020002
1.
Rated voltage Vn
2.
Rated frequency fn
3.
Rated phase current In
4.
Rated ground fault current I01n
5.
Rated phase current I´n *)
6.
Rated ground fault current I02n
7.
Rated ground fault current I03n90)*)
8.
Power consumption Pmax
9.
Power supply operating range VAUX
10. Order code
11. Serial number
12. Manufacturing date
13. MAC address for TCP/IP communication
14. Production identification
90)
P3T/en M/J006
*)Available in P3M32, P3T32 and P3G32 models only
331
Transformer protection relay
10 Installation
Unit package label
Figure 201 - P3x3x Unit package label
REL52101
Protection relay
Relais de protection
B
A
C
Easergy - P3
P3F30-CGGGG-AAENA-BA
Made in Finland
EB172730012
REL522101
135732
Easergy
45292
D
x1
A
E
3
606481
357 3 28
SCHNEIDER ELECTRIC
CS30323
F-92506 RUEIL MALMAISON CEDEX
A. Short order code
B. Serial number
C. Internal product code
D. Order code
E. EAN13 bar code
10.4 Storage
Store the relay in its original packaging in a closed, sheltered location with the
following ambient conditions:
•
•
ambient temperature: -40 °C to +70 °C (or -40 °F to +158 °F)
humidity < 90 %.
Check the ambient conditions and the packaging yearly.
10.5 Mounting
DANGER
HAZARD OF ELECTRIC SHOCK, EXPLOSION, OR ARC FLASH
•
•
•
•
•
•
•
Wear your personal protective equipment (PPE) and comply with the safe
electrical work practices. For clothing refer applicable local standards.
Only qualified personnel should install this equipment. Such work should
be performed only after reading this entire set of instructions and checking
the technical characteristics of the device.
NEVER work alone.
Turn off all power supplying this equipment before working on or inside it.
Consider all sources of power, including the possibility of backfeeding.
Always use a properly rated voltage sensing relay to ensure that all power
is off.
Do not open the secondary circuit of a live current transformer.
Connect the device's protective ground to functional ground according to
the connection diagrams presented in this document.
Failure to follow this instruction will result in death or serious injury.
332
P3T/en M/J006
10 Installation
Transformer protection relay
CAUTION
HAZARD OF CUTS
Trim the edges of the cut-out plates to remove any jagged edges.
Use protective gloves when moving and mounting the device.
Failure to follow these instructions can result in injury.
Panel mounting
Figure 202 - Panel mounting
mm
in
225
8.86
1
2
erg y
Eas
Eas erg y
Eas erg y
152
5.98
1.0
0.0-60
4-2
.3
6
3b
2.5 N•m
22 lb-in
T max. 1.2 N•m
10.6 lb-in
3c
T max. 0.5-0.6 N•m
4.4-5.3 lb-in
3 N•m
27 lb-in
3
4
3a
3a
erg yerg y
EasEas
min. 2.5mm2
Ø 5-8mm
CLICK !
mm
in
Nut M5
1.5Nm, 13.3 Ib in
Easergy
177
6.97
253.40
9.97
208
8.18
183
7.20
264
10.37
150
5.91
223.33
9.17
24.60
0.97
153
6.02
183
7.20
The conventional mounting technique has always been installing the relay on the
secondary compartment's door. A limitation of this approach could be that the
door construction is not strong enough for the relay's weight and wiring a large
amount of secondary and communication cabling could be challenging.
P3T/en M/J006
333
Transformer protection relay
10 Installation
Panel mounting with detachable display
Figure 203 - Panel mounting with detachable display
mm
in
247
9.72
180
7.09
199
7.81
199
7.83
180
7.09
Ease rgy
150
5.91
29
1.12
1
264
10.37
Easergy
210
8.27
Ø5
0.2
177
6.97
M4x20
Torx T-20
1.5Nm
mm
in
100
3.94
2
18
0.71
11.5
0.45
20
0.79
T max. 1.2Nm
10.6 lb.in
34
1.34
Eas erg y
T max. 0.5...0.6Nm
4.4...5.3 lb.in
3
180
7.09
Ø7
0.28
min. 2.5mm2
Ø 5-8mm
180
7.09
Nut M5
1.5 Nm, 13.3 Ib in
This mounting technique allows the door to be lighter as the relay's frame is
installed on the back of the secondary compartment. Normally, the relay is
mounted by the terminal blocks, hence the secondary wiring is short.
Communication cabling is easier, too, as the door movement does not need to be
considered. In this case, only the communication between relay base and display
have to be wired.
334
P3T/en M/J006
10 Installation
Transformer protection relay
Projection mounting
Figure 204 - Projection mounting
225
8.86
2
1
mm
in
Eas erg y
Easerg y
152
5.98
1.0
0.0-60
4-2
.3
6
3b
T max. 0.5...0.6Nm
4.4...5.3 lb.in
T max. 1.2Nm
10.6 lb.in
3c
3Nm
27 lb.in
2.5Nm
22 lb.in
4
3
3a
y y
ergerg
EasEas
Vamp 300
min. 2.5mm2
Ø 5-8mm
3a
ON
OK
F2
F1
I
O
Nut M5
1.5Nm, 13.3 Ib in
CLICK !
mm
in
208
8.18
183
7.20
264
10.37
Easergy
269
10.59
224
8.82
45
1.77
Vamp 300
152
5.98
ON
177
6.97
150
5.91
OK
I
O
F1
177
7.0
F2
If the depth dimension behind the compartment door is limited, the relay can be
equipped with a frame around the collar. This arrangement reduces the depth
inside the compartment by 45 mm. For more details, see 11.5 Environmental
conditions.
P3T/en M/J006
335
Transformer protection relay
10 Installation
Example of the P3 alarm facial label insertion
1
A
C
E
G
I
K
M
B
D
F
H
J
L
N
F1
F2
A
C
E
G
I
K
M
B
D
F
H
J
L
N
F1
F2
2
3
A
C
E
G
I
K
M
B
D
F
H
J
L
N
F1
F2
See "P3 Advanced Series facial label instruction" document for more information.
Protective film
NOTICE
RISK OF DESTRUCTION OF THE RELAY
The protective film on the relay's display is plastic and can melt if exposed to
high temperatures intensive sunlight. Remove the protective film after mounting
the relay.
Failure to follow these instructions can result in equipment damage.
10.6 Connections
The Easergy P3T32 has a fixed combination of analog interface, power supply,
digital input and output, communication and arc flash detection cards as per the
chosen order code. Do not remove cards from the relay's card slots in any
circumstances.
CARD SLOT ARRANGEMENT
WARNING! DO NOT REMOVE CARDS!
1
2 3 4 5 6
7 8
9 10
336
OBSERVE PRECAUTIONS
FOR HANDLING
ELECTROSTATIC
SENSITIVE
VY197B
DEVICES
P3T/en M/J006
10 Installation
Transformer protection relay
10.6.1 Supply voltage cards
Auxiliary voltage
DANGER
HAZARD OF ELECTRIC SHOCK
Before connecting the devices, disconnect the supply voltage to the unit.
Failure to follow these instructions will result in death or serious injury.
The external auxiliary voltage VAUX (110–240 V ac/dc, or optionally 24–48 V dc) of
the relay is connected to the pins 1/C/1:1–2 or 1/D/1:1–2.
The rated frequency (ac) is 50/60 Hz and the AC frequency operating range is the
following:
• 50 Hz, ±10%
• 60 Hz, ±10%
NOTICE
LOSS OF PROTECTION OR RISK OF NUISANCE TRIPPING
•
•
If the relay is no longer supplied with power or is in permanent fault state,
the protection functions are no longer active and all the Easergy P3 digital
outputs are dropped out.
Check that the operating mode and SF relay wiring are compatible with the
installation.
Failure to follow these instructions can result in equipment damage and
unwanted shutdown of the electrical installation.
P3T/en M/J006
337
Transformer protection relay
10 Installation
Figure 205 - Example of supply voltage card Power C 110-240
Table 128 - Supply voltage card Power C 110-240 & Power D 24-48
Pin No.
Symbol
Description
20
T12
Heavy duty trip relay 12 for arc protection
19
T12
Heavy duty trip relay 12 for arc protection
18
T11
Heavy duty trip relay 11 for arc protection
17
T11
Heavy duty trip relay 11 for arc protection
16
T10
Heavy duty trip relay 10 for arc protection
15
T10
Heavy duty trip relay 10 for arc protection
14
T9
Heavy duty trip relay 9 for arc protection
13
T9
Heavy duty trip relay 9 for arc protection
12
T1
Heavy duty trip relay 1 for arc protection
11
T1
Heavy duty trip relay 1 for arc protection
10
A1 NO
Signal relay 1, normal open connector
9
A1 NC
Signal relay 1, normal closed connector
8
A1
Signal relay 1, common connector
COMMON
338
7
SF NC
Service status output, normal closed
6
SF NO
Service status output, normal open
P3T/en M/J006
10 Installation
Transformer protection relay
Pin No.
Symbol
Description
5
SF
Service status output, common
COMMON
4
No connection
3
No connection
2
L/+/~
Auxiliary voltage
1
N/-/~
Auxiliary voltage
DANGER
HAZARD OF ELECTRICAL SHOCK
Connect the device's protective ground to functional ground according to the
connection diagrams presented in this document.
Failure to follow these instructions will result in death or serious injury.
10.6.2 Analog measurement cards
DANGER
HAZARD OF ELECTRICAL SHOCK
Do not open the secondary circuit of a live current transformer.
Disconnecting the secondary circuit of a live current transformer may cause
dangerous overvoltages.
Failure to follow these instructions will result in death or serious injury.
10.6.2.1 Analog measurement card 1 (slot 8)
This card contains connections for current transformers for measuring of the
phase currents A–C and two ground fault overcurrents IN, and four voltage
transformers for measuring the VN, VLL or VLN.
The relay is able to measure three phase currents, and two ground fault
overcurrents. It also measures up to four voltage signals: line-to-line, line-toneutral, neutral displacement voltage and voltage from another side
(synchrocheck). See the voltage modes selection below:
P3T/en M/J006
•
3LN, 3LN+VN, 3LN+LLY, 3LN+LNY
•
2LL+VN, 2LL+VN+LLY, 2LL+VN+LNY
•
LL+VN0+LLY+LLZ, LN+VN+LNY+LNZ
339
Transformer protection relay
10 Installation
Figure 206 - Analog measurement card 1
1 = 3L (5/1 A) + 2 I0 (5/1 A+1/0,2 A) ring lug + 4U
Table 129 - Terminal pins for card 1
Pin No.
Symbol
Description
1
IA (S1)
Phase current A 5 A (S1)
2
IA (S2)
Phase current A 5 A (S2)
3
IB (S1)
Phase current B 5 A (S1)
4
IB (S2)
Phase current B 5 A (S2)
5
IC (S1)
Phase current C 5 A (S1)
6
IC (S2)
Phase current C 5 A (S2)
7
IN1 (S1)
Ground fault overcurrent IN1 (S1) common
for 5 A and 1 A
8
IN1 (S2)
Ground fault overcurrent IN1 5 A (S2)
9
IN1 (S2)
Ground fault overcurrent IN1 1 A (S2)
10
IN2 (S1)
Ground fault overcurrent IN2 (S1) common
for 1 A and 0.2 A
340
11
IN2 (S2)
Ground fault overcurrent IN2 1 A (S2)
12
IN2 (S2)
Ground fault overcurrent IN2 0.2 A (S2)
P3T/en M/J006
10 Installation
Transformer protection relay
Table 130 - Terminal pins for card 1
Pin No.
Symbol
Description
1
VLL/VLN
Voltage VLL (a) /VLN (a)
2
VLL/VLN
Voltage VLL (b) /VLN (n)
3
VLL/VLN
Voltage VLL (a) /VLN (a)
4
VLL/VLN
Voltage VLL (b) /VLN (n)
5
VN/VLL/VLN
VoltageVN(a) / VLL (a) /VLN (a)
6
VN/VLL/VLN
Voltage VN(b) /VLL (b) /VLN (n)
7
VN/VLN/VLL
Voltage VN (da) / VLL (a) / VLN (n)
8
VN/VLN/VLL
Voltage VN (dn) / VLL (b) / VLN (n)
10.6.2.2 Analog measurement card 2 (slot 8)
This card contains connections for current transformers for measuring the phase
currents IA–IC and two ground fault overcurrents IN and four voltage transformers
for measuring the VN, VLL or VLN.
The relay is able to measure three phase currents, and two ground fault
overcurrents. It also measures up to four voltage signals: line-to-line, line-toneutral, zero-sequence voltage and voltage from another side (synchro-check).
See the voltage modes selection below:
• 3LN, 3LN+VN, 3LN+LLY, 3LN+LNY
P3T/en M/J006
•
2LL+VN, 2LL+VN+LLY, 2LL+VN+LNY
•
LL+VN+LLY+LLZ, LN+VN+LNY+LNZ
341
Transformer protection relay
10 Installation
Figure 207 - Analog measurement card 2
2 = 3L (1 A) + 2 I0 (5/1 A + 1/0.2 A) ring lug + 4U
Table 131 - Terminal pins 8/2/1:1–12
Pin No.
Symbol
Description
1
IA (S1)
Phase current A1 1 A (S1)
2
IA (S2)
Phase current A1 1 A (S2)
3
IB (S1)
Phase current B1 1 A (S1)
4
IB (S2)
Phase current B1 1 A (S2)
5
IC (S1)
Phase current C1 1 A (S1)
6
IC (S2)
Phase current C1 1 A (S2)
7
IN1 (S1)
Ground fault overcurrent IN1 (S1) common for
5 A and 1 A
8
IN1 (S2)
Ground fault overcurrent IN1 5 A (S2)
9
IN1 (S2)
Ground fault overcurrent IN1 1 A (S2)
10
IN2 (S1)
Ground fault overcurrent IN2 (S1) common for
1 A and 0.2 A
342
11
IN2 (S2)
Ground fault overcurrent IN2 1 A (S2)
12
IN2 (S2)
Ground fault overcurrent IN2 0.2 A (S2)
P3T/en M/J006
10 Installation
Transformer protection relay
Table 132 - Terminal pins 8/2/2:1–8
Pin No.
Symbol
Description
1
VLL/VLN
Voltage VLL (a) /VLN (a)
2
VLL/VLN
Voltage VLL (b) /VLN (n)
3
VLL/VLN
Voltage VLL (a) /VLN (a)
4
VLL/VLN
Voltage VLL (b) /VLN (n)
5
VLL/VLN
Voltage VLL (a) /VLN (a)
6
VLL/VLN
Voltage VLL (b) /VLN (n)
7
VN/VLL/VLN
VN (da)/ VLL (a)/ VLN (a)
8
VN/VLL/VLN
VN (dn)/ VLL (b)/ VLN (n)
10.6.2.3 Analog measurement card 1 (slot 4)
NOTE: L1, L2, and L3 are IEC phase names. For NEMA, the phases are as
follows: L1=A, L2=B, and L3=C.
