GEK-106471U
GE
Digital Energy
750/760 Feeder Management
Relay
Instruction Manual
Software Revision: 7.4x
Manual P/N: 1601-0120-AL
Manual Order Code: GEK-106471U
GE Digital Energy
650 Markland Street
Markham, Ontario
Canada L6C 0M1
Tel: +1 905 927 7070 Fax: +1 905 927 5098
Internet: http://www.gedigitalenergy.com
*1601-0120-AL*
© 2015 GE Multilin Incorporated. All rights reserved.
GE Multilin 750/760 Feeder Management Relay instruction manual for revision 7.4x
750/760 Feeder Management Relay, is a registered trademark of GE Multilin Inc.
The contents of this manual are the property of GE Multilin Inc. This documentation is
furnished on license and may not be reproduced in whole or in part without the permission
of GE Multilin. The content of this manual is for informational use only and is subject to
change without notice.
Part numbers contained in this manual are subject to change without notice, and should
therefore be verified by GE Multilin before ordering.
Part number: 1601-0120-AL (December 2015)
Safety words and definitions
The following symbols used in this document indicate the following conditions:
Indicates a hazardous situation which, if not avoided, will result in death or serious
injury.
Note
Indicates a hazardous situation which, if not avoided, could result in death or serious
injury.
Note
Indicates a hazardous situation which, if not avoided, could result in minor or
moderate injury.
Note
Indicates practices not related to personal injury.
Note
Indicates general information and practices, including operational information and
practices, that are not related to personal injury.
NOTE
Note
When this symbol appears on the unit, refer to documentation for full ratings and or
potential hazard.
General Safety Precautions
Note
Note
Ensure that all connections to the product are correct so as to avoid accidental risk of
shock and/or fire, for example such as can arise from high voltage connected to low
voltage terminals.
Follow the requirements of this manual, including adequate wiring size and type,
terminal torque settings, voltage, current magnitudes applied, and adequate isolation/
clearance in external wiring from high to low voltage circuits.
Use the device only for its intended purpose and application.
Ensure that all ground paths are uncompromised for safety purposes during device
operation and service.
Ensure that the control power applied to the device, the AC current, and voltage input
match the ratings specified on the relay nameplate. Do not apply current or voltage in
excess of the specified limits.
Only qualified personnel are to operate the device. Such personnel must be thoroughly
familiar with all safety cautions and warnings in this manual and with applicable
country, regional, utility, and plant safety regulations.
Hazardous voltages can exist in the power supply and at the device connection to
current transformers, voltage transformers, control, and test circuit terminals. Make
sure all sources of such voltages are isolated prior to attempting work on the device.
Hazardous voltages can exist when opening the secondary circuits of live current
transformers. Make sure that current transformer secondary circuits are shorted out
before making or removing any connection to the current transformer (CT) input
terminals of the device.
For tests with secondary test equipment, ensure that no other sources of voltages or
currents are connected to such equipment and that trip and close commands to the
circuit breakers or other switching apparatus are isolated, unless this is required by
the test procedure and is specified by appropriate utility/plant procedure.
When the device is used to control primary equipment, such as circuit breakers,
isolators, and other switching apparatus, all control circuits from the device to the
primary equipment must be isolated while personnel are working on or around this
primary equipment to prevent any inadvertent command from this device.
Use an external disconnect to isolate the mains voltage supply.
TOC
TABLE OF CONTENTS
Table of Contents
1: GETTING STARTED
IMPORTANT PROCEDURES .......................................................................................................... 1-1
CAUTIONS AND WARNINGS ............................................................................................... 1-1
INSPECTION CHECKLIST ...................................................................................................... 1-1
MANUAL ORGANIZATION ................................................................................................... 1-2
USING THE RELAY ............................................................................................................................ 1-3
MENU NAVIGATION ............................................................................................................. 1-3
PANEL KEYING EXAMPLE .................................................................................................... 1-6
CHANGING SETPOINTS ................................................................................................................. 1-7
INTRODUCTION ..................................................................................................................... 1-7
THE HELP KEY .................................................................................................................... 1-8
NUMERICAL SETPOINTS ...................................................................................................... 1-8
ENUMERATION SETPOINTS ................................................................................................. 1-9
OUTPUT RELAY SETPOINTS ................................................................................................ 1-13
TEXT SETPOINTS .................................................................................................................. 1-14
APPLICATION EXAMPLE ................................................................................................................. 1-15
DESCRIPTION ........................................................................................................................ 1-15
S2 SYSTEM SETPOINTS ....................................................................................................... 1-23
S3 LOGIC INPUTS SETPOINTS ............................................................................................ 1-24
S5 PROTECTION SETPOINTS .............................................................................................. 1-26
INSTALLATION ....................................................................................................................... 1-27
COMMISSIONING ............................................................................................................................. 1-28
2: INTRODUCTION
OVERVIEW ........................................................................................................................................... 2-1
DESCRIPTION ........................................................................................................................ 2-1
THEORY OF OPERATION ................................................................................................................ 2-5
DESCRIPTION ........................................................................................................................ 2-5
CURRENT AND VOLTAGE WAVEFORM CAPTURE ............................................................. 2-5
FREQUENCY TRACKING ....................................................................................................... 2-5
PHASORS, TRANSIENTS, AND HARMONICS ...................................................................... 2-6
PROCESSING OF AC CURRENT INPUTS ............................................................................ 2-6
PROTECTION ELEMENTS ...................................................................................................... 2-6
LOGIC INPUTS ...................................................................................................................... 2-7
ORDERING ........................................................................................................................................... 2-9
ORDER CODES ..................................................................................................................... 2-9
EXAMPLE ORDER CODES .................................................................................................... 2-9
ACCESSORIES ....................................................................................................................... 2-10
SPECIFICATIONS ............................................................................................................................... 2-11
APPLICABILITY ...................................................................................................................... 2-11
INPUTS .................................................................................................................................. 2-11
MEASURED PARAMETERS ................................................................................................... 2-12
PROTECTION ELEMENTS ...................................................................................................... 2-14
MONITORING ELEMENTS .................................................................................................... 2-17
CONTROL ELEMENTS ........................................................................................................... 2-18
OUTPUTS ............................................................................................................................... 2-20
OUTPUT RELAYS .................................................................................................................. 2-20
CPU ...................................................................................................................................... 2-20
PHYSICAL .............................................................................................................................. 2-21
TESTING ................................................................................................................................ 2-22
APPROVALS ........................................................................................................................... 2-23
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
TOC - I
TABLE OF CONTENTS
TOC
3: INSTALLATION
MECHANICAL INSTALLATION ...................................................................................................... 3-1
DRAWOUT CASE .................................................................................................................. 3-1
INSTALLATION ....................................................................................................................... 3-2
UNIT WITHDRAWAL AND INSERTION ................................................................................ 3-3
ETHERNET CONNECTION .................................................................................................... 3-7
REAR TERMINAL LAYOUT .................................................................................................... 3-7
ELECTRICAL INSTALLATION ......................................................................................................... 3-10
PHASE SEQUENCE AND TRANSFORMER POLARITY .......................................................... 3-11
CURRENT INPUTS ................................................................................................................. 3-11
GROUND AND SENSITIVE GROUND CT INPUTS .............................................................. 3-11
RESTRICTED EARTH FAULT INPUTS ................................................................................... 3-12
ZERO SEQUENCE CT INSTALLATION ................................................................................. 3-13
VOLTAGE INPUTS ................................................................................................................. 3-13
CONTROL POWER ................................................................................................................ 3-14
TRIP/CLOSE COIL SUPERVISION ........................................................................................ 3-15
LOGIC INPUTS ...................................................................................................................... 3-17
ANALOG INPUT .................................................................................................................... 3-17
ANALOG OUTPUTS .............................................................................................................. 3-17
SERIAL COMMUNICATIONS ................................................................................................. 3-18
RS232 COMMUNICATIONS ................................................................................................ 3-20
IRIG-B .................................................................................................................................. 3-21
4: INTERFACES
FRONT PANEL INTERFACE ............................................................................................................ 4-1
DESCRIPTION ........................................................................................................................ 4-1
DISPLAY ................................................................................................................................. 4-1
LED INDICATORS .............................................................................................................................. 4-2
DESCRIPTION ........................................................................................................................ 4-2
750/760 STATUS LED INDICATORS ............................................................................... 4-3
SYSTEM STATUS LED INDICATORS ................................................................................... 4-3
OUTPUT STATUS LED INDICATORS ................................................................................... 4-4
RELAY MESSAGES ............................................................................................................................ 4-6
KEYPAD OPERATION ............................................................................................................ 4-6
DIAGNOSTIC MESSAGES ..................................................................................................... 4-7
SELF-TEST WARNINGS ....................................................................................................... 4-7
FLASH MESSAGES ................................................................................................................ 4-9
ENERVISTA 750/760 SETUP SOFTWARE INTERFACE ........................................................ 4-12
OVERVIEW ............................................................................................................................ 4-12
HARDWARE ........................................................................................................................... 4-12
INSTALLING THE ENERVISTA 750/760 SETUP SOFTWARE .......................................... 4-14
CONNECTING ENERVISTA 750/760 SETUP TO THE RELAY ............................................ 4-17
CONFIGURING SERIAL COMMUNICATIONS ....................................................................... 4-17
USING THE QUICK CONNECT FEATURE ............................................................................ 4-18
CONFIGURING ETHERNET COMMUNICATIONS ................................................................. 4-19
CONNECTING TO THE RELAY .............................................................................................. 4-20
WORKING WITH SETPOINTS AND SETPOINT FILES ........................................................... 4-22
ENGAGING A DEVICE ........................................................................................................... 4-22
ENTERING SETPOINTS ......................................................................................................... 4-22
FILE SUPPORT ...................................................................................................................... 4-23
USING SETPOINTS FILES ..................................................................................................... 4-23
UPGRADING RELAY FIRMWARE ................................................................................................. 4-29
DESCRIPTION ........................................................................................................................ 4-29
SAVING SETPOINTS TO A FILE ........................................................................................... 4-29
TOC - II
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
TOC
TABLE OF CONTENTS
LOADING NEW FIRMWARE ................................................................................................. 4-29
ADVANCED ENERVISTA 750/760 SETUP FEATURES ......................................................... 4-32
TRIGGERED EVENTS ............................................................................................................. 4-32
WAVEFORM CAPTURE (TRACE MEMORY) ......................................................................... 4-32
DATA LOGGER ...................................................................................................................... 4-35
EVENT RECORDER ............................................................................................................... 4-35
MODBUS USER MAP ........................................................................................................... 4-36
VIEWING ACTUAL VALUES ................................................................................................. 4-37
USING ENERVISTA VIEWPOINT WITH THE 750/760 ......................................................... 4-39
PLUG AND PLAY EXAMPLE ................................................................................................. 4-39
5: SETPOINTS
OVERVIEW ........................................................................................................................................... 5-1
SETPOINTS MAIN MENU ..................................................................................................... 5-1
SETPOINT ENTRY METHODS ............................................................................................... 5-5
SETPOINT ACCESS SECURITY ............................................................................................. 5-6
COMMON SETPOINTS .......................................................................................................... 5-6
LOGIC DIAGRAMS ................................................................................................................ 5-8
S1 RELAY SETUP ............................................................................................................................... 5-9
PASSCODE ............................................................................................................................ 5-9
COMMUNICATIONS .............................................................................................................. 5-9
CLOCK ................................................................................................................................... 5-13
EVENT RECORDER ............................................................................................................... 5-14
TRACE MEMORY ................................................................................................................... 5-15
DATA LOGGER ...................................................................................................................... 5-16
FRONT PANEL ...................................................................................................................... 5-17
DEFAULT MESSAGES ........................................................................................................... 5-18
USER TEXT MESSAGES ........................................................................................................ 5-19
CLEAR DATA ......................................................................................................................... 5-20
INSTALLATION ....................................................................................................................... 5-20
MOD VERSION UPGRADE ................................................................................................... 5-21
S2 SYSTEM SETUP ............................................................................................................................ 5-22
CURRENT SENSING .............................................................................................................. 5-22
BUS VT SENSING ................................................................................................................ 5-22
LINE VT SENSING ................................................................................................................ 5-23
POWER SYSTEM ................................................................................................................... 5-23
FLEXCURVES™ .................................................................................................................... 5-24
S3 LOGIC INPUTS ............................................................................................................................. 5-26
OVERVIEW ............................................................................................................................ 5-26
LOGIC INPUTS SETUP .......................................................................................................... 5-27
BREAKER FUNCTIONS ......................................................................................................... 5-28
CONTROL FUNCTIONS ........................................................................................................ 5-30
USER INPUTS ........................................................................................................................ 5-31
BLOCK FUNCTIONS ............................................................................................................. 5-32
BLOCK OVERCURRENT ........................................................................................................ 5-34
TRANSFER FUNCTIONS ........................................................................................................ 5-35
RECLOSE (760 ONLY) ......................................................................................................... 5-36
MISCELLANEOUS .................................................................................................................. 5-36
S4 OUTPUT RELAYS ......................................................................................................................... 5-38
RELAY OPERATION ............................................................................................................... 5-38
TRIP RELAY ........................................................................................................................... 5-39
CLOSE RELAY ....................................................................................................................... 5-40
AUXILIARY RELAYS ............................................................................................................... 5-41
SELF-TEST WARNING RELAY ............................................................................................. 5-42
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
TOC - III
TABLE OF CONTENTS
TOC
S5 PROTECTION ................................................................................................................................ 5-44
OVERVIEW ............................................................................................................................ 5-44
TIME OVERCURRENT CURVE CHARACTERISTICS .............................................................. 5-45
PHASE CURRENT .................................................................................................................. 5-50
NEUTRAL CURRENT ............................................................................................................. 5-58
GROUND CURRENT ............................................................................................................. 5-64
SENSITIVE GROUND ............................................................................................................ 5-68
NEGATIVE SEQUENCE .......................................................................................................... 5-76
VOLTAGE ............................................................................................................................... 5-82
FREQUENCY .......................................................................................................................... 5-87
BREAKER FAILURE ............................................................................................................... 5-90
REVERSE POWER ................................................................................................................. 5-92
S6 MONITORING ............................................................................................................................... 5-94
CURRENT LEVEL ................................................................................................................... 5-94
POWER FACTOR ................................................................................................................... 5-95
FAULT LOCATOR .................................................................................................................. 5-97
DEMAND ............................................................................................................................... 5-99
ANALOG INPUT .................................................................................................................... 5-106
ANALOG OUTPUTS .............................................................................................................. 5-110
OVERFREQUENCY ................................................................................................................. 5-113
EQUIPMENT ........................................................................................................................... 5-114
PULSE OUTPUT .................................................................................................................... 5-121
S7 CONTROL ...................................................................................................................................... 5-123
SETPOINT GROUPS .............................................................................................................. 5-123
SYNCHROCHECK .................................................................................................................. 5-127
MANUAL CLOSE BLOCKING ............................................................................................... 5-129
COLD LOAD PICKUP ............................................................................................................ 5-131
UNDERVOLTAGE RESTORATION ......................................................................................... 5-133
UNDERFREQUENCY RESTORE ............................................................................................. 5-134
TRANSFER SCHEME ............................................................................................................. 5-136
AUTORECLOSE (760 ONLY) ................................................................................................ 5-157
S8 TESTING ......................................................................................................................................... 5-170
OUTPUT RELAYS .................................................................................................................. 5-170
PICKUP TEST ......................................................................................................................... 5-171
ANALOG OUTPUTS .............................................................................................................. 5-171
SIMULATION ......................................................................................................................... 5-172
FACTORY SERVICE ................................................................................................................ 5-176
6: ACTUAL VALUES
TOC - IV
OVERVIEW ........................................................................................................................................... 6-1
ACTUAL VALUES MAIN MENU ........................................................................................... 6-1
A1 STATUS ........................................................................................................................................... 6-6
VIRTUAL INPUTS ................................................................................................................... 6-6
HARDWARE INPUTS ............................................................................................................. 6-6
LAST TRIP DATA ................................................................................................................... 6-7
FAULT LOCATIONS ............................................................................................................... 6-8
CLOCK ................................................................................................................................... 6-8
AUTORECLOSE (760 ONLY) ................................................................................................ 6-8
A2 METERING ..................................................................................................................................... 6-10
METERING CONVENTIONS .................................................................................................. 6-10
CURRENT ............................................................................................................................... 6-11
VOLTAGE ............................................................................................................................... 6-12
FREQUENCY .......................................................................................................................... 6-13
SYNCHRONIZING VOLTAGE ................................................................................................. 6-14
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
TOC
TABLE OF CONTENTS
POWER .................................................................................................................................. 6-14
ENERGY ................................................................................................................................. 6-15
DEMAND ............................................................................................................................... 6-16
ANALOG INPUT .................................................................................................................... 6-17
A3 MAINTENANCE ........................................................................................................................... 6-18
TRIP COUNTERS ................................................................................................................... 6-18
ARCING CURRENT ............................................................................................................... 6-19
A4 EVENT RECORDER ..................................................................................................................... 6-20
EVENT RECORDS .................................................................................................................. 6-20
LAST RESET DATE ................................................................................................................ 6-24
A5 PRODUCT INFO .......................................................................................................................... 6-25
TECHNICAL SUPPORT .......................................................................................................... 6-25
REVISION CODES ................................................................................................................. 6-25
CALIBRATION DATES ........................................................................................................... 6-26
7: COMMISSIONING
OVERVIEW ........................................................................................................................................... 7-1
SAFETY PRECAUTIONS ......................................................................................................... 7-1
REQUIREMENTS .................................................................................................................... 7-2
CONVENTIONS ...................................................................................................................... 7-2
TEST EQUIPMENT ................................................................................................................. 7-3
INSTALLATION CHECKS ....................................................................................................... 7-3
WIRING DIAGRAMS ............................................................................................................. 7-4
INPUTS/OUTPUTS ............................................................................................................................ 7-6
LOGIC / VIRTUAL INPUTS 1 TO 14 ................................................................................... 7-6
VIRTUAL INPUTS 15 TO 20 ................................................................................................ 7-14
OUTPUT RELAYS .................................................................................................................. 7-14
METERING ........................................................................................................................................... 7-16
CURRENT METERING ........................................................................................................... 7-16
VOLTAGE METERING ........................................................................................................... 7-17
POWER METERING .............................................................................................................. 7-18
DEMAND METERING ............................................................................................................ 7-21
ANALOG INPUT METERING ................................................................................................. 7-23
PROTECTION SCHEMES ................................................................................................................. 7-25
SETPOINT GROUPS .............................................................................................................. 7-25
PHASE OVERCURRENT ........................................................................................................ 7-25
NEUTRAL OVERCURRENT .................................................................................................... 7-32
GROUND OVERCURRENT .................................................................................................... 7-36
NEGATIVE-SEQUENCE OVERCURRENT AND VOLTAGE .................................................... 7-37
VOLTAGE ............................................................................................................................... 7-39
FREQUENCY .......................................................................................................................... 7-45
BREAKER FAILURE ............................................................................................................... 7-49
REVERSE POWER ................................................................................................................. 7-49
MONITORING ..................................................................................................................................... 7-51
CURRENT MONITORING ...................................................................................................... 7-51
FAULT LOCATOR .................................................................................................................. 7-51
DEMAND MONITORING ....................................................................................................... 7-53
ANALOG INPUTS .................................................................................................................. 7-54
OVERFREQUENCY MONITORING ........................................................................................ 7-55
POWER FACTOR ................................................................................................................... 7-55
VT FAILURE .......................................................................................................................... 7-56
TRIP COIL MONITOR ........................................................................................................... 7-57
CLOSE COIL MONITOR ........................................................................................................ 7-57
BREAKER OPERATION FAILURE .......................................................................................... 7-58
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
TOC - V
TABLE OF CONTENTS
TOC
ARCING CURRENT ................................................................................................................ 7-58
ANALOG OUTPUT CHANNELS ............................................................................................ 7-59
IRIG-B .................................................................................................................................. 7-59
PULSE OUTPUT .................................................................................................................... 7-59
CONTROL SCHEMES ....................................................................................................................... 7-60
SETPOINT GROUP CONTROL .............................................................................................. 7-60
SYNCHROCHECK .................................................................................................................. 7-62
MANUAL CLOSE FEATURE BLOCKING .............................................................................. 7-67
COLD LOAD PICKUP BLOCKING ........................................................................................ 7-68
UNDERVOLTAGE RESTORATION ......................................................................................... 7-70
UNDERFREQUENCY RESTORATION .................................................................................... 7-74
TRANSFER SCHEME ............................................................................................................. 7-75
AUTORECLOSE (760 ONLY) ................................................................................................ 7-84
PLACING THE RELAY IN SERVICE ............................................................................................... 7-92
DESCRIPTION ........................................................................................................................ 7-92
ON-LOAD TESTING .............................................................................................................. 7-92
DIELECTRIC STRENGTH TESTING ........................................................................................ 7-94
8: APPENDIX
RELAY MODS ...................................................................................................................................... 8-1
REVERSE POWER ................................................................................................................. 8-1
CONFORMITY ..................................................................................................................................... 8-3
EU DECLARATION OF CONFORMITY ................................................................................. 8-3
REVISION HISTORY .......................................................................................................................... 8-4
RELEASE DATES ................................................................................................................... 8-4
RELEASE NOTES ................................................................................................................... 8-5
GE MULTILIN DEVICE WARRANTY ............................................................................................. 8-11
WARRANTY STATEMENT ..................................................................................................... 8-11
I: INDEX
TOC - VI
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
GE
Digital Energy
750/760 Feeder Management
Relay
Chapter 1: Getting Started
Getting Started
1.1
Important Procedures
1.1.1
Cautions and Warnings
Please read this chapter to guide you through the initial setup of your new relay.
Before attempting to install or use the relay, it is imperative that all WARNINGS and
CAUTIONS in this manual are reviewed to help prevent personal injury, equipment
damage, and/or downtime.
Note
Note
When this symbol appears on the unit, refer to documentation for full ratings and or
potential hazard.
Note
1.1.2
Inspection Checklist
 Open the relay packaging and inspect the unit for physical damage.
 View the rear nameplate and verify that the correct model has been
ordered.
 Ensure that the following items are included:
• Instruction Manual (on CD)
• GE EnerVista CD (includes software and relay documentation)
• Mounting screws.
For product information, instruction manual updates, and the latest software updates,
please visit the GE Multilin website at http://www.gedigitalenergy.com.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
1-1
IMPORTANT PROCEDURES
CHAPTER 1: GETTING STARTED
If there is any noticeable physical damage, or any of the contents listed are missing,
please contact GE Multilin immediately.
Note
NOTE
1.1.3
Manual Organization
To speed things up, this introductory chapter provides a step-by-step tutorial for a simple
feeder application. Important wiring considerations and precautions discussed in Electrical
Installation on page 3–10 should be observed for reliable operation. Detailed information
regarding accuracy, output relay contact ratings, and so forth are detailed in Specifications
on page 2–11. The remainder of this manual should be read and kept for reference to
ensure maximum benefit from the 750 and 760. For further information, please consult
your local sales representative or the factory. Comments about new features or
modifications for your specific requirements are welcome and encouraged.
Setpoints and actual values are indicated as follows in the manual:
A2 METERING  DEMAND  PHASE A CURRENT  LAST PHASE A CURRENT DEMAND
This ‘path representation’ illustrates the location of an specific actual value or setpoint with
regards to its previous menus and sub-menus. In the example above, the LAST PHASE A
CURRENT DEMAND actual value is shown to be a item in the Phase A Current sub-menu,
which itself is an item in the Demand menu, which is an item of actual values page A2
Metering).
Sub-menu levels are entered by pressing the MESSAGE  key. When inside a sub-menu,
the  MESSAGE key returns to the previous sub-menu. The MESSAGE  and MESSAGE 
keys are used to scroll through the settings in a sub-menu. The display indicates which
keys can be used at any given point. A summary of the menu structure for setpoints and
actual values can be found on pages 5–1 and 6–1, respectively.
1-2
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 1: GETTING STARTED
1.2
USING THE RELAY
Using the Relay
1.2.1
Menu Navigation
The relay has three types of display messages: actual values, setpoints, and target
messages.
Setpoints are programmable settings entered by the user. These types of messages are
located within a menu structure that groups the information into categories. Navigating
the menu structure is described below. A summary of the menu structure for setpoints and
actual values can be found in Setpoints Main Menu on page 5–1 and Actual Values Main
Menu on page 6–1, respectively.
Actual values include the following information:
1.
The status of logic inputs (both virtual and hardware), last trip information,
fault location, and relay date and time.
2.
Metering values measured by the relay, such as current, voltage, frequency,
power, energy, demand, and analog inputs.
3.
Maintenance data. This is useful statistical information that may be used for
preventive maintenance. It includes trip counters and accumulated arcing
current.
4.
Event recorder downloading tool.
5.
Product information including model number, firmware version, additional
product information, and calibration dates.
6.
Oscillography and data logger downloading tool.
7.
A list of active conditions.
Alarms, trip conditions, diagnostics, and system flash messages are grouped under Target
messages.
 Press the MENU key to access the header of each the three main
menus (for setpoints, actual values, and target messages), displayed
as follows:

SETPOINTS
[]

ACTUAL VALUES
[]

TARGET MESSAGES []
 Press the MENU key to display the header for the setpoints menu,
then press the MESSAGE  key to display the header of the first
setpoints page.
The setpoint pages are numbered, have an ‘S’ prefix for easy
identification, and have a name which provides a general idea of the
settings available in that page.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
1-3
USING THE RELAY
CHAPTER 1: GETTING STARTED
 Press the MESSAGE  and MESSAGE  keys to scroll through all the
available setpoint page headers.

SETPOINTS
S1 RELAY SETUP
[]
Press the MESSAGE  key to enter the corresponding page. Press the MESSAGE 
and MESSAGE  keys to scroll through the page headers until the required message
is reached. The end of a page is indicated by the message END OF PAGE Sn, where n
represents the number of the setpoints page.
 Press the MENU key to display the header for the actual values
menu, then press the MESSAGE  key to display the header for the
first actual values page. The actual values pages are numbered,
have an ‘A’ prefix for easy identification and have a name which
gives a general idea of the information available in that page.
Pressing the MESSAGE  and MESSAGE  keys will scroll through
all the available actual values page headers.

ACTUAL VALUES
A1 STATUS
[]
Press the MESSAGE  key to enter the corresponding page. Press the MESSAGE 
and MESSAGE  keys to scroll through the page headers until the required message
is reached. The end of a page is indicated by the message END OF PAGE An, where n
represents the number of the actual values page.
 Select the actual values menu and press the MESSAGE  key to
enter the first page. Press the MESSAGE  or MESSAGE  keys until
the A2 METERING page appears.

ACTUAL VALUES
A2 METERING
[]
 Press the MESSAGE  key to display the first sub-page heading for
Page 2 of actual values.

CURRENT
[]
 Press the MESSAGE  and MESSAGE  keys to scroll the display up
and down through the sub-page headers. Pressing the  MESSAGE
key at any sub-page heading will return the display to the heading of
the corresponding setpoint or actual value page, and pressing it
again will return the display to the actual values main menu header.
 Press the MESSAGE  key until the DEMAND sub-page heading
appears. At this point, press the MESSAGE  key to display the
messages in this sub-page.

1-4
DEMAND
[]
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 1: GETTING STARTED
USING THE RELAY
If instead you press the MESSAGE  key, the display will return to the previous subpage heading; in this case,

ENERGY
[]
When the symbols  and [] appear on the top line, it indicates that additional subpages are available and can be accessed by pressing the MESSAGE  key. Pressing
MESSAGE  while at the Demand sub-page heading displays the following:

PHASE A
CURRENT
[]
 Press the  MESSAGE key to return to the Demand sub-page
heading.
 Press the MESSAGE  key to display the actual values of this second
sub-page. Actual values messages and setpoints always have a
colon separating the name of the value and the actual value or
setpoint. This particular message displays the last Phase A current
demand as measured by the relay.
LAST PHASE A CURRENT
DEMAND:
0 A
The menu path to this value is shown as A2 METERING  DEMAND  PHASE A
CURRENT  LAST PHASE A CURRENT DEMAND. Setpoints and actual values messages
are referred to in this manner throughout the manual.
To summarize the above example, the A2 METERING  DEMAND  PHASE A CURRENT
 LAST PHASE A CURRENT DEMAND path representation describes the following keypress sequence: press the MENU key until the actual values menu header is displayed,
then press the MESSAGE  and MESSAGE  keys until the A2 METERING message
is displayed, then press the MESSAGE  and MESSAGE  keys to display the
DEMAND message, then press the MESSAGE  key to reach the PHASE A CURRENT
message, followed by MESSAGE  one last time to display the LAST PHASE A CURRENT
DEMAND actual value.
 Press the MESSAGE  key to display the next actual value message.
 Press the MESSAGE  or MESSAGE  keys to scroll the display
through all the actual value displays in this second sub-page.
MAX PHASE A CURRENT
DEMAND:
0 A
 Press the  MESSAGE key to reverse the process described above
and return the display to the previous level.

750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
PHASE A
CURRENT
[]
1-5
USING THE RELAY
CHAPTER 1: GETTING STARTED
 Press the  MESSAGE key twice to return to the A2 METERING 
DEMAND sub-page header.

1.2.2
DEMAND
[]
Panel Keying Example
The following figure gives a specific example of how the keypad is used to navigate
through the menu structure. Specific locations are referred to throughout this manual by
using a ‘path representation’. The example shown in the figure gives the key presses
required to read the total arcing current in phase B denoted by the path A3 MAINTENANCE
 ARCING CURRENT  TOTAL ARCING CURRENT ∅B.
 Press the menu key until the relay displays the actual values page.

ACTUAL VALUES
Press the MESSAGE

[]
key
ACTUAL VALUES
A1 STATUS
Press the MESSAGE

ACTUAL VALUES
A2 METERING
Press the MESSAGE

ACTUAL VALUES
A3 MAINTENANCE
[]
key
[]
key
[]
MESSAGE
MESSAGE

TRIP COUNTER
[]

ARCING CURRENT
[]
MESSAGE
MESSAGE
1-6
TOTAL ARCING CURRENT
φA:
0kA2 - cycle
TOTAL ARCING CURRENT
φB:
0kA2 - cycle
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 1: GETTING STARTED
1.3
CHANGING SETPOINTS
Changing Setpoints
1.3.1
Introduction
There are several classes of setpoints, each distinguished by the way their values are
displayed and edited.
The relay's menu is arranged in a tree structure. Each setting in the menu is referred to as a
setpoint, and each setpoint in the menu may be accessed as described in the previous
section.
The settings are arranged in pages with each page containing related settings; for
example, all the Phase Time Overcurrent 1 settings are contained within the same page. As
previously explained, the top menu page of each setting group describes the settings
contained within that page. Pressing the MESSAGE keys allows the user to move between
these top menus. A complete editable setpoint chart is available as an Excel spreadsheet
from the GE Multilin website at http://www.gedigitalenergy.com.
All of the 750/760 settings fall into one of following categories: device settings, system
settings, logic input settings, output relay settings, monitoring settings, control settings,
and testing settings.
Note
NOTE
IMPORTANT NOTE: Settings are stored and used by the relay immediately after they are
entered. As such, caution must be exercised when entering settings while the relay is in
service. Modifying or storing protection settings is not recommended when the relay is
in service, since any incompatibility or lack of coordination with other previously saved
settings may cause unwanted operations.
Now that we have become more familiar with maneuvering through messages, we can
learn how to edit the values used by all setpoint classes.
Hardware and passcode security features are designed to provide protection against
unauthorized setpoint changes. Since we will be programming new setpoints using the
front panel keys, a hardware jumper must be installed across the setpoint access terminals
(C10 and C11) on the back of the relay case. Attempts to enter a new setpoint without this
electrical connection will result in an error message.
The jumper does not restrict setpoint access via serial communications. The relay has a
programmable passcode setpoint, which may be used to disallow setpoint changes from
both the front panel and the serial communications ports. This passcode consists of up to
eight (8) alphanumeric characters.
The factory default passcode is “0”. When this specific value is programmed into the relay it
has the effect of removing all setpoint modification restrictions. Therefore, only the
setpoint access jumper can be used to restrict setpoint access via the front panel and
there are no restrictions via the communications ports.
When the passcode is programmed to any other value, setpoint access is restricted for the
front panel and all communications ports. Access is not permitted until the passcode is
entered via the keypad or is programmed into a specific register (via communications).
Note that enabling setpoint access on one interface does not automatically enable access
for any of the other interfaces (i.e., the passcode must be explicitly set in the relay via the
interface from which access is desired).
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
1-7
CHANGING SETPOINTS
CHAPTER 1: GETTING STARTED
A front panel command can disable setpoint access once all modifications are complete.
For the communications ports, writing an invalid passcode into the register previously
used to enable setpoint access disables access. In addition, setpoint access is
automatically disabled on an interface if no activity is detected for thirty minutes.
The EnerVista 750/760 Setup software incorporates a facility for programming the relay's
passcode as well as enabling and disabling setpoint access. For example, when an
attempt is made to modify a setpoint but access is restricted, the software will prompt the
user to enter the passcode and send it to the relay before the setpoint is actually written to
the relay. If a SCADA system is used for relay programming, it is the programmer’s
responsibility to incorporate appropriate security for the application.
1.3.2
The HELP Key
Pressing the HELP key displays context-sensitive information about setpoints such as the
range of values and the method of changing the setpoint. Help messages will
automatically scroll through all messages currently appropriate.
1.3.3
Numerical Setpoints
Each numerical setpoint has its own minimum, maximum, and step value. These
parameters define the acceptable setpoint value range. Two methods of editing and
storing a numerical setpoint value are available.
The first method uses the 750/760 numeric keypad in the same way as any electronic
calculator. A number is entered one digit at a time with the 0 to 9 and decimal keys. The
left-most digit is entered first and the right-most digit is entered last. Pressing ESCAPE
before the ENTER key returns the original value to the display.
The second method uses the VALUE  key to increment the displayed value by the step
value, up to a maximum allowed and then wraps around to the minimum value. Likewise,
the VALUE  key decrements the displayed value by the step value, down to a minimum
value and then wraps around to the maximum value.
For example:
 Select the S2 SYSTEM SETUP  BUS VT SENSING  NOMINAL VT
SECONDARY VOLTAGE setpoint message.
NOMINAL VT SECONDARY
VOLTAGE: 120.0 V
 Press the 6, 3, decimal, and 9 keys.
The display message will change as shown.
NOMINAL VT SECONDARY
VOLTAGE: 63.9 V
1-8
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 1: GETTING STARTED
CHANGING SETPOINTS
Until the ENTER key is pressed, editing changes are not registered by the relay.
 Therefore, press the ENTER key to store the new value in memory.
This flash message will momentarily appear as confirmation of the
storing process. If 69.28 were entered, it would be automatically
rounded to 69.3.
NEW SETPOINT
STORED
1.3.4
Enumeration Setpoints
Enumeration setpoints have data values which are part of a set whose members are
explicitly defined by a name. A set is comprised of two or more members. Enumeration
values are changed using the VALUE keys.
For example:
 Move to the S2 SYSTEM SETUP  BUS VT SENSING  VT CONNECTION
TYPE setpoint message.
VT CONNECTION TYPE:
Wye
 Press the VALUE  key until the “Delta” value is displayed as shown
(in this manual, setpoint values are always shown in double
quotation marks).
VT CONNECTION TYPE:
Delta
 Press the ENTER key to store this change into memory.
As before, confirmation of this action will momentarily flash on the
display.
NEW SETPOINT
STORED
The example shown in the following figures illustrates the key presses required to enter
system parameters such as the phase CT primary rating, ground CT primary rating, bus VT
connection type, secondary voltage, and VT ratio.
The following values will be entered:
Phase CT primary rating: 650 A
Ground CT primary rating: 100 A
Bus VT connection type: Delta
Secondary voltage: 115 V
VT Ratio: 14400 / 115 = 125.2
To set the phase CT primary rating, modify the S2 SYSTEM SETUP  CURRENT SENSING 
PHASE CT PRIMARY setpoint as shown below.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
1-9
CHANGING SETPOINTS
CHAPTER 1: GETTING STARTED
 Press the MENU key until the relay displays the setpoints menu
header.

SETPOINTS
[]
Pres MESSAGE 

SETPOINTS
S1 RELAY SETUP
[]
Press MESSAGE 

 CURRENT
SETPOINTS
[] Press
S2 SYSTEM SETUP
SENSING
MESSAGE 
[] Press
PHASE CT PRIMARY:
MESSAGE  1000 A
Press the VALUE keys until 650 A is displayed, or enter the
value directly via the numeric keypad.
Press the ENTER key to store the setpoint.
PHASE CT PRIMARY:
650 A
NEW SETPOINT
STORED
To set the ground CT primary rating, modify the S2 SYSTEM SETUP  CURRENT SENSING 
setpoint as shown below.
GROUND CT PRIMARY
 Press the MENU key until the relay displays the setpoints menu
header.

SETPOINTS
[]
Press MESSAGE 

SETPOINTS
S1 RELAY SETUP
[]
Press MESSAGE 

 CURRENT
SETPOINTS
[] Press
S2 SYSTEM SETUP
SENSING
MESSAGE 
[] Press
PHASE CT PRIMARY:
MESSAGE  1000 A
Press
GND CT PRIMARY:
MESSAGE  50 A
Press the VALUE keys until 100 A is displayed, or enter the
value directly via the numeric keypad.
Press the ENTER key to store the setpoint.
GND CT PRIMARY:
100 A
NEW SETPOINT
STORED
To set the ground bus VT connection type, modify the S2 SYSTEM SETUP  BUS VT SENSING
 VT CONNECTION TYPE setpoint as shown below.
1 - 10
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 1: GETTING STARTED
CHANGING SETPOINTS
 Press the MENU key until the relay displays the setpoints menu
header.
Press MENU

SETPOINTS
[]
Press MESSAGE 

SETPOINTS
S1 RELAY SETUP
[]
Press MESSAGE 

 CURRENT
SETPOINTS
[] Press
S2 SYSTEM SETUP
SENSING
MESSAGE 
Press

BUS VT SENSING
[]
[] Press
MESSAGE 
VT CONNECTION TYPE:
MESSAGE  Wye
Press the VALUE keys until the value of “Delta” appears on VT CONNECTION TYPE:
Delta
the display.
Press the ENTER key to store the setpoint.
NEW SETPOINT
STORED
To set the secondary voltage, modify the S2 SYSTEM SETUP  BUS VT SENSING 
NOMINAL VT SECONDARY VOLTAGE setpoint as shown below.
 Press the MENU key until the relay displays the setpoints menu
header.
Press MENU

SETPOINTS
[]
Press MESSAGE 

SETPOINTS
S1 RELAY SETUP
[]
Press MESSAGE 

 CURRENT
SETPOINTS
[] Press
S2 SYSTEM SETUP
SENSING
MESSAGE 
Press

BUS VT SENSING
MESSAGE 
[]
[] Press
VT CONNECTION TYPE:
MESSAGE  Wye
Press
NOMINAL VT SECONDARY
MESSAGE  VOLTAGE: 120.0 V
Press the VALUE keys until 115.0 V is displayed, or enter the NOMINAL VT SECONDARY
VOLTAGE: 115.0 V
value directly via the numeric keypad.
Press the ENTER key to store the setpoint.
NEW SETPOINT
STORED
To set the VT ratio, modify the S2 SYSTEM SETUP  BUS VT SENSING  VT RATIO setpoint
as shown below.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
1 - 11
CHANGING SETPOINTS
CHAPTER 1: GETTING STARTED
Press the MENU key until the relay displays the setpoints menu header.
Press MENU