This card contains connections for current measurement transformers for
measuring the phase currents L1, L2 and L3 and ground fault overcurrent IN.
Totally, the relay is able to measure six phase currents, three ground fault
overcurrents and additionally four voltages.
Figure 208 - Analog measurement card "1 = 3xI (5/1A) ring lug + Io (5/1A)”
1
3
5
7
9
11
P3T/en M/J006
2
4
6
8
10
12
343
Transformer protection relay
10 Installation
Table 133 - Pins 4/1/1:1–12
Pin No.
Symbol
Description
1
IA-2
Phase current IA-2 (S1), common for 1 A and 5 A
2
IA-2 / 5A
Phase current IA-2 (S2)
3
IA-2 / 1A
Phase current IA-2 (S2)
4
IB-2
Phase current IB-2 (S1), common for 1 A and 5 A
5
IB-2 / 5A
Phase current IB-2 (S2)
6
IB-2 / 1A
Phase current ICB2 (S2)
7
IC-2
Phase current IC-2 (S1), common for 1 A and 5 A
8
IC-2 / 5A
Phase current IC-2 (S2)
9
IC-2 / 1A
Phase current IC-2 (S2)
10
IN3
Ground fault overcurrent IN3 (S1), common for 1 A and
5A
11
IN3 / 5A
Ground fault overcurrent IN3 (S2)
12
IN3 / 1A
Ground fault overcurrent IN3 (S2)
10.6.3 I/O cards
10.6.3.1 I/O card “B = 3BIO+2Arc”
This card contains connections to two arc light sensors (for example, VA 1 DA),
three binary inputs and three binary outputs.
The option card also has three normal open trip contacts that can be controlled
either with the relay’s normal trip functions or using the fast arc matrix.
344
P3T/en M/J006
10 Installation
Transformer protection relay
Figure 209 - I/O card “B = 3BIO+2Arc”
Table 134 - Slots 2/B/1:1–20
P3T/en M/J006
Pin no.
Symbol
Description
20
T4
Trip relay 4 for arc detection (normal open)
19
T4
Trip relay 4 for arc detection (normal open)
18
T3
Trip relay 3 for arc detection (normal open)
17
T3
Trip relay 3 for arc detection (normal open)
16
T2
Trip relay 2 for arc detection (normal open)
15
T2
Trip relay 2 for arc detection (normal open)
14
BI3
Binary input 3
13
BI3
Binary input 3
12
BI2
Binary input 2
11
BI2
Binary input 2
10
BI1
Binary input 1
9
BI1
Binary input 1
8
BO COMMON
Binary output 1–3 common GND
7
BO3
Binary output 3, +30 V dc
6
BO2
Binary output 2, +30 V dc
5
BO1
Binary output 1, +30 V dc
4
Sen 2 -
Arc sensor channel 2 negative terminal
3
Sen 2 +
Arc sensor channel 2 positive terminal
345
Transformer protection relay
10 Installation
Pin no.
Symbol
Description
2
Sen 1 -
Arc sensor channel 1 negative terminal
1
Sen 1 -
Arc sensor channel 1 positive terminal
10.6.3.2 I/O card “C = F2BIO+1Arc”
This card contains connections to one arc fiber sensor, two fiber binary inputs,
two fiber binary outputs and three fast trip relays.
Arc loop sensor input is used with Arc-SLm sensor. The sensor’s sensitivity can
be set in the Arc protection setting view in Easergy Pro. If the sensitivity needs
to be reduced, increase the setting value from the default value. As an example, it
could be set up to 900. Test that the switching object no longer initiates an
unwanted sensor activation. Validate also with a strong external light source that
the arc loop channel remains operational. The default adjusted value is 737. The
setting range is from 100 to 900.
NOTE: Some applications have strong Arc flash sources, for example
switching devices such as a CB or a contactor, which could illuminate the loop
sensor during a normal switching operation.
NOTE: The setting value is a relative value for sensitivity, and it does not
anticipate any light intensity (lux) value.
Binary inputs and outputs are designed to be used with 50/125 μm, 62.5/125 μm,
100/140 μm, and 200 μm fiber sizes (Connector type: ST).
The option card also has three normal open trip contacts that can be controlled
either with the relay’s normal trip functions or using the fast arc matrix.
Figure 210 - I/O card “C = F2BIO+1Arc”
346
P3T/en M/J006
10 Installation
Transformer protection relay
Table 135 - Fiber 2 x BI/BO, 1 x Arc loop sensor, T2, T3, T4 I/O card pins (slot 2)
Connector /
Pin no.
Symbol
Description
1:6
T4
Trip relay 4 for arc detection (normal open)
1:5
T4
Trip relay 4 for arc detection (normal open)
1:4
T3
Trip relay 3 for arc detection (normal open)
1:3
T3
Trip relay 3 for arc detection (normal open)
1:2
T2
Trip relay 2 for arc detection (normal open)
1:1
T2
Trip relay 2 for arc detection (normal open)
2
BI2
Fiber binary input 2
3
BI1
Fiber binary input 1
4
BO2
Fiber binary output 2
5
BO1
Fiber binary output 1
6
Arc sensor 1
Arc sensor 1 Rx
7
Arc sensor 1
Arc sensor 1 Tx
10.6.3.3 I/O card “D = 2IGBT”
This card contains two semiconductor outputs.
Figure 211 - I/O card “D = 2IGBT”
P3T/en M/J006
347
Transformer protection relay
10 Installation
Table 136 - Slots 4/D/1:1–20
Pin no.
Symbol
Description
19–20
NC
No connection
1891)
HSO2
HSO output 2 terminal 2
1791)
5/D/1:18
5/D/1:17
5/D/1:16
5/D/1:15
HSO output 2 terminal 1
1691)
1591)
8–14
NC
No connection
7
HSO1
HSO output 1 terminal 2
5/D/1:7
5/D/1:6
5/D/1:5
5/D/1:4
6
5
HSO output 1 terminal 1
4
1–3
NC
No connection
91) Terminals
18-17 and 16-15 are interconnected, so it is sufficient to connect the wiring to terminals
15 and 17 or 16 and 18 only.
10.6.3.4 I/O option card “D=4Arc”
This card contains four arc point connections to four arc light sensors (for
example. VA 1 DA). The card provides sensors 3 to 6.
Figure 212 - I/O option card “D= 4Arc”
Table 137 - Pins 6/D/1:1–8 (slot 6)
348
Pin no.
Symbol
Description
8
Sen 6 -
Arc sensor 6 negative terminal
7
Sen 6 +
Arc sensor 6 positive terminal
6
Sen 5 -
Arc sensor 5 negative terminal
5
Sen 5 +
Arc sensor 5 positive terminal
4
Sen 4 -
Arc sensor 4 negative terminal
P3T/en M/J006
10 Installation
Transformer protection relay
Pin no.
Symbol
Description
3
Sen 4 +
Arc sensor 4 positive terminal
2
Sen 3 -
Arc sensor 3 negative terminal
1
Sen 3 +
Arc sensor 3 positive terminal
10.6.3.5 I/O card “G = 6DI+4DO”
This card provides six digital inputs and four relay outputs. The threshold level is
selectable in the order code.
The card is equipped with six dry digital inputs with hardware-selectable
activation/threshold voltage and four trip contacts. Input and output contacts are
normally open.
Figure 213 - I/O card “G = 6DI+4DO”
Table 138 - Channel numbering for "C" or "D" power module and four “G” cards in
slots 2–5/G-G-G-G
Pin no.
Trip “T” output numbering
Power
Slot 2
Slot 3
Slot 4
Slot 5
supply
P3T/en M/J006
Card type
C or D
G
G
G
G
19, 20
12
16
20
24
28
17, 18
11
15
19
23
27
15, 16
10
14
18
22
26
13, 14
9
13
17
21
25
349
Transformer protection relay
10 Installation
Pin no.
Trip “T” output numbering
11, 12
1
DI channel numbering
11, 12
6
12
18
24
9, 10
5
11
17
23
7, 8
4
10
16
22
5, 6
3
9
15
21
3, 4
2
8
14
20
1, 2
1
7
13
19
NOTE: Digital inputs are polarity-free, which means that you can freely
choose "-" and "+" terminals for each digital input.
Table 139 - Channel numbering for “C” or “D” power module, "B" or "C" arc sensor
interface card and three “G” cards in slots 3–5/G-G-G
Pin no.
Trip “T” output numbering
Power
Slot 2
Slot 3
Slot 4
Slot 5
G
G
G
19, 20
16
20
24
17, 18
15
19
23
15, 16
14
18
22
13, 14
13
17
21
11, 12
6
12
18
9, 10
5
11
17
7, 8
4
10
16
supply
Card type
C or D
B
19, 20
12
4
17, 18
11
3
15, 16
10
2
13, 14
9
11, 12
1
C
5, 6
4
3, 4
3
1, 2
2
DI channel numbering
350
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Transformer protection relay
Pin no.
Trip “T” output numbering
5, 6
3
9
15
3, 4
2
8
14
1, 2
1
7
13
NOTE: Digital inputs are polarity-free, which means that you can freely
choose "-" and "+" terminals for each digital input.
10.6.3.6 I/O card “H = 6DI + 4DO (NC)”
This card provides six digital inputs and four relays outputs that are normally
closed (NC). The threshold level is selectable in the order code.
The 6xDI+4xDO option card is equipped with six dry digital inputs with hardwareselectable activation/threshold voltage and four normally closed (NC) trip
contacts.
10.6.3.7 I/O card “I = 10DI”
This card provides 10 digital inputs. The threshold level is selectable in the order
code.
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Figure 214 - I/O card “I = 10DI”
Table 140 - Channel numbering for slots 2–5/G-I-I-I/1:1–20 when one "G" and
three "I" cards are used
Pin no.
DI numbering
Slot 2
Slot 3
Slot 4
Slot 5
G
I
I
I
19, 20
16
26
36
17, 18
15
25
35
15, 16
14
24
34
13, 14
13
23
33
Card type
11, 12
6
12
22
32
9, 10
5
11
21
31
7, 8
4
10
20
30
5, 6
3
9
19
29
3, 4
2
8
18
28
1, 2
1
7
17
27
NOTE: Digital inputs are polarity-free, which means that you can freely
choose "-" and "+" terminals for each digital input.
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Transformer protection relay
10.6.4 Arc flash sensor
DANGER
HAZARD OF NON-DETECTED LIGHT
Clean the arc sensor periodically as instructed in this user manual and after
an arc flash fault.
Failure to follow these instructions will result in death or serious
injury.
VA 1 DA is a point-type arc flash sensor. The sensor activated by strong light. It
transforms the light information into the current signal that is used by the device to
detect arc flash light.
Figure 215 - Sensor dimensions
mm
in
22.2
0.83
14
0.55
20
0.79
46.4
1.83
10
0.39
25
0.98
8
0.31
4.2
0.17
The sensor features include:
•
•
•
•
•
standard 8000–10000 lux visible light sensitivity
wide area arc flash detection
maximum 2 ms detection time
standard cable length 6 m (236.22 in) or 20 m (787.40 in) (cut to length on
site)
easy to install (two-wired non-polarity sensitive connection)
DANGER
HAZARD OF NON-DETECTED LIGHT
Never attempt to extend the length of arc flash sensor cables.
Failure to follow these instructions will result in death or serious injury.
P3T/en M/J006
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10.6.4.1 Mounting the sensors to the switchgear
DANGER
HAZARD OF ELECTRIC SHOCK, EXPLOSION, OR ARC FLASH
•
•
•
•
•
•
•
•
•
•
•
•
•
Apply appropriate personal protective equipment (PPE) and follow safe
electrical work practices. See NFPA 70E, NOM-029-STPS-2011, or CSA
Z462.
The arc fault detection system is not a substitute for proper PPE when
working on or near equipment being monitored by the system.
Information on this product is offered as a tool for conducting arc flash
hazard analysis. It is intended for use only by qualified persons who are
knowledgeable about power system studies, power distribution equipment,
and equipment installation practices. It is not intended as a substitute for
the engineering judgement and adequate review necessary for such
activities.
Only qualified personnel should install and service this equipment. Read
this entire set of instructions and check the technical characteristics of the
device before performing such work.
Perform wiring according to national standards (NEC) and any
requirements specified by the customer.
Observe any separately marked notes and warnings.
NEVER work alone.
Before performing visual inspections, tests, or maintenance on this
equipment, disconnect all sources of electric power. Assume all circuits are
live until they are completely de-energized, tested, and tagged. Pay
particular attention to the design of the power system. Consider all sources
of power, including the possibility of backfeeding.
Always use a properly rated voltage sensing relay to ensure that all power
is off.
The equipment must be grounded.
Connect the device's protective ground to functional earth according to the
connection diagrams presented in this document.
Do not open the device. It contains no user-serviceable parts.
Install all devices, doors and covers before turning on the power to this
device.
Failure to follow these instructions will result in death or serious injury.
Install arc flash sensors inside the switchgear. There are two options for mounting
the sensors:
• in customer-drilled holes on the switchgear
• on VYX001 Z-shape or VYX002 L-shape mounting plates available from
Schneider Electric or locally fabricated from supplied drawings
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Transformer protection relay
Figure 216 - VYX 001 mounting plate for sensor
mm
in
15
0.59
50
1.97
25
0.98
59
2.32
51
2.0
2.5
0.1
42
1.65
10
0.39
7
0.28
50
1.97
15
0.59
Figure 217 - VYX 002 mounting plate for sensor
mm
in
10
0.39
15
0.59
59
2.32
15
0.59
3
0.12
30
1.18
30
1.18
Figure 218 - Mounting the sensor
A
B
C
D
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10 Installation
A. Active part of the sensor
B. Cable clamp
C. Fastening screw 4 x 15 mm
D. Sensor cable
1. Press the active part of the sensor through the 10 mm hole in the panel
surface.
2. Fix it using a 4 mm screw.
10.6.4.2 Connecting the sensors to the device
The sensors are delivered with 6 or 20 m cables.
DANGER
HAZARD OF NON-DETECTED LIGHT
Never attempt to extend the length of arc flash sensor cables.
Failure to follow these instructions will result in death or serious injury.
NOTE: Use sensor type VA1DA-6W or VA1DA-20W when a shielded cable is
required.
After mounting the sensors, connect them to the device.
1. Route the wire to the nearest device using the shortest route possible.
Cut the wire to a suitable length.
Take into account the wiring methods inside the equipment. This should be
compliant with local regulations.
2. Connect the arc sensors to the screw terminals.
The polarity of the arc sensor cables is not critical.
NOTE: For the connection terminals, see section I/O cards.
3. If using a shielded cable, connect the cable shield to ground at the sensor
end.
Related topics
10.6.3.1 I/O card “B = 3BIO+2Arc”
10.6.3.2 I/O card “C = F2BIO+1Arc”
10.6.3.4 I/O option card “D=4Arc”
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Transformer protection relay
10.6.5 Communication cards
Table 141 - Communication card types and their pin numbering
Type
Communication
ports
P = Fibre PP (slot 9)
Plastic fibre interface
Signal levels
Connectors
Pin usage
Versatile Link fiber
COM 3 port (if slot 9
card)
R = Fibre GG (slot 9)
ST
Glass fibre interface
(62.5/125 μm)
COM 3 port (if slot 9
card)
K = RS-232
(slot 6)
COM 1 / COM 2
RS-232
D-connector
1 = TX COM 2
2 = TX COM 1
3 = RX COM 1
4 = IRIG-B
5 = IRIG-B GND
7 = GND
8 = RX COM 2
9 = +12V
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Type
Communication
ports
Signal levels
Connectors
Pin usage
B = RS-232
COM 3 / COM 4
RS-232
D-connector
1 = TX COM 4
(slot 9)
2 = TX COM 3
3 = RX COM 3
4 = IRIG-B
5 = IRIG-B GND
6=
7 = GND
8 = RX COM 4
9 = +12V
C = RS-232+Eth RJ
COM 3 / COM 4
RS-232
D-connector
(slot 9)
1 = TX COM 4
2 = TX COM 3
3 = RX COM 3
4 = IRIG-B
5 = IRIG-B GND
6=
7 = GND
8 = RX COM 4
9 = +12V
Ethernet
Ethernet
100 Mbps
RJ-45
1 = Transmit +
2 = Transmit 3 = Receive +
4=
5=
6 = Receive 7=
8=
358
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Transformer protection relay
Type
Communication
ports
Signal levels
Connectors
Pin usage
D = RS-232+Eth LC
COM 3 / COM 4
RS-232
D-connector
1 = TX COM 4
(slot 9)
2 = TX COM 3
3 = RX COM 3
4 = IRIG-B
5 = IRIG-B GND
6=
7 = GND
8 = RX COM 4
9 = +12V
Ethernet
Light
100 Mbps
P3T/en M/J006
LC fiber connector
1 = Receive
2 = Transmit
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Transformer protection relay
Type
Communication
ports
E = 2 x RS-485 (slot 9) COM 3 (RS-485
interface 1)
COM 4 (RS-485
interface 2)
10 Installation
Signal levels
RS-485
Connectors
Pin usage
S2 DIP switch for
termination resistors
of the RS-485
interface 2
8 = RS-485 interface 2
cable shield
connection
7 = RS-485 interface 2
“-“ connection
6 = RS-485 interface 2
“+“ connection
5 = RS-485 interface 2
ground terminal
4 = RS-485 interface 1
“-“ connection
3 = RS-485 interface 1
“+“ connection
2 = RS-485 interface 1
ground terminal
1 = RS-485 interface 1
cable shield
connection
S1 DIP switch for
termination resistors
of the RS-485
interface 1
* RS-485 interfaces 1
and 2 galvanically
isolated from each
other
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Type
Transformer protection relay
Communication
ports
F = RS-485+RJ (slot 9) Ethernet
COM 3 (RS-485
interface 1)
Signal levels
Ethernet
100 Mbps
RS-485
Connectors
Pin usage
RJ45 connector from
top:
1 = Transmit+
2 =Transmit3 =Receive+
4=
5=
6 = Receive7=
8=
DIP switch for
termination resistors
of the RS-485
interface 1
4 = RS-485 interface 1
“-“ connection
3 = RS-485 interface 1
“+“ connection
2 = RS-485 interface 1
ground terminal
1 = RS-485 interface 1
cable shield
connection
G = RS-485+LC (slot
9)
Ethernet
Light
COM 3 (RS-485
100 Mbps
interface 1)
RS-485
LC connector from
top:
1 = Receive
2 = Transmit
DIP switch for
termination resistors
of the RS-485
interface 1
4 = RS-485 interface 1
“-“ connection
3 = RS-485 interface 1
“+“ connection
2 = RS-485 interface 1
ground terminal
1= RS-485 interface 1
cable shield
connection
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Type
Communication
ports
Signal levels
Connectors
Pin usage
N = 2EthRJ
100 Mbps Ethernet
Ethernet
2 x RJ-45
1=Transmit+
(slot 9)
interface with IEC
61850
100 Mbps
2=Transmit3=Receive+
4=
5=
6=Receive7=
8=
O = 2EthLC
(slot 9)
100 Mbps Ethernet
fibre interface with IEC
61850
Light
100 Mbps
2 x LC
LC-connector from top:
-Port 2 Rx
-Port 2 Tx
-Port 1 Rx
-Port 1 Tx
NOTE: When a communication option module of type B, C, D, E, F or G are
used in slot 9, serial ports COM 3 / COM 4 are available.
RS-485 connections
Figure 219 - All shields connected through and grounded at one end
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Transformer protection relay
DIP switches
Figure 220 - DIP switches in optic fibre options
Table 142 - DIP switches in optic fibre options
DIP switch
number
Switch
position
Function
1
Left
Echo off
1
Right
Echo on
2
Left
Light on in idle state
2
Right
Light off in idle state
3
Left
Not applicable
3
Right
Not applicable
4
Left
Not applicable
4
Right
Not applicable
Fibre optics
10.6.5.1 COM 1 port
The COM 1 port is for serial communication protocols. The type of the physical
interface on this port depends on the type of the selected communication option
module. The use of some protocols may require a certain type of option module.
The parameters for this port are set via the front panel or with Easergy Pro in the
COM 1 setting view.
Table 143 - COM 1 port
Type
External
module
Order code
Cable
Typically
used
protocols
RS-232 (slot 6)
VPA3CG
VPA3CG
VX068
None
Profibus DP
10.6.5.2 COM 3 – COM 4 ports
COM 3 and COM 4 are ports for serial communication protocols. The type of the
physical interface on these ports depends on the type of the selected
communication option module. The use of some protocols may require a certain
type of option module. The parameters for these ports are set via the front panel
or with Easergy Pro in the COM 3 PORT – COM 4 PORT setting views.
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Communication information is normally sent to the control system (SCADA), but it
is also possible to use certain communication-related notifications internally, for
example alarms. This is can be done for example via the logic and different
matrices.
Figure 221 - Communication-related notifications can be connected to trip
contacts in the Output matrix setting view
Table 144 - COM 3 port
Type
External
module
Order code
Cable / order
code
Typically
used
protocols
232+00
None
None
None
- None
or
- IEC-101
232+Eth RJ
- IRIG-B
or
- GetSet
232+Eth LC
(Slot 9)
364
VIO12-AB
VIO 12 AB
and
-
VSE-002
VSE002
VIO12-AC
VIO 12 AC
and
-
VSE-002
VSE002
None
- None
- ExternalIO
None
- None
- ExternalIO
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10 Installation
Transformer protection relay
Type
External
module
Order code
Cable / order
code
Typically
used
protocols
VIO12-AD
VIO 12 AD
None
- None
and
-
VSE-002
VSE002
VSE-001
VSE001
- ExternalIO
None
- None
- IEC-103
- ModbusSlv
- SpaBus
VSE-002
VSE002
None
- None
- IEC-103
- ModbusSlv
- SpaBus
- DNP3
VPA-3CG
VPA3CG
VX072
- None
- ProfibusDP
Table 145 - COM 4 port
Type
External
module
Order code
Cable / order
code
Typically
used
protocols
232+00
None
None
None
- None
or
- IEC-101
232+Eth RJ
- IRIG-B
or
- GetSet
232+Eth LC
+VX067 (Split
cable)
(Slot 9)
P3T/en M/J006
VIO12-AB
VIO 12 AB
and
-
VSE-002
VSE002
VIO12-AC
VIO 12 AC
and
-
VSE-002
VSE002
VIO12-AD
VIO 12 AD
and
-
VSE-002
VSE002
None
- None
- ExternalIO
None
- None
- ExternalIO
None
- None
- ExternalIO
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Transformer protection relay
10 Installation
Type
External
module
Order code
Cable / order
code
Typically
used
protocols
VSE-001
VSE001
None
- None
- IEC-103
- ModbusSlv
- SpaBus
VSE-002
VSE002
None
- None
- IEC-103
- ModbusSlv
- SpaBus
- DNP3
To be able to use COM 3 and COM 4 ports, the RS-232 communication interface
(option B, C or D) has to be split in two by using a VX067 cable.
Figure 222 - VX067 cable on the D-connector of slot 9 option card
1
2
3
4
5
6
8
A
9
VX067
VX067
B
A. COM 3 port
B. COM 4 port
NOTE: It is possible to use two serial communication protocols
simultaneously, but the restriction is that the same protocol can be used only
once.
Use a VX086 cable to interface simultaneously with two protocols and IRIG-B.
The Communication > Protocol configuration setting view contains the
selection for the protocol, port settings and message/error/timeout counters. Only
serial communication protocols are valid with the RS-232 interface.
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Transformer protection relay
Figure 223 - Protocol configuration setting view
Table 146 - Parameters
Parameter
Value
Protocol
Unit
Description
Note
Protocol
Set
selection for
COM port
None
-
SPA-bus
SPA-bus (slave)
ProfibusDP
Interface to
Profibus DB
module VPA
3CG (slave)
ModbusSlv
Modbus RTU
slave
IEC-103
IEC-60870-5-10
3 (slave)
ExternalIO
Modbus RTU
master for
external I/Omodules
IEC 101
IEC-608670-5-1
01
DNP3
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DNP 3.0
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Parameter
Value
Unit
GetSet
Description
Note
Communicationi
protocola for
interface
Msg#
0–232 - 1
Message
Clr
counter since
the relay has
restarted or
since last
clearing
Errors
0–216 - 1
Protocol
Clr
interruption
since the relay
has restarted or
since last
clearing
Tout
0–216 - 1
Timeout
Clr
interruption
since the relay
has restarted or
since last
clearing
speed/DPS
Display of
1.
current
communication
parameters.
speed = bit/s
D = number of
data bits
P = parity: none,
even, odd
S = number of
stop bits
Set = An editable parameter (password needed). Clr = Clearing to zero is possible.
1. The communication parameters are set in the protocol-specific menus. For the local
port command line interface, the parameters are set in the configuration menu.
10.6.6 Local port
The relay has a USB port in the front panel.
368
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Transformer protection relay
Protocol for the USB port
The front panel USB type B port is always using the command line protocol for
Easergy Pro.
The speed of the interface is defined in the CONF/DEVICE SETUP menu via the
front panel. The default settings for the relay are 38400/8N1.
It is possible to change the front USB port's bit rate. This setting is visible only on
the relay's local display. The bit rate can be set between 1200 and 187500. This
changes the bit rate of the relay, and the Easergy Pro bit rate has to be set
separately. If the bit rate in the setting tool is incorrect, it takes a longer time to
establish the communication.
NOTE: Use the same bit rate in the relay and the Easergy Pro setting tool.
10.6.7 Connection data
Table 147 - Auxiliary power supply
VAUX
110 (-20%) – 240 (+10%) V ac/dc
110/120/220/240 V ac
110/125/220 V dc
or
24–48 ±20% V dc
24/48 V dc
Power consumption
- Normal state92)
< 20 W
- All digital outputs activated
< 28 W
- All digital outputs activated and two (2)
< 35 W
external communication devices powered
Terminal block:
Wire cross section:
- MSTB 2.5–5.08
Maximum 2.5 mm2 (13–14 AWG)
Minimum 1.5 mm2 (15–16 AWG)
Wire type: single strand or stranded with
insulated crimp terminal
Fuse
UL 489 approved miniature circuit breaker,
for example, Schneider Electric Multi C60
Series, rated 6A
92) Power
on, communications, measurements, display, LED’s and SF output active.
Table 148 - Digital inputs technical data
P3T/en M/J006
Number of inputs
As per the order code
Voltage withstand
255 V ac/dc
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Transformer protection relay
10 Installation
(as per the order code letters)
A: 24–230 V ac/dc (max. 255 V ac/dc)
Nominal operation voltage for DI inputs
B: 110–230 V ac/dc (max. 255 V ac/dc)
C: 220–230 V ac/dc (max. 255 V ac/dc)
Typical switching threshold (as per order
code letters)
A: 12 V dc
B: 75 V dc
C: 155 V dc
NOTE: For trip circuit supervision with
two digital inputs, select a lower
switching threshold (24 V or 110 V).
Current drain
< 4 mA (typical approx. 3mA)
Cycle time
10 ms
Activation time dc/ac
< 11 ms / < 15 ms
Reset time dc/ac
< 11 ms / < 15 ms
Terminal block:
Wire cross section:
- MSTB2.5–5.08
Maximum 2.5 mm2 (13–14 AWG)
Minimum 1.5 mm2 (15–16 AWG)
Wire type: single strand or stranded with
insulated crimp terminal
NOTE: Set the dc/ac mode according to the used voltage in Easergy Pro.
Table 149 - Trip contact, high break
Number of contacts
5 normal open contacts
Rated voltage
250 V ac/dc
Continuous carry
5A
Minimum making current
100 mA @ 24 Vdc
Make and carry, 0.5 s at duty cycle 10%
30 A
Make and carry, 3 s at duty cycle 10%
15 A
Breaking capacity, AC
2 000 VA
Breaking capacity, DC (L/R = 40 ms)
370
at 48 V dc:
5A
at 110 V dc:
3A
at 220 V dc
1A
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10 Installation
Transformer protection relay
Contact material
Ag alloy
Terminal block:
Wire cross section:
- MSTB2.5–5.08
Maximum 2.5 mm2 (13–14 AWG)
Minimum 1.5 mm2 (15–16 AWG)
Wire type: single strand or stranded with
insulated crimp terminal
NOTE: High-break trip contacts exist in power module C and D only.