SETPOINTS
[]
Press MESSAGE 

SETPOINTS
S1 RELAY SETUP
[]
Press MESSAGE 

 CURRENT
SETPOINTS
[] Press
S2 SYSTEM SETUP
SENSING
MESSAGE 
Press
MESSAGE 

[]
BUS VT SENSING
[] Press
VT CONNECTION TYPE:
MESSAGE  Wye
Press
NOMINAL VT SECONDARY
MESSAGE  VOLTAGE: 120.0 V
Press
VT RATIO:
MESSAGE  120.0:1
Press the VALUE keys until 125.2:1 is displayed, or enter the VT RATIO:
125.2:1
value directly via the numeric keypad.
Press the ENTER key to store the setpoint.
NEW SETPOINT
STORED
If an entered setpoint value is out of range, the relay displays the following message:
OUT-OF RANGE –
VALUE NOT STORED
To have access to information on maximum, minimum, step value, and information on
technical support, press the HELP key. For the previous example, pressing the HELP key
during setpoint entry displays the corresponding minimum, maximum and step values for
the displayed setpoint, as well as contact information if further assistance is required.
1 - 12
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 1: GETTING STARTED
CHANGING SETPOINTS
For example, the help screens for the PHASE CT PRIMARY setpoint are shown below:
PHASE CT PRIMARY:
1000 A
1.3.5
Press HELP
MIN:
MAX:
Press HELP
IN STEPS OF:
1
Press HELP
PRESS [0]-[9] OR
[VALUE ] TO EDIT
Press HELP
PRESS [ENTER] TO
STORE NEW VALUE
Press HELP
FOR FURTHER HELP
REFER TO MANUAL
Press HELP
INTERNET ADDRESS
www.GEdigitalenergy.com
Press HELP
TECH SUPPORT
Tel: (905) 927-7070
Press HELP
TECH SUPPORT
Fax: (905) 927-5098
1
5000
Output Relay Setpoints
Each output relay setpoint has the Auxiliary Output Relays 3 to 7 associated with it. Each
can be toggled on or off individually, so that any combination of relays can be activated
upon detection of the initiating condition. Output relay configuration type values are
changed by using the 3 to 7 keys. Each key toggles the display between the corresponding
number and a hyphen.
 Select the S5 PROTECTION  PHASE CURRENT  PHASE TIME
OVERCURRENT 1  PHASE TIME O/C 1 RELAYS (3-7) setpoint message.
PHASE TIME O/C 1
RELAYS (3-7): ---- If an application requires the Phase TOC protection element to
operate the Auxiliary Output 3 relay, select this output relay by
pressing the 3 key.
PHASE TIME O/C 1
RELAYS (3-7): 3--- Press the ENTER key to store this change into memory. As before,
confirmation of this action will momentarily flash on the display.
NEW SETPOINT
STORED
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
1 - 13
CHANGING SETPOINTS
CHAPTER 1: GETTING STARTED
The output relay setpoint values are represented by a 1-row, 5-column matrix. For
example, a value of 3---7 activates Auxiliary Relays 3 and 7, while a value of 34567
activates all five auxiliary relays.
1.3.6
Text Setpoints
Text setpoints accept user-defined character strings as values. They may be comprised of
upper case letters, lower case letters, numerals, and a selection of special characters. The
editing and storing of a text value is accomplished with the use of the ENTER , VALUE, and
ESCAPE keys.
For example:
 Move to message S3 LOGIC INPUTS  USER INPUT A  USER INPUT A
NAME setpoint message.
The name of this user defined input will be changed in this example
from the generic User Input A to something more descriptive.
USER INPUT A NAME:
User Input A
 If an application is to be using the relay as a substation monitor, it is
more informative to rename this input Substation Monitor. Press the
ENTER key and a solid cursor () will appear in the first character
position.
USER INPUT A NAME:
ser Input A
 Press the VALUE keys until the character S is displayed in the first
position.
 Now press the ENTER key to store the character and advance the
cursor to the next position.
 Change the second character to a u in the same manner.
 Continue entering characters in this way until all characters the text
Substation Monitor are entered.
Note that a space is selected like a character. If a character is
entered incorrectly, press the ENTER key repeatedly until the cursor
returns to the position of the error. Re-enter the character as
required.
 Once complete, press the MESSAGE  key to remove the solid
cursor and view the result. Once a character is entered by pressing
the ENTER key, it is automatically saved in flash memory as a new
setpoint.
USER INPUT A NAME:
Substation Monitor
1 - 14
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 1: GETTING STARTED
1.4
APPLICATION EXAMPLE
Application Example
1.4.1
Description
The 750 and 760 relays contain many features designed to accommodate a wide range of
applications. This chapter is provided to guide you, the first time user, through a real-world
application. The following step-by-step installation example, provides you with a quick and
convenient way of becoming familiar with the relay.
The following example is only one of many possible applications of the 750/760 relay.
Important points to keep in mind before developing settings for any multifunction
numerical relay like the 750/760 are as follows:
•
Gather system data, including, but not limited to:
– CT primary and secondary ratings for all CTs used to feed the relay
– VT primary and secondary ratings for both the bus and line VTs
– System frequency
– System phase sequence
•
Define the protection elements that will be enabled. Prepare a list of protection
functions including the following information. By default, all the protection functions
must be assumed Disabled:
– pickup parameter
– operating curve (if applicable)
– time dial or multiplier
– any additional intentional time delay
– directionality (if applicable)
•
Define how many output contacts will be energized in response to a given protection
function. Note that the 750/760 relay can be programmed to trip and, at the same
time, to energize one, a combination, or all five auxiliary relays during the process.
•
Define if the output relays will be set as fail-safe type.
•
Define if the 750/760 will be used to close the breaker. If that will be the case, gather
information on the conditions that will be used to verify synchronism.
•
Define if the relay will be used to monitor the status of the breaker. It is strongly
recommended that the 750/760 always be programmed to monitor breaker status by
means of a digital input connected to the one of the 750/760 logic inputs. Use an
auxiliary contact from the breaker either a normally open contact, 52a, which is
normally in open position when the breaker is open, or a normally closed contact, 52b,
which is in closed position when the breaker is open. A combination of both can also
be utilized, adding the capability for monitoring pole discrepancy, an indication of a
potential mechanical problem within the main contact mechanism of the breaker.
•
If the relay will be used to respond to logic inputs, prepare a list including:
– logic input name
– condition by which the logic input would be considered asserted
– function that the logic input will initiate within the 750/760.
•
If the relay will be used to perform Monitoring functions and act upon certain
conditions, gather information such as:
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
1 - 15
APPLICATION EXAMPLE
CHAPTER 1: GETTING STARTED
– minimum and maximum values
– alarm and trip values
– time delays
– demand method to be used
– breaker timings
•
It is important to familiarize yourself with the relay control functions before setting up
the relay. Some control functions such as the Transfer scheme, which takes automatic
control of the auxiliary outputs, or the autorecloser that uses the auxiliary outputs for
specific pre-defined functions, can have an unwanted effects in the performance of
other functions within the relay.
To start, simply power on the unit, and follow the instructions in this tutorial. The example
assumes the following system characteristics. It also assumes that relay setpoints are
unaltered from their factory default values.
Refer to the following figures for schematics related to this application example.
1 - 16
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 1: GETTING STARTED
APPLICATION EXAMPLE
FIGURE 1–1: Typical Three-Line Diagram
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
1 - 17
APPLICATION EXAMPLE
CHAPTER 1: GETTING STARTED
RS485 SERIAL NETWORK
FIGURE 1–2: Typical Connection Diagram
1 - 18
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 1: GETTING STARTED
APPLICATION EXAMPLE
FIGURE 1–3: Typical Control Diagram
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
1 - 19
APPLICATION EXAMPLE
CHAPTER 1: GETTING STARTED
FIGURE 1–4: Typical Breaker Control Diagram
1 - 20
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 1: GETTING STARTED
APPLICATION EXAMPLE
FIGURE 1–5: Typical Relay Control Diagram
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
1 - 21
APPLICATION EXAMPLE
CHAPTER 1: GETTING STARTED
•
Power System Data
1.
System: 3Φ, 4 wire
2.
Frequency: 60 Hz
3.
Line-to-line voltage: 13.8 kV
4.
Maximum current: 600 A
The above data will be used to set the relay system parameters.
•
Control System Requirements
1.
All protection elements used are to trip the breaker.
2.
Breaker position monitoring via 52b contact only.
3.
Only current metering is required.
4.
Contact Inputs: Remote open and close contacts from RTU.
5.
Remote/local selection from panel hand switch. Reset from RTU.
6.
Alarm after 100 second delay from substation monitor. This is normally used
to signal the remote center when someone has gained access to the
substation.
7.
Contact Outputs:
- Trip and close to breaker control circuit (trip and close relays).
- Relay failure alarm to RTU (self-test warning, no programming req’d).
- Alarm contact to RTU (setup in User Function for “Substation Monitor”)
- No data communications to other equipment.
The above data will be used to set the output relays to achieve breaker control and to
set digital inputs for breaker status, remote operations, remote status, and alarm
indication. The example assumes that the communications between the station and
the master control center will be done by the RTU. Alarms, status indication, and
breaker commands will be hard-wired from the relay to the RTU. Please note that,
similar information could be exchanged between the RTU and the relay via an RS485
or RS422 serial link using Modbus RTU protocol. Refer to GE Publication GEK-106473:
750/760 Communications Guide for additional information.
•
Instrument Transformer Data
1.
Bus VTs: 2 × Delta connected, ratio = 14.4 kV:120 V
2.
Phase CTs: 3 × Wye connected, ratio = 600:5 A
The above data will be used to set the relay system parameters, such as CT and VT
connections, VT secondary voltage, and CT and VT primary to secondary ratios.
•
1 - 22
Phase Protection Settings
1.
Time Overcurrent 1 (51P1): Curve Shape = Moderately Inverse; Pickup = 840 A;
Multiplier = 20.2
2.
Instantaneous Overcurrent 1 (50P1): Pickup = 840 A; Phases Required = Any
Two; Delay = 0 s
3.
Instantaneous Overcurrent 2 (50P2): Pickup = 10100 A; Phases Required = Any
Two; Delay = 0 s
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 1: GETTING STARTED
APPLICATION EXAMPLE
•
Neutral Protection Settings
1.
Time Overcurrent 1 (function 51N1):
- Curve shape = Moderately Inverse
- Pickup = 120 A
- Multiplier = 10
2.
Instantaneous Overcurrent 1 (function 50N1):
- Pickup = 120 A
- Phases required = Any two
- Delay = 0 seconds
3.
Instantaneous Overcurrent 2 (function 50N2):
- Pickup = 2000 A
- Phases required = Any two
- Delay = 0 seconds
The above data will be used to configure the relay protection. In this example, the
relay will be used for Phase and Neutral Overcurrent protection only; that is, functions
51P1, 50P1, 50P2, 51N1, 50N1, and 50N2.
In this manual, Neutral Overcurrent is to the residual current, calculated from the
currents measured at the phase CT inputs: terminals G7-H7 for phase A, G8-H8 for
phase B and G9-H9 for phase C. Since it is a calculated value, it cannot be used to
generate oscillography. Ground Overcurrent refers to the current measured at
terminals G10-H10, or at terminals G3-H3 for Sensitive Ground Overcurrent, when the
relay is fitted to measure sensitive ground current.
You should now be familiar with maneuvering through and editing setpoints. As such, we
will now limit our discussion to just the values that must be programmed, in order to meet
the requirements of the example application. Any setpoints not explicitly mentioned should
be left at the factory default value.
1.4.2
S2 System Setpoints
The S2 setpoints page contains setpoints for entering the characteristics of the equipment
on the feeder electrical system. In our example, these characteristics are specified under
the Power System Data and Instrument Transformer Data headings in the previous subsection. From this information and the resulting calculations, program the page S2
setpoints as indicated.
For current transformers, make the following change in the S2 SYSTEM SETUP  CURRENT
SENSING setpoints page:
PHASE CT PRIMARY: “600 A”
Since the example does not contemplate a ground CT, the setpoints for GND CT PRIMARY,
and SENSTV GND CT can be left unchanged. For additional information refer to Current
Sensing on page 5–22.
For voltage transformers, make the following changes in the S2 SYSTEM SETUP  BUS VT
SENSING setpoints page:
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
1 - 23
APPLICATION EXAMPLE
CHAPTER 1: GETTING STARTED
VT CONNECTION TYPE: “Delta”
NOMINAL VT SECONDARY VOLTAGE: “115.0 V”
(for a 138 kV system, 13.8 kV / 120 = 115 V)
(14.4 kV VTprimary / 120 V VTsecondary)
VT RATIO: “120:1”
For the case where Bus VTs are connected in Wye, the system settings are:
VT CONNECTION TYPE: “Wye”
NOMINAL VT SECONDARY VOLTAGE: “66.4 V” (the phase-to-neutral voltage must be
entered. For a 13.8 kV system, we have 13.8kV ø-ø ≡ 7.97kV ø-N; therefore, 7.97kV /
120 = 66.4 V)
VT RATIO: “120:1” (14.4 kV VTprimary / 120V VTsecondary)
For additional information, refer to Bus VT Sensing on page 5–22.
The 750/760 was designed to display primary system values. Current and voltage
measurements are performed at secondary levels, which the relay transforms to primary
values using CT and VT ratios, as well as nominal secondary values.
Configuring the relay for current measurement is simple and it only requires setting the CT
ratios. CT inputs can be 1 A or 5 A and must be specified when the relay is purchased.
There is additional flexibility with regards to the VT inputs, as nominal values are not
required before the relay is ordered; therefore, more settings are needed to prepare the
relay for voltage measurements.
Make the following change in the S2 SYSTEM SETUP  POWER SYSTEM setpoints page to
reflect the power system:
NOMINAL FREQ: “60 Hz”
For additional information, refer to Power System on page 5–23.
1.4.3
S3 Logic Inputs Setpoints
The S3 setpoints page is for entering the characteristics of the logic inputs. In our example,
these characteristics are specified under the Control System Requirements heading.
Program the S3 setpoints as indicated.
To properly configure the relay to respond to digital inputs, they need to be defined as
follows:
1.
The digital inputs should be re-named. Changing the default names to
meaningful names is strongly recommended so they can be easily identified in
the LCD and in event reports.
2.
The asserted logic must be identified. Refer to S3 Logic Inputs on page 5–26
for additional information.
3.
The functionality of the logic inputs must be defined. Note that a logic input
can be utilized for more then one application.
If step 3 is not done, the relay will not perform any function, even if the logic input is
defined and the asserted logic is met. The last two steps use the following setpoints pages:
•
•
S3 LOGIC INPUTS  BREAKER FUNCTIONS for breaker status.
S3 LOGIC INPUTS  CONTROL FUNCTIONS for local/remote operations, cold load
pick up, and setpoint group changes.
•
1 - 24
S3 LOGIC INPUTS  USER INPUTS to energize output relays adding time delay.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 1: GETTING STARTED
APPLICATION EXAMPLE
•
S3 LOGIC INPUTS  BLOCK FUNCTION to block protection functions other than
overcurrent functions
•
S3 LOGIC INPUTS  BLOCK OC FUNCTIONS to block overcurrent functions.
•
S3 LOGIC INPUTS  TRANSFER FUNCTIONS to set inputs that will work with the
automatic transfer scheme.
•
S3 LOGIC INPUTS  RECLOSER FUNCTIONS (760 relay only) to set inputs to work
with the autorecloser functions.
•
S3 LOGIC INPUTS  MISC FUNCTIONS to trigger oscillography, fault simulation, and
start demand intervals.
For breaker position monitoring, enter the following values in the S3 LOGIC INPUTS  LOGIC
INPUTS SETUP page:
INPUT 2 NAME: “Brkr Position (52b)”
INPUT 2 ASSERTED LOGIC: “Contact Close”
Then, to define the functionality of the logic input, enter the following value in the S3 LOGIC
INPUTS  BREAKER FUNCTIONS setpoint page:
52B CONTACT: “Input 2”
For the Remote Open/Close and Reset RTU contacts, enter the following values in the S3
LOGIC INPUTS  LOGIC INPUTS SETUP setpoints page to define the logic inputs. Using the
MESSAGE  key, find the appropriate logic name message and then define the logic input
asserted logic to complete the logic input definition as follows:
INPUT 3 NAME: “Local Mode”
INPUT 3 ASSERTED LOGIC: “Contact Close”
INPUT 4 NAME: “Remote Open”
INPUT 4 ASSERTED LOGIC: “Contact Close”
INPUT 5 NAME: “Remote Close”
INPUT 5 ASSERTED LOGIC: “Contact Close”
INPUT 6 NAME: “Reset”
INPUT 6 ASSERTED LOGIC: “Contact Close”
Once the Logic Input definitions are completed, it is necessary to define their functionality
by entering the following values in the S3 LOGIC INPUTS  CONTROL FUNCTIONS setpoint
page. Using the MESSAGE  key, locate the appropriate logic function and select the
corresponding logic input to perform the function.
LOCAL MODE: “Input 3”
RESET: “Input 6”
REMOTE OPEN: “Input 4”
REMOTE CLOSE: “Input 5”
If, for example, the same logic input would be needed to perform the functionality of Close
and Reset, then the following should have been entered:
RESET: “Input 5”
REMOTE CLOSE: “Input 5”
To setup an Alarm-after-Delay input, make the following changes to the S3 LOGIC INPUTS
setpoints page. Press the MESSAGE  key after each setpoint is
completed to move to the next message.
 USER INPUT A
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
1 - 25
APPLICATION EXAMPLE
CHAPTER 1: GETTING STARTED
USER INPUT A NAME: “Substation Monitor”
USER INPUT A SOURCE: “Input 1”
USER INPUT A FUNCTION: “Alarm”
USER INPUT A RELAYS (3-7): “3----”
USER INPUT A DELAY:
1.4.4
“100.00 s”
S5 Protection Setpoints
The S5 Protection setpoints page contains setpoints for entering protection element
characteristics. In our example, these characteristics are specified under the S5
PROTECTION  PHASE CURRENT and S5 PROTECTION  NEUTRAL CURRENT headings. From
this data and the resulting calculations, program the page S5 setpoints as indicated. When
setting the relay for the first time, other setpoints not listed in this example will be left
disabled.
For the Phase Time Overcurrent 1 element, enter the following values in the S5
PROTECTION  PHASE CURRENT  PHASE TIME OVERCURRENT 1 page. Press the
MESSAGE  key after each setpoint is completed to move to the next message.
PHASE TIME OC 1 FUNCTION: “Trip”
PHASE TIME OC 1 PICKUP: “1.40 x CT” (calculated as 840 A pickup / 600 A primary)
PHASE TIME OC 1 CURVE:
“Mod Inverse”
PHASE TIME OC 1 MULTIPLIER: “20.20”
PHASE TIME OC 1 RESET: “Instantaneous”
For the Phase Instantaneous Overcurrent 1 element, enter the following values in the S5
setpoints page. Press the
MESSAGE  key after each setpoint is completed to move to the next message.
PROTECTION  PHASE CURRENT  PHASE INST OVERCURRENT 1
PHASE INST OC 1 FUNCTION:
“Trip”
PHASE INST OC 1 PICKUP: “1.40 x CT” (calculated as 840 A pickup / 600 A primary)
PHASE INST OC 1 DELAY:
“0.00 s”
PHASES REQUIRED FOR OPERATION: “Any Two”
For the Phase Instantaneous Overcurrent 2 element, enter the following values in the S5
setpoints page. Press the
MESSAGE  key after each setpoint is completed to move to the next message.
PROTECTION  PHASE CURRENT  PHASE INST OVERCURRENT 2
PHASE INST OC 2 FUNCTION:
“Trip”
PHASE INST OC 2 PICKUP: “16.83 x CT” (from 10100 A pickup / 600 A primary)
PHASE INST OC 2 DELAY:
“0.00 s”
PHASES REQUIRED FOR OPERATION: “Any Two”
For the Neutral Time Overcurrent 1 element, enter the following values in the S5
PROTECTION  NEUTRAL CURRENT  NEUTRAL TIME OVERCURRENT 1 page. Press the
MESSAGE  key after each setpoint is completed to move to the next message.
NEUTRAL TIME OC 1 FUNCTION: “Trip”
NEUTRAL TIME OC 1 PICKUP: “0.20 x CT” (from 120 A pickup / 600 A primary)
NEUTRAL TIME OC 1 CURVE: “Mod Inverse”
NEUTRAL TIME OC 1 MULTIPLIER: “10.00”
NEUTRAL TIME OC 1 RESET: “Instantaneous”
For the Neutral Instantaneous Overcurrent 1 element, enter the following values in the S5
PROTECTION  NEUTRAL CURRENT  NEUTRAL INST OVERCURRENT 1 setpoints page.
Press the MESSAGE  key after each setpoint is completed to move to the next message.
1 - 26
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 1: GETTING STARTED
APPLICATION EXAMPLE
NEUTRAL INST OC 1 FUNCTION: “Trip”
NEUTRAL INST OC 1 PICKUP: “0.20 x CT” (from 120 A pickup / 600 A primary)
NEUTRAL INST OC 1 DELAY: “0.00 s”
For the Neutral Instantaneous Overcurrent 2 element, enter the following values in the S5
PROTECTION  NEUTRAL CURRENT  NEUTRAL INST OVERCURRENT 2 setpoints page.
Press the MESSAGE  key after each setpoint is completed to move to the next message.
NEUTRAL INST OC 2 FUNCTION: “Trip”
NEUTRAL INST OC 2 PICKUP: “3.33 x CT” (from 2000 A pickup / 600 A primary)
NEUTRAL INST OC 2 DELAY: “0.00 s”
The Ground Overcurrent element is disabled by entering the following values in the S5
PROTECTION  GROUND CURRENT  GROUND TIME OVERCURRENT setpoints page:
“Disabled”
“Disabled”
GROUND TIME O/C FUNCTION:
GROUND INST O/C FUNCTION:
The Negative Sequence Overcurrent elements is disabled by entering the following values
in the S5 PROTECTION  NEGATIVE SEQUENCE setpoints page:
NEG SEQ TIME OVERCURRENT  NEG SEQ TIME OC FUNCTION: “Disabled”
NEG SEQ INST OVERCURRENT  NEG SEQ INST OC FUNCTION:
1.4.5
“Disabled”
Installation
Now that programming for the sample application is complete, the relay should be put in
the Ready state. Note that the relay is defaulted to the Not Ready state when it leaves the
factory. A minor self-test warning message informs the user that the 750/760 has not yet
been programmed. If this warning is ignored, protection is active and will be using factory
default setpoints. The Relay In Service LED Indicator will be on.
The following message indicates that the relay is in the Not Ready state:
SELF-TEST WARNING
Relay Not Ready
Move to the S1 RELAY SETUP  INSTALLATION  750 OPERATION setpoint message. To put
the relay in the Ready state, press the VALUE  key until the READY message is displayed
and press ENTER . Enter “Yes” at the ARE YOU SURE? prompt. The Relay In Service LED
Indicator will now turn on and the SELF TEST WARNING: Relay Not Ready diagnostic
message will disappear.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
1 - 27
COMMISSIONING
1.5
CHAPTER 1: GETTING STARTED
Commissioning
Extensive commissioning tests are available in Chapter : Commissioning.
Commissioning tables for recording required settings are available in Microsoft Excel
format from the GE Multilin website at http://www.gedigitalenergy.com. The website also
contains additional technical papers and FAQs relevant to the 750/760 Feeder
Management Relay.
1 - 28
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
GE
Digital Energy
750/760 Feeder Management
Relay
Chapter 2: Introduction
Introduction
2.1
Overview
2.1.1
Description
The 750/760 Feeder Management Relays are microprocessor-based units intended for the
management and primary protection of distribution feeders, as well as for the
management and backup protection of buses, transformers, and transmission lines. The
760 relay is particularly suited to overhead feeders, where automatic reclosing is normally
applied.
Each relay provides protection, control, and monitoring functions with both local and
remote human interfaces. They also display the present trip/alarm conditions, and most of
the more than 35 measured system parameters. Recording of past trip, alarm or control
events, maximum demand levels, and energy consumption is also performed.
These relays contain many innovative features. To meet diverse utility standards and
industry requirements, these features have the flexibility to be programmed to meet
specific user needs. This flexibility will naturally make a piece of equipment difficult to
learn. To aid new users in getting basic protection operating quickly, setpoints are set to
typical default values and advanced features are disabled. These settings can be
reprogrammed at any time.
Programming can be accomplished with the front panel keys and display. Due to the
numerous settings, this manual method can be somewhat laborious. To simplify
programming and provide a more intuitive interface, setpoints can be entered with a PC
running the EnerVista 750/760 Setup software provided with the relay. Even with minimal
computer knowledge, this menu-driven software provides easy access to all front panel
functions. Actual values and setpoints can be displayed, altered, stored, and printed. If
settings are stored in a setpoint file, they can be downloaded at any time to the front panel
program port of the relay via a computer cable connected to the serial port of any
personal computer.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
2-1
OVERVIEW
CHAPTER 2: INTRODUCTION
A summary of the available functions and a single-line diagram of protection and control
features is shown below. For a complete understanding of each feature operation, refer to
Chapter 5: Setpoints. The logic diagrams include a reference to every setpoint related to a
feature and show all logic signals passed between individual features. Information related
to the selection of settings for each setpoint is also provided.
2-2
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
OVERVIEW
FEE
ANSI
DE
R
Ca
pac
ito
r
Ra
d ia
l
Tw
o-e
nd
ed
BU
S
Ba
cku
p
Tra
nsf
er
TR
AN
SFO
Ba
cku RMER
p
LIN
E
Ba
cku
p
CHAPTER 2: INTRODUCTION
PROTECTION / CONTROL
27
Bus / Line Undervoltage
47
Negative Sequence Voltage
50
Phase/Neutral/Gnd/Neg Seq/Sens Gnd Inst O/C
51
Phase/Neutral/Gnd/Neg Seq/Sens Gnd Time O/C
59
Bus Overvoltage/Neutral Displacement
67
Phase/Neutral/Neg Seq/Sens Gnd/Gnd Directional Control
81
Bus Underfrequency/Rate of Change
Undervoltage Automatic Restoration
Underfrequency Automatic Restoration
Breaker Failure with Current Superv.
Bus Transfer
Programmable Logic Inputs
Multiple Setpoint Groups
MONITORING / CONTROL
25
Synchrocheck
50
Phase/Neutral Current Level
55
Power Factor
79
Autoreclose (760 only)
81
Overfrequency
Breaker Open/Close
Manual Close Feature Blocking
Cold Load Pickup Feature Blocking
Breaker Operation Failure
Trip/Close Circuit Failure
Total Breaker Arcing Current
VT Failure
Demand (A, MW, Mvar, MVA)
Analog Input
Event Recording
Analog Output
Fault Locator
Trip Counter
826712A1.CDR
FIGURE 2–1: Summary of Features
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
2-3
OVERVIEW
CHAPTER 2: INTRODUCTION
SOURCE
dcmA
Rate
Level
OUTPUTS
750/760
Feeder Management Relay ¨
N
Trip Relay
Close Relay
:
5 Auxiliary Relays
Self-Test Warning Relay
8 Analog Outputs
Bus VT
:
27
1+2
59
1+2
Breaker 52
Coil Monitors
81U
1+2
25
Trip
Breaker Operation
Line VT
Calc.
I2
50
BF
50P
Level
CONTROL
Synchronism Check
Cold Load Pickup
Manual Close
Undervoltage Restoration
Underfrequency Restoration
VT
Fail
51V
Calc.
V1
27
3+4
Calc.
3Io
Calc.
3Vo
59N
Calc.
V2
1
810
Phase A only
Close
3
81
Decay
50P
Demand
55
1+2
Calc.
I1
Transfer
Auto Reclose (760)
Current
Supervision
Zone
Coordination
Calc.
I2
79X
MONITOR
50P
1+2
51P
1+2
760 Only
47
Control
46/50
67P
46/51
46/67
Calc.
V2
51N
1+2
67N
Calc.
-Vo
Control
50N
Level
50N
1+2
Control
50G
51G
67G
51SG
67SG
Control
SENSITIVE GROUND
OPERATING CURRENT
50SG
POLARIZING CURRENT*
GROUND
OPERATING CURRENT
Power Factor
Demand
Tripping
Arcing
Fault Locator
Analog Input
Overfrequency
VT Failure
Event Recorder
Oscillograph
Data Logger
COMMUNICATIONS
1 x RS232
2 x RS485 OR
1 x RS422
Modbus RTU
DNP 3.0
Control
818840AD.dwg
* POLARIZING CURRENT AND GND CURRENT
ARE MUTUALLY EXCLUSIVE SINCE BOTH USE
THE SAME RELAY CT INPUT TERMINALS
FIGURE 2–2: Functional Block Diagram
2-4
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 2: INTRODUCTION
2.2
THEORY OF OPERATION
Theory of Operation
2.2.1
Description
Relay functions are controlled by two processors: a Motorola 68332 32-bit microprocessor
measures all analog signals and logic inputs, outputs all analog signals, and controls all
output relays; a Grid Connect DSTni-LX Turbo 186 16-bit microprocessor reads all user
input including communications, and outputs to the faceplate display and LEDs. The
processors pass information to each other via an RS485 serial communications channel.
The remainder of this section describes the algorithms and operations that are critical to
protection elements.
2.2.2
Current and Voltage Waveform Capture
Current and voltage transformers (CTs and VTs) are used to scale-down the incoming
current and voltage signals from the source instrument transformers. The current and
voltage signals are then passed through a 400 Hz low pass anti-aliasing filter. All signals
are then simultaneously captured by sample and hold buffers to ensure there are no phase
shifts. The signals are converted to digital values by a 12-bit A/D converter before finally
being passed on to the 68332 CPU for analysis.
Both current and voltage are sampled sixteen times per power frequency cycle with
frequency tracking control. These ‘raw’ samples are calibrated in software and then placed
into the waveform capture buffer thus emulating a fault recorder. The waveforms can be
retrieved from the relay via the EnerVista 750/760 Setup software for display and
diagnostics.
2.2.3
Frequency Tracking
Frequency measurement is done by measuring the time between zero crossings of the Bus
VT A and Line VT voltage inputs. Both signals are passed through a 72 Hz low pass filter to
prevent false zero crossings. Frequency readings are discarded if the rate of change
between two successive cycles is greater than 10 Hz/second. This prevents momentary
false frequency readings due to noise, phase reversals, or faults.
Frequency tracking utilizes the measured frequency to set the sampling rate for current
and voltage which results in better accuracy for the FFT algorithm for off-nominal
frequencies. Also, sampling is synchronized to the Va-x voltage zero crossing which results
in better co-ordination for multiple 750/760 relays on the same bus. If a stable frequency
signal is not available then the sampling rate defaults to the nominal system frequency.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
2-5
THEORY OF OPERATION
2.2.4
CHAPTER 2: INTRODUCTION
Phasors, Transients, and Harmonics
Current waveforms are processed once every cycle with a DC Offset Filter and a Fast
Fourier Transform (FFT) to yield phasors at the fundamental power system frequency. The
resulting phasors have fault current transients and all harmonics removed. This results in
an overcurrent relay that is extremely secure and reliable and one that will not overreach.
The following diagram illustrates the signal processing performed on the AC current inputs:
996709A1.CDR
2.2.5
Processing of AC Current Inputs
The DC Offset Filter is an infinite impulse response (IIR) digital filter which removes the DC
component from the asymmetrical current present at the moment a fault occurs. This is
done for all current signals used for overcurrent protection; voltage signals bypass the DC
Offset Filter. The filter results in no overreach of the overcurrent protection; unfortunately,
the filter also causes slower overcurrent response times (0 to 50 ms) for faults marginally
over the pickup level.
The Fast Fourier Transform (FFT) uses exactly one cycle of samples to calculate a phasor
quantity which represents the signal at the fundamental frequency only; all harmonic
components are removed. Further explanation of the FFT is beyond the scope of this
discussion but can be found in any text on signal analysis. All subsequent calculations (e.g.
RMS, power, demand, etc.) are based upon the current and voltage phasors so the resulting
values do not have any harmonic components either.
A novel filtering of the phase and ground currents is employed on the relay to assure fast
and secure Phase and Ground Instantaneous over-current operation. With an integrated
CT saturation detection mechanism, these protections can detect and produce stable
operation even for fault currents heavily distorted by the saturation of the Current
Transformers.
2.2.6
Protection Elements
All protection elements are processed once every cycle to determine if a pickup has
occurred or a timer has expired. The protection elements use RMS current/voltage based
on the magnitude of the phasor; hence, protection is impervious to both harmonics and DC
transients. Timing is not affected by system frequency.
The phase input currents for the Phase over-current protections are estimated at rate of
four times per cycle.
The figure below presents the IOC trip times – from fault inception till closure of a trip rated
output – of the 750 relay. The response time depends on the ratio between the fault
current and the applied setting and varies from 16ms for high multiples of pickup to 25ms
for multiple of 1.2 times pickup.
2-6
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 2: INTRODUCTION
2.2.7
THEORY OF OPERATION
Logic Inputs
Contact inputs are de-bounced to eliminate false operations due to noise. The inputs must
be in the same state for three consecutive readings spaced evenly over one power
frequency cycle before a new state is recognized.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
2-7
THEORY OF OPERATION
CHAPTER 2: INTRODUCTION
MAIN
PROCESSOR
COMMUNICATION
PROCESSOR
818839A9.cdr
FIGURE 2–3: Hardware Block Diagram
2-8
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 2: INTRODUCTION
2.3
ORDERING
Ordering
2.3.1
Order Codes
The relay model number will be indicated on the side of the drawout unit. This
identification label can be interpreted with the following order code.
Base Unit
750 –
*
–
*
–
*
–
*
–
*
–
*
–
*
–
*
760 –
*
–
*
–
*
–
*
–
*
–
*
–
*
–
*
750
760
Phase Current
Inputs
|
|
P1
P5
Zero-Sequence
Current Inputs
|
|
|
|
G1
G5
Sensitive Ground or
Polarizing Current Input
|
|
|
|
|
|
S1
S5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
D1
|
|
|
|
|
D5
|
|
|
|
|
|
|
|
|
A1
A5
A10
A20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
B
E
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LO
Control Power
HI
Analog
Outputs
R
Breaker
Closed LED
G
Display/Ethernet
T
Environmental Protection
2.3.2
H
750 Feeder Management Relay
760 Feeder Management Relay
750 relay
760 relay with autoreclose
1 A phase current inputs
5 A phase current inputs
1 A zero-sequence current inputs
5 A zero-sequence current inputs
1 A sensitive ground current input
5 A sensitive ground current input
1 A polarizing current input
(MOD009)
5 A polarizing current input
(MOD009)
20 to 60 V DC;
20 to 48 V AC at 48 to 62 Hz
88 to 300 V DC;
70 to 265 V AC at 48 to 62 Hz
Eight (8) 0 to 1 mA analog outputs
Eight (8) 0 to 5 mA analog outputs
Eight (8) 0 to 10 mA analog outputs
Eight (8) 4 to 20 mA analog outputs
Red LED for Breaker Closed indicator
Green LED for Breaker Closed
indicator
Discontinued: Basic display
Enhanced display
Enhanced display with Ethernet
Harsh (Chemical) Environment
Conformal Coating
Example Order Codes
1.
The 750-P1-G1-S1-LO-A10-R-B specifies a 750 Feeder Management Relay
with 1 A phase, zero-sequence, and sensitive ground current Inputs, low
control power, eight 0 to 10 mA analog outputs, a red LED for the Breaker
Closed indicator, and a basic display.
2.
The 760-P5-G5-S5-HI-A20-G-T specifies a 760 Feeder Management Relay
with autoreclose, 5 A phase, zero-sequence, and sensitive ground current
inputs, high control power, eight 4 to 20 mA analog outputs, a green LED for
the Breaker Closed indicator, and enhanced display with Ethernet (10Base-T).
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
2-9
ORDERING
2.3.3
CHAPTER 2: INTRODUCTION
Accessories
• DEMO: Metal carry case in which the 750/760 can be mounted
• SR19-1 or SR19-2 PANEL: Single or double cutout 19-inch panels
• RS-232/485: RS232 to RS485 converter box for harsh industrial environments
• 1 A and 5 A PHASE CTs: 50, 75, 100, 150, 200, 250, 300, 350, 400, 500, 600, 750,
and 1000 CT ratios
• SR 1 3
--- -inch COLLAR: For shallow switchgear, the collar reduces the depth of the
8
relay by 1 3/8 inches
• SR 3-inch COLLAR: For shallow switchgear, the collar reduces the depth of the
relay by 3 inches.
2 - 10
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 2: INTRODUCTION
2.4
SPECIFICATIONS
Specifications
2.4.1
Applicability
APPLICABILITY
Systems:
Frequency:
2.4.2
3 or 4 wire, 600 kV maximum
5000 A maximum
25 to 60 Hz nominal
(frequency tracking allows operation from 16 to 65 Hz)
Inputs
CONTROL POWER
Options:
LO range:
LO/HI (specify with order)
20 to 60 V DC
20 to 48 V AC at 48 to 62 Hz
HI range:
88 to 300 V DC
70 to 265 V AC at 48 to 62 Hz
Power:
25 VA nominal, 35 VA max.
Total loss of voltage ride through time
(0% control power): 16 ms
PHASE CURRENT
Source CT:
1 to 50000 A primary,
1 or 5 A secondary
Relay input:
1 A or 5 A (specify with order)
Conversion range:
0.01 to 20 × CT
(fundamental frequency only)
Accuracy:
at < 2 × CT: ±0.5% of 2 × CT
at ≥ 2 × CT: ±1% of 20 × CT
Overload withstand:
1 second at 80 × rated current; continuous at 3 × rated current
Calculated neutral current errors:3 × phase inputs
GROUND CURRENT
Source CT:
Relay input:
Conversion range:
Accuracy:
Overload withstand:
1 to 50000 A primary,
1 or 5 A secondary
1 A or 5 A (specify with order)
0.01 to 20 × CT (fundamental frequency only)
at < 2 × CT: ±0.5% of 2 × CT
at ≥ 2 × CT: ±1% of 20 × CT
1 second at 80 × rated current; continuous at 3 × rated current
CT Input
Current
1 A Phase &
Ground
5 A Phase &
Ground
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
Burden (typical)
VA
OHMS
1A
5A
20 A
0.025 VA
0.60 VA
10 VA
0.02
5A
25 A
100 A
0.40 VA
10 VA
120 VA
0.02
2 - 11
SPECIFICATIONS
CHAPTER 2: INTRODUCTION
SENSITIVE GROUND CURRENT
Source CT:
1 to 50000 A primary,
1 or 5 A secondary
Relay input:
1 A or 5 A (specify with order)
Burden:
< 0.2 VA at 1 or 5 A
Conversion range: Low end: 0.005 × CT
Maximum: 500 A primary
(fundamental frequency only)
Accuracy:
at < 0.1 × CT: ±0.2% of 1 × CT
at ≥ 0.1 × CT: ±1% of 1 × CT
Overload withstand:
1 second at 80 × rated current; continuous at 3 × rated current
BUS AND LINE VOLTAGE
Source VT:
Source VT ratio:
Relay input:
Burden:
Maximum continuous:
Accuracy (0 to 40°C):
0.12 to 600 kV / 50 to 240 V
1 to 5000 in steps of 0.1
50 to 240 V phase-neutral
< 0.025 VA at 120 V
or > 576 KW
273 V phase-neutral (full-scale) at fundamental frequency only
±0.25% of full scale (11 to 130 V); ±0.8% of full scale (130 to 273
V). For open delta, the calculated phase has errors 2 times
those shown.
LOGIC INPUTS
Inputs:
Dry contacts:
Wet contacts:
14 contact and / or virtual inputs, 6 virtual only (functions
assigned to logic inputs)
1000 Ω maximum ON resistance (32 V DC at 2 mA provided by
relay)
30 to 300 V DC at 2.0 mA
(external DC voltage only)
ANALOG INPUT
Current Input:
Input impedance:
Conversion range:
Accuracy:
0 to 1 mA, 0 to 5 mA, 0 to 10 mA, 0 to 20 mA, or 4 to 20 mA
(programmable)
375 Ω ± 10%
0 to 21 mA
±1% of full scale
TRIP & CLOSE COIL MONITORING
Acceptable voltage range: 20 to 250 V DC
Trickle current:
2 to 5 mA
IRIG-B
Amplitude modulated:
DC shift:
Input impedance:
Error:
2.4.3
Measured Parameters
Note
NOTE
2 - 12
2.5 to 6 Vpk-pk at 3:1 signal ratio
TTL
20 kΩ ±10%
±1.0 ms
In the following specifications, accuracies are based on less than 2 × CT and 50 to 130 V
inputs. The full-scale is defined as follows: Full Scale = 2 × CT at 1 × VTFull Scale × 3 .
The harmonic components of current and voltage are removed from the input voltage and
current parameters, so all relay measurements based on these quantities respond to the
fundamental component only. To minimize errors, the A/D process utilizes a sampling rate
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 2: INTRODUCTION
SPECIFICATIONS
that is automatically adjusted to be 16 samples per power frequency cycle when a
measurable voltage is available. To prevent overreaching of overcurrent elements, a digital
filter removes the transient DC component of currents.
CURRENT
Phasors:
Phase A RMS current
Phase B RMS current
Phase C RMS current
% of load-to-trip accuracy: ±0.5% of full-scale
VOLTAGE
Phasors:
Accuracy:
Phase A-N (A-B) voltage
Phase B-N (B-C) voltage
Phase C-N (C-A) voltage
±0.25% of full scale
FREQUENCY
Measured:
Range:
Accuracy:
A-N (A-B) bus and line voltage
16 to 65 Hz
±0.02 Hz
SYMMETRICAL COMPONENTS
Current level accuracy:
±1.5% of full scale
Voltage level accuracy:
±0.75% of full scale
Current and voltage angle accuracy: ±2°
3Φ POWER FACTOR
Range:
Accuracy:
0.00 Lag to 1.00 to 0.00 Lead
±0.02
3Φ REAL POWER
Range:
Accuracy:
–3000.0 to 3000.0 MW
±1% of full scale
3Φ REACTIVE POWER
Range:
Accuracy:
–3000.0 to 3000.0 Mvar
±1% of full scale
(see note above)
3Φ APPARENT POWER
Range:
Accuracy:
–3000.0 to 3000.0 MVA
±1% of full scale (see note above)
WATT-HOURS
Range:
Accuracy:
–2.1 × 108 to 2.1 × 108 MWh
±2% of full scale (see note above) per hour
VAR-HOURS
Range:
Accuracy:
–2.1 × 108 to 2.1 × 108 Mvarh
±2% of full scale (see note above) per hour
DEMAND RANGE
Phase A/B/C current:
3Φ real power:
3Φ reactive power:
3Φ apparent power:
0 to 65535 A
–3000.0 to 3000.0 MW
–3000.0 to 3000.0 Mvar
–3000.0 to 3000.0 MVA
DEMAND MEASUREMENT
Thermal exponential, 90% response time (programmed):
5, 10, 15, 20, 30, or 60 min.
Block interval / rolling demand, time interval (programmed):
5, 10, 15, 20, 30, or 60 min.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
2 - 13
SPECIFICATIONS
CHAPTER 2: INTRODUCTION
Accuracy:
2.4.4
±2% of full scale
(see note above)
Protection Elements
PHASE / NEUTRAL / GROUND / NEGATIVE SEQUENCE TIME OVERCURRENT
Pickup level:
Dropout level:
Curves:
Curve multiplier:
Reset type:
Level accuracy:
Timing accuracy:
0.05 to 20.00 × CT in steps of 0.01
97 to 98% of pickup level, or pickup level minus 2% of nominal
current (0.02 x CT), whichever is less
ANSI Extremely/Very/Moderately/Normally Inverse, Definite
Time (0.1 s base curve), IEC Curve A/B/C and Short, FlexCurve™
A/B (programmable curves), IAC Extreme/Very/Inverse/Short
0 to 100.00 in steps of 0.01
Instantaneous/Linear
per current input
(I2 is 3 × input error)
±3% of trip time or ±40 ms (whichever is greater) at ≥ 1.03 × PU
SENSITIVE GROUND TIME OVERCURRENT
Pickup level:
Dropout level:
Curves:
Curve multiplier:
Reset type:
Level accuracy:
Timing accuracy:
0.005 to 1.000 × CT in steps of 0.001
97 to 98% of pickup level, or pickup level minus 2% of nominal
current (0.02 x CT), whichever is less
ANSI Extremely/Very/Moderately/Normally Inverse, Definite
Time (0.1 s base curve), IEC Curve A/B/C and Short, FlexCurve™
A/B (programmable curves), IAC Extreme/Very/Inverse/Short
0 to 100.00 in steps of 0.01
Instantaneous/Linear
per sensitive ground current input
±3% of trip time or ±40 ms (whichever is greater) at ≥ 1.03 × PU
VOLTAGE RESTRAINED PHASE TIME OVERCURRENT
Pickup adjustment:
Modifies pickup from 0.10 to 0.90 × VT nominal in a fixed line
relationship
PHASE / GROUND INSTANTANEOUS OVERCURRENT
0.05 to 20.00 × CT in steps of 0.01
97 to 98% of pickup level, or pickup level minus 2% of nominal
current (0.02 x CT), whichever is less
Time delay:
0 to 600.00 s in steps of 0.01
Level accuracy:
per phase / neutral / ground current input (I2 is 3 × phase input
error)
Operate time (Phase instantaneous, 0 ms time delay): 25 ms max. (output relay included),
1.5 x pickup @ 60 Hz, and 20 ms max. (solid state output
included), 1.5 x pickup @ 60 Hz
Operate time (Ground instantaneous, 0 ms time delay): 50 ms max. (output relay included),
1.5 x pickup @ 60 Hz, and 45 ms max. (solid state output
included), 1.5 x pickup @ 60 Hz
Timing accuracy:
±20 ms or ±0.1% of time delay setting (whichever is greater)
Phases:
Any one, any two, or all three (programmable) phases must
operate for output (not for I2)
Pickup level:
Dropout level:
NEUTRAL / NEGATIVE SEQUENCE INSTANTANEOUS OVERCURRENT
Pickup level:
Dropout level:
Time delay:
2 - 14
0.05 to 20.00 × CT in steps of 0.01
97 to 98% of pickup level, or pickup level minus 2% of nominal
current (0.02 x CT), whichever is less
0 to 600.00 s in steps of 0.01
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 2: INTRODUCTION
SPECIFICATIONS
per phase / neutral / ground current input (I2 is 3 × phase input
error)
Operate time (0 ms time delay): 50 ms max. (output relay included), 1.5 x pickup @ 60 Hz,
and 45 ms max. (solid state output included), 1.5 x pickup @ 60
Hz
Timing accuracy:
±20 ms or ±0.1% of time delay setting (whichever is greater)
Phases:
Any one, any two, or all three (programmable) phases must
operate for output (not for I2)
Level accuracy:
SENSITIVE GROUND INSTANTANEOUS OVERCURRENT
0.005 to 1.000 × CT in steps of 0.001
97 to 98% of pickup level, or pickup level minus 2% of nominal
current (0.02 x CT), whichever is less
Time delay:
0 to 600.00 s in steps of 0.01
Level accuracy:
per sensitive ground current input
Operate time (0 ms time delay): 50 ms max. (output relay included), 1.5 x pickup @ 60 Hz,
and 45 ms max. (solid state output included), 1.5 x pickup @ 60
Hz
Timing accuracy:
±20 ms or ±0.1% of time delay setting (whichever is greater)
Pickup level:
Dropout level:
PHASE DIRECTIONAL
Relay Connection:
Polarizing Voltage:
MTA:
Angle Accuracy:
Operation Delay:
90° (quadrature)
Vbc (phase A); Vca (phase B); Vab (phase C)
0 to 359° in steps of 1
±2°
25 to 40 ms
NEUTRAL DIRECTIONAL
Polarized by voltage, current, or both voltage and current. For voltage element polarizing,
the source VTs must be connected in Wye.
Note
NOTE
Polarizing voltage:
Polarizing current:
MTA:
Angle accuracy:
Operation delay:
–Vo
Ig
0 to 359° in steps of 1
±2°
25 to 40 ms
GROUND / SENSITIVE GROUND DIRECTIONAL
Polarized by voltage, current, or both voltage and current. For voltage element polarizing,
the source VTs must be connected in Wye.
Note
NOTE
Polarizing voltage:
Polarizing current:
MTA:
Angle accuracy:
Operation delay:
–Vo
Ig
0 to 359° in steps of 1
±2°
25 to 40 ms
BUS / LINE UNDERVOLTAGE
Minimum voltage: >
Pickup level:
Dropout level:
Curve:
Time delay:
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
programmable threshold from 0.00 to 1.25 × VT in steps of 0.01
0 to 1.25 × VT in steps of 0.01
102 to 103% of pickup
Definite Time or Inverse Time
0 to 6000.0 s in steps of 0.1
2 - 15
SPECIFICATIONS
CHAPTER 2: INTRODUCTION
Phases:
Level accuracy:
Timing accuracy:
Any one, any two, or all three (programmable) phases must
operate for output (Bus Undervoltage only)
per voltage input
±100 ms
OVERVOLTAGE
Pickup level:
Dropout level:
Time delay:
Phases:
Level accuracy:
Timing accuracy:
0 to 1.25 × VT in steps of 0.01
97 to 98% of pickup level
0.0 to 6000.0 s in steps of 0.1
(Definite Time)
Any one, any two, or all three (programmable) phases must
operate for output
per voltage input
±100 ms
NEGATIVE SEQUENCE VOLTAGE
Pickup level:
Dropout level:
Time delay:
Level accuracy:
Timing accuracy:
0 to 1.25 × VT in steps of 0.01
97 to 98% of pickup level
0 to 6000.0 s in steps of 0.1
(Definite Time / Inverse Time)
3 × voltage input error
±100 ms
UNDERFREQUENCY
Minimum voltage:
Pickup level:
Dropout level:
Time delay:
Level accuracy:
Timing accuracy:
0 to 1.25 × VT in steps of 0.01 in Phase A
20 to 65 Hz in steps of 0.01
Pickup + 0.03 Hz
0 to 600.00 s in steps of 0.01
(Definite Time)
±0.02 Hz
±100 ms
BREAKER FAILURE
Pickup level:
Dropout level:
Time delay:
Timing accuracy:
Level accuracy:
0.05 to 20.0 × CT in steps of 0.01
97 to 98% of pickup level
0.03 to 1.00 s in steps of 0.01
±20 ms error
per CT input
NEUTRAL DISPLACEMENT
Pickup level:
Dropout level:
Curves:
Curve multiplier:
Reset type:
Level accuracy:
Timing accuracy:
0.00 to 1.25 × VT in steps of 0.01
97 to 98% of pickup level
ANSI Extremely/Very/Moderately/Normally Inverse, Definite
Time (0.1 s base curve), IEC Curve A/B/C and Short, FlexCurve™
A/B (programmable curves), IAC Extreme/Very/Inverse/Short
0 to 100.00 in steps of 0.01
Instantaneous/Linear
3 × voltage input error
±50 ms
REVERSE POWER (IF ENABLED)
Pickup level:
Dropout level:
Reset time:
Level accuracy:
Time delay:
Timing accuracy:
2 - 16
0.015 to 0.600 × rated power
94 to 95% of pickup
less than 100 ms
see 3Φ Real Power metering
0.0 to 6000.0 s in steps of 0.1
±200 ms (includes Reverse Power pickup time)
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 2: INTRODUCTION
2.4.5
SPECIFICATIONS
Monitoring Elements
PHASE/NEUTRAL CURRENT
Pickup level:
Dropout level:
Time delay:
Level accuracy:
Timing accuracy:
0.05 to 20.00 × CT in steps of 0.01
97 to 98% of pickup level
0 to 60000 s in steps of 1 (Definite Time)
per current input
±100 ms
POWER FACTOR
Required voltage:
Pickup level:
Dropout level:
Time delay:
Level accuracy:
Timing accuracy:
>30% of nominal in all phases
0.50 lag to 0.50 lead in steps of 0.01
0.50 lag to 0.50 lead in steps of 0.01
0 to 60000 s in steps of 1 (Definite Time)
±0.02
±100 ms
ANALOG INPUT THRESHOLD
Pickup level:
Dropout level:
Time delay:
Level accuracy:
Timing accuracy:
0 to 65535 units in steps of 1
2 to 20% of Pickup
(programmable, under/over)
0 to 60000 s in steps of 1
±1%
±100 ms
ANALOG INPUT RATE
Pickup level:
Dropout level:
Time delay:
Level accuracy:
Timing accuracy:
–1000 to 1000 units/hour in steps of 0.1
97 to 98% of pickup level
0 to 60000.0 s in steps of 1
±1%
±100 ms
OVERFREQUENCY
Required voltage:
Pickup level:
Dropout level:
Time delay:
Level accuracy:
Timing accuracy:
>30% of nominal, phase A
20.01 to 65.00 Hz in steps of 0.01
Pickup – 0.03 Hz
0.0 to 6000.0 s in steps of 0.1
±0.02 Hz
±100 ms
FAULT LOCATOR
Range:
Memory:
–327 to 327 km (or miles)
0 to 65534 ohms
stores 10 most recent faults
DATA LOGGER
Channels:
Sample rate:
Trigger source:
Trigger position:
Storage:
8 channels; same parameters as for analog outputs available
per cycle / per second / per minute / every 5, 10, 15, 20, 30, or
60 minutes
pickup/trip/dropout, control/alarm event, logic input, manual
command, or continuous
0 to 100%
2 to 16 events with 2048 to 256 samples of data respectively
(4096 if continuous)
TRIP COUNTERS
Accumulates all ground, sensitive ground, neutral, negative sequence, and phase
overcurrent trips.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
2 - 17
SPECIFICATIONS
CHAPTER 2: INTRODUCTION
DEMAND
Demand accuracies are based on less than 2 × CT and 50 to 130 V inputs.
Note
NOTE
Measured values:
Phase A/B/C current (A), 3Φ real power (MW), 3Φ reactive power
(Mvar), 3Φ apparent power (MVA)
Measurement type:
Thermal Exponential, 90% response time (programmed):
5, 10, 15, 20, 30, or 60 min.
Block Interval / Rolling Demand, time interval (programmed):
5, 10, 15, 20, 30, or 60 min.
Block Interval with Start Demand Interval Logic Input pulses
- Amps pickup level:
10 to 10000 in steps of 1
- MW pkp level:
0.1 to 3000.0 in steps of 0.1
- Mvar pkp level:
0.1 to 3000.0 in steps of 0.1
- MVA pkp level:
0.1 to 3000.0 in steps of 0.1
- Level accuracy:
±2%
VT FAILURE
Programmable to inhibit dependent features.
BREAKER FAILURE TO OPERATE
Time delay:
Timing accuracy:
30 to 1000 ms in steps of 10
0 to 20 ms error
ACCUMULATED ARCING CURRENT
Pickup level:
Start delay:
1 to 50000 kA2-cycles in steps of 1
0 to 100 ms in steps of 1
TRIP / CLOSE COIL MONITORS
Detect open trip and close circuits.
PULSED OUTPUT
Pulsed output is 1 second on time and one second off time after the programmed interval.
LAST TRIP DATA
Records cause of most recent trip, 4 RMS currents, and 3 RMS voltages with a 1 ms time
stamp.
WAVEFORM CAPTURE
Channels:
Sample rate:
Trigger source:
Trigger position:
Storage:
4 currents, 3 voltages, 14 logic input states and 8 output relays
16 per cycle
Element pickup/trip/dropout, control/alarm event, logic input
or manual command
0 to 100%
2 to 16 events with 4096 to 512 samples of data respectively
EVENT RECORDER
Number of events:
Content:
2.4.6
512
event cause, 3 phase current phasors, 1 ground current phasor,
sensitive ground current phasors, 3 voltage phasors, system
frequency, synchronizing voltage, synchronizing frequency, and
analog input level with a 1 ms time stamp.
Control Elements
SYNCHROCHECK
Voltage difference:
Phase difference:
Frequency difference:
2 - 18
0.01 to 100.00 kV in steps of 0.01
0 to 100° in steps of 1
0.00 to 5.00 Hz in steps of 0.01
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 2: INTRODUCTION
SPECIFICATIONS
Operate time:
Bypass permissives:
up to 140 ms for 60 Hz
up to 160 ms for 50 Hz
DB & DL (dead bus and dead line)
LL & DB (live line and dead bus)
DL & LB (dead line and live bus)
DL | DB (dead line or dead bus)
DL X DB (either dead line or dead bus)
SETPOINT GROUPS
Number of groups:
Accessibility:
Included features:
4
Can be changed from logic input or through communications
TOC Curves, Phase TOC and IOC, Neutral TOC and IOC, Ground
TOC and IOC, Negative Sequence OC and Voltage, Phase
Directional, Ground Directional, Overvoltage, Undervoltage,
Underfrequency, Breaker Failure
UNDERVOLTAGE RESTORATION
Initiated by:
Minimum voltage level:
Time delay:
Incomplete seq. time:
Phases:
Level accuracy:
Timing accuracy:
Trip from Undervoltage 1 to 4
0.00 to 1.25 × VT in steps of 0.01
0 to 10000 s in steps of 1
1 to 10000 min. in steps of 1
Any one, any two, or all three (programmable) phases must
operate for output
per voltage input
±100 ms
UNDERFREQUENCY RESTORATION
Initiated by:
Minimum voltage level:
Minimum freq. level:
Time delay:
Incomplete seq. time:
Level accuracy:
Timing accuracy:
Trip from Underfrequency 1/2
0.00 to 1.25 × VT in steps of 0.01
20.00 to 65.00 Hz in steps of 0.01
0 to 10000 s in steps of 1
1 to 10000 min. in steps of 1
Per voltage and frequency input
±100 ms
MANUAL CLOSE BLOCKING
Operated by:
Programmability:
manual close command.
Block IOC for a selected period. raise TOC pickup for a selected
period.
COLD LOAD PICKUP BLOCKING
Operated by:
Programmability:
logic input command or automatically
Block IOC for a selected period; raise TOC pickup for a selected
period.
TRANSFER SCHEME
Applicability:
Closing:
Trip:
Used for double-bus system with two normally-closed
incoming and one normally-open bus tie circuit breaker.
Automatic closing of the bus tie breaker after a loss of one
source, with bus decayed voltage permissive.
Trips a pre-selected breaker after the third breaker is manually
closed (prevent parallel operation).
AUTORECLOSE (760 ONLY)
Reclose attempts:
Blocking:
Adjustability:
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
Up to four (4) before lockout.
Each reclose shot can block IOC and raise TOC Pickup.
Current supervision can adjust the maximum number of shots
to be attempted.
2 - 19
SPECIFICATIONS
2.4.7
CHAPTER 2: INTRODUCTION
Outputs
ANALOG OUTPUTS
Type:
Outputs:
Ranges:
Max. load:
Isolation:
Accuracy:
Response:
Active
8 Channels; specify one of the following output ranges when
ordering:
0 to 1 mA, 0 to 5 mA, 0 to 10 mA, 4 to 20 mA
12 kΩ for 0 to 1 mA output,
2.4 kΩ for 0 to 5 mA output,
1.2 kΩ for 0 to 10 mA output,
600 Ω for 4 to 20 mA output
Fully isolated
±1% of full scale
100% indication in less than 6 power system cycles (100 ms at
60 Hz)
SOLID STATE TRIP
Make & carry:
2.4.8
15 A at 250 V DC for 500 ms
Output Relays
Relay contacts must be considered unsafe to touch when the 750/760 is energized! If the
output relay contacts are required for low voltage accessible applications, it is the
customer’s responsibility to ensure proper insulation levels.
CONFIGURATION
Number:
Type:
Contacts:
Durability:
8
Form A: Trip (1) and Close (2) Relays
Form C: Auxiliary Relays 3 to 7 and Self-Test Warning Relay 8
silver alloy
100 000 operations (at 1800 operations/hour) at rated load
TRIP CONTACT (FORM A) RATINGS
Applicability:
Make and carry:
Carry:
Break:
Trip and Close Relays (relays 1 and 2)
30 A (per ANSI/IEEE C37.90)
10 A @ 250 VAC (continuous)
0.4 A @ 250 VDC (L/R = 40 ms)
SERVICE CONTACT (FORM C) RATINGS
Applicability:
Make and Carry:
Carry:
Break:
2.4.9
Auxiliary Relays (relays 3 to 7), and Self-Test Warning Relay
(relay 8)
30 A (per ANSI/IEEE C37.90)
5 A @ 250 VAC (continuous)
0.3 A @ 250 VDC (L/R = 40 ms)
3 A @ 240 VAC (P.F. = 0.4)
CPU
COMMUNICATIONS
Baud rate:
Parity:
Protocol:
Ethernet:
2 - 20
300 to 19200 baud
programmable
Modbus RTU or DNP 3.0
10Base-T RJ45 connector
Modbus TCP/IP
Version 2.0 / IEEE 802.3
Maximum 4 sessions
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 2: INTRODUCTION
SPECIFICATIONS
EEPROM
100000 program/erase cycles max.
CLOCK
Resolution:
Accuracy with IRIG-B:
Accuracy without IRIG-B:
Supercap backup life:
1 ms
±1 ms
±5 minutes/month
45 days when control power is off
2.4.10 Physical
TEMPERATURE
Operating range:
Ambient storage:
Ambient shipping:
–40°C to +60°C
–40°C to +80°C
–40°C to +80°C
At temperatures below –20°C, the LCD contrast may become impaired.
Note
NOTE
ENVIRONMENTAL
Ambient operating temperature:–40°C to +60°C
Ambient storage temperature:–40°C to +80°C
Humidity:
up to 90% non-condensing
Pollution degree:
2
IP Rating:
40-X
LONG-TERM STORAGE
Environment:
Correct storage:
In addition to the above environmental considerations, the
relay should be stored in an environment that is dry, corrosivefree, and not in direct sunlight.
Prevents premature component failures caused by
environmental factors such as moisture or corrosive gases.
Exposure to high humidity or corrosive environments will
prematurely degrade the electronic components in any
electronic device regardless of its use or manufacturer, unless
specific precautions, such as those mentioned in the
Environmental section above, are taken.
It is recommended that all relays be powered up once per year, for one hour continuously,
to avoid deterioration of electrolytic capacitors and subsequent relay failure.
Note
NOTE
CASE
Type:
Approvals:
Seal:
Door:
Mounting:
Weight:
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
Fully drawout unit (automatic CT shorts)
Meets CE drawout specifications
Seal provision
Dust tight door
Panel or 19" rack mount
7.9 kg (case and relay)
9.4 kg (shipping weight)
2 - 21
SPECIFICATIONS
CHAPTER 2: INTRODUCTION
2.4.11 Testing
TYPE TESTING
The table below lists the 750/760 type tests:
Standard
Test Name
Level
EIA 485
RS485 Communications Test
32 units at 4000 ft.
IEC 60068-2-30
Relative Humidity Cyclic
55°C at 95% RH
IEC 60068-2-38
Composite Temperature/Humidity
65/–10°C at 93% RH
IEC 60255-5
Dielectric Strength
2300 V AC
IEC 60255-5
Insulation Resistance
>100 MΩ / 500 V AC / 10 s
IEC 60255-21-1
Sinusoidal Vibration
2g
IEC 60255-21-2
Shock and Bump
5 g / 10 g / 15 g
IEC 60255-21-3
Seismic
6g
IEC 60255-22-1
Damped Oscillatory Burst, 1 MHz
2.5 kV / 1 kV
IEC 60255-22-2
Electrostatic Discharge: Air / Direct
15 kV / 8 kV
IEC 60255-22-3
Radiated RF Immunity
10 V/m
IEC 60255-22-4
Electrical Fast Transient / Burst Immunity
2 kV
IEC 60255-22-5
Surge Immunity
4 kV / 2 kV
IEC 60255-22-6
Conducted RF Immunity, 150 kHz to 80 MHz
10 V/m
IEC 60255-25
Radiated RF Emission
Group 1 Class A
IEC 60255-25
Conducted RF Emission
Group 1 Class A
IEC 60529
Ingress of Solid Objects and Water (IP)
IP40 (front), IP10 (back)
IEC 61000-4-8
Power Frequency Magnetic Field Immunity
100 A/m continuous
1000 A/m short duration
IEC 61000-4-9
Pulse Magnetic Field Immunity
1000 A/m
IEC 61000-4-11
Voltage Dip; Voltage Interruption
0%, 40%, 100%
IEEE C37.90.1
Oscillatory Transient SWC
±2.5 kV
IEEE C37.90.3
Electrostatic Discharge: Air and Direct
±15 kV / ±8 kV
SIMULATION
Programmable pre-fault, fault, and post-fault parameters simulation modes. Simulation of
circuit breaker and selection of whether or not to operate
outputs relays.
PRODUCTION TESTS
Thermal cycling:
Dielectric strength:
Operational test at ambient, reducing to –40°C and then
increasing to 60°C
(order code ’LO’) 550 VAC for 1 second
(order code ’HI’) 2200 VAC for 1 second
DO NOT CONNECT FILTER GROUND TO SAFETY GROUND DURING ANY PRODUCTION
TESTS.
2 - 22
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 2: INTRODUCTION
SPECIFICATIONS
2.4.12 Approvals
APPROVALS
CE:
EN:
EN LVD
(Low Voltage Directive):
ISO:
UL:
Conforms to EMC and LVD directive
EN60255-26 zone B
EMC - CE for Europe
EN60255-27
LVD - CE for Europe
GE Multilin’s Quality Management System is registered to
ISO9001:2000
UL listed for the USA and Canada, E83849
Specifications subject to change without notice.
Note
NOTE
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
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SPECIFICATIONS
2 - 24
CHAPTER 2: INTRODUCTION
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
GE
Digital Energy
750/760 Feeder Management
Relay
Chapter 3: Installation
Installation
3.1
3.1.1
Drawout Case
Mechanical Installation
The 750/760 is packaged with a drawout relay and a companion case. The case provides
mechanical protection for the drawout portion and is used to make permanent electrical
connections to external equipment. Where required, case connectors are fitted with
mechanisms, such as automatic CT shorting, to allow the safe removal of the relay from an
energized panel. There are no electronic components in the case.
FIGURE 3–1: Case Dimensions
To prevent unauthorized removal of the drawout relay, a wire lead seal can be installed
through the slot in the middle of the locking latch. With this seal in place, the relay cannot
be removed. Even though a passcode or setpoint access jumper can be used to prevent
entry of setpoints and still allow monitoring of actual values, access to the front panel
controls may still need to be restricted. As such, a separate seal can be installed on the
outside of the door to prevent it from being opened.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
3-1
MECHANICAL INSTALLATION
CHAPTER 3: INSTALLATION
DRAWOUT
CASE SEAL
FIGURE 3–2: Drawout Case Seal
3.1.2
Installation
The 750/760 can be mounted alone or adjacent to another 469/489/745/750/760 unit on
a standard 19-inch rack panel. Panel cutout dimensions for both conditions shown below.
When planning the location of your panel cutout, ensure provision is made for the front
door to swing open without interference to or from adjacent equipment.
FIGURE 3–3: Single and Double Unit Panel Cutouts
Before mounting the relay in the supporting panel, remove the unit from the case. From the
front of the panel, slide the empty case into the cutout. To ensure the front bezel is flush
with the panel, apply pressure to the bezel’s front while bending the retaining tabs 90°.
These tabs are located on the sides and bottom of the case and appear as shown in the
illustration. After bending all tabs, the case will be securely mounted so that its relay can be
inserted. The unit is now ready for panel wiring.
3-2
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 3: INSTALLATION
MECHANICAL INSTALLATION
FIGURE 3–4: Mounting Tabs
3.1.3
Unit
Withdrawal
and Insertion
FOLLOW YOUR COMPANY’S PPE AND GUIDELINE BEFORE ATTEMPTING TO WORK ON
LIVE VOLTAGE, AND SWITCHGEAR.
Note
NOTE
TURN OFF CONTROL POWER BEFORE DRAWING OUT OR RE-INSERTING THE RELAY TO
PREVENT MALOPERATION!
If an attempt is made to install a relay into a non-matching case, the case’s
configuration pin will prevent full insertion. Applying a strong force in this instance will
result in damage to the relay and case.
If using an ethernet connection, refer to Ethernet Connection (section 3.1.4) before starting
the following procedure.
To remove the unit from the case:
1.
Open the door by pulling from the top or bottom of its right side. It will rotate
to the left about its hinges.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
3-3
MECHANICAL INSTALLATION
CHAPTER 3: INSTALLATION
2.
Press upward on the locking latch, which is located below the handle, and
hold in its raised position. The tip of a small screwdriver may prove helpful in
this operation.
FIGURE 1: Press the latch up and pull the handle
3-4
3.
With the latch raised, pull the center of the handle outward. Once disengaged,
continue rotating the handle up to the stop position.
4.
The handle should reach the “stop” position with minimum effort. If the handle
is stuck or hard to rotate to its “stop” position, do NOT force it in order to
withdraw the relay. Re-insert the relay into its draw-out case, and engage the
handle. Arrange to remove the draw-out from the switchgear by removing the
wiring from the terminals. Contact the GE Digital Energy Technical Support
team for any additional assistance.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 3: INSTALLATION
MECHANICAL INSTALLATION
FIGURE 2: Rotating the handle to the “stop” position
5.
When the “stop” position is reached, the locking mechanism will release. The
relay will now slide out of the case when pulled using its handle. To free the
relay, it may sometimes be necessary to slightly adjust the handle position.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
3-5
MECHANICAL INSTALLATION
CHAPTER 3: INSTALLATION
FIGURE 3: Sliding the unit out of the case
To insert the unit into the case:
1.
Ensure that the model number on the left side of the relay matches the
requirements of the installation.
2.
Raise the locking handle to the highest position.
3.
Hold the unit immediately in front of the case and align the rolling guide pins
(near the hinges of the relay’s handle) with the case’s guide slots.
4.
Slide the unit into the case until the guide pins on the unit have engaged the
guide slots on either side of the case.
5.
Once fully inserted, grasp the handle from its center and rotate it down from
the raised position towards the bottom of the relay.
6.
Once the unit is fully inserted the latch will be heard to click, locking the
handle in the final position. The unit is mechanically held in the case by the
handle’s rolling pins, which cannot be fully lowered to the locked position until
the electrical connections are completely mated.
No special ventilation requirements need to be observed during the installation of the unit.
The unit does not require cleaning.
Note
NOTE
3-6
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 3: INSTALLATION
3.1.4
Ethernet
Connection
MECHANICAL INSTALLATION
If using the 750/760 with the Ethernet 10Base-T option, ensure that the network cable is
disconnected from the rear RJ45 connector before removing the unit from the case. This
prevents any damage to the connector.
The unit may also be removed from the case with the network cable connector still
attached to the rear RJ45 connector, provided that there is at least 16" of network cable
available when removing the unit from the case. This extra length allows the network cable
to be disconnected from the RJ45 connector from the front of the switchgear panel. Once
disconnected, the cable can be left hanging safely outside the case for re-inserting the unit
back into the case.
The unit may then be re-inserted by first connecting the network cable to the units' rear
RJ45 connector (see step 3 of Unit Withdrawal and Insertion on page 3–3).
Ensure that the network cable does not get caught inside the case while sliding in the
unit. This may interfere with proper insertion to the case terminal blocks and damage
the cable.
FIGURE 3–5: Ethernet Cable Connection
3.1.5
Rear Terminal
Layout
A broad range of applications are available for the 750/760 relays. As such, it is not
possible to present typical connections for all possible schemes. The information in this
section will cover the important aspects of interconnections, in the general areas of
instrument transformer inputs, other inputs, outputs, communications and grounding. The
figure below shows the rear terminal layout of the 750/760.
Relay contacts must be considered unsafe to touch when system is energized! If the
customer requires the relay contacts for low voltage accessible applications, it is their
responsibility to ensure proper insulation levels!
HAZARD may result if the product is not used for its intended purposes.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
3-7
MECHANICAL INSTALLATION
CHAPTER 3: INSTALLATION
FIGURE 3–6: Rear Terminal Layout
The rear terminal assignments are indicated on the following table:
Table 3–7: Rear Terminal Assignments
TERMINAL
DESCRIPTION
TERMINAL
ANALOG INPUT / OUTPUTS
3-8
DESCRIPTION
OUTPUT RELAYS
A1
ANALOG INPUT +
E1
A2
ANALOG INPUT -
E2
SOLID STATE TRIP OUT +
1 TRIP RELAY NO
A3
SHIELD (GROUND)
E3
2 CLOSE RELAY NO
A4
ANALOG OUTPUT -
E4
3 AUXILIARY RELAY NO
A5
ANALOG OUTPUT 1 +
E5
3 AUXILIARY RELAY NC
A6
ANALOG OUTPUT 2 +
E6
4 AUXILIARY RELAY NC
A7
ANALOG OUTPUT 3 +
E7
5 AUXILIARY RELAY NC
A8
ANALOG OUTPUT 4 +
E8
5 AUXILIARY RELAY NO
A9
ANALOG OUTPUT 5 +
E9
6 AUXILIARY RELAY NC
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 3: INSTALLATION
MECHANICAL INSTALLATION
Table 3–7: Rear Terminal Assignments
TERMINAL
DESCRIPTION
TERMINAL
DESCRIPTION
A10
ANALOG OUTPUT 6 +
E10
A11
ANALOG OUTPUT 7 +
E11
7 AUXILIARY RELAY NO
E12
8 SELF-TEST WARNING RELAY
NC
A12
ANALOG OUTPUT 8 +
COMMUNICATION
7 AUXILIARY RELAY NC
OUTPUT RELAYS
B1
COM1 RS485 +
F1
B2
COM1 RS485 -
F2
1 TRIP RELAY COM
B3
COM1 RS485 COM
F3
2 CLOSE RELAY COM
B4
COM1 RS422 TX +
F4
3 AUXILIARY RELAY COM
B5
COM1 RS422 TX -
F5
4 AUXILIARY RELAY NO
B6
COM2 RS485 +
F6
4 AUXILIARY RELAY COM
B7
COM2 RS485 -
F7
5 AUXILIARY RELAY COM
B8
COM2 RS485 COM
F8
6 AUXILIARY RELAY NO
B9
SHIELD (GROUND)
F9
6 AUXILIARY RELAY COM
B10
IRIG-B +
F10
7 AUXILIARY RELAY COM
IRIG-B –
F11
8 SELF-TEST WARNING RELAY
NO
RESERVED
F12
B11
B12
LOGIC INPUTS
SOLID STATE TRIP OUT -
8 SELF-TEST WARNG RELAY COM
CT and VT INPUTS / GROUND
C1
LOGIC INPUT 1
G1
C2
LOGIC INPUT 2
G2
COIL MONITOR 1 +
COIL MONITOR 2 +
C3
LOGIC INPUT 3
G3
SENSITIVE GROUND CT 
C4
LOGIC INPUT 4
G4
SYNCHRO VT  (LINE)
C5
LOGIC INPUT 5
G5
PHASE A VT  (BUS)
C6
LOGIC INPUT 6
G6
PHASE C VT  (BUS)
C7
LOGIC INPUT 7
G7
PHASE A CT 
C8
RESERVED
G8
PHASE B CT 
C9
RESERVED
G9
PHASE C CT 
C10
SETPOINT ACCESS –
G10
GROUND CT 
C11
SETPOINT ACCESS +
G11
FILTER GROUND
C12
+32 VDC
G12
SAFETY GROUND
LOGIC INPUTS
CT and VT INPUTS / POWER
D1
LOGIC INPUT 8
H1
D2
LOGIC INPUT 9
H2
COIL MONITOR 1 COIL MONITOR 2 -
D3
LOGIC INPUT 10
H3
SENSITIVE GROUND CT
D4
LOGIC INPUT 11
H4
SYNCHRO VT (LINE)
D5
LOGIC INPUT 12
H5
PHASE B VT  (BUS)
PHASE VT NEUTRAL (BUS)
D6
LOGIC INPUT 13
H6
D7
LOGIC INPUT 14
H7
PHASE A CT
D8
RESERVED
H8
PHASE B CT
D9
RESERVED
H9
PHASE C CT
D10
RESERVED
H10
GROUND CT
D11
RESERVED
H11
CONTROL POWER –
D12
DC NEGATIVE
H12
CONTROL POWER +
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
3-9
ELECTRICAL INSTALLATION
CHAPTER 3: INSTALLATION
3.2
Electrical Installation
996007ES.CDR
FIGURE 3–8: Typical Wiring Diagram
3 - 10
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 3: INSTALLATION
ELECTRICAL INSTALLATION
3.2.1
Phase
Sequence and
Transformer
Polarity
For the correct operation of many relay features, the instrument transformer polarities
shown above in the Typical Wiring Diagram on page 3–10 must be followed. Note the solid
square markings shown with all instrument transformer connections. When the
connections adhere to this drawing, the arrow shows the direction of power flow for
positive watts and the positive direction of lagging vars. The phase sequence is user
programmable to be either ABC or ACB rotation.
3.2.2
Current Inputs
The 750/760 relays have five (5) channels for AC current inputs, each with an isolating
transformer and an automatic shorting mechanism that acts when the relay is withdrawn
from its case. There are no internal ground connections on the current inputs. Current
transformers with 1 to 50000 A primaries may be used.
Verify that the relay’s nominal input current of 1 A or 5 A matches the secondary rating
of the connected CTs. Unmatched CTs may result in equipment damage or inadequate
protection.
IMPORTANT: The phase and ground current inputs will correctly measure to 20 times
the current input’s nominal rating. Time overcurrent curves become horizontal lines
for currents above the 20 × CT rating. This becomes apparent if the pickup level is set
above the nominal CT rating.
3.2.3
Ground and
Sensitive
Ground CT
Inputs
There are two dedicated ground inputs referred throughout this manual as the Ground
Current and the Sensitive Ground Current inputs. Before making ground connections,
consider that the relay automatically calculates the neutral (residual) current from the sum
of the three phase current phasors. The following figures show three possible ground
connections using the ground current input (Terminals G10 and H10) and three possible
sensitive ground connections using the sensitive ground current input (Terminals G3 and
H3).
The ground input (Terminals G10 and H10) is used in conjunction with a Zero Sequence CT
as source, or in the neutral of wye-connected source CTs. The ground current input can be
used to polarize both the neutral and sensitive ground directional elements. When using
the residual connection set the GROUND CT PRIMARY setpoint to a value equal to the PHASE
CT PRIMARY setpoint.
The sensitive ground current input is intended for use either with a CT in a source neutral of
a high-impedance grounded system, or on ungrounded systems. On ungrounded systems
it is connected residually with the phase current inputs. In this case, the SENSTV GND CT
PRIMARY setpoint should be programmed to a value equal to the PHASE CT PRIMARY
setpoint. The sensitive ground current input can be connected to a Zero Sequence CT for
increased sensitivity and accuracy when physically possible in the system.
Note
NOTE
Units that do not have the Sensitive Ground input (such as older units which have been
upgraded with new firmware) use the G3 and H3 terminals as the polarizing input. The G10
and H10 terminals are used for the Ground input. These connections will be shown on the
terminal assignment label on the back of the relay’s case.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
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ELECTRICAL INSTALLATION
CHAPTER 3: INSTALLATION
The Sensitive Ground input (G3 and H3 terminals) must only be used on systems where the
maximum ground current does not exceed 500 A.
Note
NOTE
FIGURE 3–9: Ground Inputs
FIGURE 3–10: Sensitive Ground Inputs
3.2.4
3 - 12
Restricted
Earth Fault
Inputs
Restricted Earth Fault protection is often applied to transformers having grounded wye
windings to provide sensitive ground fault detection for faults near the transformer
neutral. The Sensitive Ground input (Terminals G3 and H3) can be used.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 3: INSTALLATION
Note
NOTE
ELECTRICAL INSTALLATION
Although the 750/760 is designed for feeder protection, it can provide Restricted Earth
Fault protection on transformers that do not have dedicated protection. To use the 750/
760 for this type of protection, a stabilizing resistor and possibly a non-linear resistor will
be required. For more details see page 5–72.
FIGURE 3–11: Restricted Earth Fault Inputs
3.2.5
Zero Sequence
CT Installation
The various CT connections and the exact placement of a Zero Sequence CT, so that
ground fault current will be detected, are shown in the figure below. Twisted pair cabling
on the Zero Sequence CT is recommended.
UNSHIELDED CABLE
A
Source
B
C
SHIELDED CABLE
Ground connection to neutral
must be on the source side
N
G
Stress cone
shields
Source
A
B
C
Ground
outside CT
LOAD
LOAD
To ground;
must be on
load side
996630A5
FIGURE 3–12: Zero Sequence (Core Balance) CT Installation
3.2.6
Voltage Inputs
The 750/760 relays have four channels for AC voltage inputs, each with an isolating
transformer. Voltage transformers up to a maximum 5000:1 ratio may be used. The
nominal secondary voltage must be in the 50 to 240 V range.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
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ELECTRICAL INSTALLATION
CHAPTER 3: INSTALLATION
The three phase inputs are designated as the “bus voltage”. The Bus VT connections most
commonly used, wye and delta (or open delta), are shown in the typical wiring diagram. Be
aware that these voltage channels are internally connected as wye. This is why the jumper
between the phase B terminal and the Vcom terminal must be installed with a delta
connection.
FIGURE 3–13: Line VT Connections
Note
NOTE
If Delta VTs are used, the zero sequence voltage (V0) and neutral/sensitive ground
polarizing voltage (–V0) will be zero. Also, with this Delta VT connection, the phase-neutral
voltage cannot be measured and will not be displayed.
The single phase input is designated as the “line voltage”. The line VT input channel, used
for the synchrocheck feature, can be connected for phase-neutral voltages Van, Vbn, or Vcn;
or for phase-phase voltages Vab or Vcb as shown below.
3.2.7
Control Power
Control power supplied to the relay must match the installed power supply range. If the
applied voltage does not match, damage to the unit may occur. All grounds MUST be
connected for normal operation regardless of control power supply type.
The label found on the left side of the relay specifies its order code or model number. The
installed power supply’s operating range will be one of the following.
LO: 20 to 60 V DC or 20 to 48 V AC
HI: 88 to 300 V DC or 70 to 265 V AC
The relay should be connected directly to the ground bus, using the shortest practical
path. A tinned copper, braided, shielding and bonding cable should be used. As a
minimum, 96 strands of number 34 AWG should be used. Belden catalog number 8660
is suitable.
3 - 14
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 3: INSTALLATION
ELECTRICAL INSTALLATION
996618AL.CDR
FIGURE 3–14: Control Power Connection
3.2.8
Trip/Close Coil
Supervision
Supervision of a breaker trip coil requires the relay supervision circuit to be wired in parallel
with the Trip contact. Likewise, supervision of the close coil requires the supervision circuit
to be wired in parallel with the Close contact. Each connection places an impedance
across the associated contact, which allows a small trickle current to flow through the
related trip and close coil supervision circuitry. For external supply voltages in the 30 to
250 V DC range, this current draw will be between 2 to 5 mA. If either the trip or close coil
supervision circuitry ceases to detect this trickle current, the appropriate failure will be
declared by the relay.
When the BRKR STATE BYPASS setpoint is “Disabled”, the logic only allows a trip circuit to be
monitored when the breaker is closed and a close circuit to be monitored when the
breaker is open.
Circuit breakers equipped with standard control circuits have a 52a auxiliary contact
which only allows tripping of the breaker when it is closed. In this breaker state, the 52a
contact is closed and a trickle current will flow through the trip circuitry. When the breaker
is open, the 52a auxiliary contact is also open and no trickle current will flow. When the
breaker position monitoring inputs detect an open breaker, the trip coil supervision
monitoring function will be disabled.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
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ELECTRICAL INSTALLATION
CHAPTER 3: INSTALLATION
FIGURE 3–15: Trip/Close Coil Supervision
In a similar manner, the 52b auxiliary contact only allows closing of the breaker when it is
open. In this breaker state, the 52b contact is shorted and a trickle current will flow through
the breaker’s close circuitry. When the breaker is closed, the 52b auxiliary contact is open
and no trickle current will flow. When the breaker position monitoring inputs detect a
closed breaker, the close coil supervision monitoring function will be disabled.
When the BRKR STATE BYPASS setpoint is “Enabled”, the trip and close coil supervision
circuits can be arranged to monitor the trip and close circuits continuously, unaffected by
breaker state. This application requires that an alternate path around the 52a or 52b
contacts in series with the operating coils be provided, with modifications to the standard
wiring as shown FIGURE 3–15: Trip/Close Coil Supervision on page 3–16. With these
connections, trickle current can flow at all times. If access to the breaker coil is available, as
shown in drawing A above, continuous coil monitoring regardless of breaker state is
possible without using a resistor to bypass the 52a/b contact.
A high speed solid state (SCR) output is also provided. This output is intended for
applications where it is required to key a communications channel.
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750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 3: INSTALLATION
3.2.9
Logic Inputs
ELECTRICAL INSTALLATION
External contacts can be connected to the relay’s fourteen (14) logic inputs. As shown,
these contacts can be either dry or wet. It is also possible to use a combination of both
contact types.
Ensure correct polarity on logic input connections and do not connect any logic input
circuits to ground or else relay hardware may be damaged.
A dry contact has one side connected to Terminal C12. This is the +32 V DC voltage rail. The
other side of the dry contact is connected to the required logic input terminal. When a dry
contact closes, a current of approximately 2 mA will flow through the associated circuit.
A wet contact has one side connected to the positive terminal of an external DC power
supply. The other side of this contact is connected to the required logic input terminal. In
addition, the negative side of the external source must be connected to the relay’s DC
negative rail at Terminal D12. The maximum external source voltage for this arrangement
is 300 V DC.
Dry Contact Connection
Wet Contact Connection
750/760 RELAY
750/760 RELAY
+32 V DC
C12
+32 V DC
C12
Logic Input 1
C1
Logic Input 1
C1
32 V DC
32 V DC
30 to 300 V DC
DC Negative
D12
DC Negative
D12
LOGICIN.CDR
FIGURE 3–16: Dry and Wet Contact Connections
Note
NOTE
3.2.10 Analog Input
It is recommended to use shielded twisted pair wires grounded at one end only for analog
input and analog output connections to the relay. Ensure the maximum burden limits are
not exceeded as per relay specifications and avoid locating wire in close proximity to
current carrying cables, contactors or other sources of high EMI.
Terminals A1 (+) and A2 (–) are provided for the input of a current signal from a wide variety
of transducer outputs - refer to technical specifications for complete listing. This current
signal can represent any external quantity, such as transformer winding temperature, bus
voltage, battery voltage, station service voltage, or transformer tap position. Be sure to
observe polarity markings for correct operation. Both terminals are clamped to within 36 V
of ground with surge protection. As such, common mode voltages should not exceed this
limit. Shielded wire, with only one end of the shield grounded, is recommended to minimize
noise effects.
3.2.11 Analog
Outputs
Note
NOTE
It is recommended to use shielded twisted pair wires grounded at one end only for analog
input and analog output connections to the relay. Ensure the maximum burden limits are
not exceeded as per relay specifications, and avoid locating wire in close proximity to
current carrying cables, contactors or other sources of high EMI.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
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ELECTRICAL INSTALLATION
CHAPTER 3: INSTALLATION
The 750/760 relays provide eight (8) analog output channels whose full scale range was
specified at the time of ordering. Refer to Outputs on page 2–20 for the specifications and
Ordering on page 2–9 for the complete listing.
Each analog output channel can be programmed to represent one of the parameters
measured by the relay. For details, see Analog Outputs on page 5–110.
As shown in the Typical Wiring Diagram, the analog output signals originate from
Terminals A5 to A12 and share A4 as a common return. Output signals are internally
isolated and allow connection to devices which sit at a different ground potential. Each
analog output terminal is clamped to within 36 V of ground. To minimize the affect of noise,
external connections should be made with shielded cable and only one end of the shield
should be grounded.
If a voltage output is required, a burden resistor must be connected at the input of the
external measuring device. Ignoring the input impedance, we have
V FULL SCALE
R LOAD = ---------------------------I MAX
(EQ 3.1)
If a 5V full scale output is required with a 0 to 1 mA output channel:
V FULL SCALE
5V
R LOAD = ---------------------------- = ------------------- = 5 kΩ
I MAX
0.001 A
(EQ 3.2)
For a 0 to 5 mA channel this resistor would be 1 kW and for a 4 to 20 mA channel this
resistor would be 250 Ω. The Analog Output connection diagram is shown below.
FIGURE 3–17: Analog Output Connection
3.2.12 Serial
Communicatio
ns
The 750/760 relays provide the user with two rear communication ports which may be
used simultaneously. Both support a subset of the AEG Modicon Modbus protocol as well
as the Harris Distributed Network Protocol (DNP) as discussed in GE Publication GEK106473: 750/760 Communications Guide. Through the use of these ports, continuous
monitoring and control from a remote computer, SCADA system or PLC is possible.
The first port, COM1, can be used in a two wire RS485 mode or a four wire RS422 mode, but
will not operate in both modes at the same time. In the RS485 mode, data transmission
and reception are accomplished over a single twisted pair with transmit and receive data
alternating over the same two wires. These wires should be connected to the terminals
marked RS485. The RS422 mode uses the COM1 terminals designated as RS485 for receive
lines, and the COM1 terminals designated as RS422 for transmit lines. The second port,
COM2, is intended for the two wire RS485 mode only.
3 - 18
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 3: INSTALLATION
ELECTRICAL INSTALLATION
The RS485 port is disabled when the Ethernet option is ordered.
To minimize errors from noise, the use of shielded twisted-pair wire is recommended.
Correct polarity should also be observed. For instance, 750/760 type relays must be
connected with all B1 terminals (labeled COM1 RS485+) connected together, and all B2
terminals (labeled COM1 RS485–) connected together. Terminal B3 (COM1 RS485 COM)
should be connected to the common wire inside the shield. To avoid loop currents, the
shield should be grounded at one point only. Each relay should also be daisy-chained to
the next one in the link. A maximum of 32 devices can be connected in this manner
without exceeding driver capability. For larger systems, additional serial channels must be
added. It is also possible to use commercially available repeaters to add more than 32
relays on a single channel. Star or stub connections should be avoided entirely.
Lightning strikes and ground surge currents can cause large momentary voltage
differences between remote ends of the communication link. For this reason, surge
protection devices are internally provided at both communication ports. An isolated power
supply with an opto-coupled data interface also acts to reduce noise coupling. To ensure
maximum reliability, all equipment should have similar transient protection devices
installed.
GROUND THE SHIELD AT THE
SCADA/PLC/COMPUTER ONLY
OR AT THE SR RELAY ONLY
996620AQ.CDR
FIGURE 3–18: RS485 Wiring Diagram
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
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ELECTRICAL INSTALLATION
CHAPTER 3: INSTALLATION
818752AD.CDR
FIGURE 3–19: RS422 Wiring Diagram
3.2.13 RS232 Communications
The 9-pin RS232 serial port located on the front panel is used in conjunction with the
EnerVista 750/760 Setup software for programming setpoints and upgrading relay
firmware. A standard 9-pin RS232 cable is used to connect the relay to a personal
computer as shown below. When downloading new firmware, ensure the relay address
is set to 1 and the baud rate is set to 9600.
3 - 20
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ELECTRICAL INSTALLATION
FIGURE 3–20: RS232 Connection
3.2.14 IRIG-B
IRIG-B is a standard time code format that allows time stamping of events to be
synchronized among connected devices within 1 millisecond. The IRIG time code formats
are serial, width-modulated codes which can be either DC level shift or amplitude
modulated (AM) form. Third party equipment is available for generating the IRIG-B signal;
this equipment may use a GPS satellite system to obtain the time reference so that devices
at different geographic locations can also be synchronized.
FIGURE 3–21: IRIG-B Connection
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ELECTRICAL INSTALLATION
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CHAPTER 3: INSTALLATION
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
GE
Digital Energy
750/760 Feeder Management
Relay
Chapter 4: Interfaces
Interfaces
4.1
Front Panel Interface
4.1.1
Description
The front panel provides local operator interface with a liquid crystal display, LED status
indicators, control keys, and program port. The display and status indicators update alarm
and status information automatically. The control keys are used to select the appropriate
message for entering setpoints or displaying measured values. The RS232 program port is
also provided for connection with a computer running the EnerVista 750/760 Setup
software.
4.1.2
Display
The 40-character liquid crystal display (LCD) allows visibility under varied lighting
conditions. When the keypad and display are not being used, system information is
displayed by scrolling through a maximum of 30 user-defined default messages. These
default messages appear only after a user-defined period of inactivity. Pressing any key
during default message scrolling returns the display to the last message shown before the
default messages appeared. Any trip, alarm, or start block is displayed immediately,
automatically overriding the default messages.
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LED INDICATORS
CHAPTER 4: INTERFACES
4.2
4.2.1
Description
LED Indicators
The front panel indicators are grouped into three columns. The 750/760 Status column
indicates the state of the relay; the System Status column indicates the state of the
breaker and the system; and the Output Status column indicates the state of the output
relays. These LED indicators can be tested by and holding the HELP key for about one
second when no trips or alarms are active. As shown below, the color of each indicator
conveys its importance.
G = Green: General Condition
A = Amber: Alert Condition
R = Red: Serious Alarm or Important Status
FIGURE 4–1: 750/760 Front Panel
4-2
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CHAPTER 4: INTERFACES
4.2.2
LED INDICATORS
750/760
Status LED
Indicators
•
RELAY IN SERVICE: This indicator will be on continuously if the relay is functioning
normally and no major self-test errors have been detected. During operation the relay
continuously performs various self tests and if a major self-test fails, the indicator will
be turned off, all output relays will be de-energized, and the Self-Test Warning LED will
be turned on. This indicates a complete loss of protection. See the self-test warning
section later in this chapter.
•
TRIP: This indicator flashes when the relay detects a trip condition and operates the
Trip Relay to open the breaker. After the initiating fault has been cleared, this LED can
be turned off with a reset.
•
ALARM: While the relay is detecting an alarm condition, this indicator will flash. Even if
latched output relays are programmed to operate with the alarm, the indicator will
automatically turn off if the alarm condition clears. Such output relays will remain in
the operated state until a reset is performed.
Latched Alarm: This relay flashes while the relay is detecting an alarm condition. After
the condition clears, the indicator remains illuminated and can be turned off with a
reset.
Note
NOTE
4.2.3
System Status
LED Indicators
•
PICKUP: For the purpose of testing and calibration verification, this indicator will light
steady when any protection feature has its pickup threshold exceeded. Eventually, if
the fault condition persists, a trip will be issued by the relay. If the measured
parameter drops below its pickup level, the indicator will turn off.
•
SETPOINT GROUP 1 to 4: These indicators are flashing if the corresponding group is
selected for editing and/or display; they are continuously on if the corresponding
group is providing settings for the protection elements.
•
BREAKER OPEN: When the breaker is open, this indicator will be on continuously.
•
BREAKER CLOSED: When the breaker is closed, this indicator will be on continuously.
Breaker status indication is based on the breaker 52a and 52b contacts. With both
contacts wired to the relay, the closed status is determined by a closed 52a contact
and the open status is determined by a closed 52b contact. If both 52a and 52b
contacts are open, due to a breaker being racked out of the switchgear, both the
Breaker Open and Breaker Closed LED Indicators will be off.
With a single 52a contact, it is impossible to distinguish between a breaker open state
and a racked out breaker. In both situations, the 52a contact will be open. With a
single 52b contact, you cannot distinguish between a breaker closed state and a
racked out breaker. Likewise, the 52b contact will be open for both situations. To clarify
this ambiguity, the breaker connected function should be programmed to an
additional logic input. When this additional input is closed, a single 52a or 52b contact
will show both breaker states. When the breaker is racked out, this additional breaker
connected input should be open. In this case, both breaker status indicators will be off.
The Open and Closed Status Indicator colors are interchangeable at the time of
placing a 750/760 order.
Note
NOTE
•
RECLOSURE ENABLED (760 only): This indicator will be on continuously when
autoreclosure is allowed to operate as programmed. This is when the autoreclose
function setpoint is enabled, and if used, the block reclosure logic input is not asserted.
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LED INDICATORS
CHAPTER 4: INTERFACES
Otherwise, this indicator will be off. Note that this indicator will always be in the
opposite state of the Reclosure Disabled LED Indicator.
•
RECLOSURE DISABLED (760 only): This indicator will be on continuously when
autoreclosure is not allowed to operate as programmed. This is when the autoreclose
function setpoint is disabled, or if used, the block reclosure logic input is asserted.
Otherwise, this indicator will be off. Note that this indicator will always be in the
opposite state of the Reclosure Enabled LED.
•
RECLOSURE IN PROGRESS (760 only): If a trip initiates a reclosing sequence, this
indicator will go on continuously during each of the programmed dead times.
•
RECLOSURE LOCKOUT (760 only): If the programmed reclose sequence has
progressed to a final lockout condition, this indicator will be on continuously. Lockout
can be cleared by performing a reset.
•
LOCAL: This indicator turns on if the local mode function has been assigned a logic
input which is asserted. In local mode, the front panel OPEN and CLOSE keys operate
while the Remote Open and Remote Close logic input functions will not operate. As
well, the communication open and close commands have no effect.
Breaker operations performed by 750/760 outputs in response to logic inputs
energized with contacts from a local control switch are considered as remote
operations. When the 750/760 is in local mode, the local panel is the relay faceplate;
everything else is considered remote, even the control switch that might be installed in
the same switchgear compartment. It is important not to confuse this with the
concept of Station Local/Remote Mode, in which case the same Control Switch is
considered local.
•
MESSAGE: Under normal conditions, the default messages selected during setpoint
programming are displayed. If any alarm or trip condition is generated, a diagnostic
message overrides the displayed message and this indicator flashes. If there is more
than one condition present, MESSAGE  can be used to scroll through the messages.
Pressing any other key return to the normally displayed messages. While viewing
normally displayed messages, the Message LED continues to flash if any diagnostic
message is active. To return to the diagnostic messages from the normally displayed
messages, press the MENU key until the following message is displayed:

TARGET
MESSAGES []
Now, press the MESSAGE  key followed by the message  key to scroll through the
messages. Note that diagnostic messages for alarms disappear with the condition
while diagnostic messages for trips remain until cleared by a reset.
4.2.4
Output Status
LED Indicators
The 750/760 has eight (8) output relays: the 1 Trip, 2 Close, and 8 Self-Test Warning relays
have fixed operation while the 3 to 7 Auxiliary relays are configurable. Regardless of the
mode of operation, the corresponding front panel indicator turns on while the output relay
is signaling. If the non-operated state of an output relay is programmed as de-energized,
the corresponding indicator will be on when the normally open contacts are closed. If the
non-operated state of an output relay is programmed as energized, the corresponding
indicator will be on when the normally open contacts are open.
•
4-4
1 TRIP: A trip sequence can be initiated by a protection element, a logic input element,
a remote open command, a serial open command, or a front panel open command.
When started, the Trip LED turns on briefly while the Trip Relay is energized. After the
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 4: INTERFACES
LED INDICATORS
auxiliary breaker contacts indicate that the breaker has opened, the Trip Relay and
indicator stop operating. If both 52a and 52b auxiliary contacts are not installed,
the Trip Relay and indicator will de-energize 100 ms after the trip condition clears,
or after two seconds.
•
2 CLOSE: A close sequence can be initiated by a 760 reclosure or a remote, serial, or
front panel close command. When started, the Close LED turns on briefly while the
Close Relay energizes. After the auxiliary breaker contacts indicate that the breaker
has closed, the Close Relay and indicator stop operating. If both 52a and 52b
auxiliary contacts are not installed, the Close Relay and indicator operate for 200
ms.
•
3 to 7 AUXILIARY: These relays are intended for customer specific requirements that
can be initiated by any protection element or function whose RELAYS (3-7) setpoint has
“3”, “4”, “5”, “6”, or “7” selected. The Auxiliary LEDs (3 to 7) will turn on while the
corresponding relays are operating.
•
8 SELF-TEST WARNING: During normal operation, this indicator is off with the fail-safe
Self-Test Warning Relay energized. If any abnormal condition is detected during self
monitoring (such as a hardware failure) the indicator turns on and the relay deenergizes. If control power is lost or the relay is drawn out of its case, the Self-Test
Warning Relay signals loss of protection by de-energizing, but the LED indicator
remains off. Since there are no shorting contacts across the Self-Test Warning Relay,
both the normally open and normally closed contacts are open when the unit is drawn
out.
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RELAY MESSAGES
CHAPTER 4: INTERFACES
4.3
4.3.1
Keypad
Operation
Relay Messages
The 750/760 display messages are organized into Main Menus, Pages, and Sub-pages.
There are three main menus labeled Setpoints, Actual Values, and Target Messages.
Pressing the MENU key followed by the MESSAGE  key scrolls through the three Main
Menu headers, which appear in sequence as follows:

SETPOINTS
[]

ACTUAL VALUES
[]

TARGET MESSAGES []
Pressing the MESSAGE  key or the ENTER key from these Main Menu pages will display
the corresponding menu Page. Use the MESSAGE  and MESSAGE  keys to scroll
through the Page headers.
When the display shows SETPOINTS, pressing the MESSAGE  key or the ENTER key will
display the page headers of programmable parameters (referred to as setpoints in the
manual). When the display shows ACTUAL VALUES, pressing the MESSAGE  key or the
ENTER key displays the page headers of measured parameters (referred to as actual
values in the manual). When the display shows TARGET MESSAGES, pressing the
MESSAGE  key or the ENTER key displays the page headers of event messages or alarm
conditions.
Each page is broken down further into logical sub-pages of messages. The MESSAGE 
and MESSAGE  keys are used to navigate through the sub-pages. A summary of the
setpoints and actual values pages can be found in the Chapters : Setpoints and : Actual
Values, respectively.
The ENTER key is dual purpose. It is used to enter the sub-pages and to store altered
setpoint values into memory to complete the change. The MESSAGE  key can also be
used to enter sub-pages but not to store altered setpoints.
The ESCAPE key is also dual purpose. It is used to exit the sub-pages and to cancel a
setpoint change. The MESSAGE  key can also be used to exit sub-pages and to cancel
setpoint changes.
The VALUE keys are used to scroll through the possible choices of an enumerated setpoint.
They also decrement and increment numerical setpoints. Numerical setpoints may also be
entered through the numeric keypad.
The HELP key may be pressed at any time to display a list of context sensitive help
messages. Continue to press the HELP key to display all the help messages and return to
the original display.
The RESET key resets any latched conditions that are not presently active. This includes
resetting latched output relays, latched Trip LEDs, breaker operation failure, and trip / close
coil failures. The 760 Autoreclose Scheme is also reset with the shot counter being returned
to zero and the lockout condition being cleared.
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RELAY MESSAGES
The MESSAGE  and MESSAGE  keys scroll through any active conditions in the relay.
Diagnostic messages are displayed indicating the state of protection and monitoring
elements that are picked up, operating, or latched. When the Message LED is on there are
messages to be viewed with the MENU key by selecting target messages as described
earlier.
Pressing the OPEN key will attempt to open the breaker connected to the Trip Relay by
closing the contact. Likewise, the CLOSE key will attempt to close the breaker connected to
the Close Relay by closing the contact. The OPEN and CLOSE keys only operate when the
relay is in local mode; local mode can be enabled with a user programmed logic input.
4.3.2
Diagnostic
Messages
Diagnostic messages are automatically displayed for any active conditions in the relay
such as trips, alarms, or asserted logic inputs. These messages provide a summary of the
present state of the relay. The Message LED flashes when there are diagnostic messages
available; press the MENU key until the relay displays TARGET MESSAGES, then press the
MESSAGE  key, followed by the MESSAGE  key, to scroll through the messages. The
following shows the format of the various diagnostic messages.
PICKUP: <F>
< Cause >
These messages show any elements that are presently picked
up.
TRIP: <F>
< Cause >
These messages indicate that an element has tripped. The
message remains in the diagnostic queue until the relay is
reset.
ALARM: <F>
< Cause >
These messages show any elements that are presently
operating and have been programmed to have an alarm
function. When an element is programmed to Latched Alarm,
this message remains in the diagnostic queue after the alarm
condition clears until the relay is reset.
SELF-TEST WARNING: These messages show any self-test warnings.
< Cause >
4.3.3
Self-Test
Warnings
The relay performs self-diagnostics at initialization after power-up, and continually as a
background task, to ensure that every testable unit of the hardware and software is alive
and functioning correctly. There are two types of self-test warnings indicating either a
minor or major problem. Minor problems indicate a problem with the relay that does not
compromise protection of the power system. Major problems indicate a very serious
problem with the relay which comprises all aspects of relay operation.
The relay performs a diagnostic while counting events, to check excessive wear on nonvolatile memory (EEPROM). Maintenance alerts indicate excessive use.
"Event Rate HIgh": This alert usually indicates that communication with a programmable
logic controller or SCADA is continually recording events in the 750 event recorder.
Programmable controller should be revised or 750 setpoints adjusted to reduce event
recording.
Self-Test Warnings may indicate a serious problem with the relay hardware!
Upon detection of either a minor or major problem, the relay will:
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RELAY MESSAGES
CHAPTER 4: INTERFACES
•
De-energize the Self-Test Warning Relay, except these self-tests do not de-energize:
Clock Not Set, Internal RS485, Internal Temp, and IRIG-B Failure.
•
Indicate the failure in the diagnostic message queue.
•
Record the failure in the Event Recorder.
Upon detection of a major problem, the relay will (if possible) also:
•
Turn off the Relay In Service LED.
•
Inhibit operation of all output relays.
Table 4–2: Self-Test Warnings
Error
Severity
Description
A/D Virtual Ground
Major
This warning is caused by a failure of the analog to digital
converter. The integrity of system input measurements is
affected by this failure. Contact Multilin Technical Support.
Analog Output
+32V
Minor
Caused by the loss of the +32 V DC power supply used to
power analog outputs. Analog output currents are
affected by this failure. Contact Multilin Technical Support.
Clock Not Set
Minor
Occurs if the clock has not been set. Refer to section 5.2.3
for how to set the clock.
Minor
Caused by the loss of the +32 V DC power supply used to
power dry contacts of logic inputs. Logic inputs using
internal power are affected by this failure. Contact Multilin
Technical Support.
Major
Caused by detection of corrupted location(s) in the relay
data memory, which cannot be self-corrected. Any
function of the relay is susceptible to malfunction from this
failure. Contact Multilin Technical Support.
Maintenance
Alert
Occurs when the relay has recorded more than 51 million
events, which are written on an EEPROM. Design limit of
the Event recorder is limited by EEPROM write limit. Further
writes on the EEPROM could fail. Contact Multilin Technical
Support.
Event Rate High
Maintenance
Alert
Occurs when the relay has counted 5 million events in less
than a year. The date interval is checked at milestone
events 5 million, 10 million, 15 million and so on. This
warning indicates that the relay is recording events at a
rate higher than under normal conditions. Check if the DCS
of SCADA system is writing date and time to the device
more frequently than once per hour. Reduce the date and
time updates to twice a day, or "disable" the "RECORD DATE/
TIME EVENTS" setting.
Factory Service
Major
This warning occurs when the relay is in factory service
mode. Contact Multilin Technical Support.
Major
This warning is caused by detection of a corrupted
location in the program memory, as determined by a CRC
error checking code. Any function of the relay is
susceptible to malfunction from this failure. Contact
Multilin Technical Support.
Dry Contact +32V
EEPROM Corrupt
EEPROM Usage
High
FLASH Corrupt
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CHAPTER 4: INTERFACES
RELAY MESSAGES
Table 4–2: Self-Test Warnings
Error
Severity
Description
Force Analog Out
Minor
Occurs when the FORCE A/O FUNCTION setpoint is “Enabled”.
Force Relays
Minor
Occurs when the FORCE OUTPUT RELAYS FUNCTION setpoint
is "Enabled".
Internal RS485
Minor
Caused by a failure of the internal communication link
between the main processor and the communication
processor. Attempts to read actual values or write
setpoints were unsuccessful. Contact Multilin Technical
Support.
Internal Temp
Minor
Caused by the detection of unacceptably low (less than –
40°C) or high (greater than +85°C) temperatures detected
inside the unit.
IRIG-B Failure
Minor
Caused when IRIG-B time synchronization has been
enabled but the signal cannot be decoded. Ensure correct
IRIG-B signal is available to the device.
Not Calibrated
Minor
This warning occurs when the relay has not been factory
calibrated. Contact Multilin Technical Support.
Pickup Test
Minor
Occurs when the PICKUP TEST FUNCTION setpoint is
"Enabled".
Prototype Software
Minor
Occurs when prototype software has been loaded into the
relay. Contact Multilin Technical Support for the correct
firmware update.
Relay Not Ready
Minor
This warning occurs when the 750/760 OPERATION setpoint
has not been set to “Ready”.
Simulation Mode
Minor
This warning occurs when the simulation feature of the
relay is active.
This warning occurs when
Self-Test 1
4.3.4
Flash
Messages
Major
•
750 receives DNP protocol command to cold restart.
•
Enervista 750 Setup software sends Modbus command
to 750 for firmware update, from version 7.31 or previous
version, to version 7.40.
•
Watchdog timer expiry.
Self-Test 2
Major
This warning occurs when microprocessor self-monitoring
detects task execution failure.
Test Mode 3
Major
This warning occurs when Enervista 750 Setup software
sends Modbus command to 750 for firmware update from
version 7.40 to a following version.
Flash messages are warning, error, or general information messages displayed in response
to certain key presses. The length of time these messages remain displayed can be
programmed in S1 RELAY SETUP  FRONT PANEL  FLASH MESSAGE TIME. The factory
default flash message time is 4 seconds.
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RELAY MESSAGES
4 - 10
CHAPTER 4: INTERFACES
ADJUSTED VALUE
HAS BEEN STORED
This flash message is displayed in response to the ENTER key,
while on a setpoint message with a numerical value. The
edited value had to be adjusted to the nearest multiple of the
step value before it was stored.
COMMAND IS BEING
EXECUTED
This flash message is displayed in response to executing a
command message. Entering "Yes" at a command will display
the message ARE YOU SURE?. Entering "Yes" again will
perform the requested command and display this flash
message.
DEFAULT MESSAGE
HAS BEEN ADDED
This flash message is displayed in response to pressing the
decimal key, followed by the ENTER key twice, on any
message in S1 RELAY SETUP  DEFAULT MESSAGES.
DEFAULT MESSAGE
HAS BEEN REMOVED
This message is displayed in response to pressing the decimal
key, followed by the ENTER key twice, on any selected default
message in S1 RELAY SETUP  DEFAULT MESSAGES.
ENTER PASSCODE
IS INVALID
This flash message is displayed in response to an incorrectly
entered passcode when attempting to enable or disable
setpoint access.
ENTRY MISMATCH CODE NOT STORED
This message is displayed while changing the password with
the S1 RELAY SETUP  PASSCODE  CHANGE PASSCODE
setpoint. If the passcode entered at the PLEASE RE-ENTER
A NEW PASSCODE prompt is different from the one entered
PLEASE ENTER A NEW PASSCODE prompt, the relay
dumps the new passcode and display this message
INVALID KEY: MUST
BE IN LOCAL MODE
This flash message is displayed in response to pressing the
OPEN or close keys while the relay is in Remote Mode. The
relay must be put into Local Mode in order for these keys to be
operational.
NEW PASSCODE
STORED
This message is displayed in response to changing the
programmed passcode from the S1 RELAY SETUP  PASSCODE
 CHANGE PASSCODE setpoint. The directions to change the
passcode were followed correctly and the new passcode was
stored as entered.
NEW SETPOINT
STORED
This flash message is displayed in response to the ENTER key
while on any setpoint message. The edited value was stored
as entered.
NO CONDITIONS ARE
CURRENTLY ACTIVE
This flash message is displayed in response to the
MESSAGE  key when the relay is displaying TARGET
MESSAGES and the Message LED is off. There are no active
conditions to display in the diagnostic message queue.
OUT OF RANGE VALUE NOT STORED
This flash message is displayed in response to the ENTER key
while on a setpoint message or numerical value. The edited
value was either less than the minimum or greater than the
maximum acceptable values for the edited setpoint and as a
result was not stored.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 4: INTERFACES
RELAY MESSAGES
PLEASE ENTER A
NON-ZERO PASSCODE
This flash message is displayed while changing the passcode
with the S1 RELAY SETUP  PASSCODE  CHANGE PASSCODE
setpoint. An attempt was made to change the passcode to
“0” when it was already “0”.
PRESS [ENTER] TO
ADD AS DEFAULT
This flash message is displayed for 5 seconds in response to
pressing the decimal key, followed by the ENTER key while
displaying any setpoint or actual value message except those
in S1 RELAY SETUP  DEFAULT MESSAGES. Pressing the
ENTER key again while this message is displayed adds the
setpoint or actual value message to the default list.
PRESS [ENTER] TO
BEGIN TEXT EDIT
This message is displayed in response to the VALUE keys
while on a setpoint message with a text entry value. The
ENTER key must be pressed to begin editing.
PRESS [ENTER] TO
REMOVE MESSAGE
This flash message is displayed for 5 seconds in response to
pressing the decimal key, followed by the ENTER key while
displaying one of the selected default messages in the
subgroup S1 RELAY SETUP  DEFAULT MESSAGES. Pressing
the ENTER key again while this message is displayed removes
the default message from the list.
PRESSED KEY
IS INVALID HERE
This flash message is displayed in response to any pressed
key that has no meaning in the current context.
RESETTING LATCHED
CONDITIONS
This flash message is displayed in response to the RESET key.
All active latched conditions (trips, alarms, or latched relays)
for which the activating condition is no longer present will be
cleared.
SETPOINT ACCESS
DENIED (PASSCODE)
This flash message is displayed in response to the ENTER key
while on any setpoint message. Setpoint access is restricted
because the programmed passcode has not been entered to
allow access.
SETPOINT ACCESS
DENIED (SWITCH)
This flash message is displayed in response to the ENTER key
while on any setpoint message. Setpoint access is restricted
because the setpoint access terminals have not been
connected.
SETPOINT ACCESS
IS NOW ALLOWED
This flash message is displayed in response to correctly
entering the programmed passcode at the S1 RELAY SETUP 
PASSCODE  ALLOW ACCESS TO SETPOINTS setpoint. The
command to allow access to setpoints has been successfully
executed and setpoints can be changed and entered.
SETPOINT ACCESS
IS NOW RESTRICTED
This flash message is displayed in response to entering the
correct programmed passcode at the S1 RELAY SETUP 
PASSCODE  RESTRICT ACCESS TO SETPOINTS setpoint. The
command to restrict access to setpoints has been
successfully executed and setpoints cannot be changed.
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ENERVISTA 750/760 SETUP SOFTWARE INTERFACE
4.4
4.4.1
Overview
CHAPTER 4: INTERFACES
EnerVista 750/760 Setup Software Interface
The EnerVista 750/760 Setup software provides a graphical user interface (GUI) as one of
two human interfaces to a 750/760 device. The alternate human interface is implemented
via the device's faceplate keypad and display (see the first section in this chapter).
The EnerVista 750/760 Setup software provides a single facility to configure, monitor,
maintain, and trouble-shoot the operation of relay functions, connected over serial
communication networks. It can be used while disconnected (i.e. off-line) or connected (i.e.
on-line) to a 750/760 device. In off-line mode, settings files can be created for eventual
downloading to the device. In on-line mode, you can communicate with the device in realtime.
This no-charge software, provided with every 750/760 relay, can be run from any
computer supporting Microsoft Windows 95 or higher. This chapter provides a summary of
the basic EnerVista 750/760 Setup software interface features. The EnerVista 750/760
Setup Help File provides details for getting started and using the software interface.
With the EnerVista 750/760 Setup running on your PC, it is possible to:
4.4.2
4 - 12
Hardware
•
Program and modify setpoints
•
Load/save setpoint files from/to disk
•
Read actual values and monitor status
•
Perform waveform capture and log data
•
Plot, print, and view trending graphs of selected actual values
•
Download and playback waveforms
•
Get help on any topic
Communications from the EnerVista 750/760 Setup to the 750/760 can be accomplished
three ways: RS232, RS485, and Ethernet communications. The following figures below
illustrate typical connections for RS232, RS485, and Ethernet communications.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
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ENERVISTA 750/760 SETUP SOFTWARE INTERFACE
FIGURE 4–3: Communications using the Front RS232 Port
FIGURE 4–4: Communications using Rear RS485 Port
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ENERVISTA 750/760 SETUP SOFTWARE INTERFACE
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RS485 COM2 is disabled when the Ethernet option is ordered.
Note
NOTE
996711A1.CDR
FIGURE 4–5: Communications using Rear Ethernet Port
4.4.3
Installing the
EnerVista 750/
760 Setup
Software
The following minimum requirements must be met for the EnerVista 750/760 Setup
software to operate on your computer.
•
Pentium class or higher processor (Pentium II 300 MHz or better recommended)
•
Microsoft Windows 95, 98, 98SE, ME, NT 4.0 (SP4 or higher), 2000, XP
•
64 MB of RAM (256 MB recommended)
•
Minimum of 50 MB hard disk space (200 MB recommended)
After ensuring these minimum requirements, use the following procedure to install the
EnerVista 750/760 Setup software from the enclosed GE EnerVista CD.
4 - 14
1.
Insert the GE EnerVista CD into your CD-ROM drive.
2.
Click the Install Now button and follow the installation instructions to install the nocharge EnerVista software on the local PC.
3.
When installation is complete, start the EnerVista Launchpad application.
4.
Click the IED Setup section of the Launch Pad window.
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ENERVISTA 750/760 SETUP SOFTWARE INTERFACE
5.
In the EnerVista Launch Pad window, click the Install Software button and select the
“750 Feeder Management Relay” or “760 Feeder Management Relay” from the Install
Software window as shown below. Select the “Web” option to ensure the most recent
software release, or select “CD” if you do not have a web connection, then click the
Check Now button to list software items for the 750/760.
6.
Select the EnerVista 750/760 Setup software and release notes (if desired) from the list
and click the Download Now button to obtain the installation program.
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7.
EnerVista Launchpad will obtain the installation program from the Web or CD. Once
the download is complete, double-click the installation program to install the
EnerVista 750/760 Setup software.
8.
The program will request the user to create a backup 3.5" floppy-disk set. If this is
desired, click on the Start Copying button; otherwise, click on the CONTINUE WITH
750/760 INSTALLATION button.
9.
Select the complete path, including the new directory name, where the EnerVista 750/
760 Setup software will be installed.
10. Click on Next to begin the installation. The files will be installed in the directory
indicated and the installation program will automatically create icons and add
EnerVista 750/760 Setup software to the Windows start menu.
11. Click Finish to end the installation. The 750/760 device will be added to the list of
installed IEDs in the EnerVista Launchpad window, as shown below.
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CONNECTING ENERVISTA 750/760 SETUP TO THE RELAY
4.5
4.5.1
Configuring
Serial
Communicatio
ns
Connecting EnerVista 750/760 Setup to the Relay
Before starting, verify that the serial cable is properly connected to either the RS232 port
on the front panel of the device (for RS232 communications) or to the RS485 terminals on
the back of the device (for RS485 communications). See Hardware on page 4–12 for
connection details.
This example demonstrates an RS232 connection. For RS485 communications, the GE
Multilin F485 converter will be required. Refer to the F485 manual for additional details. To
configure the relay for Ethernet communications, see Configuring Ethernet
Communications on page 4–19.
1.
Install and start the latest version of the EnerVista 750/760 Setup software (available
from the GE EnerVista CD). See the previous section for the installation procedure.
2. Click on the Device Setup button to open the Device Setup window and click
the Add Site button to define a new site.
3. Enter the desired site name in the Site Name field. If desired, a short description of site can also be entered along with the display order of devices defined
for the site. In this example, we will use “Substation 1” as the site name. Click
the OK button when complete.
4. The new site will appear in the upper-left list in the EnerVista 750/760 Setup
window.
5. Click the Add Device button to define the new device.
6. Enter the desired name in the Device Name field and a description (optional)
of the site.
7. Select “Serial” from the Interface drop-down list. This will display a number of
interface parameters that must be entered for proper RS232 functionality.
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CONNECTING ENERVISTA 750/760 SETUP TO THE RELAY
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•
Enter the slave address and COM port values (from the S1 RELAY SETUP 
COMMUNICATIONS  PORT SETUP menu) in the Slave Address and COM Port fields.
•
Enter the physical communications parameters (baud rate and parity settings) in their
respective fields.
8. Click the Read Order Code button to connect to the 750/760 device and
upload the order code. If an communications error occurs, ensure that the
750/760 serial communications values entered in the previous step correspond to the relay setting values.
9. Click OK when the relay order code has been received. The new device will
be added to the Site List window (or Online window) located in the top left corner of the main EnerVista 750/760 Setup window.
The 750/760 Site Device has now been configured for serial communications. Proceed to
Connecting to the Relay on page 4–20 to begin communications.
4.5.2
Using the
Quick Connect
Feature
The Quick Connect button can be used to establish a fast connection through the front
panel RS232 port of a 750/760 relay. The following window will appear when the Quick
Connect button is pressed:
As indicated by the window, the Quick Connect feature quickly connects the EnerVista 750/
760 Setup software to a 750/760 front port with the following settings: 9600 baud, no
parity, 8 bits, 1 stop bit. Select the PC communications port connected to the relay and
press the Connect button.
The EnerVista 750/760 Setup software will display a window indicating the status of
communications with the relay. When connected, a new Site called “Quick Connect” will
appear in the Site List window. The properties of this new site cannot be changed.
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CONNECTING ENERVISTA 750/760 SETUP TO THE RELAY
The 750/760 Site Device has now been configured via the Quick Connect feature for serial
communications. Proceed to Connecting to the Relay on page 4–20 to begin
communications.
4.5.3
Configuring
Ethernet
Communicatio
ns
Before starting, verify that the Ethernet cable is properly connected to the RJ-45 Ethernet
port.
750/760 supports a maximum of 4 TCP/IP sessions.
Note
NOTE
1.
Install and start the latest version of the EnerVista 750/760 Setup software (available
from the GE EnerVista CD). See the previous section for the installation procedure.
2. Click on the Device Setup button to open the Device Setup window and click
the Add Site button to define a new site.
3. Enter the desired site name in the Site Name field. If desired, a short description of site can also be entered along with the display order of devices defined
for the site. In this example, we will use “Substation 2” as the site name. Click
the OK button when complete.
4. The new site will appear in the upper-left list.
5. Click the Add Device button to define the new device.
6. Enter the desired name in the Device Name field and a description (optional).
7. Select “Ethernet” from the Interface drop-down list. This will display a number
of interface parameters that must be entered for proper Ethernet functionality.
Enter the IP address, slave address, and Modbus port values assigned to the
750/760 relay (from the S1 RELAY SETUP  COMMUNICATIONS  NETWORK
CONFIGURATION menu).
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CONNECTING ENERVISTA 750/760 SETUP TO THE RELAY
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8. Click the Read Order Code button to connect to the 750/760 and upload the
order code. If an communications error occurs, ensure that the Ethernet communications values correspond to the relay setting values.
9. Click OK when the relay order code has been received. The new device will
be added to the Site List window (or Online window) located in the top left corner of the main EnerVista 750/760 Setup window.
The 750/760 Site Device has now been configured for Ethernet communications. Proceed
to the following section to begin communications.
4.5.4
Connecting to
the Relay
Now that the communications parameters have been properly configured, the user can
easily communicate with the relay.
1.
Expand the Site list by double clicking on the site name or clicking on the «+» box to
list the available devices for the given site (for example, in the “Substation 1” site
shown below).
2. Desired device trees can be expanded by clicking the «+» box. The following
list of headers is shown for each device:
Device Definitions
Settings
Actual Values
Commands
Communications
3. Expand the Settings > Relay Setup list item and double click on Front Panel to
open the Front Panel settings window as shown below:
Expand the Site List by doubleclicking or by selecting the [+] box
Communications Status Indicator
Green = OK, Red = No Comms
FIGURE 4–6: Main Window After Connection
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CONNECTING ENERVISTA 750/760 SETUP TO THE RELAY
4. The Front Panel settings window will open with a corresponding status indicator on the lower left of the EnerVista 750/760 Setup window.
5. If the status indicator is red, verify that the serial or Ethernet cable is properly
connected to the relay, and that the relay has been properly configured for
communications (steps described earlier).
The Front Panel settings can now be edited, printed, or changed according to user
specifications. Other setpoint and commands windows can be displayed and edited in a
similar manner. Actual values windows are also available for display. These windows can
be locked, arranged, and resized at will.
Refer to the EnerVista 750/760 Setup Help File for additional information about the
using the software.
Note
NOTE
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WORKING WITH SETPOINTS AND SETPOINT FILES
4.6
CHAPTER 4: INTERFACES
Working with Setpoints and Setpoint Files
4.6.1
Engaging a
Device
The EnerVista 750/760 Setup software may be used in on-line mode (relay connected) to
directly communicate with a 750/760 relay. Communicating relays are organized and
grouped by communication interfaces and into sites.
4.6.2
Entering
Setpoints
The System Setup page will be used as an example to illustrate the entering of setpoints. In
this example, we will be changing the current sensing setpoints.
1.
Establish communications with the relay.
2.
Select the Setpoint > System Setup menu item. This can be selected from the device
setpoint tree or the main window menu bar.
3.
Select the PHASE CT PRIMARY setpoint by clicking anywhere in the parameter box. This
will display three arrows: two to increment/decrement the value and another to
launch the numerical calculator.
4.
Clicking the arrow at the end of the box displays a numerical keypad interface that
allows the user to enter a value within the setpoint range displayed near the top of the
keypad:
Click Accept to exit from the keypad and keep the new value. Click on Cancel to exit
from the keypad and retain the old value.
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4.6.3
File Support
WORKING WITH SETPOINTS AND SETPOINT FILES
5.
For setpoints requiring non-numerical pre-set values (e.g. BUS VT CONNECTION TYPE
above), clicking anywhere within the setpoint value box displays a drop-down
selection menu arrow. Select the desired value from this list.
6.
For setpoints requiring an alphanumeric text string (e.g. message scratchpad
messages), the value may be entered directly within the setpoint value box.
7.
In the Setpoint / System Setup dialog box, click on Store to save the values into the
750/760. Click OK to accept any changes and exit the window. Click Cancel to retain
previous values and exit.
Opening any EnerVista 750/760 Setup file will automatically launch the application or
provide focus to the already opened application. If the file is a settings file (has a ‘750’ or
‘760’ extension) which had been removed from the Settings List tree menu, it will be added
back to the Settings List tree.
New files will be automatically added to the tree, which is sorted alphabetically with
respect to settings file names.
4.6.4
Using
Setpoints Files
Overview
The EnerVista 750/760 Setup software interface supports three ways of handling changes
to relay settings:
•
In off-line mode (relay disconnected) to create or edit relay settings files for later
download to communicating relays.
•
Directly modifying relay settings while connected to a communicating relay, then
saving the settings when complete.
•
Creating/editing settings files while connected to a communicating relay, then saving
them to the relay when complete.
Settings files are organized on the basis of file names assigned by the user. A settings file
contains data pertaining to the following types of relay settings:
•
Device Definition
•
Product Setup
•
System Setup
•
Grouped Elements
•
Control Elements
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WORKING WITH SETPOINTS AND SETPOINT FILES
•
Inputs/Outputs
•
Testing
CHAPTER 4: INTERFACES
Factory default values are supplied and can be restored after any changes.
The EnerVista 750/760 Setup display relay setpoints with the same hierarchy as the front
panel display. For specific details on setpoints, refer to Chapter 5.
Downloading and Saving Setpoints Files
Setpoints must be saved to a file on the local PC before performing any firmware
upgrades. Saving setpoints is also highly recommended before making any setpoint
changes or creating new setpoint files.
The EnerVista 750/760 Setup window, setpoint files are accessed in the Settings List
control bar window or the Files Window. Use the following procedure to download and
save setpoint files to a local PC.
1.
Ensure that the site and corresponding device(s) have been properly defined and
configured as shown in Connecting EnerVista 750/760 Setup to the Relay on page 4–
17.
2.
Select the desired device from the site list.
3.
Select the File > Read Settings from Device menu item to obtain settings information
from the device.
4.
After a few seconds of data retrieval, the software will request the name and
destination path of the setpoint file. The corresponding file extension will be
automatically assigned. Press Save to complete the process. A new entry will be
added to the tree, in the File pane, showing path and file name for the setpoint file.
Adding Setpoints Files to the Environment
The EnerVista 750/760 Setup software provides the capability to review and manage a
large group of setpoint files. Use the following procedure to add a new or existing file to the
list.
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WORKING WITH SETPOINTS AND SETPOINT FILES
1.
In the files pane, right-click on ‘Files’ and select the Add Existing Setting File item as
shown:
2.
The Open dialog box will appear, prompting the user to select a previously saved
setpoint file. As for any other MS Windows® application, browse for the file to be
added then click Open. The new file and complete path will be added to the file list.
Creating a New Setpoint File
The EnerVista 750/760 Setup software allows the user to create new setpoint files
independent of a connected device. These can be uploaded to a relay at a later date. The
following procedure illustrates how to create new setpoint files.
1.
In the File pane, right click on ‘File’ and select the New Settings File item. The
EnerVista 750/760 Setup software displays the following box will appear, allowing for
the configuration of the setpoint file for the correct firmware version. It is important to
define the correct firmware version to ensure that setpoints not available in a
particular version are not downloaded into the relay.
2.
Select the Device Type, Hardware Revision, and Firmware Version for the new setpoint
file.
3.
For future reference, enter some useful information in the Description box to facilitate
the identification of the device and the purpose of the file.
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WORKING WITH SETPOINTS AND SETPOINT FILES
CHAPTER 4: INTERFACES
4.
To select a file name and path for the new file, click the button beside the Enter File
Name box.
5.
Select the file name and path to store the file, or select any displayed file name to
update an existing file. All 750/760 setpoint files should have the extension ‘750’ or
‘760’ (for example, ‘feeder1.750’).
6.
Click Save and OK to complete the process. Once this step is completed, the new file,
with a complete path, will be added to the EnerVista 750/760 Setup software
environment.
Upgrading Setpoint Files to a New Revision
It is often necessary to upgrade the revision code for a previously saved setpoint file after
the 750/760 firmware has been upgraded (for example, this is required for firmware
upgrades). This is illustrated in the following procedure.
1.
Establish communications with the 750/760 relay.
2.
Select the Actual > A5 Product Info menu item and record the Software Revision
identifier of the relay firmware.
3.
Load the setpoint file to be upgraded into the EnerVista 750/760 Setup environment
as described in Adding Setpoints Files to the Environment on page 4–24.
4.
In the File pane, select the saved setpoint file.
5.
From the main window menu bar, select the File > Properties menu item and note the
File Version of the setpoint file. If this version (e.g. 5.00 shown below) is different than
the Software Revision code noted in step 2, select a New File Version that matches
the Software Revision code from the pull-down menu.
6.
For example, if the firmware revision is 27L720A5.000 (software revision 7.20) and the
current setpoint file revision is 5.00, change the setpoint file revision to “7.2x”.
Enter any special comments
about the setpoint file here.
7.
4 - 26
Select the desired setpoint version
from this menu. The 6.0x indicates
versions 6.00, 6.01, 6.02, etc.
When complete, click Convert to convert the setpoint file to the desired revision. A
dialog box will request confirmation. See Loading Setpoints from a File on page 4–27
for instructions on loading this setpoint file into the 750/760.
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WORKING WITH SETPOINTS AND SETPOINT FILES
Printing Setpoints and Actual Values
The EnerVista 750/760 Setup software allows the user to print partial or complete lists of
setpoints and actual values. Use the following procedure to print a list of setpoints:
1.
Select a previously saved setpoints file in the File pane or establish communications
with a 750/760 device.
2.
From the main window, select the File > Print Settings menu item.
3.
The Print/Export Options dialog box will appear. Select Settings in the upper section
and select either Include All Features (for a complete list) or Include Only Enabled
Features (for a list of only those features which are currently used) in the filtering
section and click OK.
4.
The process for File > Print Preview Settings is identical to the steps above.
5.
Setpoints lists can be printed in the same manner by right clicking on the desired file
(in the file list) or device (in the device list) and selecting the Print Device Information
or Print Settings File options.
A complete list of actual values can also be printed from a connected device with the
following procedure:
1.
Establish communications with the desired 750/760 device.
2.
From the main window, select the File > Print Settings menu item.
3.
The Print/Export Options dialog box will appear. Select Actual Values in the upper
section and select either Include All Features (for a complete list) or Include Only
Enabled Features (for a list of only those features which are currently used) in the
filtering section and click OK.
Actual values lists can be printed in the same manner by right clicking on the desired
device (in the device list) and selecting the Print Device Information option.
Loading Setpoints from a File
An error message will occur when attempting to download a setpoint file with a
revision number that does not match the relay firmware. If the firmware has been
upgraded since saving the setpoint file, see Upgrading Setpoint Files to a New Revision
on page 4–26 for instructions on changing the revision number of a setpoint file.
The following procedure illustrates how to load setpoints from a file. Before loading a
setpoints file, it must first be added to the EnerVista 750/760 Setup environment as
described in Adding Setpoints Files to the Environment on page 4–24.
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WORKING WITH SETPOINTS AND SETPOINT FILES
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CHAPTER 4: INTERFACES
1.
Select the previously saved setpoints file from the File pane of the EnerVista 750/760
Setup software main window.
2.
Select the File > Properties menu item and verify that the corresponding file is fully
compatible with the hardware and firmware version of the target relay. If the versions
are not identical, see Upgrading Setpoint Files to a New Revision on page 4–26 for
details on changing the setpoints file version.
3.
Right-click on the selected file and select the Write Settings to Device item.
4.
Select the target relay from the list of devices shown and click Send. If there is an
incompatibility, an error of following type will occur:
5.
If there are no incompatibilities between the target device and the settings file, the
data will be transferred to the relay. An indication of the percentage completed will be
shown in the bottom of the main window.
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UPGRADING RELAY FIRMWARE
4.7
4.7.1
Description
Upgrading Relay Firmware
To upgrade the 750/760 firmware, follow the procedures listed in this section. Upon
successful completion of this procedure, the 750/760 will have new firmware installed with
the original setpoints.
The latest firmware files are available from the GE Multilin website at http://
www.gedigitalenergy.com.
Note
NOTE
Enervista 750/760 Software prevents incompatible firmware from being loaded into a 750/
760 relay.
Firmware version 7.20 is compatible only with hardware version ‘L*’. Firmware version 7.01
or older is not compatible with hardware version ‘L’.
* However, firmware version 7.21 is compatible with both Hardware revs K and L.
Note
NOTE
Relay Hardware Version
Bootware Version
Compatible Application Firmware
Versions
"K"
500
7.00
7.01
7.21
"L"
600
7.20
"L"
601
7.21
Units with bootware versions earlier than 3.00 must be set to a baud rate of 9600 with a
Slave Address of 1 before downloading new firmware. The bootware version can be
checked in the A5 PRODUCT INFO  REVISION CODES  BOOTWARE REVISION actual
value.
It is recommended not to downgrade the firmware revision of the 750/760.
Downgrading an 750/760 with Ethernet option from higher firmware revision to FW
revision 7.20 can lose the Ethernet functionality in the relay. Please contact Multilin
Technical Support team for more details.
4.7.2
Saving
Setpoints To A
File
Before upgrading firmware, it is very important to save the current 750/760 settings to a
file on your PC. After the firmware has been upgraded, it will be necessary to load this file
back into the 750/760.
Refer to Downloading and Saving Setpoints Files on page 4–24 for details on saving relay
setpoints to a file.
4.7.3
Loading New
Firmware
Loading new firmware into the 750/760 flash memory is accomplished as follows:
1.
Connect the relay to the local PC and save the setpoints to a file as shown in
Downloading and Saving Setpoints Files on page 4–24.
2.
Select the Communications > Update Firmware menu item.
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UPGRADING RELAY FIRMWARE
CHAPTER 4: INTERFACES
3.
The following warning message will appear. Select Yes to proceed or No the cancel the
process. Do not proceed unless you have saved the current setpoints.
4.
The EnerVista 750/760 Setup software will request the new firmware file. Locate the
firmware file to load into the 750/760. The firmware filename has the following
format:
27 L 720 A5 . 000
Modification Number (000 = none)
A5 = Analog Board file; C5 = Control Board file
Firmware Version
Required 750/760 hardware
Product code (27 = 750)
The 750/760PC software automatically lists all filenames beginning with ‘27’. Select
the appropriate file and click OK to continue. This will be the Analog Board file.
6.
A second file request will be prompted. This will be for the Control Board file.
Both analog and control board files must have the same firmware versions.
Note
NOTE
Note
NOTE
4 - 30
5.
7.
EnerVista 750/760 Setup software now prepares the 750/760 to receive the new
firmware file. The 750/760 front panel will momentarily display “Code Programming
Mode Ready,” indicating that it is in upload mode. The 750/760 front panel continues
with display “Erasing Analog Board Flash Memory.”
With hardware revision ‘K’ and earlier, at this point EverVista 750/760 Setup software may
occasionally display the prompt shown below. If this occurs, select “Retry”. It may require
up to 5 attempts.
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UPGRADING RELAY FIRMWARE
8.
While the file is being loaded into the 750/760, a status box appears showing how
much of the new firmware file has been transferred and how much is remaining, as
well as the upgrade status. The entire transfer process takes approximately 15
minutes if communicating at 19200 baud..
9.
The EnerVista 750/760 Setup software will notify the user when the 750/760 has
finished loading the file. Carefully read any displayed messages and click OK to return
the main screen.
Cycling power to the relay is recommended after a firmware upgrade.
Note
NOTE
After successfully updating the 750/760 firmware, the relay will not be in service and will
require setpoint programming. To communicate with the relay, the following settings will
have to me manually programmed.
MODBUS COMMUNICATION ADDRESS
BAUD RATE
PARITY (if applicable)
When communications is established, the saved setpoints must be reloaded back into the
relay. See Loading Setpoints from a File on page 4–27 for details.
Modbus addresses assigned to firmware modules, features, settings, and corresponding
data items (i.e. default values, min/max values, data type, and item size) may change
slightly from version to version of firmware.
The addresses are rearranged when new features are added or existing features are
enhanced or modified. The EEPROM DATA ERROR message displayed after upgrading/
downgrading the firmware is a resettable, self-test message intended to inform users that
the Modbus addresses have changed with the upgraded firmware. This message does not
signal any problems when appearing after firmware upgrades.
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ADVANCED ENERVISTA 750/760 SETUP FEATURES
4.8
4.8.1
4.8.2
Triggered
Events
Waveform
Capture (Trace
Memory)
CHAPTER 4: INTERFACES
Advanced EnerVista 750/760 Setup Features
While the interface is in either on-line or off-line mode, data generated by triggered
specified parameters can be viewed and analyzed via one of the following features:
•
Event Recorder: The event recorder captures contextual data associated with the last
512 events, listed in chronological order from most recent to the oldest.
•
Oscillography: The oscillography waveform traces and digital states provide a visual
display of power system and relay operation data captured during specific triggered
events.
The EnerVista 750/760 Setup software can be used to capture waveforms (or view trace
memory) from the 750/760 relay at the instance of a trip. A maximum of 512 cycles can be
captured and the trigger point can be adjusted to anywhere within the set cycles. A
maximum of 16 waveforms can be buffered (stored) with the buffer/cycle trade-off.
The following waveforms can be captured:
•
Phase A, B, and C currents (Ia, Ib, and Ic)
•
Ground and Sensitive ground currents (Ig and Isg)
•
Phase A-N, B-N, and C-N voltages (Va, Vb, and Vc)
•
Digital data for output relays and contact input states.
1.
With EnerVista 750/760 Setup running and communications established, select the
Actual > Waveform Capture menu item to open the waveform capture setup
window:
Number of available files
Files to be saved or viewed
Save waveform to a file
Click on Trigger Waveform to trigger a waveform capture.
The waveform file numbering starts with the number zero in the 750/760; therefore,
the maximum trigger number will always be one less then the total number triggers
available.
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ADVANCED ENERVISTA 750/760 SETUP FEATURES
2.
Click on the Save to File button to save the selected waveform to the local PC. A new
window will appear requesting for file name and path.
3.
The file is saved as a comma separated values file, with the extension ‘CSV’. A CSV file
can be viewed and manipulated with compatible third-party software, such as
Microsoft Excel.
4.
To view a previously saved file, click the Open button and select the corresponding
CSV file.
5.
To view the captured waveforms, click the Launch Viewer button. A detailed
Waveform Capture window will appear as shown below:
TRIGGER TIME & DATE
Display the time & date of the
Trigger
Display graph values
at the corresponding
cursor line. Cursor
lines are identified by
their colors.
VECTOR DISPLAY SELECT
Click here to open a new graph
to display vectors
FILE NAME
Indicates the
file name and
complete path
(if saved)
CURSOR LINE POSITION
Indicate the cursor line position
in time with respect to the
trigger time
DELTA
Indicates time difference
between the two cursor lines
CURSOR
LINES
To move lines locate the mouse pointer
over the cursor line then click and drag
the cursor to the new location.
TRIGGER LINE
Indicates the
point in time for
the trigger
FIGURE 4–7: Waveform Capture Window Attributes
6.
The red vertical line indicates the trigger point of the relay.
7.
The date and time of the trip is displayed at the top left corner of the window. To
match the captured waveform with the event that triggered it, make note of the time
and date shown in the graph. Then, find the event that matches the same time and
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
4 - 33
ADVANCED ENERVISTA 750/760 SETUP FEATURES
CHAPTER 4: INTERFACES
date in the event recorder. The event record will provide additional information on the
cause and the system conditions at the time of the event. Additional information on
how to download and save events is shown in Event Recorder on page 4–35.
8.
From the window main menu bar, press the Preference button to open the Graph
Setup page to change the graph attributes.
Preference button
9.
The following window will appear:
Change the Color of each graph as desired, and select other options as required, by
checking the appropriate boxes. Click OK to store these graph attributes, and to close
the window.
10. The Waveform Capture window will reappear with the selected graph attributes
available for use.
4 - 34
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 4: INTERFACES
ADVANCED ENERVISTA 750/760 SETUP FEATURES
11. To view a vector graph of the quantities contained in the waveform capture, press the
Vector display button (see FIGURE 4–7: Waveform Capture Window Attributes on page
4–33) to display the following window:
12. Use the graph attribute utility described in step 7 to change the vector colors.
4.8.3
Data Logger
The data logger feature is used to sample and record up to eight actual values at an
interval that is defined by the user. Refer to Event Recorder on page 5–14 for additional
details. The Data Logger window behaves in the same manner as the Waveform Capture
described above.
4.8.4
Event
Recorder
The 750/760 event recorder can be viewed through the EnerVista 750/760 Setup software.
The event recorder stores generator and system information each time an event occurs
(e.g. breaker failure). A maximum of 512 events can be stored, where E512 is the most
recent event and E001 is the oldest event. E001 is overwritten whenever a new event
occurs. Refer to Event Records on page 6–20 for additional information on the event
recorder.
Use the following procedure to view the event recorder with EnerVista 750/760 Setup:
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
4 - 35
ADVANCED ENERVISTA 750/760 SETUP FEATURES
1.
With EnerVista 750/760 Setup running and communications established, select the
Actual > A4 Event Recorder item from the main menu. This displays the Event
Recorder window indicating the list of recorded events, with the most current event
displayed first.
EVENT LISTING
Lists the last 512 events
with the most recent
displayed at top of list.
DEVICE ID
The events shown here
correspond to this device.
2.
4.8.5
Modbus User
Map
EVENT SELECT BUTTONS
Click the All button to select
all events; click the None
button to clear all selections.
EVENT NUMBER
The event data information
is related to the event number
shown here.
EVENT DATA
System information as
measured by the relay
at the instant of the
event occurrence.
CLEAR EVENTS
Click the Clear
Events button to
clear the event list
from memory.
SAVE EVENTS
Click the Save Events
button to save the event
record to the PC as a
CSV file.
To view detailed information for a given event and the system information at the
moment of the event occurrence, change the event number on the Select Event box.
The EnerVista 750/760 Setup software provides a means to program the 750/760 User
Map (Modbus addresses 0180h to 01F7h). Refer to GE Publication GEK-106473: 750/760
Communications Guide for additional information on the User Map.
1.
4 - 36
CHAPTER 4: INTERFACES
Select a connected device in EnerVista 750/760 Setup.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 4: INTERFACES
ADVANCED ENERVISTA 750/760 SETUP FEATURES
2.
Select the Setpoint > User Map menu item to open the following window.
This window allows the desired addresses to be written to User Map locations. The
User Map values that correspond to these addresses are then displayed.
4.8.6
Viewing Actual
Values
You can view real-time relay data such as input/output status and measured parameters.
From the main window menu bar, selecting Actual Values opens a window with tabs, each
tab containing data in accordance to the following list:
•
Status: Virtual Inputs, Hardware Inputs, Last Trip Data, Fault Locations, and
Autoreclose (760 Only)
•
Metering: Current, Voltage, Frequency, Synchrocheck Voltage, Power, Energy,
Demand, and Analog Inputs
•
Maintenance: Trip Counters and Arcing Current
•
Product Information: Revision Codes and Calibration Dates
Selecting an actual values window also opens the actual values tree from the
corresponding device in the site list and highlights the current location in the hierarchy.
For complete details on actual values, refer to Chapter 6.
To view a separate window for each group of actual values, select the desired item from
the tree, and double click with the left mouse button. Each group will be opened on a
separate tab. The windows can be re-arranged to maximize data viewing as shown in the
following figure (showing actual current, voltage, and power values tiled in the same
window):
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
4 - 37
ADVANCED ENERVISTA 750/760 SETUP FEATURES
CHAPTER 4: INTERFACES
FIGURE 4–8: Actual Values Display
4 - 38
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 4: INTERFACES
USING ENERVISTA VIEWPOINT WITH THE 750/760
4.9
4.9.1
Plug and Play
Example
Using EnerVista Viewpoint with the 750/760
EnerVista Viewpoint is an optional software package that puts critical 750/760 information
onto any PC with plug-and-play simplicity. EnerVista Viewpoint connects instantly to the
750/760 via serial, ethernet or modem and automatically generates detailed overview,
metering, power, demand, energy and analysis screens. Installing EnerVista Launchpad
(see previous section) allows the user to install a fifteen-day trial version of EnerVista
Viewpoint. After the fifteen day trial period you will need to purchase a license to continue
using EnerVista Viewpoint. Information on license pricing can be found at http://
www.EnerVista.com.
1.
Install the EnerVista Viewpoint software from the GE EnerVista CD.
2.
Ensure that the 750/760 device has been properly configured for either serial or
Ethernet communications (see previous sections for details).
3.
Click the Viewpoint window in EnerVista to log into EnerVista Viewpoint. At this point,
you will be required to provide a login and password if you have not already done so.
FIGURE 4–9: EnerVista Viewpoint Main Window
4.
Click the Device Setup button to open the Device Setup window, then click the Add
Site button to define a new site.
5.
Enter the desired site name in the Site Name field. If desired, a short description of site
can also be entered along with the display order of devices defined for the site. Click
the OK button when complete. The new site will appear in the upper-left list in the
EnerVista 750/760 Setup window.
6.
Click the Add Device button to define the new device.
7.
Enter the desired name in the Device Name field and a description (optional) of the
site.
8.
Select the appropriate communications interface (Ethernet or Serial) and fill in the
required information for the 750/760. See Connecting EnerVista 750/760 Setup to the
Relay on page 4–17 for details.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
4 - 39
USING ENERVISTA VIEWPOINT WITH THE 750/760
CHAPTER 4: INTERFACES
FIGURE 4–10: Device Setup Screen (Example)
9.
Click the Read Order Code button to connect to the 750/760 device and upload the
order code. If an communications error occurs, ensure that communications values
entered in the previous step correspond to the relay setting values.
10. Click OK when complete.
11. From the EnerVista main window, select the IED Dashboard item to open the Plug and
Play IED dashboard. An icon for the 750/760 will be shown.
FIGURE 4–11: ‘Plug and Play’ Dashboard
4 - 40
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 4: INTERFACES
USING ENERVISTA VIEWPOINT WITH THE 750/760
12. Click the Dashboard button below the 750/760 icon to view the device information.
We have now successfully accessed our 750/760 through EnerVista Viewpoint.
FIGURE 4–12: EnerVista Plug and Play Screens
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
4 - 41
USING ENERVISTA VIEWPOINT WITH THE 750/760
CHAPTER 4: INTERFACES
For additional information on EnerVista viewpoint, please visit the EnerVista website at
http://www.EnerVista.com.
4 - 42
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
GE
Digital Energy
750/760 Feeder Management
Relay
Chapter 5: Setpoints
Setpoints
5.1
Overview
5.1.1
Setpoints Main Menu
The 750/760 has a considerable number of programmable setpoints which makes it
extremely flexible. The setpoints have been grouped into a number of pages and subpages as shown below. Each page of setpoints (e.g. S2 SYSTEM SETUP) has a section which
describes in detail all the setpoints found on that page.