Table 150 - Trip contact, Tx
Number of contacts
As per the order code
Rated voltage
250 V ac/dc
Continuous carry
5A
Minimum making current
100 mA at 24 Vdc
Make and carry, 0.5 s
30 A
Make and carry, 3 s
15 A
Breaking capacity, ac
2 000 VA
Breaking capacity, dc (L/R = 40 ms)
at 48 V dc:
1.15 A
at 110 V dc:
0.5 A
at 220 V dc:
0.25 A
Contact material
Ag alloy
Terminal block:
Wire cross section:
- MSTB2.5 - 5.08
Maximum Φ0.06 in. (2.5 mm2) (14 AWG)
Minimum Φ0.05 in. (1.5 mm2 ) (16 AWG)
Wire type: single strand or stranded with
insulated crimp terminal
Table 151 - Signal contact, A1 and SF
P3T/en M/J006
Number of contacts:
1
Rated voltage
250 V ac/dc
Continuous carry
5A
Minimum making current
100 mA at 24 V ac/dc
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Transformer protection relay
10 Installation
Make and carry, 0.5 s
30 A
Make and carry, 3 s
15 A
Breaking capacity, ac
2 000 VA
Breaking capacity, dc (L/R = 40 ms)
at 48 V dc:
1A
at 110 V dc:
0.3 A
at 220 V dc:
0.15 A
Contact material
Ag alloy
Terminal block
Wire cross section
- MSTB2.5–5.08
Maximum Φ0.06 in. (2.5 mm2) (14 AWG)
Minimum Φ0.05 in. (1.5 mm2) (16 AWG)
Wire type: single strand or stranded with
insulated crimp terminal
Table 152 - Local serial communication port
Number of ports
1 on front
Electrical connection
USB
Data transfer rate
200 – 187 500 b/s
Protocols
GetSet
Table 153 - COM 3-4 serial communication port
Number of physical ports
0–1 on rear panel (option)
Electrical connection
RS-232 (option, IRIG-B included)
RS-485 (option)
Profibus (option, external module)
Glass fibre connection (option, external
module)
Protocols
Modbus RTU, master
Modbus RTU, slave
Spabus, slave
IEC 60870-5-103
IEC 61870-5-101
Profibus DP
DNP 3.0
IRIG-B
372
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10 Installation
Transformer protection relay
Table 154 - Ethernet communication port
Number of ports
0–2 on rear panel (option)
Electrical connection
RJ-45 100 Mbps (option)
LC 100Mbps (option)
Protocols
IEC 61850
Modbus TCP
DNP 3.0
Ethernet/IP
IEC 61870-5-101
Table 155 - Fiber Ethernet communication port
Number of ports
0 or 2 on rear panel (option)
Connection type
LC 100 Mbps
Optical characteristics
Operates with 62.5/125 μm and 50/125 μm
multimode fiber
Center Wavelength: 1300 nm typical
Output Optical Power:
• Fiber: 62.5/125 μm, NA = 0.275 23.0 dBm
• Fiber: 50/125 μm, NA = 0.20 26.0 dBm
Input Optical Power: -31 dBm
Protocols
IEC 61850
Modbus TCP
DNP 3.0
Ethernet/IP
IEC 61870-5-101
Table 156 - Arc sensor inputs
Number of inputs
As per the order code
Supply to sensor
Isolated 12 V dc
Table 157 - Measuring circuits
Phase current inputs I' (5/1 A)
Slot 4:
T = 3 x I (5/1A) + IN (5/1A)
Rated phase current
5A
1A
- Current measuring range
0.05–250 A
0.02–50 A
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Transformer protection relay
- Thermal withstand
10 Installation
• 20 A (continuously)
• 4 A (continuously)
• 100 A (10 s)
• 20 A (10 s)
• 500 A (1 s)
• 100 A (1 s)
• 1250 A (10 ms)
• 250 A (10 ms)
- Burden
0.075 VA
0.02 VA
- Impedance
0.003 Ohm
0.02 Ohm
Rated ground fault overcurrent
5A
1A
- Current measuring range
0.05–250 A
0.02–50 A
- Thermal withstand
• 20 A (continuously)
• 4 A (continuously)
• 100 A (10 s)
• 20 A (10 s)
• 500 A (1 s)
• 100 A (1 s)
- Burden
0.075 VA
0.02 VA
- Impedance
0.003 Ohm
0.02 Ohm
Phase current inputs I (1 A, 5 A)
Slot 8:
IN input (5A and 1A)
E = 3L (5A) + 4V + 2IN (5/1A+1/0.2A)
F = 3L (1 A) + 4V + 2IN (5/1A+1/0.2A)
Rated phase current
5A
1A
- Current measuring range
0.05–250 A
0.02–50 A
- Thermal withstand
• 20 A (continuously)
• 4 A (continuously)
• 100 A (10 s)
• 20 A (10 s)
• 500 A (1 s)
• 100 A (1 s)
• 1250 A (10 ms)
• 250 A (10 ms)
- Burden
0.075 VA
0.02 VA
- Impedance
0.003 Ohm
0.02 Ohm
IN input (5 A)
Slot 8:
E = 3L (5/1A) + 4V + 2IN (5/1A+1/0.2A)
Rated ground fault overcurrent
5A
- Current measuring range
0.015–50 A
- Thermal withstand
• 20 A (continuously)
• 100 A (10 s)
• 500 A (1 s)
- Burden
0.075 VA
- Impedance
0.003 Ohm
IN input (1 A)
Slot 8:
E = 3L (5/1A) + 4V + 2IN (5/1A+1/0.2A)
Rated ground fault overcurrent
374
1 A (configurable for CT secondaries 0.1–10.0 A)
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Transformer protection relay
- Current measuring range
0.003–10 A
- Thermal withstand
• 4 A (continuously)
• 20 A (10 s)
• 100 A (1 s)
- Burden
0.02 VA
- Impedance
0.02 Ohm
IN input (0.2 A)
Slot 8:
E = 3L (5/1A) + 4V+ 2IN (5/1A+1/0.2A)
Rated ground fault overcurrent
0.2 A (configurable for CT secondaries 0.1 – 10.0 A)
- Current measuring range
0.0006–2 A
- Thermal withstand
• 0.8 A (continuously)
• 4 A (10 s)
• 20 A (1 s)
- Burden
0.02 VA
- Impedance
0.02 Ohm
Voltage inputs
Rated voltage VN
100 V (configurable for VT secondaries 50–250 V)
- Voltage measuring range
0.5–190 V
- Thermal withstand
250 V (continuously)
600 V (10 s)
- Burden
<0.015 VA (110 V), <0.06 VA (250 V)
Frequency
Rated frequency fN
45–65 Hz (protection operates accurately)
Measuring range
16–95 Hz
< 44Hz / > 66Hz (other protection is not steady except frequency protection)
Analog interface cross section and tightening torque
Table 158 - Analog interface cross-section and tightening torque
Terminal characteristics
Current inputs
Maximum wire
cross-section,
Voltage inputs
Screw clamp
Ring lug
4 (10-12)
(12–22)
2.5 (13-14)
mm2
(AWG)
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Terminal characteristics
Maximum wiring
1.2 (10.6)
0.79 (7)
0.5-0.6 (4.4-5.3)
screw tightening
torque Nm (Ib-in)
Maximum connector
-
0.3-0.4 (2.7-3.5)
retention tightening
torgue Nm (Ib-in)
Wire type
Single strand or
stranded with
insulated crimp
terminal
Ring lug width (mm)
-
8.0, M3.5
and screw size
10.6.8 External option modules
10.6.8.1 VSE-001 fiber-optic interface module
DANGER
HAZARD OF ELECTRIC SHOCK, EXPLOSION, OR ARC FLASH
•
•
•
This equipment must only be installed or serviced by qualified electrical
personnel.
Turn off all power supplying this device and the equipment in which it is
installed before working on the device or equipment.
Connect protective ground before turning on any power supplying this
device.
Failure to follow these instructions will result in death or serious injury.
An external fiber-optic module VSE-001 is used to connect the device to a fiberoptic loop or a fiber-optic star. There are four different types of serial fiber-optic
modules:
•
•
VSE001PP (Plastic-plastic)
VSE001GG (Glass-glass)
The modules provide a serial communication link up to 1 km (0.62 miles) with
VSE 001 GG. With a serial-fibre interface module, it is possible to have the
following serial protocols in use:
•
•
•
•
None
IEC-103
Modbus slave
SpaBus
The power for the module is taken from pin 9 of the D-connector or from an
external power supply interface.
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Transformer protection relay
Figure 224 - VSE-001 module
A
B
A. VSE-001
B. Communication bus
Module interface to the device
The physical interface of the VSE-001 is a 9-pin D-connector. The signal level is
RS-232.
NOTE: The product manual for VSE-001 can be found on our website.
10.6.8.2 VSE-002 RS-485 interface module
DANGER
HAZARD OF ELECTRIC SHOCK, EXPLOSION, OR ARC FLASH
•
•
•
This equipment must only be installed or serviced by qualified electrical
personnel.
Turn off all power supplying this device and the equipment in which it is
installed before working on the device or equipment.
Connect protective ground before turning on any power supplying this
device.
Failure to follow these instructions will result in death or serious injury.
An external RS-485 module VSE-002 (VSE002) is used to connect Easergy P3
protection devices to RS-485 bus. With the RS-485 serial interface module, the
following serial protocols can be used:
•
•
•
•
None
IEC-103
ModbusSlv
SpaBus
The power for the module is taken from pin 9 of the D-connector or from an
external power supply interface.
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Figure 225 - VSE-002 module
A
B
A. VSE-002
B. Communication bus
Module interface to the device
The physical interface of the VSE-002 is a 9-pin D-connector. The signal level is
RS-232 and therefore, the interface type for the module has to be selected as
RS-232.
It is possible to connect multible devices in daisychain. “Termination” has to be
selected as on for the last unit in the chain. The same applies when only one unit
is used.
Figure 226 - RS-232 and TTL interface
Termination
OFF
73 mm
ON
Interface type
TLL
RS-232
20 mm
Table 159 - RS-232 and TTL interface
Pin number
TTL mode
RS-232 mode
1
-
-
2
RXD (in)
RXD (in)
3
TXD (out)
TXD (out)
4
RTS (in)
RTS (in)
GND
GND
5
6
7
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Transformer protection relay
Pin number
TTL mode
RS-232 mode
+8V (in)
+8V (in)
8
9
10.6.8.3 VPA-3CG Profibus interface module
DANGER
HAZARD OF ELECTRIC SHOCK, EXPLOSION, OR ARC FLASH
•
•
•
This equipment must only be installed or serviced by qualified electrical
personnel.
Turn off all power supplying this device and the equipment in which it is
installed before working on the device or equipment.
Connect protective ground before turning on any power supplying this
device.
Failure to follow these instructions will result in death or serious injury.
Easergy P3T32 can be connected to Profibus DP by using an external Profibus
interface module VPA-3CG (VPA3CG). The device can then be monitored from
the host system. VPA-3CG is attached to the RS-232 D-connector at the back of
the device with a VX-072 (VX072) cable. With the Profibus interface module, the
following protocols can be used:
•
•
None
ProfibusDP
The power for the module is taken from an external power supply interface.
Figure 227 - VPA-3CG module
A
B
A. VPA-3CG
B. Communication bus
Module interface to the device
The physical interface of the VPA-3CG Profibus interface module is a 9-pin Dconnector.
Profibus devices are connected in a bus structure. Up to 32 stations (master or
slave) can be connected in one segment. The bus is terminated by an active bus
terminator at the beginning and end of each segments. When more than 32
stations are used, repeaters (line amplifiers) must be used to connect the
individual bus segments.
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The maximum cable length depends on the transmission speed and cable type.
The specified cable length can be increased by the use of repeaters. The use of
more than 3 repeaters in a series is not recommended.
A separate product manual for VPA-3CG can be found on our website.
10.6.8.4 VIO 12A RTD and analog input / output modules
VIO 12A I/O modules can be connected to Easergy P3T32 using VSE 001 or VSE
002 interface modules.
VIO 12A I/O modules can be connected to Easergy P3U20 and P3U30 using
RS-485 connection in interface modules. Alternatively VIO 12A I/O modules can
be connected to Easergy P3U20 and P3U30 using RS-232 connection. If RS-232
connection is used a separate VX082 or VX083 connection cable and VSE001 or
VSE002 option module are needed.
A separate product manual for VIO 12A is available.
10.6.9 Block diagrams
The status of the output contacts is shown when the relay is energized but none
of the protection, controlling or self-supervision elements are activated.
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Transformer protection relay
Figure 228 - Typical block diagram for P3M32, P3T32 and P3G32 relays
N -/~
1/C/1:1
L +/~
1/C/1:2
~
=
2/G/1:1
2/G/1:2
2/G/1:3
2/G/1:4
2/G/1:5
2/G/1:6
2/G/1:7
2/G/1:8
2/G/1:9
2/G/1:10
2/G/1:11
2/G/1:12
DI
DI7
DI7
DI8
DI8
DI9
DI9
DI10
DI10
DI11
DI11
DI12
DI12
DI13
DI13
DI14
DI14
DI15
DI15
DI16
DI16
3/I/1:1
3/I/1:2
3/I/1:3
3/I/1:4
3/I/1:5
3/I/1:6
3/I/1:7
3/I/1:8
3/I/1:9
3/I/1:10
3/I/1:11
3/I/1:12
3/I/1:13
3/I/1:14
3/I/1:15
3/I/1:16
3/I/1:17
3/I/1:18
3/I/1:19
3/I/1:20
DI
IA (S1)
IA (S2)
IB (S1)
IB (S2)
IC (S1)
IC (S2)
IN1 (S1)
IN1 (S2)
IN1 (S2)
IN2 (S1)
IN2 (S2)
IN2 (S2)
VLL/VLN
VLL/VLN
VLL/VLN
VLL/VLN
VN/VLL/VLN
VN/VLN/VLL
VN/VLN/VLL
VN/VLN/VLL
8/E/1:1
8/E/1:2
8/E/1:3
8/E/1:4
8/E/1:5
8/E/1:6
8/E/1:7
8/E/1:8
8/1/1:1
8/1/1:2
8/1/1:3
8/1/1:4
8/1/1:5
8/1/1:6
8/1/1:7
8/1/1:8
8/E/1:9
8/E/1:10
8/E/1:11
8/1/1:9
8/1/1:10
8/1/1:11
8/E/2:12
8/E/2:1
8/E/2:2
8/E/2:3
8/E/2:4
8/E/2:5
8/E/2:6
8/E/2:7
8/E/2:8
8/1/2:12
8/1/2:1
8/1/2:2
8/1/2:3
8/1/2:4
8/1/2:5
8/1/2:6
8/1/2:7
8/1/2:8
1
1
M
P3T32-CGITA-AAENA-BAAAB
G
DI1
DI1
DI2
DI2
DI3
DI3
DI4
DI4
DI5
DI5
DI6
DI6
1/C/1:20
1/C/1:19
1/C/1:18
1/C/1:17
1/C/1:16
1/C/1:15
T12
T12
T11
T11
T10
T10
1/C/1:14
1/C/1:13
1/C/1:12
1/C/1:11
1/C/1:10
1/C/1:9
1/C/1:8
T9
T9
T1
T1
A1 NO
A1 NC
A1 COM
1/C/1:7
1/C/1:6
1/C/1:5
SF NC
SF NO
SF COM
2/G/1:13
2/G/1:14
2/G/1:15
2/G/1:16
2/G/1:17
2/G/1:18
2/G/1:19
2/G/1:20
T13
T13
T14
T14
T15
T15
T16
T16
IA 5A
IB 5A
IC 5A
IN
5A
IN
1A
IN
1A
IN
0.2A
VA
VB
VC
VD
IꞌA (S1)
IꞌA (S2)
IꞌA (S2)
4/T/1:1
4/T/1:2
4/T/1:3
4/1/1:1
4/1/1:2
4/1/1:3
5A
1A
IꞌB (S1)
IꞌB (S2)
IꞌB (S2)
4/T/1:4
4/T/1:5
4/T/1:6
4/1/1:4
4/1/1:5
4/1/1:6
5A
1A
IꞌC (S1)
IꞌC (S2)
IꞌC (S2)
4/T/1:7
4/T/1:8
4/T/1:9
4/1/1:7
4/1/1:8
4/1/1:9
5A
1A
IN (S1)
IN (S2)
IN (S2)
4/T/1:10
4/T/1:11
4/T/1:12
4/1/1:10
4/1/1:11
4/1/1:12
5A
1A
9/N/1
Eth1
9/N/2
Eth2
DANGER
HAZARD OF ELECTRIC SHOCK, EXPLOSION, OR ARC FLASH
Connect the device's protective ground to functional ground according to the
connection diagrams presented in this document.
Failure to follow this instruction will result in death or serious injury.
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10.6.10 Connection examples
Figure 229 - Connection example of P3T32 applied to a power transformer
B
A
C
1
2
3
4
5
6
CTA
+
CTB
CTC
Slot 8/2
1
2
5A
3
4
5A
5
6
5A
Slot 8/1
52-1
P3T32
11 5A
10
Slot 4/1
52-2
CTa
CTb
CTc
+
1
2
5A
4
5
5A
7
8
5A
7
5A
Slot 4/1
Slot 8/1
9
1) Power direction
DANGER
HAZARD OF ELECTRIC SHOCK, EXPLOSION, OR ARC FLASH
•
•
Always connect the polarity of the current transformer (CT) and the
voltage transformer (VT) and their secondary ground wiring according to
the connection diagrams presented in this document.
Connect the device's protective ground to functional ground according to
the connection diagrams presented in this document.
Failure to follow this instruction will result in death or serious injury.
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10.7 Arc flash detection system setup and testing
10.7.1 Setting up the arc flash system
DANGER
HAZARD OF ELECTRIC SHOCK, EXPLOSION, OR ARC FLASH
•
•
•
•
•
•
•
•
•
•
•
•
•
Apply appropriate personal protective equipment (PPE) and follow safe
electrical work practices. See NFPA 70E, NOM-029-STPS-2011, or CSA
Z462.
The arc fault detection system is not a substitute for proper PPE when
working on or near equipment being monitored by the system.
Information on this product is offered as a tool for conducting arc flash
hazard analysis. It is intended for use only by qualified persons who are
knowledgeable about power system studies, power distribution equipment,
and equipment installation practices. It is not intended as a substitute for
the engineering judgement and adequate review necessary for such
activities.
Only qualified personnel should install and service this equipment. Read
this entire set of instructions and check the technical characteristics of the
device before performing such work.
Perform wiring according to national standards (NEC) and any
requirements specified by the customer.
Observe any separately marked notes and warnings.
NEVER work alone.
Before performing visual inspections, tests, or maintenance on this
equipment, disconnect all sources of electric power. Assume all circuits are
live until they are completely de-energized, tested, and tagged. Pay
particular attention to the design of the power system. Consider all sources
of power, including the possibility of backfeeding.
Always use a properly rated voltage sensing relay to ensure that all power
is off.
The equipment must be grounded.
Connect the device's protective ground to functional earth according to the
connection diagrams presented in this document.
Do not open the device. It contains no user-serviceable parts.
Install all devices, doors and covers before turning on the power to this
device.
Failure to follow these instructions will result in death or serious injury.
Before setting up the arc flash system:
• Mount and connect all components and sensors.
• Make sure that you understand the customer application.
1. Identify the wiring connection of sensors to the device’s connectors.
2. Identify the wiring connection to breaking devices.
3. Identify binary I/O wiring connections.
4. Proceed with configuration in Easergy Pro with consideration of the customer
application.
5. Power up the device.
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6. Reset the device by pushing the reset button.
7. Verify LED indication as described with consideration of the customer
application.
8. If connecting two devices through MT in and MT out:
DANGER
HAZARD OF LOSS OF SIGNAL
The MT in and MT out connections are not monitored. You must to
determine if external monitoring is required to detect broken or
disconnected wires.
Failure to follow these instructions will result in death or serious
injury.
a. Verify the MT in MT out connections.
b. Set the related dip switch configuration.
c. Verify the LED indications.
10.7.2 Commissioning and testing
This section contains the commissioning testing instructions. The figure below
shows the testing sequence.
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Figure 230 - Testing sequence
Arc system commissioning
Verifying the installation against
drawings and customer specifications
Checking zones
Testing arc flash sensors
Testing alarm contacts
Cross-checking between zones
Testing the circuit breaker failure
protection
Trip circuits
Filling in test results
Restoring the current measuring and
trip circuits
Gathering of test equipment
Finalizing the test report
End
10.7.2.1 Checking zones
1. Check the protected zones where sensors have been installed and compare
them against the drawings.
2. Consult the customer if the configuration does not match with the drawings.
10.7.2.2 Disconnecting trip circuits
DANGER
HAZARD OF ELECTRIC SHOCK, EXPLOSION, OR ARC FLASH
Removing trip wires may cause loss of protection. Review system drawings
and diagrams before disconnecting trip circuits.
Failure to follow this instruction will result in death or serious injury.
•
P3T/en M/J006
Disconnect the trip signals to the circuit breakers that may disturb other parts
of the system during the test.
385
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•
•
Also disconnect trip signals routed to other parts of the system, such as the
breaker failure (ANSI 50BF) backup trip to upstream breakers and the transfer
trip signals.
Test the disconnected trip signals with a multimeter.
10.7.2.3 Sensor testingTesting
DANGER
HAZARD OF ELECTRIC SHOCK, EXPLOSION, OR ARC FLASH
•
•
•
•
•
•
•
•
•
•
•
•
•
Apply appropriate personal protective equipment (PPE) and follow safe
electrical work practices. See NFPA 70E, NOM-029-STPS-2011, or CSA
Z462.
The arc fault detection system is not a substitute for proper PPE when
working on or near equipment being monitored by the system.
Information on this product is offered as a tool for conducting arc flash
hazard analysis. It is intended for use only by qualified persons who are
knowledgeable about power system studies, power distribution equipment,
and equipment installation practices. It is not intended as a substitute for
the engineering judgement and adequate review necessary for such
activities.
Only qualified personnel should install and service this equipment. Read
this entire set of instructions and check the technical characteristics of the
device before performing such work.
Perform wiring according to national standards (NEC) and any
requirements specified by the customer.
Observe any separately marked notes and warnings.
NEVER work alone.
Before performing visual inspections, tests, or maintenance on this
equipment, disconnect all sources of electric power. Assume all circuits are
live until they are completely de-energized, tested, and tagged. Pay
particular attention to the design of the power system. Consider all sources
of power, including the possibility of backfeeding.
Always use a properly rated voltage sensing relay to ensure that all power
is off.
The equipment must be grounded.
Connect the device's protective ground to functional earth according to the
connection diagrams presented in this document.
Do not open the device. It contains no user-serviceable parts.
Install all devices, doors and covers before turning on the power to this
device.
Failure to follow these instructions will result in death or serious injury.
Testing the arc flash sensors with the light-only criteria operates the trip outputs of
the device or the I/O units for the protected zone.
Testing the arc flash sensors with the light and current criteria, without an injected
current, only generates an indication on the unit that protects the zone. The
indication of the arc fault is registered by the possible main unit and I/O unit.
NOTE: Testing the arc flash sensors using a light source can trip the
neighboring zones.
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NOTE: For more information on viewing and resetting indications, see the
corresponding sensor user manual or se.com.
NOTE: Because of their placement, some sensors cannot be tested without
dismantling parts of the system. After completing the testing, reassemble the
parts and validate the compliance with original mounting. Consult the
equipment manufacturer before dismantling any parts.
10.7.2.3.1 Testing the sensors
Test the sensors with the main device. See VAMP 125 Arc Flash Protection
Device User Manual.
Reset the main device before the test.
NOTE: Because of their placement, some sensors cannot be tested without
dismantling parts of the system. After completing the testing, reassemble the
parts and validate the compliance with original mounting. Consult the
equipment manufacturer before dismantling any parts.
Figure 231 - Testing point sensors
1. Point light to each arc flash sensor, one at a time, with a powerful light source
such as camera flash unit or flashlight.
2. Check the light sensor indication from the device.
3. Check the light sensor address from the device.
4. Compare the light sensor address information from the device with the sensor
location map.
5. Fill in the test result in the test report.
See VAMP Arc Flash Protection Testing Manual.
6. Reset the device.
7. Repeat the procedure with the next sensor.
10.7.2.3.2 Testing the sensor supervision
Test the sensors with the main device.
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Figure 232 - Testing the sensor’s self-supervision
t/int
L>ex tch
La
L+I/L
Zone
Addr.
O 1 2 3 4 5 6 7 8
N
TRIP
ACT
TRIP
TS
PU
OR IN
SENS
4
3
2
1
T3
9 10
7 8
5 6
3 4
1 2
R3
T2
R2
T1
R1
11
X1
1. Disconnect one wire from one point sensor, one for each unit, to see that the
self-supervision system recognizes the fault in the sensor.
2. Wait until the arc fault indication appears.
Depending on the device, this can take several minutes. See HMI functions
and indications in the device user manual.
3. Check that the service status output operates.
4. Fill in the test results in the test report.
See the test report template in VAMP Arc Flash Protection Testing Manual.
5. Reconnect the wire and reset the system.
6. Repeat the procedure with the other units.
10.7.2.3.3 Testing the binary I/O connectivity
BI/O signals such as light and overcurrent information are transmitted between
devices through dedicated inputs/output.
1. Activate the signal outputs in the binary I/O by generating arc fault light signal,
overcurrent pickup or both.
2. Check the configuration modes used for the customer application.
3. Fill in the test result in the test report.
4. Reset the main unit.
5. Repeat the procedure with all connected I/O’s.
10.7.3 Test report
10.7.3.1 Filling in the test report
1. Download the test report template from the Schneider Electric website.
2. Fill in all the required information about the system, the tested arc flash units
and the test results.
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10.7.3.2 Test report example
Figure 233 - Test report example
Easergy P3x3x Arc stage commissioning and testing report
Customer
Information
Unit
Scaling
Customer name
Substation
Customer address
Bay
Device name:
Device location:
Serial number:
Order code:
Program version:
IP Address:
NetMask:
MAC address:
Gateway:
NTP Server:
CT primary current input:
A Pick-up setting:
CT secondary current input:
A Pick-up value:
CT residual current primary input:
A Pick-up setting:
CT residual current secondary input:
Sensor
Arc sensors
Arc stages
CBFP
A
Tested
Remarks
Tested
Remarks
Delay setting / ms
Tested
Remarks
Tested
CBFP
Remarks
1
OK
NA
2
OK
NA
3
OK
NA
4
OK
NA
5
OK
NA
6
OK
NA
Activation criteria
1
Light
I>int
Io1>int
2
Light
I>int
Io1>int
3
Light
I>int
Io1>int
4
Light
I>int
Io1>int
5
Light
I>int
Io1>int
6
Light
I>int
Io1>int
7
Light
I>int
Io1>int
8
Light
I>int
Io1>int
Stage number
A
xln
A Pick-up value:
Arc sensor status
Stage number
xln
1
2
3
4
5
6
7
8
Trip relays
Led indications
Trip relay
T1
OK
NA
T2
OK
NA
T3
OK
NA
T4
OK
NA
T9
OK
NA
T10
OK
NA
T11
OK
NA
T12
OK
NA
HS01
OK
NA
HS02
OK
Led name
NA
Tested
Led name
Tested
A
Yes
NA
B
Yes
NA
C
Yes
NA
D
Yes
NA
E
Yes
NA
F
Yes
NA
G
Yes
NA
H
Yes
NA
I
Yes
NA
J
Yes
NA
K
Yes
NA
L
Yes
NA
M
Yes
NA
N
Yes
NA
Testing device
Device
Signatures
Commissioner(s)
Calibration date
Supervisor
Date
P3T/en M/J006
389
Transformer protection relay
10 Installation
10.7.4 Troubleshooting
This table describes some common problems in the arc flash system and how
they can be solved.
Table 160 - Troubleshooting
Problem
Possible cause
Solution
The trip signal does not
Faulty trip circuit wiring
Check that the wiring of the
trip circuit is not faulty.
reach the circuit breaker.
The protection does not trip
The protection needs both
Check the dip switch
even when a sufficient light
light and current information
configuration. The protection
signal is provided.
to trip.
may be configured to
require both the light and
current condition to trip.
Faulty sensor wiring
Loose sensor wire
Check the sensor wiring.
detected by the self-
The sensor wire may have
supervision
loosened in the terminal
blocks.
Error message indicating
Light pulse to the arc flash
Check that the light pulse to
blocked sensor channel
sensor is too long.
the arc flash sensor is not
too long.
If light is supplied to the arc
flash sensor for more than
three seconds, the selfsupervision function
activates and switches the
light sensor channel to
daylight blocking mode, and
the sensor channel is
blocked. The sensor
channel indication activates
an error message indication
on the LED.
Remove the light source to
reset the blocked channel.
10.8 Voltage system configuration
Depending on the application and available voltage transformers, the relay can be
connected either to zero-sequence voltage, line-to-line voltage or line-to-neutral
voltage. The configuration parameter "Voltage measurement mode" must be set
according to the type of connection used.
Voltage measuring modes correlation for E and F analog measurement
cards
V1, V2, V3 and V4 are voltage channels for the relay.
390
P3T/en M/J006
10 Installation
Transformer protection relay
The physical voltage transformer connection in the Easergy P3T32 depends on
the used voltage transformer connection mode. This setting is defined in the
Scaling setting view. See Table 161.
Figure 234 - Example of terminal 8/E/1 and 8/E/2
Table 161 - Correlation between voltage measuring mode and physical voltage
input in Terminals 8/E/1 and 8/F/2
Terminal
Voltage channel
1
2
V1
3
4
V2
5
6
V3
7
8
V4
Mode / Used voltage
3LN
Not in use
3LN+VN
3LN+LLy
VN
VA
VB
VC
LLy
3LN+LNy
LNy
2LL+VN
Not in use
2LL+VN+LLy
2LL+VN+LNy
VAB
LL+LLy+VN+LLz
LN+LNy+VN+LNz
VA
VBC
LLy
VN
LNy
VABy
VABz
VAy
VAz
10.8.1 Multiple channel voltage measurement
Slot 8 can accommodate four different analog measurement cards. Each of them
have four voltage measurement channels.
P3T/en M/J006
391
Transformer protection relay
10 Installation
This section introduces various voltage connections and the required voltage
measuring modes for the connections. The settings are defined in the Scalings
view.
3LN
•
Voltages measured by VTs: VA, VB, VC
•
Values calculated:VAB, VBC, VCA, V1, V2, V2/V1, f, VN
•
•
Measurements available: All
Protection functions not available: ANSI 25
P3x3x 3LN
Figure 235 - 3LN
VA
VB
VC
8/E/2 : 1...8
8/F/2 : 1...8
1
2
3
4
5
6
7
8
V1
V2
V3
V4
DANGER
HAZARD OF ELECTRIC SHOCK, EXPLOSION, OR ARC FLASH
•
•
Always connect the polarity of the current transformer (CT) and the
voltage transformer (VT) and their secondary ground wiring according to
the connection diagrams presented in this document.
Connect the device's protective ground to functional ground according to
the connection diagrams presented in this document.
Failure to follow this instruction will result in death or serious injury.
3LN+VN
This connection is typically used for feeder and motor protection schemes.