SETPOINTS
S1 RELAY SETUP
[]
MESSAGE
MESSAGE
MESSAGE
MESSAGE
MESSAGE
MESSAGE
MESSAGE
MESSAGE
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL

PASSCODE
[]

COMMUNICATIONS
[]

CLOCK
[]

EVENT RECORDER
[]

TRACE MEMORY
[]

DATA LOGGER
[]

FRONT PANEL
[]

DEFAULT
MESSAGES
[]

USER TEXT
MESSAGES
[]
See page 5–9
See page 5–9
See page 5–13
See page 5–14
See page 5–15
See page 5–16
See page 5–17
See page 5–18
See page 5–19
5-1
OVERVIEW
CHAPTER 5: SETPOINTS
MESSAGE
MESSAGE
MESSAGE
MESSAGE

CLEAR DATA
[]

INSTALLATION
[]

MOD VERSION
UPGRADE
[]

END OF PAGE S1

CURRENT
SENSING
[]

BUS VT
SENSING
[]

LINE VT
SENSING
[]

POWER SYSTEM
[]

FLEXCURVE A
[]

FLEXCURVE B
[]

END OF PAGE S2

LOGIC INPUTS
SETUP
[]

BREAKER
FUNCTIONS
[]

CONTROL
FUNCTIONS
[]

USER INPUTS
[]

BLOCK
FUNCTIONS
[]

BLOCK OC
FUNCTIONS
[]

TRANSFER
FUNCTIONS
[]

RECLOSE
FUNCTIONS
[]
See page 5–20
See page 5–20
See page 5–21
MESSAGE

SETPOINTS
[]
S2 SYSTEM SETUP
MESSAGE
MESSAGE
MESSAGE
MESSAGE
MESSAGE
MESSAGE
See page 5–22
See page 5–22
See page 5–23
See page 5–23
See page 5–24
See page 5–24
MESSAGE

SETPOINTS
[]
S3 LOGIC INPUTS
MESSAGE
MESSAGE
MESSAGE
MESSAGE
MESSAGE
MESSAGE
MESSAGE
5-2
See page 5–27
See page 5–28
See page 5–30
See page 5–31
See page 5–32
See page 5–34
See page 5–35
See page 5–36
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
OVERVIEW
MESSAGE
MESSAGE

MISC
FUNCTIONS

END OF PAGE S3

1 TRIP RELAY
[]

2 CLOSE RELAY
[]

3 AUXILIARY
[]

4 AUXILIARY
[]

5 AUXILIARY
[]

6 AUXILIARY
[]

7 AUXILIARY
[]

END OF PAGE S4

PHASE
CURRENT
[]

NEUTRAL
CURRENT
[]

GROUND
CURRENT
[]

SENSTV GND
CURRENT
[]

NEGATIVE
SEQUENCE
[]

VOLTAGE
[]

FREQUENCY
[]

BREAKER
FAILURE
[]

REVERSE
POWER
[]
[]
See page 5–36
MESSAGE

SETPOINTS
[]
MESSAGE
MESSAGE
MESSAGE
MESSAGE
MESSAGE
MESSAGE
MESSAGE
See page 5–39
See page 5–40
See page 5–41
See page 5–41
See page 5–41
See page 5–41
See page 5–41
MESSAGE

SETPOINTS
S5 PROTECTION
[]
MESSAGE
MESSAGE
MESSAGE
MESSAGE
MESSAGE
MESSAGE
MESSAGE
MESSAGE
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
See page 5–50
See page 5–58
See page 5–64
See page 5–68
See page 5–76
See page 5–82
See page 5–87
See page 5–90
See page 5–92
5-3
OVERVIEW
CHAPTER 5: SETPOINTS
MESSAGE

END OF PAGE S5

CURRENT LEVEL
[]

POWER FACTOR
[]

FAULT LOCATOR
[]

DEMAND
[]

ANALOG INPUT
[]

ANALOG OUTPUTS
[]

OVERFREQUENCY
[]

EQUIPMENT
[]

PULSED OUTPUT
[]

END OF PAGE S6

SETPOINT
GROUPS
[]

SYNCHROCHECK
[]

MANUAL CLOSE
[]

COLD LOAD
PICKUP
[]

UNDERVOLTAGE
RESTORATION
[]

UNDERFREQUENCY
RESTORATION
[]

TRANSFER
[]

AUTORECLOSE
[]
MESSAGE

SETPOINTS
S6 MONITORING
MESSAGE
MESSAGE
MESSAGE
MESSAGE
MESSAGE
MESSAGE
MESSAGE
MESSAGE
MESSAGE
See page 5–94
See page 5–95
See page 5–97
See page 5–99
See page 5–106
See page 5–110
See page 5–113
See page 5–114
See page 5–121
MESSAGE

SETPOINTS
S7 CONTROL
MESSAGE
MESSAGE
MESSAGE
MESSAGE
MESSAGE
MESSAGE
MESSAGE
5-4
See page 5–123
See page 5–127
See page 5–129
See page 5–131
See page 5–133
See page 5–134
See page 5–136
See page 5–157
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
OVERVIEW
MESSAGE

END OF PAGE S7

OUTPUT RELAYS
[]

PICKUP TEST
[]

ANALOG OUTPUTS
[]

SIMULATION
[]

END OF PAGE S8
MESSAGE

SETPOINTS
S8 TESTING
MESSAGE
MESSAGE
MESSAGE
MESSAGE
5.1.2
See page 5–170
See page 5–171
See page 5–171
See page 5–172
Setpoint Entry Methods
Prior to placing the relay in operation, setpoints defining system characteristics, inputs,
relay outputs, and protection settings must be entered, via one of the following methods:
• Front panel, using the keys and display.
• Front program port, and a portable computer running the EnerVista 750/760
Setup software supplied with the relay.
• Rear RS485/RS422 COM1 port or RS485 COM2 port and a SCADA system running
user-written software.
Any of these methods can be used to enter the same information. A computer, however,
makes entry much easier. Files can be stored and downloaded for fast, error free entry
when a computer is used. To facilitate this process, the GE EnerVista CD with the EnerVista
750/760 Setup software is supplied with the relay.
The relay leaves the factory with setpoints programmed to default values, and it is these
values that are shown in all the setpoint message illustrations. Many of these factory
default values can be left unchanged.
At a minimum, the S2 SYSTEM SETUP setpoints must be entered for the system to
function correctly. To safeguard against the installation of a relay whose setpoints have
not been entered, the relay Relay Not Ready self-test warning is displayed. In addition,
the Self-Test Warning relay will be de-energized. Once the relay has been programmed for
the intended application, the S1 RELAY SETUP  INSTALLATION  760 OPERATION setpoint
should be changed from “Not Ready” (the default) to “Ready”.
Some messages associated with disabled features are hidden. These context sensitive
messages are illustrated with a dotted border on the message box. Before putting the relay
in the Ready state, each page of setpoint messages should be worked through, entering
values either by keypad or computer.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
5-5
OVERVIEW
5.1.3
CHAPTER 5: SETPOINTS
Setpoint Access Security
Hardware and passcode security features are designed into the relay to provide protection
against unauthorized setpoint changes.
To program new setpoints using the front panel keys, a hardware jumper must be installed
across the setpoint access terminals on the back of the relay. These terminals can be
permanently wired to a panel mounted key switch if desired. Attempts to enter a new
setpoint without the electrical connection across the setpoint access terminals will result in
an error message. The jumper does not restrict setpoint access via serial communications.
The relay has a programmable passcode setpoint which may be used to disallow setpoint
changes from both the front panel and the serial communications ports. This passcode
consists of up to eight (8) alphanumeric characters.
The factory default passcode is “0”. When this specific value is programmed into the relay it
has the effect of removing all setpoint modification restrictions. Therefore, only the
setpoint access jumper can be used to restrict setpoint access via the front panel and
there are no restrictions via the communications ports.
When the passcode is programmed to any other value, setpoint access is restricted for the
front panel and all communications ports. Access is not permitted until the passcode is
entered via the keypad or is programmed into a specific register (via communications).
Note that enabling setpoint access on one interface does not automatically enable access
for any of the other interfaces (i.e., the passcode must be explicitly set in the relay via the
interface from which access is desired).
A front panel command can disable setpoint access once all modifications are complete.
For the communications ports, access is disabled by writing an invalid passcode into the
register previously used to enable setpoint access. In addition, setpoint access is
automatically disabled on an interface if no activity is detected for thirty minutes.
The EnerVista 750/760 Setup software incorporates a facility for programming the relay’s
passcode as well as enabling/disabling setpoint access. For example, when an attempt is
made to modify a setpoint but access is restricted, the program will prompt the user to
enter the passcode and send it to the relay before the setpoint is actually written to the
relay. If a SCADA system is used for relay programming, it is up to the programmer to
incorporate appropriate security for the application.
5.1.4
Common Setpoints
To make the application of this device as simple as possible, similar methods of operation
and therefore similar types of setpoints are incorporated in various features. Rather than
repeat operation descriptions for this class of setpoint throughout the manual, a general
description is presented in this overview. Details that are specific to a particular feature will
be included in the discussion of the feature. The form and nature of these setpoints is
described below.
•
FUNCTION setpoint: The <ELEMENT_NAME> FUNCTION setpoint determines the
operational characteristics of each feature. The range for these setpoints is two or
more of: “Disabled”, “Enabled”, “Trip”, “Trip & AR”, “Alarm”, “Latched Alarm”, and
“Control”.
If <ELEMENT_NAME> FUNCTION: “Disabled”, then the feature is not operational. If
<ELEMENT_NAME> FUNCTION: “Enabled”, then the feature is operational.
5-6
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
OVERVIEW
If <ELEMENT_NAME> FUNCTION: “Trip”, then the feature is operational. When an output
is generated the feature declares a Trip condition, which operates the 1 Trip relay and
any other selected output relays, and displays the appropriate trip message. If
<ELEMENT_NAME> FUNCTION: “Trip & AR” (overcurrent features of 760 only), then the
feature is operational. When an output is generated, the feature declares a Trip
condition which operates the 1 Trip relay and any other selected output relays, signals
an Initiate to the autoreclose feature, and displays the appropriate trip message.
If <ELEMENT_NAME> FUNCTION: “Alarm” or “Latched Alarm”, then the feature is
operational. When an output is generated, the feature declares an “Alarm” condition
which operates any selected output relays and displays the appropriate alarm
message.
If <ELEMENT_NAME> FUNCTION: “Control” the feature is operational. When an output is
generated, the feature operates any selected output relays.
The “Trip”, “Trip & AR”, “Alarm”, and “Control” function setpoint values are also used to
select those operations that will be stored in the Event Recorder.
•
RELAYS (3–7) setpoint: The <ELEMENT_NAME> RELAYS (3-7) setpoint selects the relays
required to operate when the feature generates an output. The range is any
combination of the 3 to 7 Auxiliary relays.
•
PICKUP setpoint: The <ELEMENT_NAME> PICKUP setpoint selects the threshold above
(for over elements) or below (for under elements) which the measured parameter
causes an output from the measuring element.
•
DELAY setpoint: The <ELEMENT_NAME> DELAY setpoint selects a fixed time interval to
delay an input signal from appearing at the output.
From a contact input change of state to a contact closure of the 1 Trip relay, the total
delay is the time selected in this setpoint plus approximately 2 power frequency
periods. From an AC parameter input level change measured by an instantaneous
feature to a contact closure of the 1 Trip relay, the total delay is the time selected in
this setpoint plus approximately 2.5 power frequency periods. In both cases, auxiliary
output relays are approximately 5 ms slower.
•
DIRECTION setpoint: The <ELEMENT_NAME> DIRECTION setpoint is available for
overcurrent features which are subject to control from a directional element. The
range is “Disabled”, “Forward”, and “Reverse”.
If set to “Disabled”, the element is allowed to operate for current flow in any direction.
There is no supervision from the directional element. If set to “Forward”, the element is
allowed to operate for current flow in the forward direction only, as determined by the
directional element. If set to “Reverse”, the element is allowed to operate for current
flow in the reverse direction only, as determined by the directional element.
•
PHASES REQUIRED FOR ANY OPERATION setpoint: This setpoint is available for those
features which measure each phase parameter individually.
If set to “Any One”, then an output is generated if any one or more phase parameters
are beyond the pickup value. If set to “Any Two”, then an output is generated if any
combination of two or more phase parameters are beyond the pickup value. If set to
“All Three”, then an output is generated if all three phase parameters are beyond the
pickup value.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
5-7
OVERVIEW
5.1.5
CHAPTER 5: SETPOINTS
Logic Diagrams
The logic diagrams provided should be referred to for a complete comprehensive
understanding of the operation of each feature. These sequential logic diagrams illustrate
how each setpoint, input parameter, and internal logic is used in a feature to obtain an
output. In addition to these logic diagrams, written descriptions are provided in the
setpoints chapter which includes each feature.
5-8
•
Setpoints: Shown as a block with a heading labeled ‘SETPOINT’. The location of
setpoints is indicated by the path heading on the diagram. The exact wording of the
displayed setpoint message identifies the setpoint. Major functional setpoint
selections are listed below the name and are incorporated in the logic.
•
Measurement Units: Shown as a block with an inset box labeled ‘RUN’ with the
associated pickup/dropout setpoint shown directly above. Element operation of the
detector is controlled by the signal entering the ‘RUN’ inset. The measurement/
comparison can only be performed if a logic ‘1’ is provided at the ‘RUN’ input.
Relationship between setpoint and input parameter is indicated by the following
symbols: “<” (less than), “>” (greater than), etc. The ANSI device number (if one exists) is
indicated above the block.
•
Time Delays: Shown as a block with the following schematic symbol: |———|. If delay is
adjustable, associated delay setpoint is shown directly above, and schematic symbol
has an additional variability indication, an oblique bar. ANSI device number (62) is
indicated above the block.
•
LED Indicators: Shown as the following schematic symbol, ⊗. The exact wording of
the front panel label identifies the indicator.
•
Logic: Described with basic logic gates (AND, OR, XOR, NAND, NOR). The inverter
(logical NOT), is shown as a circle: .
•
Conditions: Shown as a rounded block with a shaded heading labeled ‘CONDITION’.
Conditions are mutually exclusive, i.e., only one condition can be active at any point in
time. Conditions latch until another condition becomes active. The output of an active
condition is 1 or logic high.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
5.2
S1 RELAY SETUP
S1 Relay Setup
5.2.1
Passcode
PATH: SETPOINTS  S1 RELAY SETUP  PASSCODE

SETPOINT ACCESS:
Allowed
Range: Allowed, Restricted
MESSAGE
RESTRICT ACCESS TO
SETPOINTS: No
Range: Yes, No.
MESSAGE
ALLOW ACCESS TO
SETPOINTS: No
Range: Yes, No.
MESSAGE
CHANGE PASSCODE?
No
Range: Yes, No.
MESSAGE
ENCRYPTED PASSCODE:
AIKFBAIK
Range: Cannot be edited.
PASSCODE
[]
If the passcode security feature is enabled, the setpoint access jumper must be installed
on the rear terminals and a passcode must also be entered to program setpoints. When
the relay is shipped from the factory the passcode is defaulted to “0”. When the passcode
is “0”, the passcode security feature is always disabled and only the setpoint access jumper
is required for changing setpoints from the front panel.
The RESTRICT ACCESS TO SETPOINTS setpoint is seen only if the passcode is not “0” and
SETPOINT ACCESS is “Allowed”
The ALLOW ACCESS TO SETPOINTS setpoint is only displayed when SETPOINT ACCESS is
“Restricted”. In this state, new setpoints cannot be entered. To regain setpoint access,
select “Yes” and follow directions to enter the previously programmed passcode. If the
passcode is correctly entered, entering new setpoints will be allowed. If no keys are
pressed for longer than 30 minutes, setpoint access automatically becomes restricted.
Removing the setpoint access jumper immediately restricts setpoint access. If passcode
protection is active but the passcode is not known, contact GE Multilin with the ENCRYPTED
PASSCODE value.
5.2.2
Communications
Main Menu
PATH: SETPOINTS  S1 RELAY SETUP  COMMUNICATIONS

COMMUNICATIONS
[]
MESSAGE
MESSAGE
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL

PORT SETUP
[]

DNP
CONFIGURATION
[]

NETWORK
CONFIGURATION
[]
See page 5–10
See page 5–11
See page 5–12
5-9
S1 RELAY SETUP
CHAPTER 5: SETPOINTS
The 750/760 relay has setpoints to enable communications through its RS232, RS485/422,
and Ethernet ports. Setpoints are also provided for configuring DNP communications
through one of these ports. The NETWORK CONFIGURATION menu is seen only if the
Ethernet option is ordered.
RS485 COM2 is disabled when the Ethernet option is ordered.
Port Setup
PATH: SETPOINTS  S1 RELAY SETUP  COMMUNICATIONS  PORT SETUP

PORT SETUP
Note
NOTE
SLAVE ADDRESS:
1
Range: 1 to 254 in steps of 1
MESSAGE
COM1 RS485/422
BAUD RATE: 9600
Range: 300, 1200, 2400,
4800, 9600, 19200
MESSAGE
COM1 RS485/422
PARITY: None
Range: None, Odd, Even
MESSAGE
COM1 RS485/422
HARDWARE: RS485
Range: RS485, RS422
MESSAGE
COM2 RS485
BAUD RATE: 9600
MESSAGE
COM2 RS485
PARITY: None
Range: 300, 1200, 2400,
4800, 9600, 19200.
Not shown for units
with Ethernet option.
Range: None, Odd, Even. Not
shown for units with
MESSAGE
FRONT RS232
BAUD RATE: 9600
Range: 300, 1200, 2400,
4800, 9600, 19200
MESSAGE
FRONT RS232
PARITY: None
Range: None, Odd, Even
[]
For additional details on the implementation of the Modbus protocol in the 750/760 relay,
and for complete memory map information, refer to GE Publication GEK-106473: 750/760
Communications Guide.
Up to 32 devices can be daisy-chained with one of them a computer or programmable
controller. Either COM1 (the two wire RS485 or the four wire RS422 serial communication
port) or COM2 (the two wire RS485 port) may be used. One relay can be connected directly
to a personal computer via the front panel RS232 port with a standard straight-through
RS232 cable.
5 - 10
•
SLAVE ADDRESS: This setpoint selects the serial communications slave address of the
relay. Both COM1 and COM2 use this same address. The front panel RS232 port
accepts any address for normal communications, but must be set to “1” when
upgrading the relay firmware. Each relay on the same RS485/422 communications
link must have a unique address.
•
COM1 RS485/422 and COM2 RS485 BAUD RATE: Selects the baud rate for the COM1/
2 communication ports. All relays on the communication link, and the computer
connecting them, must run at the same baud rate. The fastest response is obtained at
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S1 RELAY SETUP
19200 baud. Slower baud rates should be used if noise becomes a problem. The data
frame is fixed at 1 start, 8 data, and 1 stop bit.
•
COM1 and COM2 PARITY: Selects the parity for COM1 and COM2 communications
ports.
•
COM1 RS485/422 HARDWARE: Selects the COM1 hardware configuration to be either
two-wire RS485 or four-wire RS422 communications.
•
FRONT PANEL RS232 BAUD RATE and PARITY: These setpoints select the baud rate
and parity for front panel RS232 serial communications port. When upgrading the
relay firmware, the baud rate should be set to 9600.
DNP Configuration
PATH: SETPOINTS  S1 RELAY SETUP  COMMUNICATIONS  DNP CONFIGURATION

DNP
CONFIGURATION
DNP PORT:
None
Range: None, COM1, COM2,
Front
MESSAGE
DNP POINT MAPPING:
Disabled
Range: Disabled, Enabled
MESSAGE
TRANS DELAY:
0 ms
Range: 0 to 65000 ms in
steps of 1
MESSAGE
DATA LINK CONFIRM
MODE: Never
Range: Never, Sometimes,
Always
MESSAGE
DATA LINK CONFIRM
TIMEOUT: 1000 ms
Range: 0 to 65000 ms in
steps of 1
MESSAGE
DATA LINK CONFIRM
RETRIES: 3
Range: 0 to 100 in steps of 1
MESSAGE
SELECT/OPERATE ARM
TIMEOUT: 10000 ms
Range: 1 to 65000 ms in
steps of 1
MESSAGE
WRITE TIME INTERVAL:
0 min
Range: 0 to 65000 min. in
steps of 1
MESSAGE
COLD RESTART
INHIBIT: Disabled
Range: Disabled, Enabled
[]
The relay can be programmed to communicate using the DNP Protocol through one of its
ports. Refer to GE publication GEK-106473: 750/760 Communications Guide for additional
details. The following setpoints are used configure the DNP Protocol.
•
DNP PORT: Select which communications port will use the DNP protocol for
communication. The 750/760 defaults to the Modbus protocol on all ports.
•
DNP POINT MAPPING: Select whether the User Map will be available through DNP.
When enabled, the 120 User Map values are included in the DNP Object 30 point list.
Refer to GE publication GEK-106473 for details.
•
TRANS DELAY: Select the minimum time from when a DNP request is received and a
response issued. A value of zero causes the response to be issued as quickly as
possible.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
5 - 11
S1 RELAY SETUP
CHAPTER 5: SETPOINTS
•
DATA LINK CONFIRM MODE: Select the data link confirmation mode for responses
sent by the 750/760. When “Sometimes” is selected, data link confirmation is only
requested when the response contains more than one frame.
•
DATA LINK CONFIRM TIMEOUT: Select a desired timeout. If no confirmation response
is received within this time, the 750/760 re-sends the frame if retries are still available.
•
DATA LINK CONFIRM RETRIES: Select the number of retries that will be issued for a
given data link frame.
•
SELECT/OPERATE ARM TIMEOUT: Select the duration of the select / operate arm timer.
•
WRITE TIME INTERVAL: Select the time that must elapse before the 750/760 will set
the “need time” internal indication (IIN). After the time is written by a DNP master, the
IIN will be set again after this time elapses. A value of zero disables this feature.
•
COLD RESTART INHIBIT: When disabled, a cold restart request from a DNP master will
cause the 750/760 to be reset. Enabling this setpoint will cause the cold start request
to initialize only the DNP sub-module.
When COLD START INHIBIT is “Disabled”, a cold restart request causes loss of protection
until the 750/760 reset completes.
Network Configuration
PATH: SETPOINTS  S1 RELAY SETUP  COMMUNICATIONS  NETWORK CONFIGURATION

NETWORK
CONFIGURATION
IP ADDRESS:
000.000.000.000
Range: standard IP address
format
MESSAGE
SUBNET IP MASK:
255.255.255.000
Range: standard IP address
format
MESSAGE
GATEWAY IP ADDRESS:
000.000.000.000
Range: standard IP address
format
[]
These messages appear only if the 750/760 is ordered with the Ethernet option. The IP
addresses are used with the Modbus protocol. Enter the dedicated IP, subnet IP, and
gateway IP addresses provided by your network administrator.
TCP/IP Connection Management
750/760 supports a maximum of four TCP/IP connections. When four or fewer
connections are maintained, 750 will never initiate a close.
In case there are four connections and 750/760 receives a fifth connection request over
TCP/IP, then the relay will close the oldest unused connection. The new connection request
is accepted and Modbus communication proceeds.
To ensure optimal response from the relay, the typical connection timeout should be set as
indicated in the following table:
Note
NOTE
TCP/IP sessions
5 - 12
Timeout setting
up to 2
2 seconds
up to 4
3 seconds
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
5.2.3
S1 RELAY SETUP
Clock
PATH: SETPOINTS  S1 RELAY SETUP  CLOCK

CLOCK
DATE (MM/DD/YYYY):
10/23/2003
Range: 1 to 12 / 1 to 31 /
2000 to 2089
MESSAGE
TIME (HH:MM:SS):
16:30:00
Range: 0 to 23 : 0 to 59 : 0 to
59
MESSAGE
IRIG-B SIGNAL TYPE:
None
Range: None, DC Shift,
Amplitude
[]
The relay has an internal real time clock that performs time and date stamping for various
relay features such as event, maximum demand, and last trip data recording. Time
stamping on multiple relays can be synchronized to ±5 ms with the use of an IRIG-B input.
The clock has a supercap back-up so that the time and date are maintained on the loss of
relay control power. The time and date are preset at the factory, but should be changed to
correspond to the appropriate time zone.
Enter the current date and time here. The new date and time take effect the instant the
ENTER key is pressed.
The IRIG-B SIGNAL TYPE setpoint enabled the IRIG-B time synchronization and selects the
type of IRIG-B signal to use. The IRIG-B signal contains all necessary time and date
stamping data except for the year. The year must be entered with the date. If IRIG-B is
enabled and functioning properly, then setting the time and date (except for the year) as
described in the previous message will have no effect. If IRIG-B is enabled but the signal
cannot be decoded, the IRIG-B Failure self-test warning is generated. See IRIG-B on
page 3–21 for additional details on IRIG-B.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
5 - 13
S1 RELAY SETUP
5.2.4
CHAPTER 5: SETPOINTS
Event Recorder
PATH: SETPOINTS  S1 RELAY SETUP  EVENT RECORDER

EVENT RECORDER
EVENT RECORDER
FUNCTION: Enabled
Range: Enabled, Disabled
MESSAGE
RECORD PICKUP
EVENTS: Enabled
Range: Enabled, Disabled
MESSAGE
RECORD DROPOUT
EVENTS: Enabled
Range: Enabled, Disabled
MESSAGE
RECORD TRIP
EVENTS: Enabled
Range: Enabled, Disabled
MESSAGE
RECORD ALARM
EVENTS: Enabled
Range: Enabled, Disabled
MESSAGE
RECORD CONTROL
EVENTS: Enabled
Range: Enabled, Disabled
MESSAGE
RECORD LOGIC INPUT
EVENTS: Enabled
Range: Enabled, Disabled
MESSAGE
RECORD DATE/TIME
EVENTS: Enabled
Range: Enabled, Disabled
[]
The relay captures a wide variety of events and stores the last 512 in non-volatile memory.
See Event Records on page 6–20 for details. A single power system disturbance could
conceivably fill half of the event recorder due to the various events that can be captured.
Also, some events may happen on a regular basis as part of a control scheme (e.g. Power
Factor events in a capacitor bank switching scheme). For this reason, certain event types
can be ‘filtered’ from the event recorder to save room for other events. The following
setpoints describe the events that can be filtered.
The setpoint "Record Date/Time Events" should be set to "Enabled" to record date/time
synchronization only when such events occur no more than once per hour. A date/time
event recording rate greater than once per hour will cause flooding of the Event Record
and will, in turn, wear out the EEPROM. This will eventually generate the self-test warning
"Self-test warning: EEPROM corrupted," resulting in the EEPROM having to be replaced.
Ideally the date/time should be recorded no more than twice a day.
5 - 14
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
5.2.5
S1 RELAY SETUP
Trace Memory
PATH: SETPOINTS  S1 RELAY SETUP  TRACE MEMORY

TRACE MEMORY
BUFFER ORGANIZATION:
16 x 512
Range: 2 x 4096, 4 x 2048, 8
x 1024, 6 x 512
MESSAGE
TRIGGER POSITION:
25%
Range: 0 to 100% in steps of
1
MESSAGE
TRIGGER ON PICKUP:
Enabled
Range: Enabled, Disabled
MESSAGE
TRIGGER ON DROPOUT:
Disabled
Range: Enabled, Disabled
MESSAGE
TRIGGER ON TRIP:
Enabled
Range: Enabled, Disabled
MESSAGE
TRIGGER ON ALARM:
Enabled
Range: Enabled, Disabled
MESSAGE
TRIGGER ON CONTROL:
Enabled
Range: Enabled, Disabled
[]
The waveform capture feature is similar to a transient/fault recorder. It captures
oscillography/waveform data in response to a variety of system events. Data is captured
for the analog current and voltage inputs (Ia, Ib, Ic, Ig, Isg, Va, Vb, Vc, Vs) as well as digital
data for the output relays and input contact states. The trace memory data can be
downloaded to the EnerVista 750/760 Setup software for display and diagnostics
purposes. All data is stored in volatile RAM memory which means that the information is
lost when power to the relay is lost. The amount of data to capture and the trigger point
are configurable as described below.
•
BUFFER ORGANIZATION: Selects the partitioning of waveform capture data storage.
The first number indicates the number of events that can be stored in memory. The
second number indicates the number of data samples captured per channel for each
event. Note that the relay captures 16 samples per cycle. When more waveform
captures are triggered than the allowable number of events selected by this setpoint,
the oldest data is discarded to make room for the new capture.
For example, 4 × 2048 indicates that the last three events with 2048 data samples per
channel (128 cycles) can be stored in memory. Note that one buffer must be reserved
for capturing the next event.
•
TRIGGER POSITION: Selects the amount of data captured before the trigger point. For
example, if the TRIGGER POSITION is set to “25%” and the BUFFER ORGANIZATION is set
to “2 × 4096”, then there will be 1024 samples (64 cycles) captured before the trigger
point.
Changing any setpoint affecting trace memory operation clears any data that is currently
in the log.
Note
NOTE
The TRIGGER ON <EVENT_TYPE> setpoints select specific event types to trigger new
waveform captures.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
5 - 15
S1 RELAY SETUP
5.2.6
CHAPTER 5: SETPOINTS
Data Logger
PATH: SETPOINTS  S1 RELAY SETUP  DATA LOGGER

DATA LOGGER
SAMPLE RATE:
1 cycle
Range: 1 cycle; 1 second; 1,
5, 10, 15, 20, 30, 60
MESSAGE
CONTINUOUS MODE:
Disabled
Range: Enabled, Disabled
MESSAGE
BUFFER ORGANIZATION:
16 x 256
Range: 2 x 2048, 4 x 1024, 8
x 512, 16 x 256.
MESSAGE
TRIGGER POSITION:
25%
Range: 0 to 100% in steps of
1
MESSAGE
TRIGGER ON PICKUP:
Enabled
Range: Enabled, Disabled
MESSAGE
TRIGGER ON DROPOUT:
Enabled
Range: Enabled, Disabled
MESSAGE
TRIGGER ON TRIP:
Enabled
Range: Enabled, Disabled
MESSAGE
TRIGGER ON ALARM:
Enabled
Range: Enabled, Disabled
MESSAGE
TRIGGER ON CONTROL:
Enabled
Range: Enabled, Disabled
MESSAGE
CHNL 1 SOURCE:
Phase A Current
Range: Refer to the Analog
Output Parameters
MESSAGE
CHNL 2 SOURCE:
Phase B Current
Range: Refer to the Analog
Output Parameters
[]
↓
MESSAGE
CHNL 8 SOURCE:
Frequency
Range: Refer to the Analog
Output Parameters
The BUFFER ORGANIZATION, TRIGGER POSITION, and TRIGGER ON <EVENT_TYPE> setpoints
are seen only if CONTINUOUS MODE is “Disabled”.
Note
NOTE
The data logger samples and records up to eight (8) actual values at user-defined intervals.
This recorded data may be downloaded to the EnerVista 750/760 Setup software for
display and diagnostics. All data is stored in volatile RAM memory which means that the
information is lost when power to the relay is lost. Changing any setpoint affecting data
logger operation clears any data that is currently in the log.
The SAMPLE RATE setpoint selects the time interval to record the actual value data. This
setpoint multiplied by the number of samples to accumulate determines the duration of
the data log record. For example, if the sample rate is 15 minutes and continuous mode is
enabled then the duration of the data log record is equal to 15 min. × 4096 = 61440 min. =
42 days.
There are two basic modes of operation defined by the CONTINUOUS MODE setpoint:
5 - 16
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S1 RELAY SETUP
•
Continuous Mode: Enabled by setting CONTINUOUS MODE to “Enabled”. At each
sampling time the logger will record the actual value(s) programmed and store them
in the log. Up to 4096 data samples per channel will be recorded after which the
oldest data is replaced by newly sampled data.
•
Trigger Mode: Enabled by setting CONTINUOUS MODE to “Disabled”. The programmed
actual value(s) for up to the last 15 events are recorded, each in a separate buffer. The
amount of pre-trigger data to record is also selectable. Before the trigger occurs, pretrigger data is gathered as required. When the programmed trigger condition takes
place, data is collected until the buffer is filled, pre-trigger data collection begins in the
next buffer and the relay then waits for the next trigger. Once all buffers have been
filled, the oldest data is overwritten when a new trigger occurs.
The BUFFER ORGANIZATION and TRIGGER POSITION setpoints are only applicable in trigger
mode. The BUFFER ORGANZIATION selects the number triggers stored and the samples per
channel stored for each trigger. For example, “4 x 1024” indicates that the last three
triggers with 1024 data samples per channel can be stored in memory. Note that one
buffer must be reserved for capturing the next event. The TRIGGER POSITION setpoint
selects the amount of each buffer to be allocated for pre-trigger data. If set to “0%”, data
collection effectively starts once the trigger occurs. If set to 100%, only pre-trigger data will
be recorded in the buffer.
Note
NOTE
If a trigger occurs before the programmed amount of pre-trigger data is collected, the
remainder of the buffer will be filled with post-trigger data until it is full. Actual values in the
memory map provide information as to where the true trigger position is in each log buffer.
The TRIGGER ON <EVENT_TYPE> setpoints select specific event types to trigger new
waveform captures and are applicable only when the data logger is operating in trigger
mode. The CHNL 1 SOURCE to CHNL 8 SOURCE setpoints can be assigned any value
assignable as an Analog Output parameter. See Analog Output Parameters on page 5–111
for a list of values.
If all Channel Sources (1 through 8) are set to “Disabled”, then the data logger will not
collect data in continuous mode or respond to triggers in trigger mode.
Note
NOTE
5.2.7
Front Panel
PATH: SETPOINTS  S1 RELAY SETUP  FRONT PANEL

FRONT PANEL
FLASH MSG TIME:
4.0 s
Range: 0.5 to 10.0 s in steps
of 0.1
MESSAGE
DEFAULT MSG
TIME: 300 s
Range: 10 to 900 s in steps
of 1
MESSAGE
DISPLAY FILTER
CONSTANT:
0
Range: 0 to 255 in steps of 1
MESSAGE
3 KEY MAX/LAST DMND
CLEARING: Disabled
Range: Enabled, Disabled
[]
These setpoints modify front panel characteristics to suit different situations.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
5 - 17
S1 RELAY SETUP
CHAPTER 5: SETPOINTS
Note
NOTE
5.2.8
Firmware versions 3.70 and higher do not support a keypad beeper as did previous
firmware versions. The EnerVista 750/760 Setup software does not support keypad beeper
operation.
•
FLASH MSG TIME: Flash messages are status, warning, error, or information messages
displayed for several seconds in response to certain key presses during setpoint
programming. The time these messages remain on the display, overriding the normal
messages, can be changed to accommodate different user reading rates.
•
DEFAULT MSG TIME: If no keys are pressed for a period of time, the relay will
automatically begin to display a programmed set of default messages. This time can
be modified to ensure menu messages remain on the screen long enough during
programming or reading of actual values. Once default scanning starts, pressing any
key will restore the last message displayed on the screen.
•
DISPLAY FILTER CONSTANT: This value is used for filtering the displayed values of
current, voltage, and power. It determines how quickly the filter responds and how
much the filter will ‘smooth’ the display values. Smaller values result in quicker
response times, but with less smoothing. Larger values result in a slower response
time, but with more smoothing. A value of “0” completely disables the filter. A value of
“224” results in a reasonably smooth display value with a response time of about one
second. A value of “255” results in a very smooth display value, but with a response
time of about five seconds.
•
3 KEY MAX/LAST DMND CLEARING: For increased ease of maximum demand
clearing, this setpoint enables the «MENU, decimal, MESSAGE  » key sequence to
force the maximum demand values to clear. This key sequence operates on any
setpoint or actual values page. The keystrokes must be entered in the above order.
Any other variation of the key sequence will not permit the clearing of the maximum
demand values.
Default Messages
PATH: SETPOINTS  S1 RELAY SETUP  DEFAULT MESSAGES

DEFAULT
MESSAGES
3 MESSAGES SELECTED
27 MESSAGES REMAIN
Range: 0 to 30 messages
MESSAGE
GE MULTILIN
750 REV 5.10
Range: Displays the first
selected default
MESSAGE
A:
C:
MESSAGE
GND CURRENT:
0 A
0° Lag
[]
0 B:
0 Amps
0
Range: Displays the second
selected default
Range: Displays the third
selected default
Under normal conditions, if no front panel keys have been within the time specified by the
S1 RELAY SETUP  FRONT PANEL  DEFAULT MSG TIME setpoint, the screen begins to
sequentially display up to 30 default messages. Any actual value or setpoint message can
be selected for default display. In addition, up to 5 user programmable text messages can
be created for display as default messages. The relay, for example, could be set to
sequentially display a text message identifying the feeder, the system status, the measured
5 - 18
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S1 RELAY SETUP
current in each phase, and phase time overcurrent pickup value. The first message under
this subheading states the number of messages currently selected. The messages that
follow are copies of the default messages selected, in the sequence they will be displayed.
Default messages can be added to the end of the default message list, as follows:
1.
Allow access to setpoints by installing the setpoint access jumper and
entering the correct passcode.
2.
Select the setpoint or actual value message to display as a default messaged.
3.
Press the decimal key followed by the ENTER key while the message is
displayed. The screen will display PRESS [ENTER] TO ADD AS DEFAULT.
Press the ENTER key again while this message is being displayed. The
message is now added to the default message list.
Default messages can be removed from the default message list, as follows:
5.2.9
1.
Allow access to setpoints by installing the setpoint access jumper and
entering the correct passcode.
2.
Select the message to remove from the S1 RELAY SETUP  DEFAULT
MESSAGES default message list.
3.
Press the decimal key followed by the ENTER key. The screen will display
PRESS [ENTER] TO REMOVE MESSAGE. Press the ENTER key while this
message is being displayed. The message is now removed from the default
message list, and the messages that follow are moved up to fill the gap.
User Text Messages
PATH: SETPOINTS  S1 RELAY SETUP  USER TEXT MESSAGES

USER TEXT
MESSAGES
[]
TEXT 1
Range: 2 lines of 20 ASCII
characters
Up to 5 display messages can be programmed with user specific information. When these
user text messages are selected as default messages, they can provide system
identification information or operator instruction.
To add user text messages, first allow access to setpoints by installing the setpoint access
jumper and entering the correct passcode, then use the following procedure:
1.
Select the user text message from the S1 RELAY SETUP  USER TEXT
MESSAGES setpoints subgroup.
2.
Press the ENTER key. A solid cursor will appear over the first character
position.
3.
Use the VALUE keys to change the character. A space is selected like a
character.
4.
Press the ENTER key to store the character and advance the cursor. Press
ENTER to skip a character.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
5 - 19
S1 RELAY SETUP
CHAPTER 5: SETPOINTS
5.
Continue entering characters and spaces until the desired message is
displayed. If a character is entered incorrectly, repeatedly press the ENTER
key until the cursor returns to the position of the error and enter the correct
character. You may also press the ESCAPE and ENTER keys to restart the
editing process.
6.
Press either of the MESSAGE keys when editing is complete. To select this
message as a default message, follow the instructions in the section on
adding default messages.
5.2.10 Clear Data
PATH: SETPOINTS  S1 RELAY SETUP  CLEAR DATA

CLEAR DATA
CLEAR ENERGY USE
DATA? No
Range: Yes, No
MESSAGE
CLEAR MAX DEMAND
DATA? No
Range: Yes, No
MESSAGE
CLEAR EVENT RECORDER
DATA: No
Range: Yes, No
[]
These setpoints clear specific memory functions after the data has been read by an
operator. The CLEAR ENERGY USE DATA setpoint clears all accumulated power
consumption data and updates the A2 METERING  ENERGY  ENERGY USE DATA LAST
RESET date. The CLEAR MAX DEMAND DATA setpoint clears all maximum demand data
values and updates the A2 METERING  DEMAND  DMND DATA LAST RESET date.
The event recorder saves the most recent 512 events, automatically overwriting the oldest
event. The CLEAR EVENT RECORDER setpoint clears all recorded event data and updates A4
EVENT RECORDER  LAST RESET DATE  EVENT RECORDER LAST RESET.
5.2.11 Installation
PATH: SETPOINTS  S1 RELAY SETUP  INSTALLATION

5 - 20
INSTALLATION
760 OPERATION:
Not Ready
Range: Ready, Not Ready.
Reads as 750
MESSAGE
RESET TRIP COUNTER
DATA? No
Range: Yes, No
MESSAGE
RESET ARCING CURRENT
DATA? No
Range: Yes, No
MESSAGE
RESET AR COUNT
DATA? No
Range: Yes, No. Message is
only seen in 760
MESSAGE
RESET AR RATE
DATA? No
Range: Yes, No. Message is
only seen in 760
[]
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S1 RELAY SETUP
The Relay Not Ready self-test warning message will be displayed until S1 RELAY SETUP
 INSTALLATION  760 OPERATION is set to “Ready”. This warns against the installation of
a relay whose setpoints have not been entered for the required application. This setpoint is
defaulted to “Not Ready” when the relay leaves the factory.
These setpoints should be used on a new installation or after new equipment has been
installed.
The RESET TRIP COUNTER DATA setpoint clears all accumulated trip counter values and
updates the A3 MAINTENANCE  TRIP COUNTERS  TRIP COUNTERS LAST RESET actual
value. The RESET ARCING CURRENT setpoint clears all arcing current data and updates the
A3 MAINTENANCE  ARCING CURRENT  ARCING CURRENT LAST RESET date.
The RESET AR COUNT DATA setpoint clears the autoreclose shot count value and updates
the A1 STATUS  AR  AR SHOT COUNT LAST RESET date. The RESET AR RATE DATA
setpoint clears the autoreclose shot rate value and updates the ARCING CURRENT LAST
RESET date. These two setpoints are applicable to the 760 only.
5.2.12 Mod Version Upgrade
PATH: SETPOINTS  S1 RELAY SETUP  MOD VERSION UPGRADE

MOD VERSION
UPGRADE
ENABLE MOD VERSION:
000
Range: 000, 005, 008, 010
MESSAGE
ENTER PASSCODE:
00000000000000
Range: 16 alphanumeric
characters
MESSAGE
UPGRADE OPTIONS?
No
Range: Yes, No.
[]
If the Mod 008 (Reverse Power) option has been ordered with the 750/760 relay then the
setpoints in Reverse Power on page 8–1 are shown. To order this option, please contact GE
Multilin with the serial number of the relay. Refer to Reverse Power on page 8–1 for the
complete procedure for installing and verifying the Reverse Power element.
The Reverse Power setpoints are shown only if the Mod 008 feature has been enabled.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
5 - 21
S2 SYSTEM SETUP
5.3
CHAPTER 5: SETPOINTS
S2 System Setup
5.3.1
Current Sensing
PATH: SETPOINTS  S2 SYSTEM SETUP  CURRENT SENSING

CURRENT
SENSING
PHASE CT PRIMARY:
1000 A
Range: 1 to 50000 A in steps
of 1
MESSAGE
GND CT PRIMARY:
50 A
Range: 1 to 50000 A in steps
of 1
MESSAGE
SENSTV GND CT
PRIMARY: 1000 A
Range: 1 to 50000 A in steps
of 1
[]
This group of setpoints is critical for all overcurrent protection features that have settings
specified in multiples of CT rating. When the relay is ordered, the phase, ground, and
sensitive ground CT inputs must be specified as either 1 A or 5 A.
As the phase CTs are connected in wye (star), the calculated phasor sum of the three phase
currents (Ia + Ib + Ic = Neutral Current = 3I0) is used as the input for the neutral overcurrent.
In addition, a zero-sequence (core balance) CT which senses current in all of the circuit
primary conductors, or a CT in a neutral grounding conductor may also be used. For this
configuration, the ground CT primary rating must be entered. To detect low level ground
fault currents, the sensitive ground input may be used. In this case, the sensitive ground CT
primary rating must be entered. For additional details on CT connections, refer to Electrical
Installation on page 3–10 for details.
The setpoint entries are the same for Ground and Phase CTs with 1 A and 5 A secondaries.
For correct operation, the CT secondary must match the relay as indicated on the relay
identification label (e.g. 5 A for a xxx:5 CT).
5.3.2
Bus VT Sensing
PATH: SETPOINTS  S2 SYSTEM SETUP  BUS VT SENSING

BUS VT
SENSING
VT CONNECTION TYPE:
Wye
Range: None, Wye, Delta
MESSAGE
NOMINAL VT SECONDARY
VOLTAGE: 120.0 V
Range: 50.0 to 240.0 V in
steps of 0.1
MESSAGE
VT RATIO:
120.0:1
Range: 1.0 to 5000.0 in steps
of 0.1
[]
With bus VTs installed, the relay can be used to perform voltage measurements, power
calculations, and directional control of overcurrent elements.
•
5 - 22
VT CONNECTION TYPE: Enter “None” if Bus VTs are not used. If Bus VTs are used, enter
the VT connection made to the system as “Wye” or “Delta”. An open-delta connection
is entered as “Delta”. See FIGURE 3–8: Typical Wiring Diagram on page 3–10 for details
on Delta and Wye wiring.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
5.3.3
S2 SYSTEM SETUP
•
NOMINAL VT SECONDARY VOLTAGE: This setpoint represents the voltage across the
VT secondary winding when nominal voltage is applied to the primary. On a source of
13.8 kV line-line at nominal voltage, with a 14400:120 V VT in the Delta connection, the
voltage to be entered is “115 V”. For the Wye connection, the voltage to be entered is
115 / 3 = 66.4 V.
•
VT RATIO: Enter the VT primary to secondary turns ratio with this setpoint. For a
14400:120 VT, the entry would be “120:1” (since 14400 / 120 = 120.0).
Line VT Sensing
PATH: SETPOINTS  S2 SYSTEM SETUP  LINE VT SENSING

LINE VT
SENSING
VT CONNECTION TYPE:
Vbn
Range: Van, Vbn, Vcn, Vab,
Vcb
MESSAGE
NOMINAL VT SECONDARY
VOLTAGE: 120.0 V
Range: 50.0 to 240.0 V in
steps of 0.1
MESSAGE
VT RATIO:
120.0:1
Range: 1.0 to 5000.0 in steps
of 0.1
[]
With a Line VT installed, the relay can be used to check for a condition of synchronism
between two voltages, either line-line or line-neutral.
5.3.4
•
VT CONNECTION: Enter the Line VT connection made to the system. This selection is
critical to the operation of synchrocheck, as it instructs the relay which Bus VT input
voltage is to be compared to the Line VT input voltage. See FIGURE 3–13: Line VT
Connections on page 3–14 for the system connection to match this setpoint.
•
NOMINAL VT SECONDARY VOLTAGE: This setpoint represents the voltage across the
VT secondary winding when nominal voltage is applied to the primary. On a source of
13.8 kV line-line at nominal voltage, with a 14400:120 V VT in the Delta connection, the
voltage to be entered is 115 V. For the Wye connection, the voltage to be entered is
115 / 3 = 66.4 V.
•
VT RATIO: Enter the VT primary to secondary turns ratio with this setpoint. For a
14400:120 VT, the entry would be “120:1” (since 14400 / 120 = 120.0).
Power System
PATH: SETPOINTS  S2 SYSTEM SETUP  POWER SYSTEM

POWER SYSTEM
NOMINAL FREQ:
60 Hz
Range: 25 to 60 Hz in steps
of 1
MESSAGE
PHASE SEQUENCE:
ABC
Range: ABC, ACB
MESSAGE
COST OF ENERGY:
5.0 ¢/kWh
Range: 1.0 to 25.0 ¢/kWh in
steps of 0.1
[]
The power system data is entered in this setpoint subgroup.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
5 - 23
S2 SYSTEM SETUP
5.3.5
CHAPTER 5: SETPOINTS
•
NOMINAL FREQ: Enter the nominal power system frequency. This value is used as a
default to set the optimal digital sampling rate if the system frequency cannot be
measured as there is no voltage available at the bus voltage phase A input terminals.
•
PHASE SEQUENCE: Enter the phase sequence of the power system.
•
COST OF ENERGY: Kilowatt hour power usage is converted to a cost of energy using
this setpoint. The cost of energy charged by a utility is usually a variable rate
depending on total energy consumed or other factors. Enter an estimated average
cost in cents per kWh. Approximate energy cost will be determined by the relay,
providing a value useful for budgeting purposes.
FlexCurves™
PATH: SETPOINTS  S2 SYSTEM SETUP  FLEXCURVE A(B)

FLEXCURVE A
[]
MESSAGE
CURVE TRIP TIME AT
1.03 x PU:
0 ms
Range: 0 to 65535 ms in
steps of 1
CURVE TRIP TIME AT
1.05 x PU:
0 ms
Range: 0 to 65535 ms in
steps of 1
↓
Range: 0 to 65535 ms in
steps of 1
CURVE TRIP TIME AT
20.0 x PU:
0 ms
MESSAGE
Two programmable FlexCurves™ can be stored in the relay. These can be used for time
overcurrent protection in the same way as ANSI, IAC, and IEC curves. The FlexCurve™ has
setpoints for entering trip times at the following current levels: 1.03, 1.05, 1.1 to 6.0 in steps
of 0.1, and 6.5 to 20.0 in steps of 0.5. The relay converts these points to a continuous curve
by linear interpolation.
The following table shows all the pickup levels for which a trip time must be entered.
Table 5–1: FlexCurve™ Trip Times
Pickup
(I/Ipu)
5 - 24
Trip
Time
(ms)
Pickup
(I/Ipu)
Trip
Time
(ms)
Pickup
(I/Ipu)
Trip
Time
(ms)
Pickup
(I/Ipu)
1.03
2.90
4.90
10.5
1.05
3.00
5.00
11.0
1.10
3.10
5.10
11.5
1.20
3.20
5.20
12.0
1.30
3.30
5.30
12.5
1.40
3.40
5.40
13.0
1.50
3.50
5.50
13.5
1.60
3.60
5.60
14.0
1.70
3.70
5.70
14.5
Trip
Time
(ms)
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S2 SYSTEM SETUP
Table 5–1: FlexCurve™ Trip Times
Pickup
(I/Ipu)
Trip
Time
(ms)
Pickup
(I/Ipu)
Trip
Time
(ms)
Pickup
(I/Ipu)
Trip
Time
(ms)
Pickup
(I/Ipu)
1.80
3.80
5.80
15.0
1.90
3.90
5.90
15.5
2.00
4.00
6.00
16.0
2.10
4.10
6.50
16.5
2.20
4.20
7.00
17.0
2.30
4.30
7.50
17.5
2.40
4.40
8.00
18.0
2.50
4.50
8.50
18.5
2.60
4.60
9.00
19.0
2.70
4.70
9.50
19.5
2.80
4.80
10.0
20.0
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
Trip
Time
(ms)
5 - 25
S3 LOGIC INPUTS
5.4
CHAPTER 5: SETPOINTS
S3 Logic Inputs
5.4.1
Overview
The 750/760 relay has twenty (20) logic inputs which can be used to operate a variety of
logic functions for circuit breaker control, external trips, blocking of protection elements,
etc. The relay has ‘contact inputs’ and ‘virtual inputs’ that are combined in a form of
programmable logic to facilitate the implementation of various schemes.
The relay has 14 rear terminal contact inputs. These contacts can be either wet or dry (see
Logic Inputs on page 3–17 for typical wiring of the logic input contacts). External contacts
are either open or closed and are de-bounced for one power frequency cycle to prevent
false operation from induced voltage. Because of debouncing, momentary contacts must
have a minimum dwell time greater than one power frequency cycle.
The relay also has twenty (20) virtual inputs which are analogous to software switches.
They allow all the functionality of logic inputs to be invoked via serial communications or
from the front panel. This has the following advantages over contact inputs only:
• The number of logic inputs can be increased without introducing additional
hardware.
• Logic functions can be invoked from a remote location over a single RS485
communications channel.
• The same logic function can be invoked both locally via contact input or front
panel keypad, and/or remotely via communications.
• Panel switches can be replaced entirely by virtual switches to save cost and wiring.
Virtual inputs are simply memory locations in the relay which can be assigned a value via
communications or from the A1 STATUS  VIRTUAL INPUTS actual values menu. If the
value stored in memory is “0”, then the virtual input is Off; otherwise, the virtual input is On.
The state of virtual inputs is written as if it were a setpoint; these values are non-volatile
and are found in memory map locations 0090 to 00A4 hex. Momentary virtual inputs are
simulated by first writing a “1” to the corresponding register followed by writing a “0”. Due
to communications delay there will be a dwell time of 50 to 200 ms. Maintained virtual
inputs are simulated by writing a “1” to the corresponding register.
5 - 26
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
5.4.2
S3 LOGIC INPUTS
Logic Inputs Setup
PATH: SETPOINTS  S3 LOGIC INPUTS  LOGIC INPUTS SETUP

LOGIC INPUTS
SETUP
INPUT 1 NAME:
Logic Input 1
Range: 18 alphanumeric
characters
MESSAGE
INPUT 1 ASSERTED
LOGIC: Contact Close
Range: see description
below
MESSAGE
INPUT 2 NAME:
Logic Input 2
Range: 18 alphanumeric
characters
MESSAGE
INPUT 2 ASSERTED
LOGIC: Contact Close
Range: see description
below
[]
↓
MESSAGE
INPUT 20 NAME:
Logic Input 20
Range: 18 alphanumeric
characters
MESSAGE
INPUT 20 ASSERTED
LOGIC: Contact Close
Range: see description
below
Each logic input has two setpoints representing the name and asserted logic. The following
terms apply to all logic inputs:
• The state of a contact input is either “Open” or “Closed” and is determined directly
from the rear terminal inputs.
• The state of a virtual input is either “On” or “Off” and can be set from serial
communications or the A1 STATUS  VIRTUAL INPUTS actual values menu.
• The state of a logic input is either “Asserted” or “Not-Asserted”.
• The state of Logic Input n (where n = 1 to 14) is determined by combining the state
of Contact Input n with the state of Virtual Input n according to the INPUT N
ASSERTED LOGIC setpoint; this is a limited form of programmable logic.
• The state of Logic Input x (where x = 15 to 20) is determined by the state of Virtual
Input x according to the INPUT Y ASSERTED LOGIC setpoint; this is a limited form of
programmable logic.
• A logic function is invoked when its corresponding logic input is Asserted.
• One logic input can invoke many logic functions if required.
The LOGIC INPUT N NAME setpoint allows the operator to assign a user-friendly description
to logic inputs when replacing panel switches with a virtual switch. This name will be
displayed in the A1 STATUS  VIRTUAL INPUTS actual values menu.
The LOGIC INPUT N ASSERTED setpoint determines how to combine the Contact and Virtual
Input states to determine the Logic Input state. For Logic inputs 1 through 14, this setpoint
may be assigned the following values:
Value
Logic Input Asserted When:
Disabled
Never
Contact Close
Contact is closed
Contact Open
Contact is open
Virtual On
Virtual input is on
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
5 - 27
S3 LOGIC INPUTS
CHAPTER 5: SETPOINTS
Value
Logic Input Asserted When:
Virtual Off
Virtual input is off
Closed & Von
Contact is closed AND virtual input is on
Closed & Voff
Contact is closed AND virtual input is off
Open & Von
Contact is open AND virtual input is on
Open & Voff
Contact is open AND virtual input is off
Closed | Von
Contact is closed OR virtual input is on
Closed | Voff
Contact is closed OR virtual input is off
Open | Von
Contact is open OR virtual input is on
Open | Voff
Contact is open OR virtual input is off
Closed X Von
Contact is closed XOR virtual input is on
Closed X Voff
Contact is closed XOR virtual input is off
Open X Von
Contact is open XOR virtual input is on
Open X Voff
Contact is open XOR virtual input is off
For Logic Inputs 15 through 20, this setpoint may be assigned the following values:
Value
5.4.3
Logic Input Asserted When:
Disabled
Never
Virtual On
Virtual input is on
Virtual Off
Virtual input is off
Breaker Functions
PATH: SETPOINTS  S3 LOGIC INPUTS  BREAKER FUNCTIONS

BREAKER
FUNCTIONS
52a CONTACT:
Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
52b CONTACT:
Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
BRKR CONNECTED:
Disabled
Range: Input 1 to Input 20,
Disabled
[]
The following logic functions are used to determine whether the circuit breaker is open,
closed, or disconnected from the main power circuit, as monitored by auxiliary contacts on
a drawout breaker racking mechanism, or on the associated isolating disconnect switches
on a fixed circuit breaker.
If neither the 52a or 52b contacts are installed then the following functions cannot be
performed:
5 - 28
•
Monitoring of breaker position
•
Breaker Operation Failure
•
Feedback control of Trip (Output Relay 1) and Close (Output Relay 2) relays
•
Trip/Close Coil Supervision Without Permissive
•
Manual close feature blocking
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S3 LOGIC INPUTS
•
Autoreclose
•
Transfer
It is strongly recommended that the Breaker Operation Failure alarm be enabled when
either 52a or 52b breaker auxiliary contacts are installed.
Breaker logic functions must be assigned to Logic Inputs 1 to 14 as they must only be
contacts.
The 52A CONTACT and 52B CONTACT setpoints are used to monitor the 52/a and 52/b
contacts. The following table determines how these contacts affect the breaker state:
52/a CONTACT
INSTALLED?
52/b CONTACT
INSTALLED?
INTERPRETATION
Yes
Yes
52a closed indicates breaker is closed
52b closed indicates breaker is open
Yes
No
52a closed indicates breaker is closed
52a open indicates breaker is open
No
Yes
52b open indicates breaker is closed
52b closed indicates breaker is open
No
No
Breaker status unknown
When asserted, the logic input assigned by the BRKR CONNECTED setpoint indicates that
the breaker is connected to the primary system. When the breaker is determined to be
disconnected, the breaker state is shown to be neither open nor closed. For further
information regarding operation with only one auxiliary breaker contact, see System
Status LED Indicators on page 4–3.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
5 - 29
S3 LOGIC INPUTS
5.4.4
CHAPTER 5: SETPOINTS
Control Functions
PATH: SETPOINTS  S3 LOGIC INPUTS  CONTROL FUNCTIONS

CONTROL
FUNCTIONS
LOCAL MODE:
Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
RESET:
Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
REMOTE OPEN:
Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
REMOTE CLOSE:
Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
COLD LOAD PICKUP:
Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
SETPOINT GROUP 2:
Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
SETPOINT GROUP 3:
Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
SETPOINT GROUP 4:
Disabled
Range: Input 1 to Input 20,
Disabled
[]
The LOCAL MODE setpoint places the relay in local mode. The relay is in remote mode if not
forced into local mode by this setpoint. The RESET setpoint resets the last trip indicator and
latched relays. With the 760, it also resets the autoreclose lockout. The COLD LOAD PICKUP
setpoint initiates the Cold Load Pickup blocking feature. The SETPOINT GROUP 2 through
SETPOINT GROUP 4 setpoints signal the relay to make Group 2, 3, or 4 the active setpoint
group.
The REMOTE OPEN and REMOTE CLOSE setpoints initiate a breaker opening via the Trip
Relay and a breaker closure via the Close Relay, respectively. These setpoints are
operational only when the relay is in remote mode (i.e., when LOCAL MODE is set to
“Disabled”).
5 - 30
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
5.4.5
S3 LOGIC INPUTS
User Inputs
PATH: SETPOINTS  S3 LOGIC INPUTS  USER INPUTS  USER INPUT A(T)
USER INPUT A NAME:
User Input A
Range: 18 alphanumeric
characters
MESSAGE
USER INPUT A SOURCE:
Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
USER INPUT A
FUNCTION: Disabled
Range: Disabled, Trip, Trip &
AR, Alarm, Latched
MESSAGE
USER INPUT A
RELAYS (3-7): -----
Range: Any combination of 3
to 7 Auxiliary relays
MESSAGE
USER INPUT A
DELAY:
0.00 s
Range: 0.00 to 600.00 s in
steps of 0.01
USER INPUT A
Press [] for more
There are twenty (20) general purpose user input functions (User Inputs A through T) that
generate outputs in response to an asserted logic input. These functions can be used to:
initiate a trip; initiate a trip and a reclosure (760 only); log a contact operation in the event
recorder; convert an external contact into a self-resetting, latched or pulsed contact.;
convert an external contact into a Form-C contact; and provide a contact multiplier for an
external contact by operating multiple relays.
The setpoints for User Input A are shown above; setpoints for User Inputs B through T are
identical.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
5 - 31
S3 LOGIC INPUTS
5.4.6
CHAPTER 5: SETPOINTS
Block Functions
PATH: SETPOINTS  S3 LOGIC INPUTS  BLOCK FUNCTIONS

BLOCK
FUNCTIONS
BLOCK 1 TRIP RELAY:
Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
BLOCK 2 CLOSE RELAY:
Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
BLOCK RESET:
Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
BLOCK UNDERVOLT 1:
Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
BLOCK UNDERVOLT 2:
Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
BLOCK UNDERVOLT 3:
Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
BLOCK UNDERVOLT 4:
Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
BLOCK UNDERFREQ 1:
Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
BLOCK UNDERFREQ 2:
Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
BLOCK FREQ
DECAY: Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
BYPASS SYNCHROCHECK:
Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
BLOCK BREAKER
STATISTICS: Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
BLOCK NEG SEQ
VOLTAGE: Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
BLCK NTR DISPLACEMNT:
Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
BLOCK RESTORATION:
Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
BLOCK REV POWER:
Disabled
Range: Input 1 to Input 20,
Disabled
[]
The logic input functions shown above block various operations within the relay. Protection
elements will not detect faults, send messages, or illuminate indicators when blocked,
except for the BLOCK TRIP 1 RELAY setpoint.
A system condition monitor such as Synchrocheck or Closing Spring Charged can be
connected to the relay for close supervision. If BLOCK CLOSE 2 RELAY is selected, this input
must be de-asserted to permit operation of the Close Relay.
5 - 32
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S3 LOGIC INPUTS
The BYPASS SYNCHROCHECK setpoint provides a manual override of the synchrocheck
monitor, so an operator can close the feeder breaker without the programmed
synchrocheck condition.
The BLOCK BRKR STATISTICS setpoint blocks the accumulation of breaker statistical data
found on the A3 MAINTENANCE  TRIP COUNTERS and A3 MAINTENANCE  ARCING
CURRENT actual values pages. This data includes breaker operation and trip counters
along with breaker arcing current. This input could be used during testing to prevent
maintenance operations from being accumulated.
The BLOCK REV POWER setpoint is only visible when Mod 008 is enabled.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
5 - 33
S3 LOGIC INPUTS
5.4.7
CHAPTER 5: SETPOINTS
Block Overcurrent
PATH: SETPOINTS  S3 LOGIC INPUTS  BLOCK OC FUNCTIONS

5 - 34
BLOCK OC
FUNCTIONS
BLOCK ALL OC:
Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
BLOCK PHASE OC:
Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
BLOCK NEUTRAL OC:
Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
BLOCK GND OC:
Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
BLOCK SENSTV GND OC:
Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
BLOCK PHASE TIME 1:
Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
BLOCK PHASE TIME 2:
Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
BLOCK PHASE INST 1:
Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
BLOCK PHASE INST 2:
Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
BLOCK NEUTRAL TIME 1:
Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
BLOCK NEUTRAL TIME 2:
Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
BLOCK NEUTRAL INST 1:
Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
BLOCK NEUTRAL INST 2:
Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
BLOCK GND TIME:
Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
BLOCK GND INST:
Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
BLK SENSTV GND TIME:
Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
BLK SENSTV GND INST:
Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
BLOCK NEG SEQ TIME:
Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
BLOCK NEG SEQ INST:
Disabled
Range: Input 1 to Input 20,
Disabled
[]
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S3 LOGIC INPUTS
These setpoints block overcurrent protection elements. Overcurrent elements will not
detect faults, send messages, or illuminate indicators when blocked. These functions can
be used to: block overcurrent operation from downstream relays for selective tripping
schemes from external directional current/power or other supervision; block overcurrent
operation during initial feeder loading when the inrush currents are not know; block
neutral operation during single-phase switching or fault burn-off attempts; and block
timed phase and neutral operation during deliberate emergency overload operating
situations.
5.4.8
Transfer Functions
PATH: SETPOINTS  S3 LOGIC INPUTS  TRANSFER FUNCTIONS

TRANSFER
FUNCTIONS
SELECT TO TRIP:
Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
UNDERVOLT ON OTHER
SOURCE: Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
INCOMER 1 BREAKER
CLOSED: Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
INCOMER 2 BREAKER
CLOSED: Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
TIE BREAKER
CONNECTED: Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
TIE BREAKER CLOSED:
Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
BLOCK TRANSFER:
Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
TRANSFORMER LOCKOUT:
Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
SOURCE TRIP:
Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
CLOSE FROM INCOMER1:
Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
CLOSE FROM INCOMER2:
Disabled
Range: Input 1 to Input 20,
Disabled
[]
The following logic input functions are used exclusively for the bus transfer scheme. Refer
to Transfer Scheme on page 5–136 for details on implementing the bus transfer scheme.
Note
NOTE
If the bus transfer feature is required, all logic input functions necessary for the operation
of this scheme must be assigned to contact inputs before any other functions. This is to
ensure there are no conflicts.
The INCOMER 1(2) BREAKER CLOSED setpoints are used to track breaker state, for preventparallel or permission-to-transfer logic. THE CLOSE FROM INCOMER 1(2) setpoints signal the
bus tie breaker to begin a close operation.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
5 - 35
S3 LOGIC INPUTS
CHAPTER 5: SETPOINTS
The TIE BREAKER CONNECTED setpoint is used to inhibit transfers if the breaker cannot be
used to pass current from the source to the load, such as when it is in the Test or
Disconnected positions. The TIE BREAKER CLOSED setpoint is used to track breaker state,
for prevent-parallel or permission-to-transfer logic.
The TRANSFORMER LOCKOUT and SOURCE TRIP setpoints are used to initiate a transfer as
Source 1(2) is about to be lost. The BLOCK TRANSFER setpoint disables the transfer scheme.
5.4.9
Reclose (760 Only)
PATH: SETPOINTS  S3 LOGIC INPUTS  RECLOSE FUNCTIONS

RECLOSE
FUNCTIONS
INITIATE RECLOSURE:
Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
CANCEL RECLOSURE:
Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
BLOCK RECLOSURE:
Disabled
Range: Input 1 to Input 20,
Disabled
[]
These logic input setpoints are used in the autoreclose scheme and are applicable to the
760 relay only. Refer to Autoreclose (760 only) on page 5–157 for more detail.
•
INITIATE RECLOSURE: Initiates an autoreclose sequence leading to an operation of
the Close Relay. This input will not cause the Trip Output Relay of the 760 to operate. It
is intended for use where the initiating device sends an independent trip to the
breaker at the same time it sends an initiate reclosure to the 760.
•
CANCEL RECLOSURE: Cancels a reclosure sequence in progress and blocks
autoreclose scheme from operating.
•
BLOCK RECLOSURE: Cancels a reclosure sequence in progress and blocks the
autoreclose scheme from operating.
5.4.10 Miscellaneous
PATH: SETPOINTS  S3 LOGIC INPUTS  MISC FUNCTIONS

5 - 36
MISC FUNCTIONS
TRIGGER TRACE
MEMORY: Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
TRIGGER DATA LOGGER:
Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
SIMULATE FAULT:
Disabled
Range: Input 1 to Input 20,
Disabled
MESSAGE
START DMND
INTERVAL: Disabled
Range: Input 1 to Input 20,
Disabled
[]
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S3 LOGIC INPUTS
The SIMULATE FAULT input function is operational only when the relay is in simulation
testing mode, the breaker is closed (real or simulated breaker) and presently in the prefault
state. When the assigned input is asserted, the relay is forced into the fault state where the
programmed ‘fault’ values are used.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
5 - 37
S4 OUTPUT RELAYS
5.5
CHAPTER 5: SETPOINTS
S4 Output Relays
5.5.1
Relay Operation
Description
The 750/760 relay is equipped with eight electromechanical output relays: three special
purpose (Trip Relay 1, Close Relay 2, and Self-test Warning Relay 8) and five general
purpose (Auxiliary Relays 3 to 7). The special purpose relays have fixed operating
characteristics and the general purpose relays can be configured by the user. Logic
diagrams for each output relay are provided for detailed explanation of their operation.
Trip and Close Relays
Operation of these breaker-control relays is designed to be controlled by the state of the
circuit breaker as monitored by a 52a or 52b contact. Once a feature has energized one of
these relays it will remain operated until the requested change of breaker state is
confirmed by a breaker auxiliary contact and the initiating condition has reset. If the
initiating feature resets but the breaker does not change state, the output relay will be
reset after either the delay programmed in the Breaker Operation feature or a default
interval of 2 seconds expires. If neither of the breaker auxiliary contacts 52a nor 52b is
programmed to a logic input, the Trip Relay is de-energized after either the delay
programmed in the Breaker Failure feature or a default interval of 100 ms after the
initiating input resets and the Close Relay is de-energized after 200 ms. If a delay is
programmed for the Trip or Close contact seal in time, then this delay is added to the reset
time. Note that the default setting for the seal in time is 40 ms.
Table 5–2: Breaker Auxiliary Contacts and Relay Operation
5 - 38
52a
CONTACT
INSTALLED?
52b
CONTACT
INSTALLED?
RELAY OPERATION
Yes
Yes
Trip Relay remains operating until 52b indicates an
open breaker. Close Relay remains operating until
52a indicates a closed breaker.
Yes
No
Trip Relay remains operating until 52a indicates an
open breaker. Close Relay remains operating until
52a indicates a closed breaker.
No
Yes
Trip Relay remains operating until 52b indicates an
open breaker. Close Relay remains operating until
52b indicates a closed breaker.
No
No
Trip Relay operates until either the Breaker Failure
delay expires (if the Breaker Failure element is
enabled) or 100 ms after the feature causing the
trip resets. Close Relay operates for 200 ms.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S4 OUTPUT RELAYS
Auxiliary Relays 3 to 7
Operation of these relays is programmed by the user. Each relay can be selected to
become either energized or de-energized when operated, and to operate as latched, selfresetting or pulsed.
Table 5–3: Auxiliary Relay Operation
OUTPUT TYPE
5.5.2
DESCRIPTION
Latched
Upon being operated by any programmed feature, the relay output
contacts change state and remain in the new state. The relay can
be returned to the non-operated state only by the RESET key, the
reset logic input, or a computer reset command. This mode is used
for alarms which must be acknowledged, or to provide a lockout
function.
Self-resetting
Upon being operated by any programmed feature, the relay output
contacts change state and remain in the new state until all
features which operate the relay are no longer signaling it to
operate. For a relay operated by a single feature, the output
contacts follow the state of the feature.
Pulsed
Upon being operated by any programmed feature, the relay output
contacts change state and remain in the new state for a
programmed time interval called the PULSED OUTPUT DWELL TIME.
The dwell timer is started when the first feature causes operation
of the output relay.
Trip Relay
PATH: SETPOINTS  S4 OUTPUT RELAYS  1 TRIP RELAY

1 TRIP RELAY
[]
TRIP RELAY SEAL IN
TIME: 0.04 s
Range: 0.00 to 9.99 s in steps
of 0.01
A TRIP RELAY SEAL IN TIME can be programmed for the Trip Relay. This time is added to the
reset time of the Trip Relay, thus extending its pulse width. This is for use in applications
where the 52 contacts reporting breaker state to the 750/760 are faster than the 52
contacts that are responsible for interrupting coil current.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
5 - 39
S4 OUTPUT RELAYS
CHAPTER 5: SETPOINTS
FIGURE 5–1: Output Relay 1 Trip Logic
5.5.3
Close Relay
PATH: SETPOINTS  S4 OUTPUT RELAYS  2 CLOSE RELAY

2 CLOSE RELAY
[]
CLOSE RELAY SEAL IN
TIME: 0.04 s
Range: 0.00 to 9.99 s in steps
of 0.01
A CLOSE RELAY SEAL IN TIME can be programmed for the Close Relay. This time is added to
the reset time of the Close Relay, thus extending its pulse width. This is for use in
applications where the 52 contacts reporting breaker state to the 750/760 are faster than
the 52 contacts that are responsible for interrupting coil current.
5 - 40
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S4 OUTPUT RELAYS
FIGURE 5–2: Output Relay 2 Close Logic
5.5.4
Auxiliary Relays
PATH: SETPOINTS  S4 OUTPUT RELAYS  3(7) AUX RELAY

3 AUXILIARY
RELAY 3 NAME:
Auxiliary
Range: 16 alphanumeric
characters
MESSAGE
RELAY 3 NON-OPERATED
STATE: De-energized
Range: Energized, Deenergized
MESSAGE
RELAY 3 OUTPUT TYPE:
Self-Resetting
Range: Self-Resetting,
Latched, Pulsed
MESSAGE
PULSED OUTPUT DWELL
TIME:
0.1 s
Range: 0.1 to 6000.0 s in
steps of 0.1
[]
The Typical Wiring Diagram on page 3–10 shows relay contacts with no control power
applied. If the RELAY 3(7) NON-OPERATED STATE setpoint is “De-energized”, then the state of
the relay contacts is as shown in the wiring diagram. If the non-operated state is
“Energized”, then the state of the relay contacts is opposite to that shown in the wiring
diagram.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
5 - 41
S4 OUTPUT RELAYS
CHAPTER 5: SETPOINTS
This PULSED OUTPUT DWELL TIME setpoint is only displayed if the RELAY 3 OUTPUT TYPE is
selected as “Pulsed”. This setpoint determines the minimum time interval during which the
pulsed contacts remain in the operated state. The actual time interval may be for as long
as the controlling function is asserted, this interval being whichever of the above two time
intervals is longer.
FIGURE 5–3: Output Relays 3 to 7 Auxiliary Logic
5.5.5
Self-Test Warning Relay
There are no user-programmable setpoints associated with the Self-Test Warning Relay
(Output Relay 8). The logic for this relay is shown below:
5 - 42
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S4 OUTPUT RELAYS
FIGURE 5–4: Output Relay 8 Self-Test Warning Logic
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
5 - 43
S5 PROTECTION
5.6
CHAPTER 5: SETPOINTS
S5 Protection
5.6.1
Overview
Description
The relay has a total of six phase, two neutral, one ground, one sensitive ground, and one
negative sequence time overcurrent elements. The programming of the time-current
characteristics of these elements is identical in all cases and will only be covered in this
section. The required curve is established by programming a Pickup Current, Curve Shape,
Curve Multiplier, and Reset Time. The Curve Shape can be either a standard shape or a
user-defined shape programmed with the FlexCurve™ feature.
Accurate coordination may require changing the time overcurrent characteristics of
particular elements under different conditions. For manual closing or picking up a cold
load, a different time-current characteristic can be produced by increasing the pickup
current value. In the 760, the pickup current can also be raised between autoreclose shots.
The following setpoints are used to program the time-current characteristics.
•
<Element_Name> PICKUP: The pickup current is the threshold current at which the
time overcurrent element starts timing. There is no intentional ‘dead band’ when the
current is above the pickup level. However, accuracy is only guaranteed above a 1.03
per unit pickup level. The dropout threshold is 98% of the pickup threshold. Enter the
pickup current corresponding to 1 per unit on the time overcurrent curves as a
multiple of the source CT. For example, if 100: 5 CTs are used and a pickup of 90 amps
is required for the time overcurrent element, enter “0.9 x CT”.
•
<Element_Name> CURVE: Select the desired curve shape. If none of the standard
curve shapes is appropriate, a custom FlexCurve™ can be created by entering the trip
times at 80 different current values; see S2 SYSTEM SETUP  FLEXCURVE A . Curve
formulas are given for use with computer based coordination programs. Calculated
trip time values are only valid for I / Ipu > 1. Select the appropriate curve shape and
multiplier, thus matching the appropriate curve with the protection requirements. The
available curves are shown in the table below.
Table 5–4: TOC Curve Selections
•
5 - 44
ANSI
GE Type IAC
IEC
Other
Extremely Inverse
Extremely Inverse
Curve A (BS142)
Definite Time
Very Inverse
Very Inverse
Curve B (BS142)
FlexCurve™ A
Normally Inverse
Inverse
Curve C (BS142)
FlexCurve™ B
Moderately
Inverse
Short Inverse
IEC Short Inverse
<Element_Name> MULTIPLIER: A multiplier setpoint allows shifting of the selected
base curve in the vertical time direction. Unlike the electromechanical time dial
equivalent, trip times are directly proportional to the value of the time multiplier
setpoint. For example, all trip times for a multiplier of 10 are 10 times the multiplier 1
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S5 PROTECTION
or base curve values. Setting the multiplier to zero results in an instantaneous
response to all current levels above pickup.
•
<Element_Name> RESET: Time overcurrent tripping time calculations are made with
an internal ‘energy capacity’ memory variable. When this variable indicates that the
energy capacity has reached 100%, a time overcurrent trip is generated. If less than
100% is accumulated in this variable and the current falls below the dropout threshold
of 97 to 98% of the pickup value, the variable must be reduced. Two methods of this
resetting operation are available, Instantaneous and Linear. The Instantaneous
selection is intended for applications with other relays, such as most static units,
which set the energy capacity directly to zero when the current falls below the reset
threshold. The Linear selection can be used where the relay must coordinate with
electromechanical units. With this setpoint, the energy capacity variable is
decremented according to the following equation.
T RESET = E × M × C R
(EQ 5.1)
where:TRESET = reset time in seconds; E = energy capacity reached (per unit);
M = curve multiplier; CR = characteristic constant (5 for ANSI, IAC, Definite Time, and
FlexCurves™; 8 for IEC)
Note
NOTE
When the setpoint group changes, the setpoints for pickup, curve, multiplier and reset may
change. Accumulated ‘energy capacity’ continues to accumulate, using the new setpoint
group parameters. For example, assume the following conditions:
• Setpoint group 1 had curve "Definite time" set for 4 seconds.
• Setpoint group 2 had curve "Definite time" set for 8 seconds.
• Initially group 1 was active.
• Current rose above threshold at time T = 0 seconds.
• Setpoint group changed from group 1 to group 2 at time T = 1 seconds.
At this time the ‘energy capacity’ accumulator was at 25% = (1 second x
(100% / 4 seconds)).
• Current remained above the threshold.
• Using the new multiplier setpoint and continuing from 25% accumulated, the time
remaining after setpoint group change was 6 seconds = (100% - 25%) x 8 seconds.
• Timed element operated at time T = 7 seconds.
Graphs of standard time-current curves on 11” × 17” log-log graph paper are available
upon request. Requests may be placed with our literature department.
Note
NOTE
5.6.2
Time Overcurrent Curve Characteristics
Definite Time Curve:
Definite Time curves trip as soon as the pickup level is exceeded for a specified period of
time. The base Definite Time curve has a delay of 0.1 seconds. The curve multiplier adjusts
this delay from 0.00 to 10.00 seconds in steps of 0.01.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
5 - 45
S5 PROTECTION
CHAPTER 5: SETPOINTS
ANSI Curves:
The ANSI time overcurrent curve shapes conform to industry standards and the ANSI
C37.90 curve classifications for extremely, very, and moderately inverse. The ANSI curves
are derived from the following formula:
D
B
E


T = M ×  A + -------------------------- + ---------------------------------2- + ---------------------------------3-

( ( I ⁄ I pu ) – C ) 
( I ⁄ I pu ) – C ( ( I ⁄ I pu ) – C )
(EQ 5.2)
where:T = trip time (seconds); M = multiplier value; I = input current;
Ipickup = pickup current setpoint; A, B, C, D, E = constants
Table 5–5: ANSI Curve Constants
ANSI Curve Shape
A
B
C
D
E
ANSI Extremely Inverse
0.0399
0.2294
0.5000
3.0094
0.7222
ANSI Very Inverse
0.0615
0.7989
0.3400
–0.2840
4.0505
ANSI Normally Inverse
0.0274
2.2614
0.3000
–4.1899
9.1272
ANSI Moderately Inverse
0.1735
0.6791
0.8000
–0.0800
0.1271
Table 5–6: ANSI Curve Trip Times (in seconds)
Multiplier
(TDM)
3.0
Current ( I / Ipickup)
4.0
5.0
6.0
ANSI Extremely Inverse
1.5
2.0
0.5
1.0
2.0
4.0
6.0
8.0
10.0
2.000
4.001
8.002
16.004
24.005
32.007
40.009
0.872
1.744
3.489
6.977
10.466
13.955
17.443
0.330
0.659
1.319
2.638
3.956
5.275
6.594
0.184
0.368
0.736
1.472
2.208
2.944
3.680
0.5
1.0
2.0
4.0
6.0
8.0
10.0
1.567
3.134
6.268
12.537
18.805
25.073
31.341
0.663
1.325
2.650
5.301
7.951
10.602
13.252
0.268
0.537
1.074
2.148
3.221
4.295
5.369
0.171
0.341
0.682
1.365
2.047
2.730
3.412
0.124
0.247
0.495
0.990
1.484
1.979
2.474
0.093
0.185
0.371
0.742
1.113
1.483
1.854
7.0
8.0
9.0
10.0
0.075
0.149
0.298
0.596
0.894
1.192
1.491
0.063
0.126
0.251
0.503
0.754
1.006
1.257
0.055
0.110
0.219
0.439
0.658
0.878
1.097
0.049
0.098
0.196
0.393
0.589
0.786
0.982
0.094
0.189
0.378
0.755
1.133
1.510
1.888
0.085
0.170
0.340
0.680
1.020
1.360
1.700
0.078
0.156
0.312
0.625
0.937
1.250
1.562
0.073
0.146
0.291
0.583
0.874
1.165
1.457
0.151
0.302
0.604
1.208
1.812
0.135
0.270
0.541
1.082
1.622
0.123
0.246
0.492
0.983
1.475
0.113
0.226
0.452
0.904
1.356
ANSI Very Inverse
0.130
0.260
0.520
1.040
1.559
2.079
2.599
0.108
0.216
0.432
0.864
1.297
1.729
2.161
ANSI Normally Inverse
0.5
1.0
2.0
4.0
6.0
5 - 46
2.142
4.284
8.568
17.137
25.705
0.883
1.766
3.531
7.062
10.594
0.377
0.754
1.508
3.016
4.524
0.256
0.513
1.025
2.051
3.076
0.203
0.407
0.814
1.627
2.441
0.172
0.344
0.689
1.378
2.067
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S5 PROTECTION
Table 5–6: ANSI Curve Trip Times (in seconds)
Multiplier
(TDM)
1.5
2.0
3.0
4.0
8.0
10.0
34.274
42.842
14.125
17.656
6.031
7.539
4.102
5.127
0.5
1.0
2.0
4.0
6.0
8.0
10.0
0.675
1.351
2.702
5.404
8.106
10.807
13.509
0.379
0.757
1.515
3.030
4.544
6.059
7.574
0.239
0.478
0.955
1.910
2.866
3.821
4.776
0.191
0.382
0.764
1.527
2.291
3.054
3.818
Current ( I / Ipickup)
5.0
6.0
3.254
4.068
2.756
3.445
7.0
8.0
9.0
10.0
2.415
3.019
2.163
2.704
1.967
2.458
1.808
2.260
0.141
0.281
0.563
1.126
1.689
2.252
2.815
0.133
0.267
0.533
1.066
1.600
2.133
2.666
0.128
0.255
0.511
1.021
1.532
2.043
2.554
0.123
0.247
0.493
0.986
1.479
1.972
2.465
ANSI Moderately Inverse
0.166
0.332
0.665
1.329
1.994
2.659
3.324
0.151
0.302
0.604
1.208
1.812
2.416
3.020
IEC Curves:
For European applications, the relay offers the four standard curves defined in IEC 255-4
and British standard BS142. These are defined as IEC Curve A, IEC Curve B, IEC Curve C, and
Short Inverse. The formulae for these curves are:


K
T = M ×  ---------------------------
E
 ( I ⁄ Ipu ) – 1
(EQ 5.3)
where: T = trip time (seconds), M = multiplier setpoint, I = input current,
Ipickup = pickup current setpoint, K, E = constants.
Table 5–7: IEC (BS) Inverse Time Curve Constants
IEC (BS) Curve Shape
K
E
IEC Curve A (BS142)
0.140
0.020
IEC Curve B (BS142)
13.500
1.000
IEC Curve C (BS142)
80.000
2.000
IEC Short Inverse
0.050
0.040
Table 5–8: IEC Curve Trip Times (in seconds)
Multiplier
(TDM)
0.05
0.10
0.20
0.40
0.60
0.80
1.00
1.5
2.0
0.860
1.719
3.439
6.878
10.317
13.755
17.194
0.501
1.003
2.006
4.012
6.017
8.023
10.029
3.0
4.0
0.315
0.630
1.260
2.521
3.781
5.042
6.302
0.249
0.498
0.996
1.992
2.988
3.984
4.980
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
Current ( I / Ipickup)
5.0
6.0
IEC Curve A
0.214
0.428
0.856
1.712
2.568
3.424
4.280
0.192
0.384
0.767
1.535
2.302
3.070
3.837
7.0
8.0
9.0
10.0
0.176
0.353
0.706
1.411
2.117
2.822
3.528
0.165
0.330
0.659
1.319
1.978
2.637
3.297
0.156
0.312
0.623
1.247
1.870
2.493
3.116
0.149
0.297
0.594
1.188
1.782
2.376
2.971
5 - 47
S5 PROTECTION
CHAPTER 5: SETPOINTS
Table 5–8: IEC Curve Trip Times (in seconds)
Multiplier
(TDM)
Current ( I / Ipickup)
4.0
5.0
6.0
IEC Curve B
1.5
2.0
3.0
0.05
0.10
0.20
0.40
0.60
0.80
1.00
1.350
2.700
5.400
10.800
16.200
21.600
27.000
0.675
1.350
2.700
5.400
8.100
10.800
13.500
0.338
0.675
1.350
2.700
4.050
5.400
6.750
0.225
0.450
0.900
1.800
2.700
3.600
4.500
0.05
0.10
0.20
0.40
0.60
0.80
1.00
3.200
6.400
12.800
25.600
38.400
51.200
64.000
1.333
2.667
5.333
10.667
16.000
21.333
26.667
0.500
1.000
2.000
4.000
6.000
8.000
10.000
0.267
0.533
1.067
2.133
3.200
4.267
5.333
0.05
0.10
0.20
0.40
0.60
0.80
1.00
0.153
0.306
0.612
1.223
1.835
2.446
3.058
0.089
0.178
0.356
0.711
1.067
1.423
1.778
0.056
0.111
0.223
0.445
0.668
0.890
1.113
0.044
0.088
0.175
0.351
0.526
0.702
0.877
0.169
0.338
0.675
1.350
2.025
2.700
3.375
7.0
8.0
9.0
10.0
0.135
0.270
0.540
1.080
1.620
2.160
2.700
0.113
0.225
0.450
0.900
1.350
1.800
2.250
0.096
0.193
0.386
0.771
1.157
1.543
1.929
0.084
0.169
0.338
0.675
1.013
1.350
1.688
0.075
0.150
0.300
0.600
0.900
1.200
1.500
0.114
0.229
0.457
0.914
1.371
1.829
2.286
0.083
0.167
0.333
0.667
1.000
1.333
1.667
0.063
0.127
0.254
0.508
0.762
1.016
1.270
0.050
0.100
0.200
0.400
0.600
0.800
1.000
0.040
0.081
0.162
0.323
0.485
0.646
0.808
0.034
0.067
0.135
0.269
0.404
0.538
0.673
0.031
0.062
0.124
0.247
0.371
0.494
0.618
0.029
0.058
0.115
0.231
0.346
0.461
0.576
0.027
0.054
0.109
0.218
0.327
0.435
0.544
0.026
0.052
0.104
0.207
0.311
0.415
0.518
IEC Curve C
0.167
0.333
0.667
1.333
2.000
2.667
3.333
IEC Short Time
0.038
0.075
0.150
0.301
0.451
0.602
0.752
IAC Curves:
The curves for the General Electric type IAC relay family are derived from the formulae:
D
E
B


T = M ×  A + -------------------------- + ---------------------------------2- + ---------------------------------3-

( ( I ⁄ I pu ) – C ) 
( I ⁄ I pu ) – C ( ( I ⁄ I pu ) – C )
(EQ 5.4)
where: T = trip time (seconds), M = multiplier setpoint, I = input current,
Ipickup = pickup current setpoint, A to E = constants.
Table 5–9: GE Type IAC Inverse Curve Constants
IAC Curve Shape
5 - 48
A
B
C
D
E
IAC Extreme Inverse
0.0040
0.6379
0.6200
1.7872
0.2461
IAC Very Inverse
0.0900
0.7955
0.1000
–1.2885
7.9586
IAC Inverse
0.2078
0.8630
0.8000
–0.4180
0.1947
IAC Short Inverse
0.0428
0.0609
0.6200
–0.0010
0.0221
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S5 PROTECTION
Table 5–10: IAC Curve Trip Times
Multiplier
(TDM)
Current ( I / Ipickup)
4.0
5.0
6.0
IAC Extremely Inverse
1.5
2.0
3.0
0.5
1.0
2.0
4.0
6.0
8.0
10.0
1.699
3.398
6.796
13.591
20.387
27.183
33.979
0.749
1.498
2.997
5.993
8.990
11.987
14.983
0.303
0.606
1.212
2.423
3.635
4.846
6.058
0.178
0.356
0.711
1.422
2.133
2.844
3.555
0.5
1.0
2.0
4.0
6.0
8.0
10.0
1.451
2.901
5.802
11.605
17.407
23.209
29.012
0.656
1.312
2.624
5.248
7.872
10.497
13.121
0.269
0.537
1.075
2.150
3.225
4.299
5.374
0.172
0.343
0.687
1.374
2.061
2.747
3.434
0.5
1.0
2.0
4.0
6.0
8.0
10.0
0.578
1.155
2.310
4.621
6.931
9.242
11.552
0.375
0.749
1.499
2.997
4.496
5.995
7.494
0.266
0.532
1.064
2.128
3.192
4.256
5.320
0.221
0.443
0.885
1.770
2.656
3.541
4.426
0.5
1.0
2.0
4.0
6.0
8.0
10.0
0.072
0.143
0.286
0.573
0.859
1.145
1.431
0.047
0.095
0.190
0.379
0.569
0.759
0.948
0.035
0.070
0.140
0.279
0.419
0.559
0.699
0.031
0.061
0.123
0.245
0.368
0.490
0.613
0.123
0.246
0.491
0.983
1.474
1.966
2.457
7.0
8.0
9.0
10.0
0.074
0.149
0.298
0.595
0.893
1.191
1.488
0.062
0.124
0.248
0.495
0.743
0.991
1.239
0.053
0.106
0.212
0.424
0.636
0.848
1.060
0.046
0.093
0.185
0.370
0.556
0.741
0.926
0.113
0.227
0.453
0.906
1.359
1.813
2.266
0.101
0.202
0.405
0.810
1.215
1.620
2.025
0.093
0.186
0.372
0.745
1.117
1.490
1.862
0.087
0.174
0.349
0.698
1.046
1.395
1.744
0.083
0.165
0.331
0.662
0.992
1.323
1.654
0.180
0.360
0.719
1.439
2.158
2.878
3.597
0.168
0.337
0.674
1.348
2.022
2.695
3.369
0.160
0.320
0.640
1.280
1.921
2.561
3.201
0.154
0.307
0.614
1.229
1.843
2.457
3.072
0.148
0.297
0.594
1.188
1.781
2.375
2.969
0.026
0.052
0.105
0.210
0.314
0.419
0.524
0.026
0.051
0.102
0.204
0.307
0.409
0.511
0.025
0.050
0.100
0.200
0.301
0.401
0.501
0.025
0.049
0.099
0.197
0.296
0.394
0.493
0.093
0.186
0.372
0.744
1.115
1.487
1.859
IAC Very Inverse
0.133
0.266
0.533
1.065
1.598
2.131
2.663
IAC Inverse
0.196
0.392
0.784
1.569
2.353
3.138
3.922
IAC Short Inverse
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
0.028
0.057
0.114
0.228
0.341
0.455
0.569
0.027
0.054
0.108
0.217
0.325
0.434
0.542
5 - 49
S5 PROTECTION
5.6.3
CHAPTER 5: SETPOINTS
Phase Current
Main Menu
PATH: SETPOINTS  S5 PROTECTION  PHASE CURRENT