392
•
Voltages measured by VTs: VA, VB, VC, VN
•
Values calculated: VAB, VBC, VCA, V1, V2, V2/V1, f
•
•
Measurements available: All
Protection functions not available: ANSI 25
P3T/en M/J006
10 Installation
Transformer protection relay
P3x3x 3LN + Vo
Figure 236 - 3LN+VN
VA
VB
VC
8/E/2 : 1...8
8/F/2 : 1...8
1
2
3
4
5
6
7
8
V1
V2
V3
V4
DANGER
HAZARD OF ELECTRIC SHOCK, EXPLOSION, OR ARC FLASH
•
•
Always connect the polarity of the current transformer (CT) and the
voltage transformer (VT) and their secondary ground wiring according to
the connection diagrams presented in this document.
Connect the device's protective ground to functional ground according to
the connection diagrams presented in this document.
Failure to follow this instruction will result in death or serious injury.
3LN+LLy
Connection of voltage transformers for synchrocheck application. The other side
of the CB has line-to-line connection for reference voltage.
P3T/en M/J006
•
Voltages measured by VTs: VA, VB, VC, VABy
•
Values calculated: VAB, VBC, VCA, V1, V2, V2/V1, f, VN
•
•
Measurements available: All
Protection functions not available: -
393
Transformer protection relay
10 Installation
P3x3x 3LN + LLy
Figure 237 - 3LN+LLy
VA
VB
VC
8/E/2 : 1...8
8/F/2 : 1...8
1
2
3
4
5
6
7
8
V1
V2
V3
V4
DANGER
HAZARD OF ELECTRIC SHOCK, EXPLOSION, OR ARC FLASH
•
•
Always connect the polarity of the current transformer (CT) and the
voltage transformer (VT) and their secondary ground wiring according to
the connection diagrams presented in this document.
Connect the device's protective ground to functional ground according to
the connection diagrams presented in this document.
Failure to follow this instruction will result in death or serious injury.
3LN+LNy
This connection is typically used for feeder protection scheme where line-toneutral voltage is required for synchrocheck application.
394
•
Voltages measured by VTs: VA, VB, VC, VAy
•
Values calculated: VAB, VBC, VCA, V1, V2, V2/V1, f, VN
•
•
Measurements available: All
Protection functions not available: ANSI 25
P3T/en M/J006
10 Installation
Transformer protection relay
P3x3x 3LN + LNy
Figure 238 - 3LN+LNy
VA
VB
VC
8/E/2 : 1...8
8/F/2 : 1...8
1
2
3
4
5
6
7
8
V1
V2
V3
V4
DANGER
HAZARD OF ELECTRIC SHOCK, EXPLOSION, OR ARC FLASH
•
•
Always connect the polarity of the current transformer (CT) and the
voltage transformer (VT) and their secondary ground wiring according to
the connection diagrams presented in this document.
Connect the device's protective ground to functional ground according to
the connection diagrams presented in this document.
Failure to follow this instruction will result in death or serious injury.
2LL+VN
Connection of two line-to-line and neutral displacement voltage measurement
schemes.
P3T/en M/J006
•
Voltages measured by VTs: VAB, VBC, VN
•
Values calculated: VCA, VA, VB, VC, V1, V2, V2/V1, f
•
•
Measurements available: All
Protection functions not available: ANSI 25
395
Transformer protection relay
10 Installation
P3x3x 2LL + Vo
Figure 239 - 2LL+VN
VA
VB
VC
8/E/2 : 1...8
8/F/2 : 1...8
1
2
3
4
5
6
7
8
V1
V2
V3
V4
DANGER
HAZARD OF ELECTRIC SHOCK, EXPLOSION, OR ARC FLASH
•
•
Always connect the polarity of the current transformer (CT) and the
voltage transformer (VT) and their secondary ground wiring according to
the connection diagrams presented in this document.
Connect the device's protective ground to functional ground according to
the connection diagrams presented in this document.
Failure to follow this instruction will result in death or serious injury.
2LL+VN+LLy
Connection of two line-to-line and neutral displacement voltage schemes. Line-toline reference voltage is taken from the other side of the CB for synchrocheck
scheme.
396
•
Voltages measured by VTs: VAB, VBC, VN, VABy
•
Values calculated: VCA, VA, VB, VC, V1, V2, V2/V1, f
•
•
Measurements available: All
Protection functions not available: -
P3T/en M/J006
10 Installation
Transformer protection relay
P3x3x 2LL + Vo + LLy
Figure 240 - 2LL+VN+LLy
VA
VB
VC
8/E/2 : 1...8
8/F/2 : 1...8
1
2
3
4
5
6
7
8
V1
V2
V3
V4
DANGER
HAZARD OF ELECTRIC SHOCK, EXPLOSION, OR ARC FLASH
•
•
Always connect the polarity of the current transformer (CT) and the
voltage transformer (VT) and their secondary ground wiring according to
the connection diagrams presented in this document.
Connect the device's protective ground to functional ground according to
the connection diagrams presented in this document.
Failure to follow this instruction will result in death or serious injury.
2LL+VN+LNy
Connection of two line-to-line and neutral displacement voltage schemes. The
other side of the CB has phase-to-neutral connection for synchrocheck.
P3T/en M/J006
•
Voltages measured by VTs: VAB, VBC, VN, VAy
•
Values calculated: VCA, VA, VB, VC, V1, V2, V2/V1, f
•
•
Measurements available: All
Protection functions not available: -
397
Transformer protection relay
10 Installation
P3x3x 2LL + Vo + LNy
Figure 241 - 2LL+VN+LNy
VA
VB
VC
8/E/2 : 1...8
8/F/2 : 1...8
1
2
3
4
5
6
7
8
V1
V2
V3
V4
DANGER
HAZARD OF ELECTRIC SHOCK, EXPLOSION, OR ARC FLASH
•
•
Always connect the polarity of the current transformer (CT) and the
voltage transformer (VT) and their secondary ground wiring according to
the connection diagrams presented in this document.
Connect the device's protective ground to functional ground according to
the connection diagrams presented in this document.
Failure to follow this instruction will result in death or serious injury.
LL+VN+LLy+LLz
This scheme has two CBs to be synchronized. The left side of the bus bar has
line-to-line and the right side line-to-line connection for synchrocheck's reference
voltages. In the middle, the system voltages are measured by phase-to-neutral
and open delta connection.
398
•
Voltages measured by VTs: VAB, VN, VABy, VABz
•
Values calculated: VA, VB, VC, f
•
•
Measurements available: Protection functions not available: ANSI 67
P3T/en M/J006
10 Installation
Transformer protection relay
P3x3x LL + Vo + LLy + LLz
Figure 242 - LL+VN+LLy+LLz
VA
VB
VC
8/C/1 : 11...12
8/D/1 : 11...12
8/E/2 : 1...8
8/F/2 : 1...8
1
2
3
4
5
6
7
8
V1
V2
V3
V4
DANGER
HAZARD OF ELECTRIC SHOCK, EXPLOSION, OR ARC FLASH
•
•
Always connect the polarity of the current transformer (CT) and the
voltage transformer (VT) and their secondary ground wiring according to
the connection diagrams presented in this document.
Connect the device's protective ground to functional ground according to
the connection diagrams presented in this document.
Failure to follow this instruction will result in death or serious injury.
LN+VN+LNy+LNz
This scheme has two CBs to be synchronized. The left and right sides of the bus
bar have line-to-neutral connections for synchrocheck's reference voltages. In the
middle, system voltages are measured by phase-to-neutral and broken delta
connection.
P3T/en M/J006
•
Voltages measured by VTs: VL, VN, VLy, VLz
•
Values calculated: VAB, VBC, VCA, f
•
•
Measurements available: Protection functions not available: ANSI 67
399
Transformer protection relay
10 Installation
P3x3x LN + Vo + LNy + LNz
Figure 243 - LN+VN+LNy+LNz
VA
VB
VC
8/E/2 : 1...8
8/F/2 : 1...8
1
2
3
4
5
6
7
8
V1
V2
V3
V4
DANGER
HAZARD OF ELECTRIC SHOCK, EXPLOSION, OR ARC FLASH
•
•
Always connect the polarity of the current transformer (CT) and the
voltage transformer (VT) and their secondary ground wiring according to
the connection diagrams presented in this document.
Connect the device's protective ground to functional ground according to
the connection diagrams presented in this document.
Failure to follow this instruction will result in death or serious injury.
10.9 CSH120 and CSH200 Core balance CTs
Function
The specifically designed CSH120 and CSH200 core balance CTs are for direct
ground fault overcurrent measurement. The difference between CSH120 and
CSH200 is the inner diameter.
Because of their low-voltage insulation, they can only be used on cables.
400
P3T/en M/J006
10 Installation
Transformer protection relay
Figure 244 - CSH120 and CSH200 core balance CTs
Characteristics
CSH120
CSH200
Inner diameter
120 mm (4.7 in)
200 mm (7.9 in)
Weight
0.6 kg (1.32 lb)
1.4 kg (3.09 lb)
Accuracy
±5% at 20°C (68°F)
±6% max. from -25°C to 70°C
(-13°F to +158°F)
Transformation ratio
1/470
Maximum permissible
20 kA - 1 s
current
Operating temperature
-25°C to +70°C (-13°F to +158°F)
Storage temperature
-40°C to +85°C (-40°F to +185°F)
Dimensions
Figure 245 - Dimensions
A
B
C
H
G
I
K
F
E
A. 4 horizontal mounting holes Ø 6
P3T/en M/J006
J
D
B. 4 vertical mounting holes Ø 6
401
Transformer protection relay
10 Installation
Dime C.
nsion
s
D.
E.
F.
G.
H.
I.
J.
K.
CSH12 120
164
44
190
80
40
166
65
35
(6.46)
(1.73)
(7.48)
(3.14)
(1.57)
(6.54)
(2.56)
(1.38)
256
46
274
120
60
254
104
37
(10.1)
(1.81)
(10.8)
(4.72)
(2.36)
(10)
(4.09)
(1.46)
0
(4.75)
(in)
CSH20 196
0
(7.72)
(in)
DANGER
HAZARD OF ELECTRIC SHOCK, ELECTRIC ARC OR BURNS
•
•
•
•
•
•
•
Only qualified personnel should install this equipment. Such work should
be performed only after reading this entire set of instructions and checking
the technical characteristics of the device.
NEVER work alone.
Turn off all power supplying this equipment before working on or inside it.
Consider all sources of power, including the possibility of backfeeding.
Always use a properly rated voltage sensing device to confirm that all
power is off.
Only CSH120 and CSH200 core balance CTs can be used for direct
ground fault overcurrent measurement.
Install the core balance CTs on insulated cables.
Cables with a rated voltage of more than 1000 V must also have an
grounded shielding.
Failure to follow these instructions will result in death or serious injury.
Assembly
Group the MV cable (or cables) in the middle of the core balance CT.
Use non-conductive binding to hold the cables.
Remember to insert the three medium-voltage cable shielding groundng cables
through the core balance CT.
402
P3T/en M/J006
10 Installation
Transformer protection relay
Figure 246 - Assembly on MV cables
CAUTION
HAZARD OF NON-OPERATION
Connect the secondary circuit and the cable shielding of the CSH core
balance CTs to ground in the shortest possible manner according to the
connection diagram presented in this document.
Failure to follow these instructions can result in equipment damage.
Connection
Connection to Easergy P3T32
To ground fault current IN input, on connector X1, terminals 9 and 10 (shielding).
Recommended cable
•
•
•
•
•
•
Sheathed cable, shielded by tinned copper braid
Minimum cable cross-section 0.93 mm² (AWG 18)
Resistance per unit length < 100 mΩ/m (30.5 mΩ/ft)
Minimum dielectric strength: 1000 V (700 Vrms)
Connect the cable shielding in the shortest manner possible to Easergy
P3T32
Flatten the connection cable against the metal frames of the cubicle.
The connection cable shielding is grounded in Easergy P3T32.
The maximum resistance of the Easergy P3T32 connection wiring must not
exceed 4 Ω (i.e. 20 m maximum for 100 mΩ/m or 66 ft maximum for 30.5 mΩ/ft).
Connecting two CSH120 or CSH200 CTs in parallel
Two CSH200 CTs can be connected in parallel if the cables do not fit through a
single CT.
P3T/en M/J006
403
Transformer protection relay
10 Installation
Fit one CT per a set of cables.
Ensure the wiring polarity is correct. The maximum permissible current at the
primary is limited to 6 kA - 1 s for all cables.