PHASE
CURRENT
[]
MESSAGE
MESSAGE
MESSAGE
MESSAGE

PHASE TIME
OVERCURRENT 1
[]

PHASE TIME
OVERCURRENT 2
[]

PHASE INST
OVERCURRENT 1
[]

PHASE INST
OVERCURRENT 2
[]

PHASE
DIRECTIONAL
[]
See below
See page 5–53
See page 5–54
Phase overcurrent protection comprises two time overcurrent, two instantaneous
overcurrent, and a phase directional element. The directional element determines whether
current flow is in the forward or reverse direction, as determined by the connected polarity
of the input CTs and the maximum torque angle selected for the phase directional
element. Each phase overcurrent element can be programmed to either disable
directionality or provide a trip for current flow in the forward/reverse direction only. Two
elements allow the use of ‘lo-set’ and ‘hi-set’ detectors in autoreclose applications, zoneselective (blocking) schemes, and distinct settings for faults in different directions. Phase
overcurrent protection elements can be blocked individually or by logic inputs.
Phase Time Overcurrent
PATH: SETPOINTS  S5 PROTECTION  PHASE CURRENT  PHASE TIME OVERCURRENT 1(2)

5 - 50
PHASE TIME
OVERCURRENT 1
PHASE TIME OC 1
FUNCTION: Trip
Range: Disabled, Trip, Trip &
AR, Alarm, Latched
MESSAGE
PHASE TIME OC 1
RELAYS (3-7): -----
Range: Any combination of 3
to 7 Auxiliary relays
MESSAGE
PHASE TIME OC 1
PICKUP: 1.00 x CT
Range: 0.05 to 20.00 x CT in
steps of 0.01
MESSAGE
PHASE TIME OC 1
CURVE: Ext. Inverse
Range: see Table 5–4: TOC
Curve Selections on
MESSAGE
PHASE TIME OC 1
MULTIPLIER:
1.00
Range: 0.00 to 100.00 in
steps of 0.01
MESSAGE
PHASE TIME OC 1
RESET: Instantaneous
Range: Instantaneous,
Linear
MESSAGE
PHASE TIME OC 1
DIRECTION: Disabled
Range: Disabled, Forward,
Reverse
MESSAGE
PHASE TIME OC 1 VOLT
RESTRAINT: Disabled
Range: Enabled, Disabled
[]
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S5 PROTECTION
Phase Time Overcurrent 1 and 2 are identical elements. Each consists of the equivalent of
three separate time overcurrent relays, ANSI Device 51P, with identical characteristics.
These elements can be controlled by the phase directional element, providing operation
for current flow in the permitted direction only. Voltage restrained operation which reduces
the pickup level with reduced voltage is also available.
Multiplier for Pickup Current
Select “Disabled” for the PHASE TIME OC 1 VOLT RESTRAINT setpoint if voltage restraint is
not required. When set to “Enabled”, this feature lowers the pickup value of each individual
phase time overcurrent element in a fixed relationship with the corresponding phase input
voltage. When voltage restraint is enabled, it is not allowed to change the pickup current
setting if the manual close blocking, cold load pickup blocking or autoreclose features are
controlling the protection. If the BUS INPUT VT TYPE is selected to “None”, this feature is
automatically disabled.
1.0
0.9
0.8
0.7
0.6
0.5
0.4
0.3
0.2
0.1
0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1.0
Phase-Phase Voltage ÷ VT Nominal Phase-phase Voltage
818784A4.CDR
FIGURE 5–5: Voltage Restraint Characteristic for Phase TOC
Note
NOTE
If voltage restraint is enabled, the adjusted pickup, calculated by adjusting the pickup
value by the multiplier, will not fall below 0.05 × CT, which is the lowest value for the PHASE
TIME OC PICKUP.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
5 - 51
S5 PROTECTION
CHAPTER 5: SETPOINTS
FIGURE 5–6: Phase TOC Logic (1 of 2)
5 - 52
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S5 PROTECTION
FIGURE 5–7: Phase TOC Logic (2 of 2)
Phase Instantaneous Overcurrent
PATH: SETPOINTS  S5 PROTECTION  PHASE CURRENT  PHASE INST OVERCURRENT 1(2)

PHASE INST
OVERCURRENT 1
PHASE INST OC 1
FUNCTION: Trip
Range: Disabled, Trip, Trip & AR, Alarm,
Latched Alarm, Control
MESSAGE
PHASE INST OC 1
RELAYS (3-7): -----
Range: Any combination of 3 to 7
Auxiliary relays
MESSAGE
PHASE INST OC 1
PICKUP: 1.00 x CT
Range: 0.05 to 20.00 x CT in steps of
0.01
MESSAGE
PHASE INST OC 1
DELAY: 0.00 s
Range: 0.00 to 600.00 s in steps of 0.01
MESSAGE
PHASES REQUIRED FOR
OPERATION: Any One
Range: Any One, Any Two, All Three
MESSAGE
PHASE INST OC 1
DIRECTION: Disabled
Range: Disabled, Forward, Reverse
[]
Phase Instantaneous Overcurrent 1 and 2 are identical elements. Each consists of the
equivalent of three separate instantaneous overcurrent relays, ANSI device 50P, all with
identical characteristics. These elements can be controlled by the phase directional
element, providing operation for current flow in the permitted direction only.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
5 - 53
S5 PROTECTION
CHAPTER 5: SETPOINTS
FIGURE 5–8: Phase IOC Logic
Phase Directional Overcurrent
PATH: SETPOINTS  S5 PROTECTION  PHASE CURRENT  PHASE DIRECTIONAL

PHASE
DIRECTIONAL
PHASE DIRECTIONAL
FUNCTION: Disabled
Range: Disabled, Alarm, Latched Alarm,
Control
MESSAGE
PHASE DIRECTIONAL
RELAYS (3-7): -----
Range: Any combination of 3 to 7
Auxiliary relays
MESSAGE
PHASE DIRECTIONAL
MTA: 30° Lead
Range: 0 to 359° in steps of 1
MESSAGE
MIN POLARIZING
VOLTAGE: 0.05 x VT
Range: 0.00 to 1.25 x VT in steps of
0.01
MESSAGE
BLK OC WHEN VOLT MEM
EXPIRES: Disabled
Range: Disabled, Enabled
[]
Directional overcurrent relaying is necessary for the protection of multiple source feeders,
when it is essential to discriminate between faults in different directions. It would be
impossible to obtain correct relay selectivity through the use of a non-directional
overcurrent relay in such cases. Fault directional control (ANSI device 67) is incorporated
into the relay for all phase, neutral, sensitive ground, and negative sequence overcurrent
5 - 54
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S5 PROTECTION
elements. If directional control is selected, it will determine whether current flow in each
phase is in the forward or reverse direction, as determined by the connection of the phase
source CTs, selected MTA angle, voltage and current phasors. Each overcurrent element
can be individually programmed to operate for flow only in specific directions. For
increased security, all overcurrent elements under directional control add one power
frequency cycle of intentional delay to prevent operational errors on current ‘swings’. Some
terms commonly used in directional relaying are defined as:
•
Operating Current: the quantity whose directionality is to be tested.
•
Polarizing Voltage: a voltage whose phase will remain reasonably constant between
a non-faulted and a faulted system, used as a phase reference for the operating
current.
•
Relay Connection: for phase directional relaying, the characteristic angle between the
operating current and polarizing voltage in the non-faulted system.
•
Zero Torque Line: the boundary line between operating and blocking regions in the
complex plane; in an electromechanical directional relay, an operating current near
this line generates minimum torque.
•
Maximum Torque Line: the line perpendicular, through the origin, to the Zero Torque
Line in the complex plane; in an electromechanical directional relay, an operating
current near this line will generate a maximum amount of torque.
•
Maximum Torque Angle (MTA): the angle by which the Maximum Torque Line is
rotated from the Polarizing Voltage.
The following diagram shows the phasors involved for Phase A directional polarization, but
the general principles can be applied to all directional elements.
FIGURE 5–9: Phase A Directional Overcurrent Polarization
The 750/760 uses the secure 90° or quadrature connection exclusively for phase
directional polarization. An MTA setting of 90° represents a phase current in-phase with its
phase voltage, which is leading the polarizing voltage by 90°. The table below shows the
operating currents and polarizing voltages used for phase directional control.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
5 - 55
S5 PROTECTION
CHAPTER 5: SETPOINTS
Table 5–11: Phase Directional Operating Characteristics
Quantity
Operating
Current
polarizing voltage
ABC Phase Sequence
ACB Phase Sequence
Phase A
Ia
Vbc
Vcb
Phase B
Ib
Vca
Vac
Phase C
Ic
Vab
Vba
To increase security for three phase faults very close to the location of the VTs used to
measure the polarizing voltage, a voltage memory feature is incorporated. This feature
remembers the last measurement of the polarizing voltage which is greater than the MIN
POLARIZING VOLTAGE value and uses it to determine direction. The voltage memory
remains valid for one second after the voltages have collapsed. Once the voltage memory
has expired, after one second, the phase overcurrent elements under directional control
can be set to block or trip on overcurrent. When set to “Enabled”, the BLOCK OC WHEN VOLT
MEM EXPIRES setpoint will block the operation of any phase overcurrent element under
directional control when voltage memory expires. When set to “Disabled”, directional
blocking of any Phase Overcurrent element will be inhibited. The voltage memory is
updated immediately when the polarizing voltage is restored.
To complement the voltage memory feature, a Close Into Fault (CIF) feature allows close-in
faults to be cleared when energizing a line. When the BLOCK OC WHEN VOLT MEM EXPIRES
setpoint is “Disabled”, the CIF feature permits operation of any phase overcurrent element
if current appears without any voltage. When set to “Enabled” the CIF feature inhibits
operation of any phase overcurrent element under directional control under these
conditions. In both cases, directional blocking will be permitted to resume when the
polarizing voltage becomes greater than the MIN POLARIZING VOLTAGE setpoint.
Setting the BLOCK OC WHEN VOLT MEM EXPIRES to “Enabled” will block all phase
overcurrent elements under directional control (phase overcurrent element set to trip in
either the forward or reverse direction) from operating.
Settings:
5 - 56
•
PHASE DIRECTIONAL FUNCTION: The directional element function must be selected
as “Control”, “Alarm” or “Latched Alarm” to enable the directionality check to the TOC
and IOC elements as per programmed directional parameters and as described in this
section. When the “Alarm” function is selected, the 750/760 will flash the “Alarm” LED
while the direction is “REVERSE”, and will turn it off when the condition disappear.
When the “Latched Alarm” function is selected, the 750/760 will flash the “Alarm” LED
while the direction is “REVERSE”. In this case the “Alarm” LED will remain illuminated
after the condition has cleared, until the 750/760 RESET button is pressed.
•
PHASE DIRECTIONAL RELAYS: Select auxiliary contacts (3 to 7) to enable the operation
of the output contacts (3 to 7) when the current is in REVERSE DIRECTION. If under
Output Relay Settings, the “Output Type” of the Auxiliary relays (3 to 7) is set to
“Latched”, they will remain in the operated state, regardless of the status of the
“Alarm” LED, until pressing the RESET button.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S5 PROTECTION
•
PHASE DIRECTIONAL MTA: Enter the maximum torque angle from 0 to 359°, by which
the operating current leads the polarizing voltage. This is the angle of maximum
sensitivity. The factory default value for maximum torque angle is 30°. This is an
appropriate angle for an inductive fault angle of 60°, which is typical of the upper
voltage range of distribution feeders. See the Phase A Directional Overcurrent
Polarization figure for more information.
•
MINIMUM POLARIZING VOLTAGE: This setting defines the minimum phase-to-phase
voltage used for voltage polarization of the current phase directional element. This
setting applies either to the measured phases-to-phase voltage when delta (open
delta) PTs are connected to the relay, or to the computed phase-to-phase voltage,
when “wye” PTs are connected to the relay. The type of PT connection “Delta” or “Wye”
need be set accordingly.
For example in the case of “Wye” VT connection, and the 66.4 V setting selected under
BUS NOMINAL SECONDARY VOLTAGE, the minimum polarizing voltage of 0.5 x VT will
result into 0.5 x (66.4V x √3) = 57.5 V. For Delta VT connection and a BUS NOMINAL
SECONDARY VOLTAGE setting of 115 V, the minimum polarizing voltage is computed as
0.5 x VT or 0.5 x 115 V = 57.5 V.
•
BLOCK OC WHEN VOLT MEM EXPIRES: Select the required operation upon expiration
of voltage memory. When set to “Enabled”, all Phase OC elements under directional
control are blocked from operating when voltage memory expires. When set to
“Disabled”, all phase overcurrent elements are be inhibited by directional control. This
setpoint also determines the operation of phase overcurrent elements under
directional control upon ‘Close Into Fault’ (CIF).
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
5 - 57
S5 PROTECTION
CHAPTER 5: SETPOINTS
818010B9.CDR
FIGURE 5–10: Phase Directional Logic
5.6.4
Neutral Current
Main Menu
PATH: SETPOINTS  S5 PROTECTION  NEUTRAL CURRENT

NEUTRAL
CURRENT
[]
MESSAGE
MESSAGE
MESSAGE
MESSAGE

NEUTRAL TIME
OVERCURRENT 1
[]

NEUTRAL TIME
OVERCURRENT 2
[]

NEUTRAL INST
OVERCURRENT 1
[]

NEUTRAL INST
OVERCURRENT 2
[]

NEUTRAL
DIRECTIONAL
[]
See page 5–59
See page 5–59
See page 5–60
See page 5–60
See page 5–61
Four neutral overcurrent protection elements are provided. Two time overcurrent elements
and two instantaneous overcurrent elements. They all monitor the calculated neutral
current (3Io = Ia + Ib + Ic) which has DC offset and harmonic components removed. Neutral
5 - 58
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S5 PROTECTION
overcurrent elements can be controlled by the neutral directional element allowing
operation for faults in the permitted direction only. Also, the elements can be blocked
individually or as a group by logic inputs.
Neutral Time Overcurrent
PATH: SETPOINTS  S5 PROTECTION  NEUTRAL CURRENT  NEUTRAL TIME... 1(2)

NEUTRAL TIME
OVERCURRENT 1
NEUTRAL TIME OC 1
FUNCTION: Disabled
Range: Disabled, Trip, Trip &
AR, Alarm, Latched
MESSAGE
NEUTRAL TIME OC 1
RELAYS (3-7): -----
Range: Any combination of 3
to 7 Auxiliary relays
MESSAGE
NEUTRAL TIME OC 1
PICKUP: 1.00 x CT
Range: 0.05 to 20.00 x CT in
steps of 0.01
MESSAGE
NEUTRAL TIME OC 1
CURVE: Ext. Inverse
Range: See Table 5–4: TOC
Curve Selections on
MESSAGE
NEUTRAL TIME OC 1
MULTIPLIER:
1.00
Range: 0.00 to 100.00 in
steps of 0.01
MESSAGE
NEUTRAL TIME OC 1
RESET: Instantaneous
Range: Instantaneous,
Linear
MESSAGE
NEUTRAL TIME OC 1
DIRECTION: Disabled
Range: Disabled, Forward,
Reverse
[]
Neutral Time Overcurrent elements 1 and 2 are programmed in this subgroup. They are
two identical protection elements each equivalent to a single ANSI device 51N neutral time
overcurrent relay.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
5 - 59
S5 PROTECTION
CHAPTER 5: SETPOINTS
FIGURE 5–11: Neutral TOC Logic
Neutral Instantaneous OC
PATH: SETPOINTS  S5 PROTECTION  NEUTRAL CURRENT  NEUTRAL INST... 1(2)

NEUTRAL INST
OVERCURRENT 1
NEUTRAL INST OC 1
FUNCTION: Disabled
Range: Disabled, Trip, Trip &
AR, Alarm, Latched
MESSAGE
NEUTRAL INST OC 1
RELAYS (3-7): -----
Range: Any combination of 3
to 7 Auxiliary relays
MESSAGE
NEUTRAL INST OC 1
PICKUP: 1.00 x CT
Range: 0.05 to 20.00 x CT in
steps of 0.01
MESSAGE
NEUTRAL INST OC 1
DELAY: 0.00 s
Range: 0.00 to 600.00 s in
steps of 0.01
MESSAGE
NEUTRAL INST OC 1
DIRECTION: Disabled
Range: Disabled, Forward,
Reverse
[]
The Neutral Instantaneous Overcurrent elements 1 and 2 are programmed in this
subgroup. They are two identical protection elements each equivalent to a single ANSI
device 50N neutral instantaneous overcurrent relay.
5 - 60
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S5 PROTECTION
FIGURE 5–12: Neutral IOC Logic
Neutral Directional Overcurrent
PATH: SETPOINTS  S5 PROTECTION  NEUTRAL CURRENT  NEUTRAL DIRECTIONAL

NEUTRAL
DIRECTIONAL
NEUTRAL DIRECTIONAL
FUNCTION: Disabled
Range: Disabled, Alarm,
Latched Alarm,
MESSAGE
NEUTRAL DIRECTIONAL
RELAYS (3-7): -----
Range: Any combination of 3
to 7 Auxiliary relays
MESSAGE
NEUTRAL POLARIZING:
Voltage
Range: Voltage, Current,
Dual
MESSAGE
NEUTRAL DIRECTIONAL
MTA: 315° Lead
Range: 0 to 359° Lead in
steps of 1
MESSAGE
MIN POLARIZING
VOLTAGE: 0.05 x VT
Range: 0.00 to 1.25 x VT in
steps of 0.01
[]
The Neutral Directional feature controls the operation of all neutral overcurrent elements
and allows them to discriminate between forward or reverse faults. Refer to Phase
Directional Overcurrent on page 5–54 for more details on directional principles. Neutral
directional can be either voltage, current, or dual polarized. The calculated neutral current
is always the operating current.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
5 - 61
S5 PROTECTION
CHAPTER 5: SETPOINTS
When voltage polarized, the polarizing quantity is the zero sequence voltage which is
calculated from the bus input voltages. The VT Connection Type must be wye in this case. If
the polarizing voltage drops below the MIN OPERATING VOLTAGE value, the direction
defaults to forward. The following table shows the operating current and polarizing voltage
used for neutral directional control
Table 5–12: Neutral Directional Characteristics
Quantity
Neutral
Note
NOTE
Operating
Current
3Io = Ia + Ib + Ic
Polarizing Voltage
(VT connection = Wye)
–Vo = –(Va + Vb + Vc) / 3
Polarizing Current
Ig (see note below)
On relays with bootware revision 3.00 or newer, the polarizing current is input via the
Ground CT input. Otherwise, the polarizing current is input via a dedicated polarizing CT
input. See Current Inputs on page 3–11 for additional details.
When current polarized the Ground CT Input (Terminals G10 and H10) is used to determine
neutral current direction. The polarizing current comes from a source CT measuring the
current flowing from the ground return into the neutral of a ground fault current source
which is usually a transformer. The direction is Forward when the neutral current is within
±90° of the polarizing current. Otherwise, the direction is Reverse. If the polarizing current
is less than 5% of CT nominal then the direction defaults to forward.
Dual polarization provides maximum security and reliability. If the polarizing voltage
magnitude is insufficient then current polarizing takes control. If the polarizing current
magnitude is insufficient then the voltage polarizing takes control. If neither voltage nor
current polarizing is possible then the direction defaults to forward.
FIGURE 5–13: Neutral Directional Voltage Polarization
The Neutral Directional specific setpoints are described below.
•
5 - 62
NEUTRAL POLARIZING: If neutral directional control with both voltage and current
polarized elements is desired, enter “Dual”. If neutral directional control with only the
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S5 PROTECTION
voltage polarized element is desired, enter “Voltage”. If neutral directional control with
only the current polarized element is desired, enter “Current”.
•
NEUTRAL DIRECTIONAL MTA: Enter the maximum torque angle by which the
operating current leads the polarizing voltage. This is the angle of maximum
sensitivity. This setpoint affects voltage polarizing only. Additional information is
provided in the figure above.
•
MIN POLARIZING VOLTAGE: This setpoint affects the voltage element only. As the
system zero sequence voltage is used as the polarizing voltage for this element, a
minimum level of voltage must be selected to prevent operation caused by system
unbalanced voltages or VT ratio errors. For well-balanced systems and 1% accuracy
VTs, this setpoint can be as low as 2% of VT nominal voltage. For systems with highresistance grounding or floating neutrals, this setpoint can be as high as 20%. The
default value of “0.05 × VT” is appropriate for most solidly grounded systems.
818823AG.CDR
FIGURE 5–14: Neutral Directional Logic
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
5 - 63
S5 PROTECTION
5.6.5
CHAPTER 5: SETPOINTS
Ground Current
Main Menu
PATH: SETPOINTS  S5 PROTECTION  GROUND CURRENT

GROUND
CURRENT
[]
MESSAGE
MESSAGE

GROUND TIME
OVERCURRENT
[]

GROUND INST
OVERCURRENT
[]

GROUND
DIRECTIONAL
[]
See page 5–64
See page 5–65
See page 5–66
Separate protection is provided for ground time overcurrent and ground instantaneous
overcurrent. These elements monitor the ground current input on Terminals G10 and H10.
Ground overcurrent elements can be blocked individually or as a group by logic inputs.
Ground overcurrent elements can be controlled by the ground directional element allowing
operation for faults in the permitted direction only.
Ground Time Overcurrent
PATH: SETPOINTS  S5 PROTECTION  GROUND CURRENT  GROUND TIME
OVERCURRENT

GROUND TIME
OVERCURRENT
GND TIME OC
FUNCTION: Disabled
Range: Disabled, Trip, Trip &
AR, Alarm, Latched
MESSAGE
GND TIME OC
RELAYS (3-7): -----
Range: Any combination of 3
to 7 Auxiliary relays
MESSAGE
GND TIME OC
PICKUP: 1.00 x CT
Range: 0.05 to 20.00 x CT in
steps of 0.01
MESSAGE
GND TIME OC
CURVE: Ext. Inverse
Range: See TOC Curve
Selections on page
MESSAGE
GND TIME OC
MULTIPLIER:
Range: 0.00 to 100.00 in
steps of 0.01
MESSAGE
GND TIME OC
RESET: Instantaneous
Range: Instantaneous,
Linear
MESSAGE
GND TIME OC
DIRECTION: Disabled
Range: Disabled, Forward,
Reverse
[]
1.00
The equivalent of a single ground time overcurrent relay, ANSI device 51G, is programmed
in this subgroup.
5 - 64
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S5 PROTECTION
FIGURE 5–15: Ground TOC Logic
Ground Instantaneous Overcurrent
PATH: SETPOINTS  S5 PROTECTION  GROUND CURRENT  GRND INST OVERCURRENT

GROUND INST
OVERCURRENT
GND INST OC
FUNCTION: Disabled
Range: Disabled, Trip, Trip &
AR, Alarm, Latched
MESSAGE
GND INST OC
RELAYS (3-7): -----
Range: Any combination of 3
to 7 Auxiliary relays
MESSAGE
GND INST OC
PICKUP: 1.00 x CT
Range: 0.05 to 20.00 x CT in
steps of 0.01
MESSAGE
GND INST OC
DELAY: 0.00 s
Range: 0.00 to 600.00 s in
steps of 0.01
MESSAGE
GND INST OC
DIRECTION: Disabled
Range: Disabled, Forward,
Reverse
[]
The equivalent of a single ground instantaneous relay, ANSI device 50G, is programmed in
this subgroup.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
5 - 65
S5 PROTECTION
CHAPTER 5: SETPOINTS
50G
PICKUP
Setpoint Control
818070AU.CDR
FIGURE 5–16: Ground IOC Logic
Ground Directional Overcurrent
PATH: SETPOINTS  S5 PROTECTION  GROUND CURRENT  GROUND DIRECTIONAL

5 - 66
GROUND
DIRECTIONAL
GND DIRECTIONAL
FUNCTION: Disabled
Range: Disabled, Alarm,
Latched Alarm,
MESSAGE
GND DIRECTIONAL
RELAYS (3-7): -----
Range: Any combination of 3
to 7 Auxiliary relays
MESSAGE
GND POLARIZING
Voltage
Range: Voltage, Current,
Dual
MESSAGE
GND DIRECTIONAL
MTA: 315° Lead
Range: 0 to 359° Lead in
steps of 1
MESSAGE
MIN POLARIZING
VOLTAGE: 0.05 x VT
Range: 0.00 to 1.25 x VT in
steps of 0.01
[]
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S5 PROTECTION
The Ground Directional feature controls operation of all ground overcurrent elements and
allows them to discriminate between forward or reverse faults. Refer to Phase Directional
Overcurrent on page 5–54 for additional details on directional principles. Ground
directional can be either voltage, current, or dual polarized. The ground current input is
always the operating current.
When voltage polarized, the polarizing quantity is the zero sequence voltage which is
calculated from the bus input voltages. The VT Connection Type must be Wye in this case.
If the polarizing voltage drops below the MIN OPERATING VOLTAGE value, the direction
defaults to forward. The following table shows the operating current and polarizing
quantities used for ground directional control.
Table 5–13: Ground Directional Characteristics
Quantity
Ground
Note
NOTE
Operating
Current
Ig
Polarizing Voltage
(VT connection = Wye)
–Vo = –(Va + Vb + Vc) / 3
Polarizing Current
Ipol (see note below)
On relays with bootware revision 3.00 or newer, the ground directional element may only
be voltage polarized since these relays do not have a polarizing current input. Otherwise,
the polarizing current is input via a dedicated polarizing CT input. See Current Inputs on
page 3–11 for more details.
When current polarized, the ‘Polarizing CT Input’ is used to determine ground current
direction. The polarizing current comes from a source CT measuring the current flowing
from the ground return into the neutral of a ground fault current source which is usually a
transformer. The direction is Forward when the ground current is within ±90° of the
polarizing current. Otherwise, the direction is Reverse. If the polarizing current is less than
5% of CT nominal then the direction defaults to forward.
Dual polarization provides maximum security and reliability. If the polarizing voltage
magnitude is insufficient then the current polarizing takes control. If the polarizing current
magnitude is insufficient then the voltage polarizing takes control. If neither voltage nor
current polarizing is possible then the direction defaults to forward.
•
GND POLARIZING: If ground directional control with both voltage and current
polarized elements is desired, enter “Dual”. If ground directional control with only the
voltage polarized element is desired, enter “Voltage”. If ground directional control with
only the current polarized element is desired, enter “Current”.
•
GND DIRECTIONAL MTA: Enter the maximum torque angle by which the operating
current leads the polarizing voltage. This is the angle of maximum sensitivity. This
setpoint affects voltage polarizing only.
•
MIN POLARIZING VOLTAGE: This setpoint affects the voltage element only. As the
system zero sequence voltage is used as the polarizing voltage for this element, a
minimum level of voltage must be selected to prevent operation caused by system
unbalanced voltages or VT ratio errors. For well-balanced systems and 1% accuracy
VTs, this setpoint can be as low as 2% of VT nominal voltage. For systems with highresistance grounding or floating neutrals, this setpoint can be as high as 20%. The
default value of “0.05 x VT” is appropriate for most solidly grounded systems.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
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S5 PROTECTION
CHAPTER 5: SETPOINTS
818872A4.CDR
FIGURE 5–17: Ground Directional Overcurrent Logic
5.6.6
Sensitive Ground
Main Menu
PATH: SETPOINTS  S5 PROTECTION  SENSITIVE GND CURRENT

SENSITIVE GND
CURRENT
[]
MESSAGE
MESSAGE
MESSAGE
5 - 68

SENSITIVE GND
[]
TIME OVERCURRENT
See page 5–69

SENSITIVE GND
[]
INST OVERCURRENT
See page 5–70

SENSITIVE GND
DIRECTIONAL
[]
See page 5–71

RESTRICTED
EARTH FAULT
[]
See page 5–73
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S5 PROTECTION
Two sensitive ground overcurrent elements and a restricted earth fault element are
provided. One time overcurrent element and one instantaneous element. Sensitive ground
overcurrent elements can be controlled by the sensitive ground directional element
allowing operation for faults in the permitted direction only. Also, the elements can be
blocked individually or as a group by logic inputs.
Sensitive Ground Time Overcurrent
PATH: SETPOINTS  S5 PROTECTION  SENSITIVE GND CURRENT  SENSITIVE GND TIME...

SENSTV GND TIME OC
FUNCTION: Disabled
Range: Disabled, Trip, Trip &
AR, Alarm, Latched
MESSAGE
SENSTV GND TIME OC
RELAYS (3-7): -----
Range: Any combination of 3
to 7 Auxiliary relays
MESSAGE
SENSTV GND TIME OC
PICKUP: 1.000 x CT
Range: 0.005 to 1.000 x CT in
steps of 0.001
MESSAGE
SENSTV GND TIME OC
CURVE: Ext. Inverse
Range: See Table 5–4: TOC
Curve Selections on
MESSAGE
SENSTV GND TIME OC
MULTIPLIER:
1.00
Range: 0.00 to 100.00 in
steps of 0.01
MESSAGE
SENSTV GND TIME OC
RESET: Instantaneous
Range: Instantaneous,
Linear
MESSAGE
SENSTV GND TIME OC
DIRECTION: Disabled
Range: Disabled, Forward,
Reverse
SENSITIVE GND
[]
TIME OVERCURRENT
The sensitive ground time overcurrent element, ANSI device 51SG is programmed in this
subgroup.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
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S5 PROTECTION
CHAPTER 5: SETPOINTS
FIGURE 5–18: Sensitive Ground TOC Logic
Sensitive Ground Instantaneous Overcurrent
PATH: SETPOINTS  S5 PROTECTION  SENSITIVE GND...  SENSITIVE GND INST...

SENSTV GND INST OC
FUNCTION: Disabled
Range: Disabled, Trip, Trip &
AR, Alarm, Latched
MESSAGE
SENSTV GND INST OC
RELAYS (3-7): -----
Range: Any combination of 3
to 7 Auxiliary relays
MESSAGE
SENSTV GND INST OC
PICKUP: 1.000 x CT
Range: 0.005 to 1.000 x CT in
steps of 0.001
MESSAGE
SENSTV GND INST OC
DELAY: 0.00 s
Range: 0.00 to 600.00 s in
steps of 0.01
MESSAGE
SENSTV GND INST OC
DIRECTION: Disabled
Range: Disabled, Forward,
Reverse
SENSITIVE GND
[]
INST OVERCURRENT
The sensitive ground instantaneous overcurrent element, ANSI device 50SG is
programmed in this subgroup.
5 - 70
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S5 PROTECTION
FIGURE 5–19: Sensitive Ground IOC Logic
Sensitive Ground Directional Overcurrent
PATH: SETPOINTS  S5 PROTECTION  SENSITIVE GND...  SENSITIVE GND DIRECTIONAL

SENSITIVE GND
DIRECTIONAL
SENSTV GND DIRECTN
FUNCTION: Disabled
Range: Disabled, Alarm,
Latched Alarm,
MESSAGE
SENSTV GND DIRECTN
RELAYS (3-7): -----
Range: Any combination of 3
to 7 Auxiliary relays
MESSAGE
SENS GND POLARIZING
Voltage
Range: Voltage, Current,
Dual
MESSAGE
SENSTV GND DIRECTN
MTA: 315° Lead
Range: 0 to 359° Lead in
steps of 1
MESSAGE
MIN POLARIZING
VOLTAGE: 0.05 x VT
Range: 0.00 to 1.25 x VT in
steps of 0.01
[]
The sensitive ground directional feature controls the operation of all sensitive ground
overcurrent elements and allows them to discriminate between forward or reverse faults.
Refer to Phase Directional Overcurrent on page 5–54 for more details on directional
principles. Sensitive ground directional can be either voltage, current, or dual polarized.
The sensitive ground current input is always the operating current.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
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S5 PROTECTION
CHAPTER 5: SETPOINTS
When voltage polarized, the polarizing quantity is the zero sequence voltage which is
calculated from the bus input voltages. The VT Connection Type must be Wye in this case.
If the polarizing voltage drops below the MIN OPERATING VOLTAGE value, the direction
defaults to forward. The following table shows the operating current and polarizing
quantities used for sensitive ground directional control.
Table 5–14: Sensitive Ground Directional Characteristics
Quantity
Sensitive Ground
Note
NOTE
Operating
Current
Isg
Polarizing Voltage
(VT connection = Wye)
–Vo = –(Va + Vb + Vc) / 3
Polarizing Current
Ig (see note below)
On relays with bootware revision 3.00 or newer, the polarizing current is input via the
Ground CT input. Otherwise, the polarizing current is input via a dedicated polarizing CT
input. See Current Inputs on page 3–11 for more details.
When current polarized, the Ground CT Input is used to determine sensitive ground current
direction. The polarizing current comes from a source CT measuring the current flowing
from the ground return into the neutral of a ground fault current source which is usually a
transformer. The direction is Forward when the sensitive ground current is within ±90° of
the polarizing current. Otherwise, the direction is Reverse. If the polarizing current is less
than 5% of CT nominal then the direction defaults to forward.
Dual polarization provides maximum security and reliability. If the polarizing voltage
magnitude is insufficient then the current polarizing takes control. If the polarizing current
magnitude is insufficient then the voltage polarizing takes control. If neither voltage nor
current polarizing is possible then the direction defaults to forward.
5 - 72
•
SENS GND POLARIZING: If sensitive ground directional control with both voltage and
current polarized elements is desired, enter “Dual”. With this setpoint, both polarizing
quantities must agree that the operating current is in the reverse direction for the
sensitive ground directional element to operate the selected output relays. If sensitive
ground directional control with only the voltage polarized element is desired, enter
“Voltage”. If sensitive ground directional control with only the current polarized
element is desired, enter “Current”.
•
SENSTV GND DIRECTN MTA: Enter the maximum torque angle by which the operating
current leads the polarizing voltage. This is the angle of maximum sensitivity. This
setpoint affects voltage polarizing only.
•
MIN POLARIZING VOLTAGE: This setpoint affects the voltage element only. As the
system zero sequence voltage is used as the polarizing voltage for this element, a
minimum level of voltage must be selected to prevent operation caused by system
unbalanced voltages or VT ratio errors. For well-balanced systems and 1% accuracy
VTs, this setpoint can be as low as 2% of VT nominal voltage. For systems with highresistance grounding or floating neutrals, this setpoint can be as high as 20%. The
default value of “0.05 x VT” is appropriate for most solidly grounded systems.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S5 PROTECTION
FIGURE 5–20: Sensitive Ground Directional Logic
Restricted Earth Fault
PATH: SETPOINTS  S5 PROTECTION  SENSTV GND CURRENT  RESTRICTED EARTH...

RESTRICTED
EARTH FAULT
RESTRICTED EARTH FLT
FUNCTION: Disabled
Range: Disabled, Trip, Alarm,
Latched Alarm,
MESSAGE
RESTRICTED EARTH FLT
RELAYS (3-7): -----
Range: Any combination of 3
to 7 Auxiliary relays
MESSAGE
RESTRICTED EARTH FLT
PICKUP: 0.100 x CT
Range: 0.005 to 1.000 x CT in
steps of 0.001
MESSAGE
RESTRICTED EARTH FLT
DELAY: 0.00 s
Range: 0.00 to 600.00 s in
steps of 0.01
[]
Restricted Earth Fault protection is often applied to transformers having grounded wye
windings, to provide sensitive ground fault detection for faults near the transformer
neutral. The Sensitive Ground Input (Terminals G3, H3) can be used.
Although the 750/760 is designed for feeder protection, it can provide Restricted Earth
Fault protection on transformers that do not have dedicated protection. To use the 750/
760 for this type of protection, a stabilizing resistor and possibly a non-linear resistor will
be required.
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S5 PROTECTION
CHAPTER 5: SETPOINTS
The inclusion of a stabilizing resistor encourages the circulating fault current to flow via the
magnetizing impedance of the saturated current transformer thus minimizing spill current
in the REF relay. A non-linear resistor will be required where the voltage across the inputs
would be greater than 2000 V. Refer to Restricted Earth Fault Inputs on page 3–12 for the
connections required to use the 750/760 to perform Restricted Earth Fault protection.
To determine the appropriate value for the Stabilizing Resistor, use the following equation:
Vs
I F ⋅ ( R CT + 2R L )
R s = ----- = ------------------------------------Is
Is
(EQ 5.5)
where:RS = resistance value of the stabilizing resistor,
VS = voltage at which the 750/760 will operate
IS = current flowing through the stabilizing resistor and the 750/760,
IF = maximum secondary fault current magnitude
RCT = internal resistance of the current transformer, and RL = resistance of attached wire
leads
A non-linear resistor is recommended if the peak fault voltage may be above the relays
maximum of 2000 V. The following calculation is done to determine if a non-linear resistor
is required. When required, this should be provided by the end-user.
It is assumed that the ratio of the CT kneepoint (VK) VS is to 2 for stability. Thus,
V K = 2V S
(EQ 5.6)
Next, the voltage that would result from a fault must be determined, neglecting saturation,
V f = I f ⋅ ( R CT + 2R L + R S )
(EQ 5.7)
The peak value of this fault voltage would be:
VP = 2 2 ⋅ Vk ⋅ ( Vf – VK )
(EQ 5.8)
If VP is greater than 2000 V, then a non-linear resistor must be used.
Sample Application:
The CTs used in this example are 3000/1, 10P10, 15 VA, and the transformer used in the
example is an 11 kV / 400 V, 2000 kVA. At 10P10 the voltage at which the CT will saturate
will be 10 x 15 = 150 V. An equivalent IEEE description for this CT would be 3000/1, C150.
5 - 74
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S5 PROTECTION
FIGURE 5–21: Restricted Earth Fault Sample Application
We have: RCT = 3.7 Ω, RL = 0.954 Ω (assuming 600 feet of #12 wire), and X(%) = impedance
of transformer = 7% = 0.07
The rated transformer current through wye windings is given as:
2000 kVA
I P = -------------------------- = 2887 A
3 ⋅ 400 V
(EQ 5.9)
and the maximum fault current is:
IP
2887 A
I MAXf = ------------- = ----------------- = 41243 A
X(%)
0.07
(EQ 5.10)
Therefore, the secondary full load current is:
2887 A
I SFLC = ----------------- = 0.962 A
3000
(EQ 5.11)
and the maximum secondary fault current is:
0.962 A
I Smax = ------------------- = 13.74 A = I f
0.07
(EQ 5.12)
A VK / VS ratio of 2 is assumed to ensure operation. As such,
VS = If (RCT + 2RL) = 77.05 V and
VK = 2VS = 154.1 V
To calculate the size of the stabilizing resistor, assume IPICKUP to be 30% rated transformer
current, that is:
I PICKUP = 0.3 × 2887 A = 866 A (Primary)
(EQ 5.13)
This means also (assuming 1% for CT magnetizing current):
866 A
I RELAY PICKUP = -------------- – ( 4 × 0.01 ) = 0.248 A = I S
3000
(EQ 5.14)
and therefore:
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
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S5 PROTECTION
CHAPTER 5: SETPOINTS
Vs
77.05 Ω
R s = ----- = -------------------- = 311 Ω
Is
0.248 A
(EQ 5.15)
To determine whether a non-linear resistor is required, we have:
V f = I f ⋅ ( R CT + 2R L + R s ) = 13.748 A × ( 3.7 Ω + ( 2 × 0.954 Ω ) + 311 Ω ) = 4353 V
VP = 2 2 ⋅ VK ⋅ ( VF – VK )
→ use 150 V as value for V K
(EQ 5.16)
= 2 2 ⋅ 150 V × ( 4353 V – 150 V ) = 2246 V
A non-linear resistor is recommended as the peak fault voltage is above relay voltage
maximum of 2000 V.
FIGURE 5–22: Restricted Earth Fault Logic
5.6.7
Negative Sequence
Main Menu
PATH: SETPOINTS  S5 PROTECTION  NEGATIVE SEQUENCE

NEGATIVE
SEQUENCE
[]
MESSAGE
MESSAGE
MESSAGE
5 - 76

NEG SEQUENCE
[]
TIME OVERCURRENT
See page 5–77

NEG SEQUENCE
[]
INST OVERCURRENT
See page 5–78

NEG SEQUENCE
DIRECTIONAL
[]
See page 5–79

NEG SEQUENCE
VOLTAGE
[]
See page 5–81
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S5 PROTECTION
Separate protection is provided for the calculated negative sequence time overcurrent,
instantaneous overcurrent and voltage. Each of these features can be individually blocked
by logic inputs.
Negative Sequence Time Overcurrent
PATH: SETPOINTS  S5 PROTECTION  NEGATIVE SEQUENCE  NEG SEQUENCE TIME...

NEG SEQ TIME OC
FUNCTION: Disabled
Range: Disabled, Trip, Trip &
AR, Alarm, Latched
MESSAGE
NEG SEQ TIME OC
RELAYS (3-7): -----
Range: Any combination of 3
to 7 Auxiliary relays
MESSAGE
NEG SEQ TIME OC
PICKUP: 1.00 x CT
Range: 0.05 to 20.00 x CT in
steps of 0.01
MESSAGE
NEG SEQ TIME OC
CURVE: Ext. Inverse
Range: See Table 5–4: TOC
Curve Selections on
MESSAGE
NEG SEQ TIME OC
MULTIPLIER:
1.00
Range: 0.00 to 100.00 in
steps of 0.01
MESSAGE
NEG SEQ TIME OC
RESET: Instantaneous
Range: Instantaneous,
Linear
MESSAGE
NEG SEQ TIME OC
DIRECTION: Disabled
Range: Disabled, Forward,
Reverse
NEG SEQUENCE
[]
TIME OVERCURRENT
A time overcurrent element operating on the negative sequence component of current,
ANSI device 46 is programmed in this subgroup.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
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S5 PROTECTION
CHAPTER 5: SETPOINTS
FIGURE 5–23: Negative Sequence TOC Logic
Negative Sequence Instantaneous Overcurrent
PATH: SETPOINTS  S5 PROTECTION  NEGATIVE SEQUENCE  NEG SEQUENCE INST...

NEG SEQ INST OC
FUNCTION: Disabled
Range: Disabled, Trip, Trip &
AR, Alarm, Latched
MESSAGE
NEG SEQ INST OC
RELAYS (3-7): -----
Range: Any combination of 3
to 7 Auxiliary relays
MESSAGE
NEG SEQ INST OC
PICKUP: 1.000 x CT
Range: 0.05 to 20.00 x CT in
steps of 0.001
MESSAGE
NEG SEQ INST OC
DELAY: 0.00 s
Range: 0.00 to 600.00 s in
steps of 0.01
MESSAGE
NEG SEQ INST OC
DIRECTION: Disabled
Range: Disabled, Forward,
Reverse
NEG SEQUENCE
[]
INST OVERCURRENT
A instantaneous overcurrent element operating on the negative sequence component of
current, ANSI device 46 is programmed in this subgroup.
5 - 78
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S5 PROTECTION
FIGURE 5–24: Negative Sequence IOC Logic
Negative Sequence Directional Overcurrent
PATH: SETPOINTS  S5 PROTECTION  NEGATIVE SEQUENCE  NEG SEQUENCE DIR...

NEG SEQUENCE
DIRECTIONAL
NEG SEQ DIRECTIONAL
FUNCTION: Disabled
Range: Disabled, Alarm, Latched Alarm,
Control
MESSAGE
NEG SEQ DIRECTIONAL
RELAYS (3-7): -----
Range: Any combination of 3 to 7
Auxiliary relays
MESSAGE
NEG SEQ DIRECTIONAL
MTA: 315° Lead
Range: 0 to 359° Lead in steps of 1
MESSAGE
MIN POLARIZING
VOLTAGE: 0.05 x VT
Range: 0.00 to 1.25 x VT in steps of
0.01
[]
The negative sequence directional feature controls the operation of all negative sequence
overcurrent elements and allows them to discriminate between forward or reverse faults.
Refer to Phase Directional Overcurrent on page 5–54 for more details on directional
principles. The operating current and polarizing voltage is shown in the following table. If
the polarizing voltage drops below the MIN OPERATING VOLTAGE value, the direction
defaults to forward.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
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S5 PROTECTION
CHAPTER 5: SETPOINTS
Table 5–15: Negative Sequence Directional Characteristics
Quantity
Operating Current
2
Negative Sequence
(ABC phase sequence)
I a + a I b + aI c
I a2 = ---------------------------------3
Negative Sequence
(ACB phase sequence)
I a + aI b + a I c
I a2 = ---------------------------------3
2
Polarizing Voltage
2
V a + a V b + aV c
– V a2 = – --------------------------------------3
2
V a + aV b + a V c
– V a2 = – --------------------------------------3
The setpoints for Negative Sequence Directional are described below.
•
NEG SEQ DIRECTIONAL MTA: Enter the maximum torque angle by which the
operating current leads the polarizing voltage. This is the angle of maximum
sensitivity.
•
MIN POLARIZING VOLTAGE: As the system negative sequence voltage is used as the
polarizing voltage for this element, a minimum level of voltage must be selected to
prevent operation caused by system unbalanced voltages or VT ratio errors. For wellbalanced systems and 1% accuracy VTs, this setpoint can be as low as 2% of VT
nominal voltage. For systems with high-resistance grounding or floating neutrals, this
setpoint can be as high as 20%. The default value of “0.05 x VT” is appropriate for most
solidly grounded systems.
FIGURE 5–25: Negative Sequence Directional Logic
5 - 80
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S5 PROTECTION
Negative Sequence Voltage
PATH: SETPOINTS  S5 PROTECTION  NEGATIVE SEQUENCE  NEG SEQUENCE VOLTAGE

NEG SEQUENCE
VOLTAGE
NEG SEQ VOLTAGE
FUNCTION: Disabled
Range: Disabled, Trip, Alarm,
Latched Alarm,
MESSAGE
NEG SEQ VOLTAGE
RELAYS (3-7): -----
Range: Any combination of 3
to 7 Auxiliary relays
MESSAGE
NEG SEQ VOLTAGE
PICKUP: 0.10 x VT
Range: 0.00 to 1.25 x VT in
steps of 0.01
MESSAGE
NEG SEQ VOLTAGE
DELAY: 2.0 s
Range: 0.0 to 6000.0 s in
steps of 0.1
[]
To protect against loss of one or two source phases, or against a reversed phase sequence
of voltage, the negative sequence voltage element can be used to either cause a trip or
generate an alarm when the negative sequence voltage exceeds the specified threshold
for a specified time delay.
FIGURE 5–26: Negative Sequence Voltage Logic
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
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S5 PROTECTION
5.6.8
CHAPTER 5: SETPOINTS
Voltage
Main Menu
PATH: SETPOINTS  S5 PROTECTION  VOLTAGE

VOLTAGE
[]
MESSAGE
MESSAGE
MESSAGE
MESSAGE
MESSAGE
MESSAGE

BUS
UNDERVOLTAGE 1
[]

BUS
UNDERVOLTAGE 2
[]

LINE
UNDERVOLTAGE 3
[]

LINE
UNDERVOLTAGE 4
[]

OVERVOLTAGE 1
[]

OVERVOLTAGE 2
[]

NEUTRAL
DISPLACEMENT
[]
See page 5–83
See page 5–83
See page 5–84
See page 5–84
See page 5–85
See page 5–85
See page 5–86
There are four undervoltage protection elements which can be used for a variety of
applications:
•
Undervoltage Protection: For voltage sensitive loads, such as induction motors, a
drop in voltage will result in an increase in the drawn current, which may cause
dangerous overheating in the motor. The undervoltage protection feature can be used
to either cause a trip or generate an alarm when the voltage drops below a specified
voltage setting for a specified time delay.
•
Permissive Functions: The undervoltage feature may be used to block the functioning
of external devices by operating an output relay, when the voltage falls below the
specified voltage setting. Note that all internal features that are inhibited by an
undervoltage condition, such as underfrequency and overfrequency, have their own
inhibit functions independent of the undervoltage protection features.
•
Source Transfer Schemes: In the event of an undervoltage, a transfer signal may be
generated to transfer a load from its normal source to a standby or emergency power
source.
The undervoltage elements can be programmed to have an inverse time delay
characteristic. The undervoltage delay setpoint defines a family of curves as shown below.
The operating time is given by:
D
T = ------------------------1 – V ⁄ V pu
(EQ 5.17)
where:T = Operating Time
D = Undervoltage Delay setpoint
V = Voltage as a fraction of the nominal VT Secondary Voltage
Vpu = Pickup Level
5 - 82
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S5 PROTECTION
At 0% of pickup, the operating time equals the Undervoltage Delay setpoint.
Note
NOTE
D=5.0
20.0
2.0 1.0
18.0
Time (seconds)
16.0
14.0
12.0
10.0
8.0
6.0
4.0
2.0
0.0
0
10
20 30
40
50
60
70
80 90 100 110
% of V pickup
FIGURE 5–27: Inverse Time Undervoltage Curves
Bus Undervoltage
PATH: SETPOINTS  S5 PROTECTION  VOLTAGE  BUS UNDERVOLTAGE 1(2)

BUS
UNDERVOLTAGE 1
BUS UNDERVOLTAGE 1
FUNCTION: Disabled
Range: Disabled, Trip, Alarm,
Latched Alarm,
MESSAGE
BUS UNDERVOLTAGE 1
RELAYS (3-7): -----
Range: Any combination of 3
to 7 Auxiliary relays
MESSAGE
BUS UNDERVOLTAGE 1
PICKUP: 0.75 x VT
Range: 0.00 to 1.25 x VT in
steps of 0.01
MESSAGE
BUS UNDERVOLTAGE 1
CURVE: Definite Time
Range: Definite Time, Inverse
Time.
MESSAGE
BUS UNDERVOLTAGE 1
DELAY:
2.0 s
Range: 0.0 to 6000.0 s in
steps of 0.1
MESSAGE
PHASES REQUIRED FOR
OPERATION: All Three
Range: Any One, Any Two, All
Three
MESSAGE
MIN OPERATING
VOLTAGE: 0.30 x VT
Range: 0.00 to 1.25 x VT in
steps of 0.01
[]
Bus Undervoltage 1 and 2 are identical elements that generate outputs in response to
undervoltage conditions on the bus voltage inputs. The time delay characteristic can be
programmed as definite time or inverse time. A minimum operating voltage level is
programmable to prevent undesired operation before voltage becomes available. The
setpoints for Bus Undervoltage 1 are shown above; the Bus Undervoltage 2 setpoints are
identical.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
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S5 PROTECTION
CHAPTER 5: SETPOINTS
Vbc
FIGURE 5–28: Bus Undervoltage Logic
Line Undervoltage
PATH: SETPOINTS  S5 PROTECTION  VOLTAGE  LINE UNDERVOLT AGE 3(4)

LINE
UNDERVOLTAGE 3
LINE UNDERVOLT 3
FUNCTION: Disabled
Range: Disabled, Trip, Alarm,
Latched Alarm,
MESSAGE
LINE UNDERVOLT 3
RELAYS (3-7): -----
Range: Any combination of 3
to 7 Auxiliary relays
MESSAGE
LINE UNDERVOLT 3
PICKUP: 0.75 x VT
Range: 0.00 to 1.25 x VT in
steps of 0.01
MESSAGE
LINE UNDERVOLT 3
CURVE: Definite Time
Range: Definite Time, Inverse
Time.
MESSAGE
LINE UNDERVOLT 3
DELAY:
2.0 s
Range: 0.0 to 6000.0 s in
steps of 0.1
MESSAGE
MIN OPERATING
VOLTAGE: 0.30 x VT
Range: 0.00 to 1.25 x VT in
steps of 0.01
[]
Line undervoltage 3 and 4 are identical protection elements that generate outputs in
response to an undervoltage condition on the line voltage input. The time delay
characteristic can be programmed as either definite time or inverse time. A minimum
5 - 84
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S5 PROTECTION
operating voltage level is programmable to prevent undesired operation before voltage
becomes available. The setpoints for the Line Undervoltage 3 element are shown above;
the Line Undervoltage 4 setpoints are identical.
FIGURE 5–29: Line Undervoltage Logic
Overvoltage
PATH: SETPOINTS  S5 PROTECTION  VOLTAGE  OVERVOLTAGE 1(2)

OVERVOLTAGE 1
OVERVOLTAGE 1
FUNCTION: Disabled
Range: Disabled, Trip, Alarm,
Latched Alarm,
MESSAGE
OVERVOLTAGE 1
RELAYS (3-7): -----
Range: Any combination of 3
to 7 Auxiliary relays
MESSAGE
OVERVOLTAGE 1
PICKUP: 1.25 x VT
Range: 0.00 to 1.25 x VT in
steps of 0.01
MESSAGE
OVERVOLTAGE 1
DELAY:
2.0 s
Range: 0.0 to 6000.0 s in
steps of 0.1
MESSAGE
PHASES REQUIRED FOR
OPERATION: All Three
Range: Any One, Any Two, All
Three
[]
To protect voltage sensitive loads and circuits against sustained overvoltage conditions,
the Overvoltage 1 and 2 protection features can be used to either cause a trip or generate
an alarm when the voltage exceeds a specified voltage value for a specified time delay.
The setpoints above are repeated for both Overvoltage 1 and 2.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
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S5 PROTECTION
CHAPTER 5: SETPOINTS
FIGURE 5–30: Overvoltage Logic
Neutral Displacement
PATH: SETPOINTS  S5 PROTECTION  VOLTAGE  NEUTRAL DISPLACEMENT

NEUTRAL
DISPLACEMENT
NTR DISPLACEMENT
FUNCTION: Disabled
Range: Disabled, Trip, Alarm,
Latched Alarm,
MESSAGE
NTR DISPLACEMENT
RELAYS (3-7): -----
Range: Any combination of 3
to 7 Auxiliary relays
MESSAGE
NTR DISPLACEMENT
PICKUP: 1.00 x VT
Range: 0.00 to 1.25 x VT in
steps of 0.01
MESSAGE
NTR DISPLACEMENT
CURVE: Ext. Inverse
Range: See Table 5–4: TOC
Curve Selections on
MESSAGE
NTR DISPLACEMENT
MULTIPLIER:
1.0 s
Range: 0.00 to 100.00 in
steps of 0.01
MESSAGE
NTR DISPLACEMENT
RESET: Instantaneous
Range: Instantaneous,
Linear
[]
The 750/760 incorporates a Neutral Displacement element, which uses the internally
derived 3V0 value. This protection element requires the three phase Bus VTs to be wye
connected. When setting the pickup level for this element, it is important to consider the
error in the VT ratio as well as the normal voltage unbalance on the system. The Neutral
Displacement setpoints are as follows.
Note
NOTE
5 - 86
The same curves used for the time overcurrent elements are used for Neutral
Displacement. When using the curve to determine the operating time of the Neutral
Displacement element, substitute the ratio of neutral voltage to the pickup level for the
current ratio shown on the horizontal axis of the curve plot.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S5 PROTECTION
Be aware that the neutral displacement feature should be applied with caution. It would
normally be applied to give line to ground fault coverage on high impedance grounded or
ungrounded systems, which are isolated. This constraint stems from the fact that a
measurement of 3V0 cannot discriminate between a faulted circuit and an adjacent
healthy circuit. Use of a time delayed back-up or an alarm mode allow other protections
an opportunity to isolate the faulted element first.
FIGURE 5–31: Neutral Displacement Logic
5.6.9
Frequency
Main Menu
PATH: SETPOINTS  S5 PROTECTION  FREQUENCY

FREQUENCY
[]
MESSAGE
MESSAGE

UNDERFREQ 1
[]

UNDERFREQ 2
[]

FREQUENCY
DECAY
[]
See page 5–88
See page 5–88
See page 5–89
The 750/760 can be used as the primary detecting relay in automatic load shedding
schemes based on underfrequency. The need for such a relay arises if during a system
disturbance, an area becomes electrically isolated from the main system and suffers a
generation deficiency due to the loss of either transmission or generation facilities. If
reserve generation is not available in the area, conditions of low system frequency will
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
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S5 PROTECTION
CHAPTER 5: SETPOINTS
occur which may lead to a complete collapse. The 750/760 provides two underfrequency
and one rate-of-change of frequency protection elements which can automatically
disconnect sufficient load to restore an acceptable balance between load and generation.
Underfrequency
PATH: SETPOINTS  S5 PROTECTION  FREQUENCY  UNDERFREQ 1(2)

UNDERFREQ 1
UNDEFREQUENCY 1
FUNCTION: Disabled
Range: Disabled, Trip, Alarm,
Latched Alarm,
MESSAGE
UNDEFREQUENCY 1
RELAYS (3-7): -----
Range: Any combination of 3
to 7 Auxiliary relays.
MESSAGE
UNDEFREQUENCY 1
PICKUP: 59.00 Hz
Range: 20.00 to 65.00 Hz in
steps of 0.01
MESSAGE
UNDEFREQUENCY 1
DELAY:
2.00 s
Range: 0.00 to 600.00 s in
steps of 0.1
MESSAGE
MINIMUM OPERATING
VOLTAGE: 0.70 x VT
Range: 0.00 to 1.25 x VT in
steps of 0.01
MESSAGE
MINIMUM OPERATING
CURRENT: 0.20 x CT
Range: 0.00 to 1.25 x CT in
steps of 0.01
[]
There are two identical underfrequency protection elements, ANSI devices 81U-1 and 81U2. The setpoints for the Underfrequency 1 element are shown above; the Underfrequency 2
setpoints are identical. See Overview on page 5–44 for additional setting details.
5 - 88
•
MINIMUM OPERATING VOLTAGE: Enter the minimum voltage required for
underfrequency element operation. This setpoint prevents incorrect operation before
energization of the source to the relay location, and during voltage dips.
•
MINIMUM OPERATING CURRENT: Enter the minimum value of current required on any
phase to allow the underfrequency element to operate. This setpoint is used to
prevent underfrequency tripping during periods of light load, when this action would
have an insignificant effect on the system.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S5 PROTECTION
FIGURE 5–32: Underfrequency Logic
Frequency Decay
PATH: SETPOINTS  S5 PROTECTION  FREQUENCY  FREQUENCY DECAY

FREQUENCY
DECAY
FREQ DECAY
FUNCTION: Disabled
Range: Disabled, Trip, Alarm,
Latched Alarm,
MESSAGE
FREQ DECAY
RELAYS (3-7): -----
Range: Any combination of 3
to 7 Auxiliary relays
MESSAGE
FREQ DECAY
RATE: 1.0 Hz/s
Range: 0.1 to 5.0 Hz/s in
steps of 0.1
MESSAGE
FREQ DECAY
PICKUP: 59.00 Hz
Range: 20.00 to 65.00 Hz in
steps of 0.01
MESSAGE
FREQ DECAY
DELAY:
2.00 s
Range: 0.00 to 600.00 s in
steps of 0.01
MESSAGE
MIN OPERATING
VOLTAGE: 0.70 x VT
Range: 0.00 to 1.25 x VT in
steps of 0.01
MESSAGE
MIN OPERATING
CURRENT: 0.00 x CT
Range: 0.00 to 1.25 x CT in
steps of 0.01
[]
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
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S5 PROTECTION
CHAPTER 5: SETPOINTS
There is one frequency decay protection element, ANSI device 81D which can provide a
faster response to system disturbances than the underfrequency elements. See the
previous section for descriptions of the MIN OPERATING CURRENT and MIN OPERATING
VOLTAGE setpoints. See Overview on page 5–44 for additional setting details
FIGURE 5–33: Frequency Decay Logic
5.6.10 Breaker Failure
PATH: SETPOINTS  S5 PROTECTION  BREAKER FAILURE

5 - 90
BREAKER
FAILURE
BRKR FAILURE
FUNCTION: Disabled
Range: Disabled, Alarm,
Latched Alarm,
MESSAGE
BRKR FAILURE
RELAYS (3-7): -----
Range: Any combination of 3
to 7 Auxiliary relays
MESSAGE
BRKR FAILURE
DELAY 1:
0.10 s
Range: 0.03 to 1.00 s in steps
of 0.01
MESSAGE
BRKR FAILURE
DELAY 2:
0.00 s
Range: 0.00 to 1.00 s in steps
of 0.01
MESSAGE
BRKR FAILURE
CURRENT: 1.00 x CT
Range: 0.05 to 20.00 x CT in
steps of 0.01
[]
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S5 PROTECTION
Breaker failure monitors the phase currents while a trip command exists. If any phase
current is above the set level after the BRKR FAILURE DELAY time expires, a breaker failure
will be declared, which will operate the selected output relays and force the 750/760
autoreclose scheme to lockout.
To provide user flexibility, the 750/760 has included two programmable delays for the
breaker failure function. The timers can be used singularly or in combination with each
other. The difference between the two is their location in the logic diagram. BRKR FAILURE
DELAY 1 starts counting down from the user programmed delay setpoint once a Trip
condition is recognized. On the other hand, BRKR FAILURE DELAY 2 provides a delay where
it does not begin counting down until a trip condition is present, Delay 1 has expired, and
one of the phase currents is above the BRKR FAILURE CURRENT setpoint. If one of the
delays is not required, simply program the unwanted timer to its minimum value.
Note
NOTE
The operation of the filter that reduces the overreaching effect of asymmetrical offset
currents will cause the measured current to ramp down to zero after the breaker trips. It is
strongly recommended that a margin of at least 1.5 power frequency cycles be added to
the expected breaker time-to-trip for the BRKR FAILURE DELAY 1 and BRKR FAILURE DELAY
2 setpoints.
FIGURE 5–34: Breaker Failure Logic
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
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S5 PROTECTION
CHAPTER 5: SETPOINTS
5.6.11 Reverse Power
PATH: SETPOINTS  S5 PROTECTION  REVERSE POWER

REVERSE
POWER
REVERSE POWER
FUNCTION: Disabled
Range: Disabled, Trip, Alarm,
Control
MESSAGE
REVERSE POWER
RELAYS (3-7): -----
Range: Any combination of 3
to 7 Auxiliary relays
MESSAGE
REVERSE POWER
PICKUP: 0.050 xRATED
Range: 0.015 to 0.600 x
RATED in steps of
MESSAGE
REVERSE POWER
DELAY:
10.0 s
Range: 0.0 to 6000.0 s in
steps of 0.1
[]
A Reverse Power element is generally associated with generator protection. Such an
element is used to detect loss of mechanical power coming into the turbine and to trip the
unit to prevent turbine blade heating or other adverse effects in turbo-generator sets. The
REVERSE POWER PICKUP setting is usually set as low as the relay can measure, but no
higher than one-half the electrical power required to motor the generator with total loss of
mechanical power. The Reverse Power element is not normally used in conventional feeder
protection applications.
The Reverse Power element generates an output when the three-phase reverse real power
is greater than the REVERSE POWER PICKUP setting. It is recommended to set REVERSE
POWER DELAY to 1 second or higher to avoid problems with power oscillations that may be
experienced on synchronization; a setting in the range of 10 to 15 seconds is typical. Recall
that the rated power is calculated as follows:
Rated Power =
Note
NOTE
3 × V sec(line-line) × VT Ratio × I sec(rated) × CT Ratio
(EQ 5.18)
The sensitivity of this element and the requirement to have two times pickup limits its
range of application. The motoring power cannot be less that 3% of rated, and the angle
away from the 180° angle of maximum sensitivity should not be greater than ±85 to 87°
due to reactive loading on the generator.
This element is optional and available from GE Multilin as Mod 008. To order, please contact
the factory with the serial number of the 750/760 relay. Refer to Reverse Power on page 8–
1 for the complete procedure for installing and verifying the Reverse Power element.
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750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S5 PROTECTION
FIGURE 5–35: Reverse Power Logic
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
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S6 MONITORING
5.7
CHAPTER 5: SETPOINTS
S6 Monitoring
5.7.1
Current Level
Main Menu
PATH: SETPOINTS  S6 MONITORING  CURRENT LEVEL

CURRENT LEVEL
[]
MESSAGE

PHASE
CURRENT

NEUTRAL
CURRENT
[]
[]
See below.
See page 5–95
In addition to the conventional overcurrent protection elements that are used for tripping,
separate phase and neutral current level detectors are provided for alarm or control
purposes. These elements allow longer time delays to be programmed.
Phase Current Level
PATH: SETPOINTS  S6 MONITORING  CURRENT LEVEL  PHASE CURRENT

PHASE
CURRENT
PHASE CURRENT
FUNCTION: Disabled
Range: Disabled, Alarm,
Latched Alarm,
MESSAGE
PHASE CURRENT
RELAYS (3-7): -----
Range: Any combination of 3
to 7 Auxiliary relays
MESSAGE
PHASE CURRENT
PICKUP: 1.10 x CT
Range: 0.05 to 20.00 x CT in
steps of 0.01
MESSAGE
PHASE CURRENT
DELAY:
2 s
Range: 0 to 60000 s in steps
of 1
[]
FIGURE 5–36: Phase Current Level Logic
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750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S6 MONITORING
Neutral Current Level
PATH: SETPOINTS  S6 MONITORING  CURRENT LEVEL  NEUTRAL CURRENT

NEUTRAL
CURRENT
NEUTRAL CURRENT
FUNCTION: Disabled
Range: Disabled, Alarm,
Latched Alarm,
MESSAGE
NEUTRAL CURRENT
RELAYS (3-7): -----
Range: Any combination of 3
to 7 Auxiliary relays
MESSAGE
NEUTRAL CURRENT
PICKUP: 1.00 x CT
Range: 0.05 to 20.00 x CT in
steps of 0.01
MESSAGE
NEUTRAL CURRENT
DELAY:
2 s
Range: 0 to 60000 s in steps
of 1
[]
See Common Setpoints on page 5–6 for additional setting details.
FIGURE 5–37: Neutral Current Level Logic
5.7.2
Power Factor
PATH: SETPOINTS  S6 MONITORING  POWER FACTOR  POWER FACTOR 1(2)

POWER FACTOR 1
PWR FACTOR 1
FUNCTION: Disabled
Range: Disabled, Alarm,
Latched Alarm,
MESSAGE
PWR FACTOR 1
RELAYS (3-7): -----
Range: Any combination of 3
to 7 Auxiliary relays
MESSAGE
PWR FACTOR 1
PICKUP: 0.80
Range: –0.99 to 1.00 in steps
of 0.01
MESSAGE
PWR FACTOR 1
DROPOUT: 1.00
Range: –0.99 to 1.00 in steps
of 0.01
MESSAGE
PWR FACTOR 1
DELAY:
50 s
Range: 0 to 60000 s in steps
of 1
[]
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
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S6 MONITORING
CHAPTER 5: SETPOINTS
It is generally desirable for a system operator to maintain the power factor as close to
unity as possible to minimize both costs and voltage excursions. Since the power factor is
variable on common non-dedicated circuits, it is advantageous to compensate for low
(lagging) power factor values by connecting a capacitor bank to the circuit when required.
The relay allows two stages of capacitance switching for power factor compensation.
The relay calculates the average power factor in the three phases as follows:
Total 3 Phase Real Power
Average Power Factor = ---------------------------------------------------------------------------Total 3 Phase Apparent Power
(EQ 5.19)
996710A1.CDR
FIGURE 5–38: Capacitor Bank Switching
Two independent elements are available for monitoring power factor, each having a
pickup and a dropout level. For each element, when the measured power factor becomes
more lagging than the pickup level (i.e. numerically less than), the relay operates a userselected output contact. This output can be used to control a switching device which
connects capacitance to the circuit, or to signal an alarm to the system operator. After
entering this state, when the power factor becomes less lagging than the power factor
dropout level for a time larger than the set delay, the relay will reset the output contact to
the non-operated state.
The power factor feature is inhibited from operating unless all three voltages are above
30% of nominal and one or more currents is above 0. Power Factor 1 and 2 delay timers
will only be allowed to time when the 30% threshold is exceeded on all phases and the
power factor remains outside of the programmed pickup and dropout levels. In the same
way, when a power factor condition starts the Power Factor 1 or 2 delay timer, if all three
phase voltages fall below the 30% threshold before the timer has timed-out, the element
will reset without operating. A loss of voltage during any state will return both Power Factor
1 and 2 to the reset state.
For the PWR FACTOR 1(2) PICKUP and PWR FACTOR 1(2) DROPOUT setpoints, positive values
indicate lagging power factor.
5 - 96
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S6 MONITORING
FIGURE 5–39: Power Factor Logic
5.7.3
Fault Locator
PATH: SETPOINTS  S6 MONITORING  FAULT LOCATOR

FAULT LOCATOR
LENGTH OF FEEDER:
0.1 km
Range: 0.1 to 99.9 km/Miles
in steps of 0.1
MESSAGE
UNITS OF LENGTH:
km
Range: km, Miles
MESSAGE
Zpos (RESISTIVE) OF
FEEDER: 0.01 Ω
Range: 0.01 to 99.99 Ω in
steps of 0.01
MESSAGE
Zpos (INDUCTIVE) OF
FEEDER: 0.01 Ω
Range: 0.01 to 99.99 Ω in
steps of 0.01
MESSAGE
Zzero (RESISTIVE) OF
FEEDER: 0.01 Ω
Range: 0.01 to 99.99 Ω in
steps of 0.01
MESSAGE
Zzero (INDUCTIVE) OF
FEEDER: 0.01 Ω
Range: 0.01 to 99.99 Ω in
steps of 0.01
MESSAGE
FAULT TYPE OUTPUT TO
RELAYS 4-7: Disabled
Range: Disabled, Enabled
MESSAGE
FAULT LOCATION AFTER
TRIP: Disabled
Range: Disabled, Enabled
[]
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
5 - 97
S6 MONITORING
CHAPTER 5: SETPOINTS
The relay calculates the distance to fault with fault resistance compensation. For the fault
location feature, a fault is defined as an event that has caused a current level greater than
the pickup threshold of an overcurrent protection feature programmed to “Trip” or “Trip &
AR” (760 only), which has remained for sufficient time to cause the relay to produce a Trip
command. After this has happened, the apparent distance to the fault is calculated in a
background mode, maintaining all other features in operation. The distance calculation is
based on the assumptions that:
1.
The feeder positive and zero sequence impedances are a constant per unit
distance, and
2.
Mutual compensation is not required.
If the feeder utilizes conductors of different sizes, or more than one physical arrangement
of conductors, or shares poles or towers with a parallel feeder, these assumptions are
incorrect and errors are introduced.
The algorithm uses prefault system data to reduce the error caused by variable fault
resistance, so inaccuracy is introduced for a fault which occurs when no load current was
present. Also, error is introduced if the feeder has sources at locations other than the
location of the relay, due to infeed effects.
The algorithm contains three sets of equations that are used to perform the calculations
for a specific fault type: phase-to-ground, phase-to-phase-to-ground, phase-to-phase,
and three-phase. Each of the sets (other than three-phase) consists of a subset which
covers all combinations of phases. The algorithm therefore uses a fault identification
procedure to select the appropriate equations to be used for calculation. This procedure
uses both prefault and fault current phasors from memory to identify the type of fault. The
prefault data is taken from a sample collected three power frequency cycles before the
pickup of the overcurrent element to ensure the sample contains only load current. The
after fault data is taken from samples collected 1.5 power frequency cycles after
overcurrent pickup to ensure the current had existed for at least one complete sampling
interval.
As well as the apparent distance to the fault, the locator records the feeder apparent
reactance (with fault resistance removed if prefault current was available.) This parameter
can be very useful in estimating the location of a fault on a feeder tap, where the apparent
distance can be calculated as beyond the feeder end. The date, time, type of fault, and
phases involved are also stored for the event. Non-volatile memory is provided for the past
ten events, in a FIFO queue, available under A1 STATUS  FAULT LOCATIONS.
Note
NOTE
5 - 98
If the feeder has a source with a grounded neutral, and is therefore capable of providing
ground fault current, the bus VTs must be both connected and selected as “Wye” in S2
SYSTEM SETUP  BUS VT SENSING  VT CONNECTION TYPE to allow the fault locator to
perform the calculations properly. If the fault classification results in a phase to ground
fault, the program checks that the setpoint noted above is set to ‘Wye’ before the
calculation is permitted.
•
LENGTH OF FEEDER: Enter the total length of the feeder, in kilometers or miles as
selected by the UNITS OF LENGTH setpoint.
•
UNITS OF LENGTH: Enter the units of measurement, in kilometers or miles.
•
Zpos (RESISTIVE/INDUCTIVE) OF FEEDER: Enter the total real/imaginary component
of the feeder positive sequence impedance, in actual ohms.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S6 MONITORING
•
Zzero (RESISTIVE/INDUCTIVE) OF FEEDER: Enter the total real/imaginary component
of the feeder zero sequence impedance, in actual ohms.
•
FAULT TYPE OUTPUT TO RELAYS 4-7: Selects whether fault type indication on output
relays 4 to 7 is enabled. When enabled, relays 4 to 7 will operate to indicate the most
recent fault type (i.e. Fault Location 0 Fault Type). The auxiliary relays are reset to their
non-operated state after the relay is reset. Any combination of relays 4 to 7 may be
operated, with outputs as shown below:
Phase A faults operate the 4 Auxiliary relay.
Phase B faults operate the 5 Auxiliary relay.
Phase C faults operate the 6 Auxiliary relay.
Neutral faults operate the 7 Auxiliary relay.
•
5.7.4
FAULT LOCATION AFTER TRIP: Users utilizing the Fault Distance feature may define a
fault distance message to display along with other active conditions. When set to
“Enabled”, a fault distance message will be displayed when a trip has occurred. The
fault distance message will be removed when the active conditions are reset. This
message only appears after the first Trip condition; any subsequent Trips will only
update the fault distance value (if required).
Demand
Main Menu
PATH: SETPOINTS  S6 MONITORING  DEMAND

DEMAND
[]
MESSAGE
MESSAGE
MESSAGE

CURRENT
[]

REAL POWER
[]

REACTIVE POWER
[]

APPARENT POWER
[]
See page 5–101
See page 5–102
See page 5–103
See page 5–104
Current demand is measured on each phase, and on three phases for real, reactive, and
apparent power. Setpoints allow the user to emulate some common electrical utility
demand measuring techniques for statistical or control purposes.
Note
NOTE
The relay is not approved as or intended to be a revenue metering instrument. If used in a
peak load control system, the user must consider the accuracy rating and method of
measurement employed, and the source VTs and CTs, in comparison with the electrical
utility revenue metering system.
The relay can be set to calculate demand by any of three methods.
•
Thermal Exponential: This selection emulates the action of an analog peak recording
thermal demand meter. The relay measures the quantity (RMS current, real power,
reactive power, or apparent power) on each phase every second, and assumes the
circuit quantity remains at this value until updated by the next measurement. It
calculates the thermal demand equivalent based on:
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
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S6 MONITORING
CHAPTER 5: SETPOINTS
d(t) = D(1 – e
– kt
)
(EQ 5.20)
whered = demand value after applying input quantity for time t (in minutes),
D = input quantity (constant), k = 2.3 / thermal 90% response time.
Demand (%)
100
80
60
40
20
0
0
3
6
9
12
15
18
21
24
27
30
Time (min)
FIGURE 5–40: Thermal Demand Characteristic (15 minute response)
The 90% thermal response time characteristic defaults to 15 minutes. A setpoint
establishes the time to reach 90% of a steady-state value, just as the response time of
an analog instrument. A steady state value applied for twice the response time will
indicate 99% of the value.
•
Block Interval: This selection calculates a linear average of the quantity (RMS current,
real power, reactive power, or apparent power) over the programmed demand time
interval, starting daily at 00:00:00 (i.e. 12 am). The 1440 minutes per day is divided into
the number of blocks as set by the programmed time interval. Each new value of
demand becomes available at the end of each time interval.
The Block Interval with Start Demand Interval Logic Input calculates a linear average
of the quantity (RMS current, real power, reactive power, or apparent power) over the
interval between successive Start Demand Interval logic input pulses. Each new value
of demand becomes available at the end of each pulse. The S3 LOGIC INPUTS  MISC
FUNCTIONS  START DMND INTERVAL setpoint programs the input for the new
demand interval pulses.
•
5 - 100
Rolling Demand: This selection calculates a linear average of the quantity (RMS
current, real power, reactive power, or apparent power) over the programmed
demand time interval, in the same way as Block Interval. The value is updated every
minute and indicates the demand over the time interval just preceding the time of
update.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S6 MONITORING
Current Demand
PATH: SETPOINTS  S6 MONITORING  DEMAND  CURRENT

CURRENT
CURRENT DEMAND
FUNCTION: Disabled
Range: Disabled, Alarm,
Latched Alarm,
MESSAGE
MEASUREMENT TYPE:
Thermal Exponential
Range: Thermal Exponential,
Block Interval, Rolling
MESSAGE
THERMAL 90% RESPONSE
TIME: 15 min
Range: 5 min, 10 min, 15
min, 20 min, 30 min,
MESSAGE
TIME INTERVAL:
20 min
Range: 5 min, 10 min, 15
min, 20 min, 30 min,
MESSAGE
CURRENT DEMAND
RELAYS (3-7): -----
Range: Any combination of
the 3 to 7 Auxiliary
MESSAGE
CURRENT DEMAND
PICKUP: 1000 A
Range: 10 to 10000 A in
steps of 1
[]
The current demand for each phase is calculated individually, and the demand for each
phase is monitored by comparing to a single current demand pickup value. If the current
demand pickup is equaled or exceeded by any phase, the relay can cause an alarm or
signal an output relay.
For the THERMAL 90% RESPONSE TIME setpoint, enter the time required for a steady state
current to indicate 90% of the actual value. This setpoint allows the user to approximately
match the response of the relay to analog instruments. This setpoint is visible only if
MEASUREMENT TYPE is “Thermal Exponential”.
For the TIME INTERVAL setpoint, enter the time period over which the current demand
calculation is to be performed. This setpoint is visible only if MEASUREMENT TYPE is “Block
Interval” or “Rolling Demand”.
See Common Setpoints on page 5–6 for additional setting details.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
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CHAPTER 5: SETPOINTS
FIGURE 5–41: Current Demand Logic
Real Power Demand
PATH: SETPOINTS  S6 MONITORING  DEMAND  REAL POWER

REAL POWER
REAL PWR DEMAND
FUNCTION: Disabled
Range: Disabled, Alarm,
Latched Alarm,
MESSAGE
MEASUREMENT TYPE:
Block Interval
Range: Thermal Exponential,
Block Interval, Rolling
MESSAGE
THERMAL 90% RESPONSE
TIME: 15 min
Range: 5 min, 10 min, 15
min, 20 min, 30 min,
MESSAGE
TIME INTERVAL:
20 min
Range: 5 min, 10 min, 15
min, 20 min, 30 min,
MESSAGE
REAL PWR DEMAND
RELAYS (3-7): -----
Range: Any combination of
the 3 to 7 Auxiliary
MESSAGE
REAL PWR DEMAND
PICKUP: 10.0 MW
Range: 1 to 30000 kW. Autoranging; see table
[]
The real power demand is monitored by comparing to a pickup value. If the real power
demand pickup is ever equaled or exceeded, the relay can be configured to cause an
alarm or signal an output relay.
See page –99 for details on the MEASUREMENT TYPE setting.
For the THERMAL 90% RESPONSE TIME setpoint, enter the time required for a steady state
power to indicate 90% of the actual value. This setpoint allows the user to approximately
match the response of the relay to analog instruments. This setpoint is visible only if
MEASUREMENT TYPE is “Thermal Exponential”.
For the TIME INTERVAL , enter the time over which the real power demand calculation is to
be performed. For the REAL POWER DEMAND PICKUP, power quantities auto-range to show
units appropriate to the power system size (see table below). This setpoint is visible only if
MEASUREMENT TYPE is “Block Interval” or “Rolling Demand”.
Table 5–16: Auto-Ranging Units
Nominal Power (PN)
5 - 102
Power Units
Resolution
PN < 1 MVA
kW
1
1 MVA ≤ PN < 10 MVA
MW
0.01
10 MVA ≤ PN
MW
0.1
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S6 MONITORING
FIGURE 5–42: Real Power Demand Logic
Reactive Power Demand
PATH: SETPOINTS  S6 MONITORING  DEMAND  REACTIVE POWER

REACTIVE POWER
REACTIVE PWR DMND
FUNCTION: Disabled
Range: Disabled, Alarm,
Latched Alarm,
MESSAGE
MEASUREMENT TYPE:
Block Interval
Range: Thermal Exponential,
Block Interval, Rolling
MESSAGE
THERMAL 90% RESPONSE
TIME: 15 min
Range: 5 min, 10 min, 15
min, 20 min, 30 min,
MESSAGE
TIME INTERVAL:
20 min
Range: 5 min, 10 min, 15
min, 20 min, 30 min,
MESSAGE
REACTIVE PWR DMND
RELAYS (3-7): -----
Range: Any combination of
the 3 to 7 Auxiliary
MESSAGE
REACTIVE PWR DMND
PICKUP: 10.0 Mvar
Range: 1 to 30000 kvar.
Auto-ranging; see
[]
The reactive power demand is monitored by comparing to a pickup value. If the reactive
power demand pickup is ever equaled or exceeded, the relay can be configured to cause
an alarm or signal an output relay.
See page –99 for details on the MEASUREMENT TYPE setting.
For the THERMAL 90% RESPONSE TIME setpoint, enter the time required for a steady state
reactive power to indicate 90% of the actual value. This setpoint allows the user to
approximately match the response of the relay to analog instruments. This setpoint is
visible only if MEASUREMENT TYPE is “Thermal Exponential”.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
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S6 MONITORING
CHAPTER 5: SETPOINTS
For the TIME INTERVAL , enter the time period to perform the reactive power demand
calculation. For the REACTIVE PWR DEMAND PICKUP, the power quantities auto-range to
show units appropriate to the power system size (see table below). This setpoint is visible
only if MEASUREMENT TYPE is “Block Interval” or “Rolling Demand”.
Table 5–17: Auto-Ranging Units
Nominal Power (PN)
Power Units
Resolution
PN < 1 MVA
kvar
1
1 MVA ≤ PN < 10 MVA
Mvar
0.01
10 MVA ≤ PN
Mvar
0.1
FIGURE 5–43: Reactive Power Demand Logic
Apparent Power Demand
PATH: SETPOINTS  S6 MONITORING  DEMAND  APPARENT POWER

5 - 104
APPARENT POWER
APPARENT PWR DMND
FUNCTION: Disabled
Range: Disabled, Alarm,
Latched Alarm,
MESSAGE
MEASUREMENT TYPE:
Block Interval
Range: Thermal Exponential,
Block Interval, Rolling
MESSAGE
THERMAL 90% RESPONSE
TIME: 15 min
Range: 5 min, 10 min, 15
min, 20 min, 30 min,
MESSAGE
TIME INTERVAL:
20 min
Range: 5 min, 10 min, 15
min, 20 min, 30 min,
MESSAGE
APPARENT PWR DMND
RELAYS (3-7): -----
Range: Any combination of
the 3 to 7 Auxiliary
MESSAGE
APPARENT PWR DMND
PICKUP: 10.0 MVA
Range: 1 to 30000 kVA. Autoranging; see table
[]
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S6 MONITORING
The apparent power demand is monitored by comparing to a pickup value. If the apparent
power demand pickup is ever equaled or exceeded, the relay can be configured to cause
an alarm or signal an output relay.
See page –99 for details on the MEASUREMENT TYPE setting.
For the THERMAL 90% RESPONSE TIME setpoint, enter the time required for a steady state
apparent power to indicate 90% of the actual value. This setpoint allows the user to
approximately match the response of the relay to analog instruments. This setpoint is
visible only if MEASUREMENT TYPE is “Thermal Exponential”.
For the TIME INTERVAL , enter the time period to perform the apparent power demand
calculation. For the APPARENT PWR DMND PICKUP, the power quantities auto-range to show
units appropriate to the power system size (see table below). This setpoint is visible only if
MEASUREMENT TYPE is “Block Interval” or “Rolling Demand”.
Table 5–18: Auto-Ranging Units
Nominal Power (PN)
Power Units
Resolution
PN < 1 MVA
kVA
1
1 MVA ≤ PN < 10 MVA
MVA
0.01
10 MVA ≤ PN
MVA
0.1
FIGURE 5–44: Apparent Power Demand Logic
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
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S6 MONITORING
5.7.5
CHAPTER 5: SETPOINTS
Analog Input
Main Menu
PATH: SETPOINTS  S6 MONITORING  ANALOG INPUT

ANALOG INPUT
[]
MESSAGE
MESSAGE
MESSAGE
MESSAGE

ANALOG INPUT
SETUP
[]

ANALOG
THRESHOLD 1
[]

ANALOG
THRESHOLD 2
[]

ANALOG INPUT
RATE 1
[]

ANALOG INPUT
RATE 2
[]
See page 5–106
See page 5–107
See page 5–107
See page 5–109
See page 5–109
The relay can monitor any external quantity, such as transformer winding temperature,
bus voltage, battery voltage, station service voltage, transformer tap position, etc., via an
auxiliary current input called the analog input. Any one of the standard transducer output
ranges 0 to 1 mA, 0 to 5 mA, 0 to 10 mA, 0 to 20 mA, or 4 to 20 mA can be connected to the
analog input terminals.
Two independent elements are available for monitoring the analog input level, Analog
Threshold 1 and 2, each having a user programmable name, pickup level, drop out ratio,
and a time delay. For each element, when the measured analog input quantity exceeds
the pickup level for longer than the associated time delay, the relay can be configured to
cause a trip, an alarm, or signal an output contact. The element will drop out only when the
user programmed drop out ratio has been met. There are also two elements which
measure the analog input rate-of-change, Analog In Rate 1 and 2, which operate in a
similar fashion.
Analog Input Setup
PATH: SETPOINTS  S6 MONITORING  ANALOG INPUT  ANALOG INPUT SETUP

5 - 106
ANALOG INPUT
SETUP
A/I NAME:
ANALOG INPUT
Range: Any combination of
20 alphanumeric
MESSAGE
A/I UNITS:
μA
Range: Any combination of 6
alphanumeric
MESSAGE
A/I RANGE:
0-20 mA
Range: 0-1 mA, 0-5 mA, 4-20
mA, 0-20 mA, 0-10
MESSAGE
A/I MIN
VALUE:
MESSAGE
A/I MAX
VALUE: 20000 μA
[]
0 μA
Range: 0 to 65535 units in
steps of 1.
Range: 0 to 65535 units in
steps of 1.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S6 MONITORING
Before the analog input can be used for monitoring, the value of the input must be
converted to the quantity that is being measured. The relay simplifies this process by
internally scaling the transducer output, and displaying and monitoring the actual
measured parameter. Note the resolution that will result from the selection of the minimum
and maximum setpoints. For example, if 0 to 20 mA is to be represented via the 0 to 20 mA
analog input, an input of 4.5 mA will translate to a 5 mA actual value reading. This is due to
the rounding up of the value, since the analog input actual value is an F1 format. If a range
of 0 to 200 mA was programmed to be represented via the 0 to 20 mA input, 4.5 mA will
result in a 45 mA actual value.
For the A/I MIN VALUE and A/I MAX VALUE setpoints, enter the value which corresponds to
the minimum/maximum output value of the transducer. For example, if a temperature
transducer which outputs 4 to 20 mA for temperatures 0 to 250°C is connected to the
analog input, then enter “0” for A/I MIN VALUE. The relay then interprets 4 mA as
representing 0°C. Intermediate values between the minimum and maximum are scaled
linearly.
Analog Threshold
PATH: SETPOINTS  S6 MONITORING  ANALOG INPUT  ANALOG THRESHOLD 1(2)

ANALOG
THRESHOLD 1
A/I THRESHLD 1 NAME:
ANALOG THRESHLD1
Range: Any combination of
18 alphanumeric
MESSAGE
ANALOG THRESHLD 1
FUNCTION: Disabled
MESSAGE
ANALOG THRESHLD 1
RELAYS (3-7): -----
Range: Disabled, Trip, Alarm,
Latched Alarm,
Control, Blk Thrsh 1.
See Note below.
Range: Any combination of
the 3 to 7 Auxiliary
MESSAGE
ANALOG THRESHLD 1
PICKUP:
100 μA
Range: 0 to 65535 units in
steps of 1
MESSAGE
ANALOG THRESHLD 1
DROP OUT RATIO: 5%
Range: 2 to 20% in steps of 1
MESSAGE
ANALOG THRESHLD 1
PICKUP TYPE: Over
Range: Over, Under
MESSAGE
ANALOG THRESHLD 1
DELAY:
100 s
Range: 0 to 60000 s in steps
of 1
[]
Monitoring of the analog input can be performed by two separate functions, each
operating at different thresholds of analog input current and each having a selection to
trip, alarm, or control. For user flexibility, independent user names can also be
programmed for each Analog Threshold.
Note that connected analog input will still be read and displayed in A2 METERING
ANALOG INPUT if both ANALOG THRESHLD 1 FUNCTION and ANALOG THRESHLD 2
FUNCTION are set to “Disabled”.
The Blk Thrsh 1 value applies to the ANALOG THRESHLD 2 FUNCTION setpoint only.
Note
NOTE
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
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S6 MONITORING
CHAPTER 5: SETPOINTS
The units for the ANALOG THRESHLD 1 PICKUP setpoint are determined by the A/I UNITS
setpoint.
The ANALOG THRESHLD 1 PICKUP TYPE setpoint determines if pickup will occur when the
analog input is over or under the programmed threshold.
The value programmed in the ANALOG THRESHLD 1 DROP OUT RATIO setpoint represents
the variation of pickup value, in percentage of pickup, at which the element will effectively
drop out. The drop out ratio is defined as follows:
pickup × dropout ratio
Drop Out = pickup – -------------------------------------------------------- when PICKUP TYPE is Over
100
pickup × dropout ratio
Drop Out = pickup + -------------------------------------------------------- when PICKUP TYPE is Under
100
(EQ 5.21)
For example, if the pickup level is 5000 μA, then a ANALOG THRESHLD 1 PICKUP TYPE set to
“Over” and a ANALOG THRESHLD 1 DROP OUT RATIO set to “10%” results in a drop out of
4500 μA. Conversely, if the ANALOG THRESHLD 1 PICKUP TYPE is “Under” with the same
drop out ratio, the actual drop out will be 5500 μA.
FIGURE 5–45: Analog Input Threshold Logic
5 - 108
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S6 MONITORING
Analog Input Rate of Change
PATH: SETPOINTS  S6 MONITORING  ANALOG INPUT  ANALOG INPUT RATE 1(2)

ANALOG INPUT
RATE 1
A/I RATE 1
FUNCTION: Disabled
Range: Disabled, Alarm,
Latched Alarm,
MESSAGE
A/I RATE 1
RELAYS (3-7): -----
Range: Any combination of
the 3 to 7 Auxiliary
MESSAGE
A/I RATE 1 PICKUP:
10.0 μA
/hour
Range: –1000.0 to 1000.0
units in steps of 1
MESSAGE
A/I RATE 1
DELAY:
0 s
Range: 0 to 60000 s in steps
of 1
[]
The relay has fast and slow analog input rates of change. The fast rate of change
measures over the last one minute interval and detects a rapid increase or decrease in the
input quantity. The slow rate of change measures over the last one hour interval and
detects the long term trend of the input quantity. A positive rate indicates an increasing
analog input and a negative rate indicates a decreasing analog input.
The fast (slow) analog input rate of change is calculated as follows. Every second (minute)
the present analog input reading is captured and a new rate of change calculated for the
previous minute (hour). The rate is calculated using the previous sixty analog input
readings and the ‘Least Squares Approximation’ method that generates an equation for
the best line through the sample points as shown below. The rate of change is equal to the
slope of this line which is a stable quantity not unduly affected by noise or fluctuations
from the input.
7.5
7
ANALOG
INPUT 6.5
(mA)
ANALOG INPUT
ANALOG INPUT RATE
6
5.5
0
5
10
15
20
25
30
35
40
45
50
55
60
Time (seconds)
FIGURE 5–46: Analog Input Rate of Change Measurement
Note that connected analog input will still be read and displayed in A2 METERING  A/I if
both A/I RATE 1 FUNCTION and A/I RATE 2 FUNCTION are set to “Disabled”.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
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CHAPTER 5: SETPOINTS
FIGURE 5–47: Analog Input Rate of Change Logic
5.7.6
Analog Outputs
PATH: SETPOINTS  S6 MONITORING  ANALOG OUTPUTS  ANALOG OUTPUT 1(8)

ANALOG
OUTPUTS
A/O 1 SOURCE:
Disabled
Range: See Table 5–19:
Analog Output
MESSAGE
A/O 1 MIN:
–100.0 MW
Range: See Table 5–19:
Analog Output
MESSAGE
A/O 1 MAX:
100.0 MW
Range: See Table 5–19:
Analog Output
[]
There are three analog output channel types: A, B, and C (see Table 5–19: Analog Output
Parameters on page 5–111 for parameter-channel correspondence). Type A channel
ranges extend from a minimum of 0 units. Type B channels range between definite
boundaries. Type C channels include the direction of flow. The following diagram illustrates
these characteristics.
FIGURE 5–48: Analog Outputs Channel Characteristics
5 - 110
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S6 MONITORING
Each channel can be programmed to represent a parameter from the following table:
Table 5–19: Analog Output Parameters (Sheet 1 of 2)
Parameter Name
Range / Units
Step
Defaults
Min.
Channel
Type
Max.
Phase A/B/C Current
0 to 65535 Amps
1
0
2000
A
Phase A/B/C Current Angle
0 to 359° Lag
1
0
359
A
Average Current
0 to 65535 Amps
1
0
2000
A
% Of Load-To-Trip
0 to 2000%
1
0
1000
A
Neutral Current
0 to 65535 Amps
1
0
2000
A
Neutral Current Angle
0 to 359° Lag
1
0
359
A
Phase AN/BN/CN Voltage
0.00 to 655.35 kV
0.01
0.00
100.00
A
Phase AN/BN/CN Voltage Angle
0 to 359° Lag
1
0
359
A
Average Phase Voltage
0.00 to 655.35 kV
0.01
0.00
100.00
A
Line AB/BC/CA Voltage
0.00 to 655.35 kV
0.01
0.00
100.00
A
Line AB/BC/CA Voltage Angle
0 to 359° Lag
1
0
359
A
Average Line Voltage
0.00 to 655.35 kV
0.01
0.00
100.00
A
Frequency
20.00 to 65.00 Hz
0.01
47.00
63.00
B
3φ Real Power
–3000.0 to 3000.0 MW1
0.1
–100.0
100.0
C
3φ Reactive Power
–3000.0 to 3000.0 Mvar1
0.1
–100.0
100.0
C
3φ Apparent Power
0.0 to 3000.0 MVA1
0.1
0.0
100.0
A
3φ Power Factor
0.00 Lead to 0.00 Lag
0.01
0.99 Lag
0.50 Lag
B
Last Phase A/B/C Demand
0 to 65535 Amps
1
0
2000
A
Last Watt Demand
–3000.0 to 3000.0 MW1
0.1
–100.0
100.0
C
Last Var Demand
–3000.0 to 3000.0 Mvar1
0.1
–100.0
100.0
C
Last VA Demand
0.0 to 3000.0 MVA1
0.1
0.0
100.0
A
Analog Input
0 to 65535 Units
1
0
1000
A
Last Fault Distance
–327.67 to 327.67 km/mi
0.01
–50.00
50.00
C
Positive Watthours
0.0 to 6553.5 MWh1
0.1
0.0
1000.0
A
Negative Watthours
0.0 to 6553.5 MWh1
0.1
0.0
1000.0
A
Positive Varhours
0.0 to 6553.5 Mvarh1
0.1
0.0
1000.0
A
Negative Varhours
0.0 to 6553.5 Mvarh1
0.1
0.0
1000.0
A
1
Power and energy quantities auto-range to display units appropriate to power system size.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
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S6 MONITORING
CHAPTER 5: SETPOINTS
Table 5–19: Analog Output Parameters (Sheet 2 of 2)
Parameter Name
Range / Units
Step
Defaults
Min.
Channel
Type
Max.
Ground Current
0 to 65535 Amps
1
0
2000
A
Ground Current Angle
0 to 359° Lag
1
0
359
A
Polarizing Current
0 to 65535 Amps
1
0
2000
A
Polarizing Current Angle
0 to 359° Lag
1
0
359
A
φA/φB/φC Real Power
–3000.0 to 3000.0 MW1
0.1
–100.0
100.0
C
φA/φB/φC Reactive Power
–3000.0 to 3000.0 Mvar1
0.1
–100.0
100.0
C
φA/φB/φC Apparent Power
0.0 to 3000.0 MVA1
0.1
0.0
100.0
A
φA/φB/φC Power Factor
0.00 Lead to 0.00 Lag
0.01
0.99 Lag
0.50 Lag
B
Synchro Voltage
0.00 to 655.35 kV
0.01
0.00
100.00
A
Synchro Voltage Angle
0 to 359° Lag
1
0
359
A
Synchro Frequency
20.00 to 65.00 Hz
0.01
47.00
63.00
B
Frequency Decay Rate
–10.00 to 10.00 Hz/s
0.01
–0.50
0.50
C
Positive/Negative/Zero Sequence Current
0 to 65535 Amps
1
0
2000
A
Pos/Neg/Zero Sequence Current Angle
0 to 359° Lag
1
0
359
A
Positive/Negative/Zero Sequence Voltage
0.00 to 655.35 kV
0.01
0.00
100.00
A
Pos/Neg/Zero Sequence Voltage Angle
0 to 359° Lag
1
0
359
A
Synchro Voltage Difference
0.00 to 655.35 kV
0.01
0.00
100.00
A
Synchro Angle Difference
0 to 359° Lag
1
0
359
A
Synchro Frequency Difference
20.00 to 65.00 Hz
0.01
47.00
63.00
B
Sensitive Ground Current
0.00 to 655.35 A
0.01
0.00
20.00
A
Sensitive Ground Current Angle
0 to 359° Lag
1
0
359
A
Neutral Voltage
0.00 to 655.35 kV
0.01
0.00
100.00
A
Neutral Voltage Angle
0 to 359° Lag
1
0
359
A
1
Power and energy quantities auto-range to display units appropriate to power system size.
5 - 112
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
5.7.7
S6 MONITORING
Overfrequency
PATH: SETPOINTS  S6 MONITORING  OVERFREQUENCY

OVERFREQUENCY
OVERFREQUENCY
FUNCTION: Disabled
Range: Disabled, Alarm,
Latched Alarm,
MESSAGE
OVERFREQUENCY
RELAYS (3-7): -----
Range: Any combination of 3
to 7 Auxiliary relays
MESSAGE
OVERFREQUENCY
PICKUP: 60.50 Hz
Range: 20.00 to 65.00 Hz in
steps of 0.01
MESSAGE
OVERFREQUENCY
DELAY:
5.0 s
Range: 0.0 to 6000.0 s in
steps of 0.1
[]
A significant overfrequency condition, likely caused by a breaker opening and
disconnecting load from a particular generation location, can be detected and used to
quickly ramp the turbine speed back to normal. If this is not done, the over speed can lead
to a turbine trip, which would then subsequently require a turbine start up before restoring
the system. If the overfrequency turbine ramp down is successful, the system restoration
can be much quicker. The overfrequency monitoring feature of the relay can be used for
this purpose at a generating location.
The overfrequency feature is inhibited from operating unless the phase A voltage is above
30% of nominal. When the supply source is energized, the overfrequency delay timer will
only be allowed to time when the 30% threshold is exceeded and the frequency is above
the programmed pickup level. In the same way, when an overfrequency condition starts
the overfrequency delay timer and the phase A voltage falls below the 30% threshold
before the timer has expired, the element will reset without operating.
Note that the system frequency will still be measured and displayed in A2 METERING 
FREQ if both the Overfrequency and Underfrequency functions are set to “Disabled”.
FIGURE 5–49: Overfrequency Logic
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
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S6 MONITORING
5.7.8
CHAPTER 5: SETPOINTS
Equipment
Main Menu
PATH: SETPOINTS  S6 MONITORING  EQUIPMENT

EQUIPMENT
[]
MESSAGE
MESSAGE
MESSAGE
MESSAGE
MESSAGE

TRIP COUNTER
[]

ARCING CURRENT
[]

BREAKER
OPERATION
[]

COIL MONITOR 1
[]

COIL MONITOR 2
[]

VT FAILURE
[]
See page 5–114
See page 5–115
See page 5–117
See page 5–118
See page 5–118
See page 5–119
The equipment monitoring features are provided to detect failures or unusual operating
conditions of the feeder circuit breaker and the bus VTs.
Trip Counter
PATH: SETPOINTS  S6 MONITORING  EQUIPMENT  TRIP COUNTER

TRIP COUNTER
TRIP COUNTER
FUNCTION: Disabled
Range: Disabled, Alarm,
Latched Alarm,
MESSAGE
TRIP COUNTER
RELAYS (3-7): -----
Range: Any combination of 3
to 7 Auxiliary relays
MESSAGE
TRIP COUNTER
LIMIT: 10000 Trips
Range: 1 to 10000 Trips in
steps of 1
[]
When the total number of BREAKER TRIPS detected reaches the TRIP COUNTER LIMIT
setpoint, an output will occur. The BREAKER TRIPS value can be viewed in the A3
MAINTENANCE  TRIP COUNTERS menu.
5 - 114
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S6 MONITORING
FIGURE 5–50: Trip Counter Logic
Arcing Current
PATH: SETPOINTS  S6 MONITORING  EQUIPMENT  ARCING CURRENT

ARCING CURRENT
ARCING CURRENT
FUNCTION: Disabled
Range: Disabled, Alarm,
Latched Alarm,
MESSAGE
ARCING CURRENT
RELAYS (3-7): -----
Range: Any combination of 3
to 7 Auxiliary relays
MESSAGE
ARCING CURRENT
START DELAY: 32 ms
Range: 0 to 100 ms in steps
of 1
MESSAGE
TOTAL ARCING CURRENT
LIMIT: 1000 kA2-cyc
Range: 1 to 50000 kA2-cyc in
steps of 1
[]
The relay calculates an estimate of the per-phase wear on the breaker contacts by
measuring and integrating the arcing current squared passing through the contacts while
they are opening. These per-phase values are added to accumulated totals for each phase
and compared to a programmed threshold value. When the threshold is met or exceeded
in any phase, the relay can be used to generate an alarm. The threshold value can be set to
a maintenance specification provided by the breaker manufacturer.
For the TOTAL ARCING CURRENT START DELAY setpoint, enter the expected ms time delay,
from the moment a trip command is issued, until the breaker contacts will actually begin to
open. This setpoint is used by the relay to determine when to start integrating. The
integration continues for 100 ms, by which time most modern breakers will have cleared a
fault.
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CHAPTER 5: SETPOINTS
For the TOTAL ARCING CURRENT LIMIT, enter the total arcing current in kA2–cycle, at which
this feature is to cause an alarm. For example, if an alarm is desired as soon as the total
arcing current in any phase equals or exceeds 1000 kA2–cycle, enter “1000” for this
setpoint. An output will occur when the total arcing current in any phase reaches this
setpoint.
Note that the total arcing current for each phase will still be available for display under A3
MAINTENANCE  ARCING CURRENT if the ARCING CURRENT FUNCTION set to “Disabled”.
750
Trip
Command
Breaker
Contacts
Part
Arc
Extinguished
Total Area =
Breaker
Arcing
Current
(kA x cycle)
Programmable
Start Delay
100 ms
Start
Integration
Stop
Integration
ARCING.CDR
FIGURE 5–51: Arcing Current Measurement
5 - 116
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S6 MONITORING
FIGURE 5–52: Arcing Current Logic
Breaker Operation
PATH: SETPOINTS  S6 MONITORING  EQUIPMENT  BREAKER OPERATION

BREAKER
OPERATION
BRKR OPERATION
FUNCTION: Disabled
Range: Disabled, Alarm,
Latched Alarm,
Control
MESSAGE
BRKR OPERATION
RELAYS (3-7): -----
Range: Any combination of 3
to 7 Auxiliary relays
MESSAGE
BRKR OPERATION
DELAY: 0.10 s
Range: 0.03 to 1.00 s in steps
of 0.01
[]
Circuit breakers typically have both a 52a (breaker tripped = open) contact and a 52b
(breaker tripped = closed) contact. Either or both of these contacts can be connected to
the relay logic inputs, from which breaker status is detected. Interpretation of breaker
status depends on which 52 contacts are installed. See System Status LED Indicators on
page 4–3 and Breaker Functions on page 5–28 for more information on 52a (52b) contacts.
If neither 52a nor 52b contacts are installed, correct breaker operation will not be verified
and a breaker operation alarm can never occur.
A breaker operation failure can be caused by either of the following conditions if BRKR
OPERATION FUNCTION is set to “Alarm” or “Control”.
•
The breaker does not respond to a trip command within the programmed breaker
operation delay time.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
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S6 MONITORING
CHAPTER 5: SETPOINTS
•
The breaker does not respond to a close command within the programmed time.
When a breaker operation failure is declared, the selected output relays will operate, but
the Close Relay and 760 autoreclosure will be inhibited. If the 760 already has a reclosure
scheme in progress, it will be sent to lockout.
A Breaker Operation failure condition results if the breaker does not respond within the
BRKR OPERATION DELAY time. This time is a characteristic of the breaker being used.
FIGURE 5–53: Breaker Operation Logic
Coil Monitor
PATH: SETPOINTS  S6 MONITORING  EQUIPMENT  COIL MONITOR 1(2)

5 - 118
COIL MONITOR 1
COIL MON 1 NAME:
Trip Coil Monitor
Range: Any combination of
18 alphanumeric
MESSAGE
COIL MON 1
FUNCTION: Disabled
Range: Disabled, Alarm,
Latched Alarm,
Control
MESSAGE
COIL MON 1
RELAYS (3-7): -----
Range: Any combination of 3
to 7 Auxiliary relays
MESSAGE
BREAKER STATE
BYPASS: Disabled
Range: Enabled, Disabled
MESSAGE
COIL MON 1
DELAY: 5 s
Range: 5 to 100 s in steps of
1
MESSAGE
COIL MON 1
TYPE: Trip
Range: Trip, Close
[]
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S6 MONITORING
Coil Monitor 1 and 2 are programmed in this subgroup. They are two identical elements
that may be used to monitor trip or close coils. The operation of this feature is described in
Trip/Close Coil Supervision on page 3–15.
Detection of a failed circuit regardless of the breaker state (i.e. detection of a failed trip
circuit when the breaker is open) requires BRKR STATE BYPASS to be “Enabled”. Generally,
this selection will require a wiring modification of the breaker, as detailed in Trip/Close Coil
Supervision on page 3–15.
Upon detection of failure in the Trip/Close coil circuit the "Trip/Close Coil Monitor" output is
latched when set for the Alarm function. Operator intervention is required for the reset.
Note
NOTE
FIGURE 5–54: Coil Monitor Logic
VT Failure
PATH: SETPOINTS  S6 MONITORING  EQUIPMENT  VT FAILURE

VT FAILURE
VT FAILURE
FUNCTION: Disabled
Range: Disabled, Alarm,
Latched Alarm,
MESSAGE
VT FAILURE
RELAYS (3-7): -----
Range: Any combination of 3
to 7 Auxiliary relays
MESSAGE
VT FAILURE
DELAY: 10 s
Range: 0 to 60000 s in steps
of 1
[]
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
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CHAPTER 5: SETPOINTS
The 750/760 detects a VT fuse failure when there are significant levels of negative
sequence voltage without correspondingly significant levels of negative sequence current
measured at the output CTs. Also, if there is not a significant amount of positive sequence
voltage when there is positive sequence current then it could indicate that all the VT fuses
have been pulled or the VTs have been racked out.
FIGURE 5–55: VT Failure Logic
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750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
5.7.9
S6 MONITORING
Pulse Output
PATH: SETPOINTS  S6 MONITORING  PULSED OUTPUT

PULSED OUTPUT
PULSED OUTPUT
FUNCTION: Disabled
Range: Disabled, Alarm,
Latched Alarm,
MESSAGE
POS WATTHOURS PULSED
RELAYS (3-7): -----
Range: Any combination of
the 3 to 7 Auxiliary
MESSAGE
POS WATTHOURS PULSED
INTERVAL: 10.0 MWh
Range: 0.0 to 6553.5 MWh in
steps of 0.1 (auto-
MESSAGE
NEG WATTHOURS PULSED
RELAYS (3-7): -----
Range: Any combination of
the 3 to 7 Auxiliary
MESSAGE
NEG WATTHOURS PULSED
INTERVAL: 10.0 MWh
Range: 0.0 to 6553.5 MWh in
steps of 0.1 (auto-
MESSAGE
POS VARHOURS PULSED
RELAYS (3-7): -----
Range: Any combination of
the 3 to 7 Auxiliary
MESSAGE
POS VARHOURS PULSED
INTERVAL: 10.0 Mvarh
Range: 0.0 to 6553.5 Mvarh
in steps of 0.1 (auto-
MESSAGE
NEG VARHOURS PULSED
RELAYS (3-7): -----
Range: Any combination of
the 3 to 7 Auxiliary
MESSAGE
NEG VARHOURS PULSED
INTERVAL: 10.0 Mvarh
Range: 0.0 to 6553.5 Mvarh
in steps of 0.1 (auto-
[]
The 750/760 can operate selected auxiliary relays after an adjustable interval for the
quantities shown above. Pulses occur at the end of each programmed interval. Upon
power up of the relay the Pulse Output function, if enabled, will continue from where it was
at loss of control power. For example, if control power is removed when the positive
watthours actual value is 16.0 MWh, when control power is re-applied a pulse will occur at
26 MWh if the interval is set to 10.0 MWh.
Note that the Output relay(s) used for this element must be set to “Self-Resetting” under S4
OUTPUT RELAYS. The pulses will consist of a one second on time and a one second off time.
This feature should be programmed such that no more than one pulse per two seconds will
be required or the pulsing will lag behind the interval activation.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
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S6 MONITORING
CHAPTER 5: SETPOINTS
FIGURE 5–56: Pulsed Output Logic
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CHAPTER 5: SETPOINTS
5.8
S7 CONTROL
S7 Control
5.8.1
Setpoint Groups
PATH: SETPOINTS  S7 CONTROL  SETPOINT GROUPS