DE80231
•
•
404
P3T/en M/J006
11 Test and environmental conditions
Transformer protection relay
11 Test and environmental conditions
11.1 Disturbance tests
Table 162 - Disturbance tests
Test
Standard & Test class /
level
Test value
Emission
IEC/EN 60255-26 (ed3)
Conducted
Class A / CISPR 22
0.15–30 MHz
Emitted
Class A / CISPR 11 / IACS
150 k Hz – 6 GHz
E10
Immunity
IEC/EN 60255-26 (ed3)
Slow damped oscillatory
IEC/EN 61000-4-18
±2.5kVp CM
IEEE C37.90.1
±2.5kVp DM
IEC/EN 61000-4-18
±2.5kVp CM
IEC/EN 61000-4-2 Level 4
±8 kV contact
wave
1 MHz
Fast damped oscillatory
wave
3 MHz, 10 MHz and 30 MHz
Static discharge (ESD)
±15 kV air
Emitted HF field
Fast transients (EFT)
IEC/EN 61000-4-3 Level 3
80 MHz – 6 GHz, 10 V/m
IEEE C37.90.2 / IACS E10
80–1000 MHz, 20 V/m
IEC/EN 61000-4-4 Level 4
±4 kV, 5/50 ns, 5 kHz
IEEE C37.90.1
Surge
IEC/EN 61000-4-5 Level 4
±4 kV, 1.2/50 μs, CM
±2 kV, 1.2/50 μs, DM
Conducted HF field
IEC/EN 61000-4-6 Level 3
0.15–80 MHz, 10 Vrms
Power-frequency magnetic
IEC/EN 61000-4-8
300 A/m (continuous)
field
Pulse magnetic field
P3T/en M/J006
1000 A/m 1–3 s
IEC/EN 61000-4-9 Level 5
1000 A/m, 1.2/50 μs
405
Transformer protection relay
11 Test and environmental conditions
Test
Standard & Test class /
level
Test value
ac and dc voltage dips
IEC/EN 61000-4-29,
0% of rated voltage - Criteria
IEC/EN 61000-4-11
A
• ac: ≥ 0.5 cycle
• dc: ≥ 10 ms
40% of rated voltage Criteria C
• ac: 10 cycles
• dc: 200 ms
70% of rated voltage Criteria C
• ac: 25 cycles
• dc: 500 ms
ac and dc voltage
IEC/EN 61000-4-29,
100% interruption - Criteria
interruptions
IEC/EN 61000-4-11
C
• ac: 250 cycles
• dc: 5 s
Voltage alternative
IEC/EN 61000-4-17
component
15% of operating voltage
(dc) / 10 min
11.2 Electrical safety tests
Table 163 - Electrical safety tests
Test
Standard & Test class /
level
Test value
Impulse voltage withstand
IEC/EN 60255-27, Class III
5 kV, 1.2/50 μs, 0.5 J
1 kV, 1.2/50 μs, 0.5 J
Communication
Dielectric test
IEC/EN 60255-27, Class III
2 kV, 50 Hz
0.5 kV, 50 Hz
Communication
Insulation resistance
IEC/EN 60255-27
> 100 MΩ at 500 Vdc using
only electronic/brushless
insulation tester
Protective bonding
IEC/EN 60255-27
shall not exceed 0,1 Ω
resistance
Clearance and creepage
Design criteria for distances
distance
as per IEC 60255-27 Annex
C (pollution degree 2,
overvoltage category 3)
406
P3T/en M/J006
11 Test and environmental conditions
Transformer protection relay
Test
Standard & Test class /
level
Burden
IEC 60255-1
Contact performance
IEC 60255-1
Test value
11.3 Mechanical tests
Table 164 - Mechanical tests
Test
Standard & Test class /
level
Test value
IEC 60255-21-1, Class II /
1 Gn, 10 Hz – 150 Hz
Device in operation
Vibrations
IEC 60068-2-6, Fc
Shocks
IEC 60255-21-2, Class II /
10 Gn / 11 ms
IEC 60068-2-27, Ea
Seismic
IEC 60255-21-3 Method A,
2 G horizontal / 1 G vertical ,
Class II
1–35 Hz
IEC 60255-21-1, Class II /
2 Gn, 10 Hz – 150 Hz
Device de-energized
Vibrations
IEC 60068-2-6, Fc
Shocks
IEC 60255-21-2, Class II /
30 Gn / 11 ms
IEC 60068-2-27, Ea
Bump
IEC 60255-21-2, Class II /
20 Gn / 16 ms
IEC 60068-2-27, Ea
11.4 Environmental tests
Table 165 - Environmental tests
Test
Standard & Test class /
level
Test value
Dry heat
EN / IEC 60068-2-2, Bd
70°C (158°F)
Temperature test
UL 50893)
55°C (131°F)
Cold
EN / IEC 60068-2-1, Ad
-40°C (-40°F)
Damp heat, cyclic
EN / IEC 60068-2-30, Db
From 25°C (77°F) to 55°C
Device in operation
(131°F)
From 93% RH to 98% RH
Testing duration: 6 days
P3T/en M/J006
407
Transformer protection relay
11 Test and environmental conditions
Test
Standard & Test class /
level
Test value
Damp heat, static
EN / IEC 60068-2-78, Cab
40°C (104°F)
93% RH
Testing duration: 10 days
Change of temperature
IEC / EN 60068-2-14, Nb
Lower temp -40°C
Upper temp 70°C
5 cycles
Flowing mixed gas corrosion IEC 60068-2-60, Ke
test, method 1
25° C (77° F), 75 % RH
21 days 100 ppb H2S, 500
ppb SO2
Flowing mixed gas corrosion IEC 60068-2-60, Ke
test, method 4
25° C (77° F), 75 % RH
21 days 10 ppb H2S, 200
ppb NO2, 10 ppb CL2, 200
ppb SO2
Device in storage
Dry heat
EN / IEC 60068-2-2, Bb
70°C (158°F)
Cold
EN / IEC 60068-2-1, Ab
-40°C (-40°F)
93) Test
condition: Device operated continuously. All digital inputs and digital outputs activated with 5 s
on, 30 s off duty cycle, carrying maximum rated loads.
11.5 Environmental conditions
Table 166 - Environmental conditions
Condition
Value
Ambient temperature, in-
-40 – 60°C (-40 –140°F)97)
service94) 95) 96)
Ambient temperature, storage
-40 – 70°C (-40 –158°F)
Relative air humidity
< 95%, no condensation allowed
Maximum operating altitude
2000 m (6561.68 ft)
94) The
display contrast is affected by ambient temperatures below -25°C (-13°F).
a cold start, in temperatures below -30°C (-22°F), allow the relay to stabilize for a few
minutes to achieve the specified accuracy.
96) 55°C Max ambient temperature according to UL 508
97) Recommended values with VYX 695 projection mounting frame:
• device with 1 x raising frame → maximum ambient temperature 55°C
• device with 2 x raising frame → maximum ambient temperature 50°C
95) After
408
P3T/en M/J006
11 Test and environmental conditions
Transformer protection relay
11.6 Casing
Table 167 - Casing
Parameter
Value
Degree of protection (IEC 60529)
IP54 Front panel, IP20 rear side, IP10 rear
side (if analog measurement card with ring
lug connectors is used)98)
Dimensions (W x H x D)
270 x 176 x 230 mm / 10.63 x 6.93 x 9.06
in
Weight
4.2 kg (9.272 lb) or higher (depends of
options)
98) UL508
P3T/en M/J006
Environment – flat surface mounting in a type 1 enclosure or equivalent
409
Transformer protection relay
12 Maintenance
12 Maintenance
DANGER
HAZARD OF ELECTRIC SHOCK, EXPLOSION, OR ARC FLASH
•
•
•
•
•
•
•
•
Wear your personal protective equipment (PPE) and comply with the safe
electrical work practices. For clothing, see applicable local standards.
Only qualified personnel should install this equipment. Such work should
be performed only after reading this entire set of instructions and checking
the technical characteristics of the device.
NEVER work alone.
Turn off all power supplying this equipment before working on or inside it.
Consider all sources of power, including the possibility of backfeeding.
Always use a properly rated voltage sensing device to ensure that all
power is off.
Do not open the secondary circuit of a live current transformer.
Always connect the polarity of the current transformer (CT) and the voltage
transformer (VT) and their secondary ground wiring according to the
connection diagrams presented in this document.
Connect the device's protective ground to functional ground according to
the connection diagrams presented in this document.
Failure to follow this instruction will result in death or serious injury.
The Easergy P3 protection relays and arc flash detection products together with
their extension units, communication accessories, arc flash detection sensors and
cabling, later called “device”, require maintenance in work according to their
specification. Keep a record of the maintenance actions. The maintenance can
include, but is not limited to:
• preventive maintenance
• periodic testing
• hardware cleaning
• system status messages
• spare parts
• self-supervision
12.1 Preventive maintenance
Check the device visually when the switch gear is de-energized. During the
inspection, pay attention to:
•
•
•
•
•
dirty components
loose wire connections
damaged wiring
indicator lights
other mechanical connections
Perform visual inspection every three (3) years minimum.
Related topics
2.5.7 Testing the LEDs and LCD screen
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12 Maintenance
Transformer protection relay
12.2 Periodic testing
Test the device periodically according to the end user's safety instructions and
national safety instructions or law. Carry out functional testing every five (5) years
minimum.
Conduct the testing with a secondary injection principle for the protection stages
used in the device and its extension units.
In corrosive or offshore environments, carry out functional testing every three (3)
years. For the testing procedures, see separate testing manuals.
12.3 Hardware cleaning
Special attention must be paid that the device do not become dirty. If cleaning is
required, wipe out dirt from the units.
12.4 System status messages
If the device’s self checking detects an unindented system status, it will in most
cases provide an alarm by activating the service LED and indication status
notification on the LCD screen. If this happens, store the possible message and
contact your local representative for further guidance.
12.5 Spare parts
Use an entire unit as a spare part for the device to be replaced. Always store
spare parts in storage areas that meet the requirements stated in the user
documentation.
12.6 Self-supervision
NOTICE
LOSS OF PROTECTION OR RISK OF NUISANCE TRIPPING
•
•
If the relay is no longer supplied with power or is in permanent fault state,
the protection functions are no longer active and all the Easergy P3 digital
outputs are dropped out.
Check that the operating mode and SF relay wiring are compatible with the
installation.
Failure to follow these instructions can result in equipment damage and
unwanted shutdown of the electrical installation.
Description
The electronic parts and the associated circuitry as well as the program execution
are supervised by means of a separate watchdog circuit. Besides supervising the
device, the watchdog circuit attempts to restart the microcontroller in an
P3T/en M/J006
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12 Maintenance
inoperable situation. If the microcontroller does not restart, the watchdog issues a
self-supervision signal indicating a permanent internal condition.
When the watchdog circuit detects a permanent fault, it always blocks any control
of other digital outputs (except for the self-supervision SF output). In addition, the
internal supply voltages are supervised. Should the auxiliary supply of the device
disappear, an indication is automatically given because the device status
inoperative (SF) output functions on a working current principle. This means that
the SF relay is energized, the 1/C/1:5–7 (or 1/D/1:5-7) contact closed, when the
auxiliary supply is on and the Easergy P3T32 device is fully operational.
In addition to the dedicated self-supervision function, the protection relay has
several alarm signals that can be connected to outputs through the output matrix.
The alarms include:
•
•
•
•
•
•
remote communication inactive
extension I/O communication inactive
communication Port 1 down
communication Port 2 down
selfdiag 1, 2 or 3 alarm
password open
NOTE: SF output is referenced as "service status output" in the setting tool.
To get self-supervision alarms to SF output contact, they must be linked in the
DIAGNOSIS setting view’s section SELFDIAG SIGNAL CONFIGURATION.
Required alarms are first linked to a Selfdiag1, Selfdiag2 or Selfdiag3 group
(Figure 247).
Figure 247 - Selfdiag alarm signal configuration
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12 Maintenance
Transformer protection relay
Having the Seldiag alarm grouping made, the appropriate alarms can be assigned
to SF relay. By default, selfdiag alarm 2 is linked to SF relay (Figure 248). The
function of this default setup is the same as in the older systems where this
configuration was not possible.
Figure 248 - Linking Selfdiag alarm 1-3 to SF relay
It is possible to choose what selfdiag alarms 1-3 do when activated. This option
can be done through the output matrix (Figure 249). This allows you to categorize
and prioritize actions for each selfdiag alarms individually. For example, in this
configuration, selfdiag alarm 2 activates T9.
Figure 249 - Selecting selfdiag 1-3 actions. The number of outputs varies
depending on the device and order code
12.6.1 Diagnostics
The device runs self-diagnostic tests for hardware and software in boot sequence
and also performs runtime checking.
Permanent inoperative state
If a permanent inoperative state has been detected, the device releases an SF
relay contact and the service LED is set on. The local panel also displays a
detected fault message. The permanent inoperative state is entered when the
device is not able to handle main functions.
Temporal inoperative state
When the self-diagnostic function detects a temporal inoperative state, a Selfdiag
matrix signal is set and an event (E56) is generated. If the inoperative state was
only temporary, an off event is generated (E57). The self-diagnostic state can be
reset via the front panel.
Diagnostic registers
There are four 16-bit diagnostic registers which are readable through remote
protocols.
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12 Maintenance
Table 168 - Readable registers through remote communication protocols
Register
Bit
Code
Description
SelfDiag1
0 (LSB)
(Reserved)
(Reserved)
1
(Reserved)
(Reserved)
2
T1
Detected digital
3
T2
4
T3
5
T4
6
T5
7
T6
8
T7
9
T8
10
A1
11
A2
12
A3
13
A4
14
A5
15
T9
0 (LSB)
T10
1
T11
2
T12
3
T13
4
T14
5
T15
6
T16
7
T17
8
T18
9
T19
10
T20
11
T21
output fault
SelfDiag2
Detected digital
output fault
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12 Maintenance
Transformer protection relay
Register
SelfDiag4
Bit
Code
12
T22
13
T23
14
T24
0 (LSB)
+12V
Description
Detected internal
voltage fault
1
ComBuff
BUS: detected buffer
error
2
Order Code
Detected order code
error
3
Slot card
Detected option card
error
4
FPGA conf.
Detected FPGA
configuration error
5
I/O unit
Detected ARC I/O
unit error
6
Arc sensor
Detected faulty arc
sensor
7
QD-card error
Detected QD-card
error
8
BI
Detected ARC BI
error
9
LowAux
Low auxiliary supply
voltage
The code is displayed in self-diagnostic events and on the diagnostic menu on the
local panel and Easergy Pro.
NOTE: All signals are not necessarily available in every Easergy P3 product.
12.7 Arc flash detection system maintenance
The device requires maintenance to ensure that it works according to the
specification. Carry out testing every fours (4) years.
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12 Maintenance
DANGER
HAZARD OF UNEXPECTED SYSTEM OPERATION
Carry out periodic system testing as per the testing recommendation in this
manual or if the protection system scheme has been changed.
Failure to follow these instructions will result in death or serious injury.
DANGER
HAZARD OF UNEXPECTED SYSTEM OPERATION
•
•
If the arc flash detection unit is no longer supplied with power or is in
permanent non-operational state, the protection functions are no longer
active and all the output contacts are dropped out.
To detect a power-off or a permanent fault state, connect the watchdog
(SF) output contact to a monitoring device such as SCADA or DCS.
Failure to follow these instructions will result in death or serious injury.
Keep record of the maintenance actions performed for the system.
The maintenance can include but is not limited to:
• visual inspection
• periodic testing
• hardware cleaning
• sensor condition and positioning check
• checking the obstruction of sensors
12.7.1 Visual inspection
Do visual inspection once every three (3) years minimum.
1. De-energize the switchgear.
2. Inspect the device, sensors and cabling.
Pay attention to:
◦ possible dirty arc sensors
◦ loose wire connections
◦ damaged wiring
◦ indicator lights (device start-up)
◦ other mechanical connections
12.7.2 Hardware cleaning
Pay special attention to ensure that the device, its extension units and sensors do
not become dirty.
416
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12 Maintenance
Transformer protection relay
DANGER
HAZARD OF UNEXPECTED SYSTEM OPERATION
•
•
Do not use any type of solvents or gasoline to clean the device, sensors
or cables.
When cleaning the sensor, make sure that the cleaning solution does not
contact anything other than the sensor.
Failure to follow these instructions will result in death or serious injury.
•
•
If cleaning is required, wipe out dirt from the device.
Use a dry cleaning cloth or equivalent together with mild soapy water to clean
any residues from the light sensor.
12.7.3 Sensor condition and positioning check
Always check that the sensor positioning remains as it was originally designed
after:
• commissioning
• sensor replacement
• modification procedure
• cleaning
• arc flash fault
• periodic testing
Check for obstruction of the sensors.
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13 Order codes and accessories
13 Order codes and accessories
13.1 Order codes
When ordering, state:
• Order code of the relay
• Quantity
• Accessories (see the order codes in section Accessories)
Figure 250 - P3T32 order code
Slot
1
P3T32 -
2
3
4
5
A
6
-
7
A
8
9
10
A -
Application
T32 = Transformer protection relay with differential protection
Nominal Supply voltage [V]
C
= Power C 110-230 V (80 .. 265 Vac/dc, 5 x DO heavy duty, A1, SF)
D
= Power D 24-48 V (18 .. 60 Vdc, 5 x DO heavy duty, A1, SF)
I/O Card I
G
= 6DI+4DO (6 x DI, 4 x DO)
B
= 3BIO+2Arc (3 x BI/BO, 2 x Arc point sensor, T2, T3, T4)
C
= F2BIO+1Arc (Fibre 2 x BI/BO, 1 x Arc loop sensor, T2, T3, T4)
Slot 3 = A, G, H or I
Slot 3 = A, G, H or I
Slot 3 = A, G, H or I
I/O Card II
A
G
H
I
=
=
=
=
None
6DI+4DO (6 x DI, 4 x DO)
6DI+4DO (6 x DI, 4 x DO(NC))
10DI (10 x DI)
I/O Card III
1
= 3xI (5/1A) ringlug + Io (5/1A) for transformer differential protection
(1
Slot 8 = 1 or 2
I/O Card IV
A
= None
Option card I
A
= None
D
= 4Arc (4 x Arc sensor)
K
= RS232 (RS232)
Future option
A
= None
Analog measurement card (See application)
1
2
= 3L(5A) + 2Io (5/1A+1/0,2A) ringlug + 4U
= 3L(1A) + 2Io (5/1A+1/0.2A) ringlug + 4U
Slot 4 = 1
Slot 4 = 1
Communication interface I
A
= None
B
= RS232 (RS232, IRIG-B)
C
= RS232+RJ (RS232, IRIG-B + Ethernet RJ-45 100 Mbs)
D
= RS232+LC (RS232, IRIG-B + Ethernet LC 100 Mbs)
E
= 2xRS485 (2-wire)
F
= RS485+RJ (RS485 2-wire + Ethernet RJ-45 100 Mbs)
G
= RS485+LC (RS485 2-wire + Ethernet LC 100 Mbs)
= 2xRJ (Ethernet RJ 100 Mbs, RSTP)
N
O
= 2xLC (Ethernet LC 100 Mbs, RSTP)
P
= PP (Plastic / Plastic serial fibre)
R
= GG (Glass / Glass serial fibre)
Reserved
A
= Reserved
Display type
B
= 128x128 (128 x 128 LCD matrix)
C
= 128x128Ext (128 x 128 LCD matrix, detachable)
(2
Nominal DI voltage (voltage withstand)
A
= 24 Vdc/ac (255 Vdc/ac)
B
= 110 Vdc/ac (255 Vdc/ac)
C
= 220 Vdc/ac (255 Vdc/ac)
Product version
A
= Version 2.1
Future option
A
= None
Region
A
= English, IEC
B
= English, ANSI
Slot 4 = 1 and Slot 8 = 1 or 2
1) 1) If slot 8 = 1 or 2, then slot 4 = 1
2) By default, the cable length is 2 m (6.56 ft). You can order cables of other
length separately: VX001-1 (1 m/3.28 ft), Vx001-3 (3 m/9.84 ft) or VX001-5 (5 m/
16.40 ft).
NOTE: All PCBA cards are conformally coated.
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13 Order codes and accessories
Transformer protection relay
13.2 Accessories
Table 169 - Accessories for Easergy P3 Advanced
Product
reference
Description
REL code
P3F30
P3L30
VA1DA-20
Arc sensor, 20 m
REL52801
X
X
X
X
X
Arc sensor, 20 m, shielded,
REL52802
X
X
X
X
X
VA1DA-20S-HF
P3M30 / P3G30 /
P3M32 P3G32
P3T32
halogen free
VA1DA-20S
Arc sensor, 20 m, shielded
REL52803
X
X
X
X
X
VA1DA-6
Arc sensor, 6 m connect
REL52804
X
X
X
X
X
VA1DA-6S-HF
Arc sensor, 6 m, halogen free REL52805
X
X
X
X
X
VA1DA-6S
Arc sensor, 6 m, shielded
REL52806
X
X
X
X
X
VA1EH-20
Arc sensor, 20 m pipe sensor
REL52807
X
X
X
X
X
Arc sensor, 20 m pipe sensor, REL52808
X
X
X
X
X
cable
VA1EH-20S
shielded
VA1EH-6
VA1EH-6S
Arc sensor, 6 m pipe sensor
REL52809
X
X
X
X
X
Arc sensor, 6 m pipe sensor,
REL52810
X
X
X
X
X
REL52839
X
X
X
X
X
REL52840
X
X
X
X
X
REL52851
X
X
X
X
X
REL52852
X
X
X
X
X
shielded
VA1DA-6W
Arc sensor, 6 m, shielded at
sensor end
VA1DA-20W
Arc sensor, 20 m, shielded at
sensor end
VA2DV-3-SE
Arc sensor, 3 m, shielded,
metal pipe
VA2DV-6-SE
Arc sensor, 6 m, shielded,
metal pipe
ARC SLM-1
Arc fiber sensor, 1 m
REL52870
X
X
X
X
X
ARC SLM-5
Arc fiber sensor, 5 m
REL52871
X
X
X
X
X
ARC SLM-10
Arc fiber sensor, 10 m
REL52872
X
X
X
X
X
ARC SLM-15
Arc fiber sensor, 15 m
REL52873
X
X
X
X
X
ARC SLM-20
Arc fiber sensor, 20 m
REL52874
X
X
X
X
X
ARC SLM-25
Arc fiber sensor, 25 m
REL52875
X
X
X
X
X
ARC SLM-30
Arc fiber sensor, 30 m
REL52876
X
X
X
X
X
ARC SLM-35
Arc fiber sensor, 35m
REL52877
X
X
X
X
X
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13 Order codes and accessories
Product
reference
Description
REL code
P3F30
P3L30
P3M30 / P3G30 /
P3M32 P3G32
P3T32
ARC SLM-40
Arc fiber sensor, 40 m
REL52878
X
X
X
X
X
ARC SLM-50
Arc fiber sensor, 50 m
REL52879
X
X
X
X
X
VIO12AASE
RTD module, 12pcs RTD
REL52811
X
X
X
X
X
REL52812
X
X
X
X
X
REL52813
X
X
X
X
X
REL52814
X
X
X
X
X
inputs, Optical Tx
VIO12ABSE
RTD module, 12pcs RTD
inputs, RS485
VIO12ACSE
RTD module, 12pcs RTD
inputs, mA in/out
VIO12ADSE
RTD module, 12pcs RTD
inputs, mA in/out
VPA3CGSE
Profibus interface module
REL52815
X
X
X
X
X
Bluefer
Nomad wireless adapter
REL52850
X
X
X
X
X
VSE001-GGSE
Fiber optic module (Glass -
REL52816
X
X
X
X
X
REL52817
X
X
X
X
X
REL52818
X
X
X
X
X
REL52819
X
X
X
X
X
Glass)
VSE001-GPSE
Fiber optic module (Glass Plastic)
VSE001-PGSE
Fiber optic module (Plastic Glass)
VSE001-PPSE
Fiber optic module (Plastic Plastic)
VSE002
RS485 module
REL52820
X
X
X
X
X
VX052-3
USB programming cable
REL52822
X
X
X
X
X
REL52823
X
X
X
X
X
(Easergy Pro)
VX067
P3x split cable for
COM1-2&COM3-4 ports
VX072
P3x Profibus cable
REL52824
X
X
X
X
X
VYX001
Mounting plate for sensor Z-
REL52828
X
X
X
X
X
REL52829
X
X
X
X
X
REL52831
X
X
X
X
X
REL52832
X
X
X
X
X
shape
VYX002
Mounting plate for sensor Lshape
VYX301
VSE00x Wall fastening
module
VYX695
420
Raising frame, P3x, 45 mm
P3T/en M/J006
13 Order codes and accessories
Transformer protection relay
Product
reference
Description
REL code
P3F30
P3L30
P3M30 / P3G30 /
P3M32 P3G32
P3XWAF
Wall mounting kit P3x3x and
REL52842
X
X
REL52838
X
X
EMS59572
X
X
EMS59573
X
X
59660
X
X
59661
X
X
59662
X
X
LPVT hub termination, use
VW3A8306
X
X
this if all LPVT are not
RC
X
X
P3T32
X
V321
VX086
P3x (RS232) COM1/2+3/4+IRIG-B(3xD9)
EMS59572
Voltage adapter - 47… 240 V
- RJ45 output
EMS59573
LPVT hub connector, RJ45
input - RJ45 output
CCA770
Screened Ethernet cable
between LPVT hub or Voltage
adapter and P3 relay, 0.6 m
CCA772
Screened Ethernet cable
between LPVT hub or Voltage
adapter and P3 relay, 2 m
CCA774
Screened Ethernet cable
between LPVT hub or Voltage
adapter and P3 relay, 4 m
VW3A8306RC
present
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14 Firmware revision
14 Firmware revision
Table 170 - Firmware revisions
FW revision
Changes
Version: 30.206
• Added power direction setting
Release date: October 2022
• Calculated residual voltage available in sample mode disturbance recording
• Added 5th under frequency stage
• Shorter operate time for under frequency protection (now 80 ms)
• Improved inrush blocking for differential stage (applies to P3M32, P3G32 and
P3T32 )
• Added VI5-VI12 to mimic display
• Communications
◦ IEC 104 communication protocol added (consult Schneider Electric’s
representative for availability)
◦ Added DI / DO signals to SPA, Ethernet IP and IEC 103
◦ Added SOTF TRIP, Io>>>>> START/TRIP, IoDir>>> START/TRIP, Uc> START/
TRIP, Uo>>> START/TRIP to IEC 101/103/104 and DNP3
◦ Added Iv> START/TRIP, If5> START/TRIP to IEC 101/104 DNP3
Version: 30.205.1
• SW selectable phase CT secondary current between 1 A or 5 A. This applies to
hardware which has 5 A phase current inputs in Slot 8:
Release date: February 2021
◦ E = 3L(5A) + 2Io(5/1A+1/0,2A) + 4U
◦ 1 = 3L(5A) + 2Io (5/1A+1/0,2A) ringlug + 4U
• Upgraded and restored 5th harmonic blocking stage for the dI> stage.
• Added START signals for 87dI>, 87dI>>, 64REF dIo> and 64REF dIo>> stages.
They are visible in matrix, DNP3, IEC 101, IEC 103 and IEC 61850 protocols.
• Added TRIP signals of 64REF dIo> and 64REF dIo>> to IEC 103 communication
protocol
Version: 30.205
Release date: October 2021
• Polarity of the output contacts in the power supply card is now SW selectable
between NO and NC
• Frequency stage improvement
• Global trip line to output matrix
• Phasor symbol improvement in the HMI
• Local panel control no longer requires activation of the Operator access level
when it is disabled in the Objects setting view
• HMI password enhancement with letters and characters
• Communication:
◦ IEC61850 new LN (LTIM) added for time management
◦ IEC61850 new LN (ZMOT) added for running hours
◦ Modbus update to access arc sensor status
◦ New timeout mechanism added for Telnet/Serial/Http connections
Version: 30.204
Release date: January 2021
•
• Updated secondary current representation for P3T32
• Communications:
◦ IEC61850 and Modbus: Alarm setting and operations left parameters for circuit
breaker monitoring
◦ Ethernet/IP communication protocol restored back to use
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14 Firmware revision
Transformer protection relay
FW revision
Changes
Version: 30.203
• Cybersecurity for the ANSI models to meet California Law 2020: HTTP, FTP and
Release date: July 2020
Telnet removed
• I>>> stage latch function upgrade during the power on-off-on state
• RSTP network reconstruction optimization
• Adjusted time stamps for disturbance recorder and events logs
• Backlight off default timeout changed to 10 min
• Added Modbus registers for alarm setting of CB wear (read) and Operation left
data (read)
• DNP3 updates:
◦ Added function 24 record current time
◦ Added VO and LED status to BI data list
◦ Added the possibility to configure time reference to UTC
Version: 30.202
Release date: July 2020
• LPIT support
◦ for P3U30 and P3F30 models only
◦ The high-speed arc flash current (Arc I>) is not supported in this release.
◦ CT secondary in slot 8 adjustable to 1–10 A
• Modbus
◦ Added PME/PSO support
◦ Voltage measurements descriptions
Version: 30.201
Release date: January 2020
Cybersecurity improvements:
• passwords are stored as salted hash
• password resetting procedure changed
• new user account Administrator added
• editing output matrix and several communication settings through Ethernet
interface blocked
Version: 30.111
Release date: October 2019
• Improved menu titles for COM ports and Ethernet ports in the Protocol
Configuration menu
• IEC-61850 speed optimizations
• Added IRIG-B support for option 'K' in slot 6
• Support for eight (8) controllable objects and protocol parameters for Modbus, IEC
61850, IEC 103, IEC 101, Device Net, Profibus, DNP 3, and SPAbus
• Modbus:
◦ registers to include protection function status
◦ added LED status information
Version: 30.110
Release date: August 2019
• ANSI terminology
• Digital inputs 33–36 added to DNP and IEC 101 protocol
• Phase-wise cumulative breaking current over IEC 61850
• Temperature LN to IEC 61850
• Add VI5-20 and VO7-20 added to IEC 103 protocol mapping
• Ethernet/IP protocol removed
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14 Firmware revision
FW revision
Changes
Version: 30.109
• Arc protection I>int. start setting changed to be relative to CT primary instead of
Release date: March 2019
application nominal current.
• Unit for start setting of I0>int. arc protection changed to "pu".
• Negative sequence voltage 47-1, 47-2, and 47-3(ANSI 47) stages added.
• Maximum number of disturbance records increased from 12 to 24.
• IEC 61850 logical nodes added for digital inputs 32....36.
• Digital inputs 33...36 added to IEC 103 protocol.
• BIO and IGBT support added to P3x3x models.
Version: 30.108
Release date: December 2018
• Intermittent ground fault (ANSI 67NI) changed:
◦ New start setting "Sensitive/Normal" and VN check for trip added
• CB condition monitoring upgraded with opening counts and opening, closing and
charging times
• Fault locator enhanced to allow multiple line segments.
• LED matrix in P3x3x enhanced:
◦ LEDs can now be configured more flexibly.
◦ It is now possible to select for each individual LED whether it should be blinking,
latched, or non-volatile (keep its state over reboot).
◦ Each LED also has a configurable description, one for green color and another
for red.
• COMTRADE files can be read over Modbus.
• Product and vendor data changed to Schneider Electric in EDS file. This change
affects CIP protocols: DeviceNet and Ethernet/IP.
• Pole slip protection (ANSI 78) added for P30G and P3G32.
• New CBFP functions added: "CBFP1" and "CBFP2".
• Restricted ground fault protection (ANSI 64REF) for P3T32 and P3G32.
• Faulty phase detection added for ANSI 67N (I0Dir) stage.
• Ethernet's redundancy protocols are now in separate menus.
Version: 30.106
Release date: 16.5.2018
• The setting "Inv. time coefficient k" in stages 50/51-1, 67N-1, 67N-2, 50N/51N-1,
67N-1, 67N-2, 67N-3 has three decimals instead of two and the minimum value for
the ground fault overcurrent was changed from 0.05 to 0.025.
• Communication protocol updates
Version: 30.104
First release
Release date: 2.10.2017
424
P3T/en M/J006
Schneider Electric
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92500 Rueil Malmaison - France
Phone: +33 (0) 1 41 29 70 00
www.schneider-electric.com
As standards, specifications, and designs change from time to time,
please ask for confirmation of the information given in this publication.
© 2022 Schneider Electric All Rights Reserved.
P3T/en M/J006 — 11/2022
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