SETPOINT
GROUPS
ACTIVE SETPOINT
GROUP: Group 1
Range: Group 1, Group 2,
Group 3, Group 4
MESSAGE
EDIT SETPOINT GROUP:
Active Group
Range: Group 1, Group 2,
Group 3, Group 4,
MESSAGE
OPEN BREAKER
INHIBIT: Disabled
Range: Enabled, Disabled
MESSAGE
OVERCURRENT PICKUP
INHIBIT: Disabled
Range: Enabled, Disabled
MESSAGE
OVERVOLTAGE PICKUP
INHIBIT: Disabled
Range: Enabled, Disabled
MESSAGE
UNDERVOLTAGE PICKUP
INHIBIT: Disabled
Range: Enabled, Disabled
MESSAGE
UNDERFREQ PICKUP
INHIBIT: Disabled
Range: Enabled, Disabled
[]
All setpoints contained under the S5 PROTECTION setpoints page are reproduced in four
groups, identified as Groups 1, 2, 3, and 4. These multiple setpoints provide the capability
of both automatic and manual changes to protection settings for different operating
situations. Automatic (adaptive) protection setpoint adjustment is available to change
settings when the power system configuration is altered. By monitoring the state of a bus
tie breaker on the bus connected to the associated feeder breaker, different settings may
be used depending the tie breaker state. Automatic group selection can be initiated by use
of a logic input. The manual adjustment capability is available for those users who use
different settings for different seasons of the year. Manual group selection can be initiated
from the keypad or via communications.
In order to allow the display and editing of one group while another group is used for
protection, two operating states have been assigned to setpoint groups. The “Active
Group” is used for protection, and is indicated by the appropriate faceplate LED indicator
being turned on continuously. The 'Edit' group is displayed and may be used to alter
protection settings. It is indicated by the appropriate faceplate LED indicator being flashed.
If a single group is selected to be both the Active and Edit group, the appropriate indicator
is on continuously.
The setpoint group to be edited is selected through the EDIT SETPOINT GROUP setpoint.
Group 1 is the default for the “Active Group” and will be used unless another group is
requested to become active. The active group can be selected with the ACTIVE SETPOINT
GROUP setpoint or by logic input. If there is a conflict in the selection of the active group,
between a setpoint and logic input, or between two logic inputs, the higher numbered
group will be made active. For example, if the logic inputs for Group 2, 3, and 4 are all
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
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S7 CONTROL
CHAPTER 5: SETPOINTS
asserted the relay would use Group 4. If the logic input for Group 4 then becomes deasserted, the relay will use Group 3. Any change from the default Group 1 will be stored in
the event recorder.
In some application conditions, the user may require that the relay will not change from
the present active group. This prevention of a setpoint group change can be applied when
any of the overcurrent (phase, neutral, ground, sensitive ground, or negative sequence),
overvoltage, bus or line undervoltage, or underfrequency elements are picked-up.
Note
NOTE
Pickup of a protection element is possible when set to any value except “Disabled”, so
elements not used to perform tripping can also inhibit setpoint changes. A setpoint change
can also be prevented if the breaker is open, so that a fault detected before a reclosure will
not cause a group change while the breaker is open.
FIGURE 5–57: Setpoint Control (1 of 3)
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S7 CONTROL
FIGURE 5–58: Setpoint Control (2 of 3)
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
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S7 CONTROL
CHAPTER 5: SETPOINTS
FIGURE 5–59: Setpoint Control (3 of 3)
Each setpoint group includes the selection of Auxiliary Output Relays 3 to 7 that can be
operated by the protection features. As these relays are hard-wired to external equipment,
the selection should only be changed from that in setpoint Group 1 with considerable care.
5 - 126
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CHAPTER 5: SETPOINTS
5.8.2
S7 CONTROL
Synchrocheck
PATH: SETPOINTS  S7 CONTROL  SYNCHROCHECK

SYNCHROCHECK
SYNCHROCHECK
FUNCTION: Disabled
Range: Disabled, Alarm,
Latched Alarm,
MESSAGE
SYNCHROCHECK
RELAYS (3-7): -----
Range: Any combination of 3
to 7 Auxiliary relays
MESSAGE
DEAD SOURCE
PERMISSIVE: Off
Range: Off, DB&DL, LL&DB,
DL&LB, DL|DB,
MESSAGE
DEAD BUS MAX
VOLTAGE: 0.20 x VT
Range: 0.00 to 1.25 x VT in
steps of 0.01
MESSAGE
DEAD LINE MAX
VOLTAGE: 0.20 x VT
Range: 0.00 to 1.25 x VT in
steps of 0.01
MESSAGE
LIVE BUS MIN
VOLTAGE: 0.80 x VT
Range: 0.00 to 1.25 x VT in
steps of 0.01
MESSAGE
LIVE LINE MIN
VOLTAGE: 0.80 x VT
Range: 0.00 to 1.25 x VT in
steps of 0.01
MESSAGE
MAX VOLTAGE
DIFFERENCE: 2.00 kV
Range: 0.01 to 100.00 kV in
steps of 0.01
MESSAGE
MAX ANGLE
DIFFERENCE: 24°
Range: 0 to 100° in steps of 1
MESSAGE
MAX FREQ
DIFFERENCE: 2.00 Hz
Range: 0.00 to 5.00 Hz in
steps of 0.01
[]
If a breaker can be a paralleling point between two generation sources, it is common
practice to automatically perform a check to ensure the sources are within allowable
voltage limits before permitting closing of the breaker. Synchrocheck provides this feature
by checking that the bus and line input voltages are within the programmed differentials of
voltage magnitude, phase angle position, and frequency. If this feature is enabled, the
check will be performed before either manual close or automatic reclose signals can
operate the Close Output Relay. The synchrocheck programming can allow for permitted
closing if either or both of the sources are de-energized. The measured line input voltage
magnitude and frequency are also made available as actual values under A2 METERING
 SYNCHRO VOLTAGE. The frequency is only displayed if the voltage at the relay terminals
is at least 10.0 V. The differential values of angle, magnitude, and frequency are also made
available for display.
With a Delta connected Bus VT, Phase to Neutral voltages cannot be determined. Thus
Synchrocheck cannot be used with a Delta connected Bus VT and a Wye connected Line
VT.
The DEAD SOURCE PERMISSIVE setpoint selects the combination of dead and live sources
that bypass synchrocheck and permit a breaker closure. The voltage levels that determine
whether a source is dead or live are configurable in the four setpoints following this one.
The DEAD SOURCE PERMISSIVE range is as follows:
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
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S7 CONTROL
CHAPTER 5: SETPOINTS
“Off”: Dead source permissive is disabled.
“DB&DL”: Dead Bus AND Dead Line.
“LL&DB”: Live Line AND Dead Bus.
“DL&LB”: Dead Line AND Live Bus.
“DL|DB”: Dead Line OR Dead Bus.
“DLxDB”: Dead Line XOR Dead Bus (one source is Dead and one is Live).
For the DEAD BUS MAX VOLTAGE and DEAD LINE MAX VOLTAGE setpoints, enter the voltage
magnitude as a fraction of the bus or line VT input nominal voltage. If the bus or line
voltage falls below these values, the single bus/line voltage input used for synchrocheck
will be considered ‘dead’, or de-energized.
For the LIVE BUS MIN VOLTAGE and LIVE LINE MIN VOLTAGE setpoints, enter the voltage
magnitude as a fraction of the bus or line VT input nominal voltage. If the bus or line
voltage rises above the respective setting, the single bus or line voltage input used for
synchrocheck is established as ‘live’, or energized.
The voltage, angular, and frequency differences of the primary systems are also entered
through the MAX VOLTAGE DIFFERENCE, MAX ANGLE DIFFERENCE, and MAX FREQ
DIFFERENCE setpoints, respectively. A voltage magnitude, angular, or frequency differential
on the two input voltages below the values entered here is within the permissible limit for
synchronism.
FIGURE 5–60: Synchrocheck Logic
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750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
5.8.3
S7 CONTROL
Manual Close Blocking
PATH: SETPOINTS  S7 CONTROL  MANUAL CLOSE

MANUAL CLOSE
MANUAL CLOSE
FUNCTION: Disabled
Range: Disabled, Alarm,
Latched Alarm,
MESSAGE
MANUAL CLOSE
RELAYS (3-7): -----
Range: Any combination of 3
to 7 Auxiliary relays
MESSAGE
MANUAL CLOSE BLOCK
TIME:
5 s
Range: 1 to 1000 s in steps
of 1
MESSAGE
PHASE INST OC 1
BLOCKING: Disabled
Range: Disabled, Enabled
MESSAGE
NEUTRAL INST OC 1
BLOCKING: Disabled
Range: Disabled, Enabled
MESSAGE
GND INST OC
BLOCKING: Disabled
Range: Disabled, Enabled
MESSAGE
SENSTV GND INST OC
BLOCKING: Disabled
Range: Disabled, Enabled
MESSAGE
NEG SEQ INST OC
BLOCKING: Disabled
Range: Disabled, Enabled
MESSAGE
PHASE TIME OC 1
RAISED PICKUP:
0%
Range: 0 to 100% in steps of
1
MESSAGE
NEUTRAL TIME OC 1
RAISED PICKUP:
0%
Range: 0 to 100% in steps of
1
MESSAGE
GND TIME OC
RAISED PICKUP:
0%
Range: 0 to 100% in steps of
1
MESSAGE
SENSTV GND TIME OC
RAISED PICKUP:
0%
Range: 0 to 100% in steps of
1
MESSAGE
NEG SEQ TIME OC
RAISED PICKUP:
Range: 0 to 100% in steps of
1
MESSAGE
SELECT SETPOINT
GROUP: Active Group
[]
0%
Range: Group 1, Group 2,
Group 3, Group 4,
The 750/760 can be programmed to block instantaneous overcurrent elements and raise
the pickup level of time overcurrent elements when a manual breaker close is performed.
This prevents optimally set overcurrent elements from erroneously operating on startup
due to inrush currents.
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CHAPTER 5: SETPOINTS
FIGURE 5–61: Manual Close Blocking Logic
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5.8.4
S7 CONTROL
Cold Load Pickup
PATH: SETPOINTS  S7 CONTROL  COLD LOAD PICKUP

COLD LOAD
PICKUP
COLD LOAD PICKUP
FUNCTION: Disabled
Range: Disabled, Alarm,
Latched Alarm,
MESSAGE
COLD LOAD PICKUP
RELAYS (3-7): -----
Range: Any combination of 3
to 7 Auxiliary relays
MESSAGE
OUTAGE TIME BEFORE
COLD LOAD: 100 min
Range: 1 to 1000 min. in
steps of 1
MESSAGE
COLD LOAD PICKUP
BLOCK TIME:
5 s
Range: 1 to 1000 s in steps
of 1
MESSAGE
PHASE INST OC 1
BLOCKING: Disabled
Range: Disabled, Enabled
MESSAGE
NEUTRAL INST OC 1
BLOCKING: Disabled
Range: Disabled, Enabled
MESSAGE
GND INST OC
BLOCKING: Disabled
Range: Disabled, Enabled
MESSAGE
SENSTV GND INST OC
BLOCKING: Disabled
Range: Disabled, Enabled
MESSAGE
NEG SEQ INST OC
BLOCKING: Disabled
Range: Disabled, Enabled
MESSAGE
PHASE TIME OC 1
RAISED PICKUP:
0%
Range: 0 to 100% in steps of
1
MESSAGE
NEUTRAL TIME OC 1
RAISED PICKUP:
0%
Range: 0 to 100% in steps of
1
MESSAGE
GND TIME OC
RAISED PICKUP:
0%
Range: 0 to 100% in steps of
1
MESSAGE
SENSTV GND TIME OC
RAISED PICKUP:
0%
Range: 0 to 100% in steps of
1
MESSAGE
NEG SEQ TIME OC
RAISED PICKUP:
Range: 0 to 100% in steps of
1
MESSAGE
SELECT SETPOINT
GROUP: Active Group
[]
0%
Range: Group 1, Group 2,
Group 3, Group 4,
The 750/760 can be programmed to block instantaneous overcurrent elements and to
raise the pickup level of time overcurrent elements when a cold load condition is detected.
Under normal operating conditions, the actual load on a feeder is less than the maximum
connected load, since not all consumers require maximum load at the same time. When
such a feeder is closed after a prolonged outage, the feeder inrush and motor accelerating
current may be above some protection settings. Without historical data on a particular
feeder, some utilities assume an initial cold load current of about 500% of normal load,
decaying to 300% after one second, 200% after 2 seconds, and 150% after 3 seconds. See
the following figure for details.
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Current (% of normal)
500
400
300
NORMAL TRIP SETTING
200
X
PICKUP
PICKUP
100
OUTAGE
0
-1
0
1
2
3
4
5
6
Time (seconds)
LOAD ENERGIZED
FIGURE 5–62: Cold Load Pickup
A cold load condition is initiated and overcurrent settings are altered when all phase
currents drop below 5% of the nominal current for an amount of time greater than the
OUTAGE TIME BEFORE COLD LOAD setpoint. The cold load condition can also be
immediately initiated by asserting the logic input function ‘Cold Load Pickup’. Overcurrent
settings are returned to normal after any phase current is restored to greater than 10% of
nominal and then a timer of duration equal to COLD LOAD PICKUP BLOCK TIME expires.
FIGURE 5–63: Cold Load Pickup Logic
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5.8.5
S7 CONTROL
Undervoltage Restoration
PATH: SETPOINTS  S7 CONTROL  UNDERVOLTAGE RESTORATION

UNDERVOLTAGE
RESTORATION
UNDERVOLT RESTORE
FUNCTION: Disabled
Range: Disabled, Alarm,
Latched Alarm,
MESSAGE
UNDERVOLT RESTORE
RELAYS (3-7): -----
Range: Any combination of 3
to 7 Auxiliary relays
MESSAGE
UNDERVOLT RESTORE
SOURCE: Bus
Range: Bus, Line
MESSAGE
PHASES REQUIRED FOR
OPERATION: All Three
Range: Any One, Any Two, All
Three.
MESSAGE
UNDERVOLT RESTORE
MIN VOLTS: 0.90 x VT
Range: 0.00 to 1.25 x VT in
steps of 0.01
MESSAGE
UNDERVOLT RESTORE
DELAY:
10 s
Range: 0 to 10000 s in steps
of 1
MESSAGE
INCOMPLETE SEQUENCE
TIME:
100 min
Range: 1 to 10000 min. in
steps of 1
[]
This scheme is initiated by either the Bus or Line Undervoltage elements. After the feeder
breaker has been tripped, it will display the UVolt Restore Init message (if the function is
set to “Alarm” or “Latched Alarm”) and operate any programmed output relays. Once
initiated it will monitor the bus voltage level, and send a close command to the Close Relay
when the voltage on the programmed number of phases has risen above the programmed
level for a selected time interval. The scheme is equipped with an incomplete sequence
timer, so it will not remain initiated for an indeterminate time, but will automatically reset if
the voltage does not recover during the programmed interval. Initiation of the scheme can
be canceled by a reset command. Cancellation of a previous initiation is only effective if the
voltage is above the restoration threshold. A “Block Restoration” logic input is available to
prevent both initiation and operation. It is recommended that if automatic undervoltage
restoration is to be used, that the cold load pickup feature is also enabled, to prevent the
breaker from tripping shortly after it is automatically closed.
The PHASES REQUIRED FOR OPERATION setpoint is seen only if UNDERVOLT RESTORE SOURCE
is “Bus”.
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FIGURE 5–64: Undervoltage Restoration Logic
5.8.6
Underfrequency Restore
PATH: SETPOINTS  S7 CONTROL  UNDERFREQUENCY RESTORATION

UNDERFREQUENCY
RESTORATION
UNDERFREQ RESTORE
FUNCTION: Disabled
Range: Disabled, Alarm,
Latched Alarm,
MESSAGE
UNDERFREQ RESTORE
RELAYS (3-7): -----
Range: Any combination of 3
to 7 Auxiliary relays
MESSAGE
UNDERFREQ RESTORE
MIN VOLTS: 0.90 x VT
Range: 0.00 to 1.25 x VT in
steps of 0.01
MESSAGE
UNDERFREQ RESTORE
MIN FREQ: 59.90 Hz
Range: 20.00 to 65.00 Hz in
steps of 0.01
MESSAGE
UNDERFREQ RESTORE
DELAY:
10 s
Range: 0 to 10000 s in steps
of 1
MESSAGE
INCOMPLETE SEQUENCE
TIME:
100 min
Range: 1 to 10000 min. in
steps of 1
[]
This scheme is initiated by a trip of either the Bus Underfrequency elements. After the
feeder breaker has been tripped, it will display the UFreq Restore Init and operate any
programmed output relays. Once initiated it will monitor the bus voltage level and
frequency, and send a close command to the Close Relay when the voltage on the phase A
input has risen above the programmed minimum level and frequency for a selected time
interval. The scheme is equipped with an incomplete sequence timer, so it will not remain
initiated for an indeterminate time, but will automatically reset if the voltage does not
recover during the programmed interval. Initiation of the scheme can be canceled by a
reset command. Cancellation of a previous initiation is only effective if the voltage and
frequency are above the restoration thresholds. A “Block Restoration” logic input is
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available to prevent both initiation and operation. It is recommended that if automatic
underfrequency restoration is to be used, that the cold load pickup feature is also enabled,
to prevent the breaker from tripping shortly after it is automatically closed.
FIGURE 5–65: Underfrequency Restoration Logic
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5.8.7
CHAPTER 5: SETPOINTS
Transfer Scheme
Settings
PATH: SETPOINTS  S7 CONTROL  TRANSFER

TRANSFER
TRANSFER FUNCTION:
Disabled
Range: Disabled, Incomer 1,
Incomer 2, Bus Tie
MESSAGE
BUS TRANSFER LOGIC:
Scheme 1
Range: Scheme1, Scheme 2
MESSAGE
TRANSFER DELAY THIS
SOURCE: 1.0 s
Range: 0.0 to 10.0 s in steps
of 0.1
MESSAGE
TRANSFER DELAY OTHER
SOURCE: 3.0 s
Range: 0.0 to 10.0 s in steps
of 0.1
MESSAGE
BLOCK TRIP ON DOUBLE
LOSS: Disabled
Range: Disabled, Enabled
MESSAGE
TRANSFER DELAY SELECT
TO TRIP: 0.0 s
Range: 0.0 to 10.0 s in steps
of 0.1
MESSAGE
TRANSFER READY
RELAY 3: Disabled
Range: Disabled, Enabled
[]
The Transfer scheme is intended for application to a set of three circuit breakers on a
Main-Tie-Main arrangement, two of which (Incomers 1 and 2) connect sources of electrical
energy to two busses which could be paralleled through the Bus Tie breaker. The normal
system configuration is with both incoming breakers closed and the bus tie breaker open.
The transfer scheme implemented in the 750/760 is known as Open Transfer, with an
“Open before Close” operation sequence; this means that the faulty incomer is removed
from service before the tie breaker is closed. FIGURE 5–66: Transfer Scheme One Line
Diagram on page 5–146 shows this arrangement. The equipment designations on this
drawing will be used in the discussion.
The transfer scheme minimizes the effect of outages on one of the incoming supplies by
opening the incoming breaker connected to that supply, and then re-energizing the dead
bus by closing the bus tie breaker to transfer the dead bus to the live source. To protect
against damage to motors connected to the dead bus, the bus tie breaker is not allowed to
close, after a transfer has been initiated, until the decaying (residual) voltage on the bus
has been reduced to a safe level.
After the lost source has been reestablished, the scheme provides three methods to
restore the system to normal configuration. Two methods are manual and one is
automatic.
•
Manual Method 1, when the sources cannot be synchronized:
The bus tie breaker must be manually opened before the open incomer can be
manually closed. In this procedure the incomer will only be allowed to close if the
incoming source (Line VT) voltage is above a live threshold and the load (Bus VT)
voltage is below a dead threshold value.
•
5 - 136
Manual Method 2, when the sources are synchronized with synchrocheck supervision:
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
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It is possible to manually close the open incomer to parallel all three breakers. The
scheme will then automatically open a breaker that had been previously selected to
trip if all three breakers become closed. If the bus tie breaker is ‘Selected To Trip’, it will
be tripped by the system and will open.
•
Automatic method:
The automatic method of returning the system to normal configuration uses the
undervoltage tripped portion of the restoration scheme. Undervoltage restoration will
work only if the relay has issued a trip signal during the tripping process of the faulty
incomer. The required trip signal is not issued if the Line Undervoltage 4 Element (27-4)
is set for Alarm or Control.
Note
NOTE
If Undervoltage Restoration is used to restore the system, Line Undervoltage 4 (27-4) must
be set to Trip, instead of Control or Alarm, and the feature Block Trip on Double Loss will not
function properly.
In addition to the relay required for each of the three circuit breakers, the system requires
two manual operated control switches or equivalent devices.
1.
Device 43/10: Select to Trip Control Switch.
This is a three-position switch with at least three contacts, one for each relay, which
obey the following table:
Contact No.
Position
1: Incomer 1
1
2
3
2: Incomer 2
3: Tie Breaker
X
X
X
It is required to connect one contact to each relay. This switch selects the breaker that
will trip in the eventuality that all three breakers become closed, to prevent the two
incoming systems to remain connected in parallel. The contacts can be either
normally-open or normally-closed, depending on the asserted logic of the
corresponding logic input used for this purpose.
Discussion: Typically this switch is always asserted, even when the selected breaker is
open, and the other two breakers are closed. In this mode, the switch energizes the
Trip contact and activates the Trip LED on the relay front panel. To avoid this, a breaker
52A contact can be wired in series with the 43/10 switch.
Advantage: Connecting the breaker 52A contact in series with this switch will prevent
energization of the Trip contact and turning of Trip LED "ON". When the breaker is
opened, the 52A contact stays open and prevents asserting of the logic input when
the switch is positioned to the relay with the open breaker.
Disadvantage: In certain conditions, connecting the breaker 52A contact in series
with this switch can facilitate accidental momentary breaker closing (i.e., breaker
bumping) due to human error, while in the transfer scheme the other two breakers are
still closed. When this switch is connected to the relay without a 52A contact in series,
breaker closing is inhibited internally.
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2.
Device 43/83: Block - Enable Transfer.
This is an optional two-position switch or equivalent device, with at least three
contacts (one for each relay) that obeys the following table:
Contact No.
Position
1: Block
1: Incomer 1
X
2: Incomer 2
X
3: Tie Breaker
X
2: Enable
One contact must be connected to each relay. This switch selects either the transfer
scheme in Block position or the transfer scheme in Enable position. The contacts are
either normally-open or normally-closed, depending on the asserted logic of the
corresponding logic input used for this purpose.
When Device 43/83 is in the “Block” position, the contact connected to 750/760 places
the corresponding logic input in the “Asserted Position”, blocking the operation of the
Auto Transfer Scheme. At this point in time, a system condition that might trip one of
the incomers will not initiate the transfer sequence.
Because a relay is required on the bus tie breaker, it allows bus-splitting operation. This is
accomplished by setting the time overcurrent elements in the relay on the bus tie breaker
to trip faster than the incomers, opening the bus tie before an incomer when operating
from only one source.
The 750/760 relay offers a selection of two Transfer Schemes for Bus Transfer Logic:
Scheme 1 and Scheme 2. Each scheme can be used in conjunction with both non-drawout
and drawout switchgear. Drawout switchgear designs can make use of an auxiliary switch
that confirms that the monitored breaker is racked in and in the “Connected” position, and
therefore ready for operation. Fixed breaker installations can use contacts on the
associated isolating disconnect switches (if available) for this purpose.
Either of the selected Auto Transfer Schemes can be applied to any one of the following
systems: The scheme design can be applied to:
5 - 138
1.
Substations with no signaling from upstream equipment. The initiating signal
is generated by one of the two 750/760 relays protecting the Incomers.
2.
Substations with an upstream circuit breaker equipped with a trip signal
(Device 94). In addition to the local 750/760 relays, the signal triggering the
transfer sequence can be originated from the upstream protection. An
auxiliary contact from the tripping device (94) is fed to one of the 750/760
logic inputs, which is programmed as “Source Trip”.
3.
Substations with a source transformer and transformer fault detection signal
(Device 86T). In addition to the local 750/760 relays, the signal triggering the
transfer sequence can be originated from the protection of the upstream
transformers. An auxiliary contact from the tripping device (86T) is fed to one
of the 750/760 logic inputs, which is programmed as “Lockout Trip”.
4.
Both 2 and 3 above.
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The only differences in implementing the transfer scheme among the configurations
presented above is by connecting additional logic signals to the relay when available and
by placing a jumper on one logic input if the breaker is non-drawout and has no
disconnect auxiliary switches.
Besides the setpoints and logic incorporated into the transfer scheme, the relays make use
of:
• Some or all of the logic inputs,
• Phase instantaneous overcurrent (Device 50P-1 or 2),
• Neutral overcurrent (Device 50N-1 or 2),
• Both line undervoltage elements (Devices 27-3 and 27-4),
• The synchrocheck (Device 25) features of the relays.
Schematic diagrams of the DC connections required by an both Scheme 1 and Scheme 2
are presented in the schematics on pages –148 to –149. Logic for each relay of the scheme
is presented in the logic diagrams on pages –150 to –152 for Scheme 1 and pages –154 to
–156 for Scheme 2. Connections that are not required for configurations other than
Configuration 4 above are indicated as “optional” on the schematic diagrams.
Note
NOTE
1.
All connections for AC voltage and current are outlined in Chapter 3.
2.
The scheme design requires that the AC voltage connections for ‘Line’ and ‘Bus’
sources on the incomer relays be in accordance with FIGURE 5–66: Transfer Scheme
One Line Diagram on page 5–146 regardless of configuration.
3.
The connection of AC voltage to the relay on the bus tie does not affect operation of
the scheme, but the connection to the line voltage input terminals must be a phasephase voltage.
For the following discussion assume that Source 1 is the failed side. Identical logic with all
1s and 2s interchanged applies to Relay 2 for a loss of Source 2. A transfer (trip of Incomer
1 followed by Bus Tie closing) from Relay 1 can be initiated by:
• Operation of transformer 1 lockout relay (Device 86T1).
• Operation of the Source 1 breaker auxiliary trip device (Device 94-1).
• Time out of Relay 1 line voltage inverse time undervoltage element (Device 27-4)
caused by low voltage on Source 1.
A transfer initiation is blocked if:
• Any of the three breakers is not in the connected state.
• Incoming Breaker 2 (which is to become the new source) is presently open.
• Devices 50P-1 or 2, or 50N-1 or 2, detect an overcurrent condition on bus 1, to
prevent a faulted bus from being transferred to a healthy source.
• The line definite time Undervoltage element (Device 27-3) on Source 2 is operated,
indicating low voltage on the other source.
If any one of the above conditions is present, the TRANSFER NOT READY message will
be displayed by the relays.
Once a condition has caused the 750/760 relay on Incomer 1 (Relay 1) to initiate a transfer,
the following sequence of events will take place:
1.
Relay 1 trips Incomer 1 breaker (Breaker 1).
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CHAPTER 5: SETPOINTS
2.
Relay 1 issues a close signal to the 750/760 on the Bus Tie breaker (Relay 3).
3.
The trip command is maintained until Relay 1 determines that Breaker 1 has
opened.
4.
When Relay 3 receives the close command from Relay 1, it is captured and
retained until either the Bus Tie breaker (Breaker 3) closes or the Block
Transfer logic input is received.
5.
Relay 3 is inhibited from initiating a close command to Breaker 3 by its
synchrocheck element.
6.
Synchrocheck monitors the voltage on the disconnected bus, and provides
the bus decayed (residual) voltage permission-to-close when the Bus 1
voltage decays to the preset level.
The three breakers are under prevent-parallel checking whenever the transfer scheme is
operational. If a third breaker is closed when the other two breakers are already closed, the
scheme will automatically trip the breaker selected by Switch 43/10, ‘Selected To Trip’.
Additional Setpoints for Transfer Scheme
The following settings are required for the proper operation of the Auto Transfer Scheme:
• Logic inputs definition: Refer to Logic Inputs Setup on page 5–27 for additional
information. In this step, the Logic Inputs are identified and the asserted logic is
defined.
• Logic inputs for breaker functions: Refer to Breaker Functions on page 5–28 for
additional information. Since the scheme monitors the status of the breaker, it is
necessary to set a digital input for that purpose.
• Logic inputs for control functions: Refer to Control Functions on page 5–30 for
additional information. These settings are required to define how the relay will
receive external commands.
• Logic inputs for transfer functions: Refer to Transfer Functions on page 5–35 for
additional information. These are the settings that relate the Logic Inputs defined
above, with their specific functions within the scheme.
Note
NOTE
If the bus transfer feature is required, all logic inputs functions necessary for the
operation of this scheme must be assigned to contact inputs before any other
functions. This will ensure there are no conflicts.
• Line Undervoltage 3 (27-3): Required to block transfer initiation from the other
relay, as the other source is experiencing low voltage. Also, Device 27-3 is enabled
by instantaneous overcurrent to block transfer initiation.
• Line Undervoltage 4 (27-4): Required to initiate a transfer on loss-of-source.
• Instantaneous phase (50P1 or 50P2), and neutral overcurrent (50N1 or 50N2). Fault
detectors, used as inputs to the transfer scheme logic, to block a transfer while a
fault is present on the load side of the breaker.
• Synchrocheck (25) to supervise the initial closing of the incoming breakers, to
provide synchronism check supervision when paralleling the busses, or measure
the residual voltage on the bus that has lost source.
• Transfer function: Specific settings related to the Auto Transfer Scheme
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Note
NOTE
Output Relays 4-7 Auxiliary (all breakers): These output relays are used to implement
the transfer scheme, and must therefore not be operated by any other feature of the
relay. These relays must be programmed to have a no operated state of “Deenergized” with the output type as “Self-reset”. These are the default settings.
Setting the Transfer Scheme
If the transfer scheme is not required, set TRANSFER FUNCTION to “Disabled”. If not disabled,
this setpoint assigns the function of the associated circuit breaker to the relay. This
selection programs the relay to use the logic required by each of the three breakers. Select
“Incomer 1” or “Incomer 2” for this setpoint if the relay is associated with the breaker to be
used as Incomer 1 or 2 respectively. Select “Bus Tie” if the relay is associated with the bus
tie breaker.
The BUS TRANSFER LOGIC setpoint selects the desired transfer scheme: Scheme 1, or
Scheme 2. The default setting of this setpoint is set to “Scheme 1”. The 750 relay provides
two different transfer scheme: Scheme 1 and Scheme 2. Refer to the related section in this
chapter for scheme description and logic diagrams.
Note
NOTE
The setting for the BUS TRANSFER LOGIC for all three relays performing bus auto
transfer must be set to the same scheme number, or else the transfer will not be
performed correctly.
The TRANSFER DELAY THIS SOURCE time establishes an interval from the reset of an
operated instantaneous overcurrent element on this source, during which the line
instantaneous undervoltage element (Device 27-3) is allowed to block a transfer. The
TRANSFER DELAY OTHER SOURCE delay time prevents transfers that could otherwise be
caused by a non-simultaneous return of source voltages after a loss of both sources. It
establishes an interval from the return of the first source to the return of the second source
during which a transfer cannot be initiated.
The BLOCK TRIP ON DOUBLE LOSS setpoint selects the required scheme operation in the
event of a simultaneous loss of both Source 1 and Source 2. If it is desired to have both of
the Incomers trip on timed undervoltage when this occurs, select “Disabled”. If it is desired
to prevent the Incomers from tripping on timed undervoltage when this occurs, select
“Enabled”. With either selection a transfer-initiated close of the bus tie breaker is not
allowed.
The TRANSFER DELAY SELECT TO TRIP setpoint provides selection of time delay to be
applied to the 750/760 trip output relay, and trip the “Selected to Trip” breaker, such as
when all three breakers are detected closed. The following conditions must be met to start
the TRANSFER DELAY SELECT TO TRIP setpoint provides selection of time delay to be
applied to the 750/760 trip output relay, and trip the “Selected to Trip” breaker, such as
when all three breakers are detected closed. The following conditions must be met to start
the TRANSFER DELAY SELECT TO TRIP time delay:
Incomer 1 (Incomer 2)
•
Incomer 1 breaker connected
•
Incomer 2 breaker closed
•
Tie-breaker connected
•
Tie-breaker closed
•
Selected to Trip input set to Incomer 1 breaker
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•
Transfer scheme not blocked
Tie-Breaker (750-3)
•
Incomer 1 breaker closed
•
Incomer 2 breaker closed
•
Tie-breaker connected
•
Tie-breaker closed
•
Selected to Trip input set to Tie-breaker
•
Transfer scheme not blocked
The TRANSFER READY RELAY (3) setpoint selects the setting “Enabled” to operate auxiliary
output relay # 3 upon transfer ready conditions, or “Disabled” when such operation is not
required.
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Practical scheme for overall TRANSFER READY indication can be developed by selecting
the setting “Enabled” from all three 750 relays to operate the aux. output relay # 3, and
wiring the relays in series with a DC source to turn on a single light bulb (“white light”). The
aux. 3 output relay from each 750 relay can be wired to turn on an individual light bulb as
well. Refer to the DC ratings of the aux. output relays before wiring to a DC source.
The TRANSFER READY flag will be high, if all of the following conditions are met:
Incomer 1: 750/760-1 (Incomer 2: 750/760-2) relays:
•
The “Incomer 1” setting selected under TRANSFER FUNCTION setpoint
•
The transfer scheme is not blocked from “Block Transfer” input
•
Bus Tie Breaker is open (52a/b contacts)
•
Incomer 1 breaker is connected and closed
•
Incomer 2 breaker is connected and closed
•
No transformer lockout, or source trip is present
•
No undervoltage is detected on any of the two sources
Tie-breaker 750/760 relay:
Note
NOTE
•
The “Bus Tie” setting is selected under TRANSFER FUNCTION setpoint
•
The transfer is not blocked from “Block Transfer” input
•
Bus Tie Breaker is connected and open (52a/b contacts)
•
Incomer 1 breaker is closed
•
Incomer 2 breaker is closed
If Undervoltage Restoration is used to restore the system automatically, Line Undervoltage
4 (27-4) must be set to “Trip”, instead of “Control” or “Alarm”, and the Block Trip on Double
Loss feature will not work properly.
The settings and functions of other elements associated with the transfer scheme are
shown below:
•
Output Relays 4-7 Auxiliary (all breakers): These output relays are used to implement
the transfer scheme, and must therefore not be operated by any other feature of the
relay. These relays must be programmed to have a not operated state of ‘Deenergized’ with the output type as ‘Self-reset’. These are the default settings.
•
Instantaneous Phase (50P1 or 2) and Neutral (50N-1 or 2) [Incomers 1 and 2 only]:
These fault detectors can be used as an input to transfer scheme logic in this
application, and therefore the function setpoint of elements that are used must be set
to Control. These elements block a transfer while a fault, which can cause a severe
voltage dip, is present on the load side of the breaker. This fault should be cleared by
time overcurrent protection on the incomer or an upstream breaker. If Device 50P is
set properly, during this event it will allow Device 27-4 to time out before the inverse
time phase overcurrent operates, but still prevent transfer initiation. The 50P element
should be set above the maximum current caused by either the bus motor
contribution to an upstream fault, or the maximum current during low voltage
conditions. The 50N element should be set to detect arcing ground faults, but allow
permitted unbalances.
•
Line Undervoltage 3 (27-3) [Incomers 1 and 2 only]: Since this element is used as an
input to transfer scheme logic in this application, set LINE UNDERVOLTAGE 3 FUNCTION
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to “Control”. An Undervoltage 3 operation signals Relay 2 to block transfer initiation
from that relay, as Source 1 is experiencing low voltage. Also, Device 27-3 is enabled
by instantaneous overcurrent to block transfer initiation. This ensures that if a fault on
the load side of Bus 1 causes a dip below the undervoltage pickup setting, transfer will
not be initiated until the voltage has risen above the voltage setting for the interval
established by the TRANSFER DELAY THIS SOURCE setpoint. The Device 27-3 pickup
setting should be below the minimum expected normal (low) voltage, usually around
0.9 of pickup voltage. A Definite Time curve with the delay set to zero provides
instantaneous operation. The minimum operating voltage must be set to zero.
Line Undervoltage 4 (27-4) [Incomers 1 and 2 only]: Since this element is used as a
transfer scheme logic input in this application, set LINE UNDERVOLTAGE 4 FUNCTION to
“Control”. An Undervoltage 4 operation initiates a transfer on loss-of-source. Typical
settings have a pickup about 0.7 to 0.8 of pickup voltage, an “Inverse Time” curve
setting, and a delay setting to provide operation in 0.7 to 1.4 seconds at 0 V. The
minimum operating voltage must be set to zero.
The pickup voltage for both Undervoltage features must not be equal, or transfer will
not take place, since both elements will pickup at the same time, causing 27-3 to block
transfer.
Note
NOTE
•
Synchrocheck (25) [Incomers 1 and 2 only]: The synchrocheck function can be
selected as either Control or Alarm. It is imperative that the DEAD SOURCE PERMISSIVE
setpoint be “LL&DB” (Live Line and Dead Bus) to allow initial closing of the incoming
breakers. The user establishes all other setpoints for this element.
Synchrocheck (25) [Bus Tie only]: This element is used to provide synchronism check
supervision when paralleling the busses. The Dead Source Permissive portion of this
feature is also used to measure the residual voltage on the bus that has lost source. To
ensure that transfers are supervised by the decayed voltage magnitude only, the ‘insynchronism’ elements are blocked while a transfer is in progress. The synchrocheck
function can be selected as either Control or Alarm. It is imperative that the DEAD
SOURCE PERMISSIVE setpoint be either “DL|DB” (Dead Line or Dead Bus) or “DLXDB”
(Dead Line or Dead Bus, but not both) to allow for transfers to either incomer.
The DEAD BUS MAX VOLTAGE and DEAD LINE MIN VOLTAGE setpoints establish the level
of decayed voltage above which transfers are inhibited. A normal setting for this
element is about 0.25 of pickup of nominal voltage. Because the 750/760 measures a
single phase-phase voltage, these values should be multiplied by 1/ 3 to cover the
case of a phase-ground fault on a measured phase reducing that phase voltage but
leaving the other two phases at a higher voltage. If experience shows this setpoint
causes a delay of transfer presenting problems, it is occasionally raised to a maximum
of 0.40 of pickup. The user establishes all other setpoints for this element.
The Logic Inputs for Incomers 1 and 2 and the Bus Tie relays are programmed as follows.
Note that the input number matches the wiring shown on the DC schematics. It is not
necessary that the specific inputs are programmed as shown, but field connections must
match the logic functions.
Note
NOTE
5 - 144
If logic inputs identified as optional on the schematics and the following table are not
required, they can be programmed to perform other functions. The Message Mode may be
programmed to Disabled or Self Reset.
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S7 CONTROL
Table 5–20: Logic Inputs for Incomer 1, 2, and Bus Tie Relays
Input
Incomer #1
Name
Asserted
Logic
Name
Asserted
Logic
Local Mode
Contact
Close
Local Mode
Contact
Close
Local Mode
Contact
Close
2
Remote Close
Contact
Close
Remote
Close
Contact
Close
Remote
Close
Contact
Close
3
Remote Open
Contact
Close
Remote
Open
Contact
Close
Remote
Open
Contact
Close
4
52a or 52b
Contact
Contact
Close
52a or 52b
Contact
Contact
Close
52a or 52b
Contact
Contact
Close
5
Breaker
Connected
Contact
Close
Breaker
Connected
Contact
Close
Breaker
Connected
Contact
Close
6
Selected To
Trip
Contact
Close
Selected To
Trip
Contact
Close
Selected To
Trip
Contact
Close
7
Undervoltage
On Other
Source
Contact
Close
Undervolta
ge On Other
Source
Contact
Close
Close From
Incomer 1
Contact
Close
8
Incomer 2
Breaker
Closed
Contact
Close
Incomer 1
Breaker
Closed
Contact
Close
Incomer 1
Breaker
Closed
Contact
Close
9
Tie Breaker
Connected
Contact
Close
Tie Breaker
Connected
Contact
Close
Close from
Incomer 2
Contact
Close
10
Tie Breaker
Closed
Contact
Close
Tie Breaker
Closed
Contact
Close
Incomer 2
Breaker
Closed
Contact
Close
11
Block Transfer
Contact
Close
Block
Transfer
Contact
Close
Block
Transfer
Contact
Close
12
Transformer
Lockout
Contact
Close
Transforme
r Lockout
Contact
Close
13
Source Trip
Contact
Close
Source Trip
Contact
Close
optional
optional
NOTE
Name
Bus Tie
1
optional
Note
Asserted
Logic
Incomer #2
The asserted logic in the above table is based on the specific requirements of the
application example in this section to illustrate the transfer scheme function and in
accordance to the type of contacts shown in the Transfer Scheme Incomer No. 1 DC
Schematic on page 5–147, the Transfer Scheme Incomer No. 2 DC Schematic on page 5–
148, and the Transfer Scheme Bus Tie Breaker DC Schematic on page 5–149, which are all
normally open. For additional information refer to S3 Logic Inputs on page 5–26.
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FIGURE 5–66: Transfer Scheme One Line Diagram
5 - 146
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FIGURE 5–67: Transfer Scheme Incomer No. 1 DC Schematic
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CHAPTER 5: SETPOINTS
FIGURE 5–68: Transfer Scheme Incomer No. 2 DC Schematic
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S7 CONTROL
FIGURE 5–69: Transfer Scheme Bus Tie Breaker DC Schematic
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
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CHAPTER 5: SETPOINTS
.
FIGURE 5–70: Transfer Scheme 1 Incomer No. 1 Logic
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FIGURE 5–71: Transfer Scheme 1 Incomer No. 2 Logic
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FIGURE 5–72: Transfer Scheme 1 Bus Tie Breaker Logic
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S7 CONTROL
Transfer Scheme 2
The performance of Transfer Scheme 2 logic is similar to Transfer Scheme 1 logic except
during the following conditions:
1.
The detection of transformer trip (86T), or Source trip (94) will result into tripping the
Incomer breaker if all of the following conditions check true:
a. The local Incomer breaker is connected,
b. The tie breaker is open
c. The other Incomer breaker is closed
d. No Undervoltage condition on Other Source
e. No overcurrent conditions
2.
The detection of Line Undervoltage conditions (UV4 - usually set with time delay), will
trip the Incomer breaker if all of the following conditions check true:
a. The local Incomer breaker is connected,
b. The tie breaker is open
c. The other Incomer breaker is closed
d. No Undervoltage condition on Other Source
e. No overcurrent conditions
In addition to the above logic, the logic for each breaker relay per scheme 2 provides an
output to the synchrocheck logic, where a block to 2 Close Relay is formed. Please refer to
Synchrocheck logic diagram for details.
Scheme 2 logic provides for the following power system conditions:
1.
Tripping of the Incomer breaker during transformer lockout 86T, Source trip 94, or
Undervoltage (UV4) is blocked, if this breaker is the only one supplying power to both
buses, such as in single ended configuration – the other Incomer breaker open and
the tie-breaker closed. A fault on any of the buses is detected by Coordinated Timed
Over-Current protection, which is not part of the transfer scheme.
2.
Any of the three breakers can be closed when in racked-out (disconnected) position
such as during breaker maintenance.
3.
Tripping of an Incomer breaker is blocked by the detection of over-current condition
during source under-voltage. The block is held until the voltage is detected above the
UV3 pickup level after the Transfer Delay This Source timer expires.
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CHAPTER 5: SETPOINTS
FIGURE 5–73: Transfer Scheme 2 Incomer No. 1 Logic
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FIGURE 5–74: Transfer Scheme 2 Incomer No. 2 Logic
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CHAPTER 5: SETPOINTS
FIGURE 5–75: Transfer Scheme 2 Bus Tie Breaker Logic
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CHAPTER 5: SETPOINTS
5.8.8
S7 CONTROL
Autoreclose (760 only)
Main Menu
PATH: SETPOINTS  S7 CONTROL  AUTORECLOSE

AUTORECLOSE
[]
MESSAGE
MESSAGE
MESSAGE
MESSAGE
MESSAGE
MESSAGE
MESSAGE

SCHEME SETUP
[]

RATE
SUPERVISION
[]

CURRENT
SUPERVISION
[]

ZONE
COORDINATION
[]

RECLOSURE 1
[]

RECLOSURE 2
[]

RECLOSURE 3
[]

RECLOSURE 4
[]
See page 5–159
See page 5–162
See page 5–163
See page 5–164
See page 5–167
The 760 has a very flexible autoreclose scheme that allows for the many different control
strategies typical of utility applications. Up to four reclosure ‘shots’ are possible with
separately programmable ‘dead times’ for each shot. Reclosure can be initiated from any
760 overcurrent element or from external sources. Between each shot, overcurrent
protection setpoints can be adjusted in order to co-ordinate with downstream devices. To
prevent breaker wear, a ‘current supervision’ feature can reduce the number of shots when
the fault current is high. A ‘zone co-ordination’ feature can maintain protection
coordination with downstream reclosers. Logic inputs are available for blocking and
disabling the scheme.
Front panel LEDs indicate the present state of the autoreclose scheme. Note that display
message group A1 STATUS  AUTORECLOSE can also be accessed to determine the
present state of the autoreclose scheme.
• Reclosure Enabled: The scheme is enabled and may reclose if a trip occurs.
• Reclosure Disabled: The scheme is not enabled and will not reclose until the
scheme is enabled.
• Reclosure In Progress: An autoreclosure has been initiated but the breaker has not
yet been closed.
• Reclosure Lockout: The scheme has gone to ‘lockout’ and must be reset before
further reclosures are permitted.
The scheme is considered enabled when all of the following five conditions are true:
1.
The AUTORECLOSE FUNCTION setpoint is set to “Enabled”.
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2.
Either a 52a or 52b contact is installed and has been programmed to a logic
input function.
3.
Neither the ‘Block Reclosure’ nor ‘Cancel Reclosure’ logic input functions are
asserted.
4.
The scheme is not in the lockout state.
5.
The AR Block Time Upon Manual Close timer is not active.
A simplified description of how the autoreclose scheme works follows. Refer to the
Autoreclosure Application Example on page 5–168 for further details.
A fault occurs resulting in an overcurrent element tripping the circuit breaker and initiating
a reclosure. Once the breaker is detected open a ‘dead timer’ is started. Once this timer
exceeds the value programmed for the DEAD TIME BEFORE RECLOSURE Reclosure 1
setpoint, the shot counter is incremented and a breaker closure is initiated using the ‘2
Close’ output contact. At the same time, overcurrent element characteristics are modified
according to the Reclosure 1 setpoints.
If the fault is permanent, subsequent overcurrent element(s) will trip and initiate reclosure.
The scheme will eventually go to lockout when the MAX NUMBER OF RECLOSURE SHOTS has
been met and another trip occurs. If a breaker failure condition is detected at any time
during operation, the scheme will again go straight to lockout. When in lockout, the 760
disables the reclose scheme and returns all protection setpoints to their initial values. To
re-enable the autoreclose scheme the relay must be reset via the front panel reset key, the
Reset logic input function, communications, or by a manual close operation. The latter
resets the scheme only after the AR BLOCK TIME UPON MANUAL CLOSE timer expires, and
no overcurrent elements are active.
If the fault is transient in nature then no overcurrent element(s) will trip after the breaker
has closed. The scheme will automatically reset when the reset timer, started upon the first
reclosure initiation, exceeds the AR RESET TIME setpoint value. This autoreclosure reset
returns the shot counter to zero and all protection setpoints to their initial values.
An anti-pumping feature is built into the reset mechanism. Otherwise, breaker pumping
could occur when the fault level is between the initial overcurrent pickup level and the
adjusted overcurrent pickup level for a reclosure shot. It prevents a permanent fault from
continuously repeating the trip breaker, initiate reclose, close breaker, automatic reset of
autoreclose scheme, trip breaker sequence. If this condition is detected the anti-pumping
feature returns protection setpoints to their initial values without resetting the shot
counter. The relay will then continue to trip and reclose until lockout is reached.
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S7 CONTROL
Scheme Setup
PATH: SETPOINTS  S7 CONTROL  AUTORECLOSE  SCHEME SETUP

AUTORECLOSE
FUNCTION: Disabled
Range: Enabled, Disabled
MESSAGE
MAX NUMBER OF
RECLOSURE SHOTS: 1
Range: 1 to 4 in steps of 1
MESSAGE
AR RESET
TIME: 60 s
Range: 1 to 1000 s in steps
of 1
MESSAGE
AR BLOCK TIME UPON
MANUAL CLOSE: 10 s
Range: 0 to 200 s in steps of
1
MESSAGE
AR EXTERNAL CLOSE
LOGIC: Disabled
Range: Enabled, Disabled
MESSAGE
INCOMPLETE SEQUENCE
TIME: 30 s
Range: 1 to 1000 s in steps
of 1
MESSAGE
RECLOSURE ENABLED
RELAYS (3-7): -----
Range: Any combination of
the 3 to 7 Auxiliary
MESSAGE
RECLOSURE IN PROGRESS
RELAYS (3-7): -----
Range: Any combination of
the 3 to 7 Auxiliary
MESSAGE
RECLOSURE LOCKOUT
RELAYS (3-7): -----
Range: Any combination of
the 3 to 7 Auxiliary
SCHEME SETUP
[]
The setpoints shown above setup the general characteristics of the scheme. The AR
FUNCTION and MAX NUMBER OF RECLOSURE SHOTS setpoints are critical and must be set
appropriately.
For an overcurrent element to initiate a reclosure it must be programmed to the “Trip & AR”
function.
Note
NOTE
•
MAX NUMBER OF RECLOSURE SHOTS: This setpoint specifies the number of
reclosures that should be attempted before reclosure lockout occurs. The dead time
and overcurrent characteristics for each reclosure shot are entered in the subsequent
message groups RECLOSURE 1 to RECLOSURE 4.
•
AR RESET TIME: The reset timer is used to set the total time interval for a single fault
event, from the first trip until either lockout or successful reclosure. Generally, this
setpoint is set to the same delay that would be used for the ‘reclaim time’ in a
traditional scheme with fixed protection settings. This time must be set to a value
greater than the sum of all programmed dead times plus the maximum time to trip on
each reclose shot.
Set the AR RESET TIME timer to a delay longer than the INCOMPLETE SEQUENCE timer.
Note
NOTE
•
AR BLOCK TIME UPON MANUAL CLOSE: The autoreclose scheme can be disabled for
a programmable time delay after the associated circuit breaker is manually closed.
This prevents manual reclosing onto a fault. This delay must be longer than the
slowest expected trip from any protection not blocked after manual closing. If no
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overcurrent elements activate after a manual close and this timer expires, the
autoreclose scheme is automatically reset. The lockout state will be cleared and the
shot counter will be set to zero.
Manual circuit breaker closures can be initiated by either the front panel breaker
CLOSE key when in local mode, or by the Remote Close logic input and computer
communications when in remote mode.
Note
NOTE
•
AR EXTERNAL CLOSE LOGIC: For applications where the breaker may be closed
directly, without using the 760 to provide the closing signal to the breaker, enabling
this setpoint will use breaker state to determine if a manual close has occurred. The
760 uses the detection of a manual close to disable the autoreclose scheme to
prevent reclosing onto a fault. Also, if the Autoreclose scheme is in the lockout state, a
successful manual close would result in the autoreclose scheme being automatically
reset after the AR BLOCK TIME UPON MANUAL CLOSE time has expired.
When “Enabled”, this setpoint uses the detection of the breaker going from the open
state to the closed state to determine if a manual close has occurred. The breaker
state is determined by the 52a/b contact feedback to the 760. When set to “Disabled”,
only close commands sent via the 760 will be considered as a manual close for the
autoreclose scheme logic.
•
INCOMPLETE SEQUENCE TIME: This timer sets the maximum time interval allowed for
a single reclose shot. It is started whenever a reclosure is initiated and is active when
the scheme is in the “Reclosure In Progress” state. If all conditions allowing a breaker
closure are not satisfied when this timer expires, the reclosure initiation is abandoned.
Any combinations of the following conditions block the breaker from closing:
– Breaker status logic inputs (52a or 52b) fail to report the breaker has opened;
– The “Block 2 Close Relay” logic input function is asserted;
– The synchrocheck feature is blocking breaker closes.
This timer must be set to a delay less than the AR RESET TIME timer.
Note
NOTE
5 - 160
•
RECLOSURE ENABLED RELAYS: Select the relays required to operate while the front
panel Reclosure Enabled indicator is on.
•
RECLOSURE IN PROGRESS RELAYS: Select the relays required to operate while the
front panel Reclosure In Progress indicator is on. This indicator is on when the
autoreclose scheme has been initiated, but has not yet sent a close command. This
output could be used to block the operation of a transformer tap changer during a
reclosure sequence.
•
RECLOSURE LOCKOUT RELAYS: Select the relays required to operate while the front
panel Reclosure Lockout indicator is on. This indicator is on when the autoreclose
scheme has progressed to a lockout condition, such that no further breaker closures
will be initiated until the 760 has been reset.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
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S7 CONTROL
FIGURE 5–76: Autoreclose Scheme Setup Logic
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Autoreclose Rate Supervision
PATH: SETPOINTS  S7 CONTROL  AUTORECLOSE  RATE SUPERVISION

RATE
SUPERVISION
RATE SUPERVISION
FUNCTION: Disabled
Range: Disabled, Alarm,
Latched Alarm,
MESSAGE
RATE SUPERVISION
RELAYS (3-7): -----
Range: Any combination of
the 3 to 7 Auxiliary
MESSAGE
MAX AUTORECLOSE
RATE: 25 /hr.
Range: 1 to 50/hr. in steps of
1
[]
The autoreclose rate supervision feature monitors the number of reclosures per hour. Once
the number of reclosures within one hour exceeds the MAX AUTORECLOSE RATE setpoint,
the autoreclose scheme is sent to lockout.
FIGURE 5–77: Autoreclose Rate Supervision Logic
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S7 CONTROL
Autoreclose Current Supervision
PATH: SETPOINTS  S7 CONTROL  AUTORECLOSE  CURRENT SUPERVISION

CURRENT
SUPERVISION
CURRENT SUPERVISION
FUNCTION: Disabled
Range: Enabled, Disabled
MESSAGE
3 SHOTS FOR CURRENT
ABOVE: 17.00 x CT
Range: 0.00 to 20.00 x CT in
steps of 0.01
MESSAGE
2 SHOTS FOR CURRENT
ABOVE: 18.00 x CT
Range: 0.00 to 20.00 x CT in
steps of 0.01
MESSAGE
1 SHOTS FOR CURRENT
ABOVE: 19.00 x CT
Range: 0.00 to 20.00 x CT in
steps of 0.01
MESSAGE
CURRENT SUPERVISION
TO LOCKOUT: Disabled
Range: Enabled, Disabled
MESSAGE
LOCKOUT FOR CURRENT
ABOVE: 20.00 x CT
Range: 0.00 to 20.00 x CT in
steps of 0.01
[]
The current supervision feature is used to limit breaker wear. When fault current exceeds
user-programmed levels, it reduces the number of reclose shots permitted.
Once a reclose sequence is initiated, the maximum current measured on any phase is
compared to the setpoint current levels. The relay then determines the maximum number
of shots allowed or whether the scheme goes immediately to lockout. The lowest number
of permitted shots, whether set by the MAX NUMBER OF RECLOSE SHOTS setpoint or the
Current Supervision feature, always takes precedence unless current supervision takes the
scheme to lockout. Lockout has the highest priority. Once the current supervision feature
has reduced the total number of shots, a subsequent shot can still reduce the limit further.
The fault current level above which the number of autoreclosure shots will be reduced to
one, two, or three shots can be selected. If the autoreclose scheme is to be taken directly to
lockout without reclosing, set the CURRENT SUPERVISION TO LOCKOUT setpoint to “Enabled”
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
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FIGURE 5–78: Autoreclose Current Supervision Logic
Autoreclose Zone Coordination
PATH: SETPOINTS  S7 CONTROL  AUTORECLOSE  ZONE COORDINATION

ZONE
COORDINATION
ZONE COORDINATION
FUNCTION: Disabled
Range: Enabled, Disabled
MESSAGE
PHASE CURRENT
INCREASE: 1.00 x CT
Range: 0.05 to 20.00 x CT in
steps of 0.01
MESSAGE
NEUTRAL CURRENT
INCREASE: 1.00 x CT
Range: 0.05 to 20.00 x CT in
steps of 0.01
MESSAGE
MAX FAULT CLEARING
TIME:
10 s
Range: 1 to 1000 s in steps
of 1
[]
The 760 autoreclose scheme can be programmed to maintain coordination of overcurrent
elements with a downstream recloser. If a downstream recloser is programmed to use
different protection settings for different reclose shots, it may be necessary to change the
protection setpoints on the 760 each time the recloser operates. To ensure that protection
coordination is maintained, each 760 reclosure shot must be coordinated with each
downstream recloser shot. In addition, the 760 reclose shot counter must always match
the recloser shot counter. When a fault occurs downstream of the recloser and the 760
feeder breaker does not trip and reclose, the 760 reclosure shot counter must still be
incremented.
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Once enabled, this scheme assumes an external reclose operation has occurred when the
feeder phase or neutral current exhibits a step increase in magnitude, due to fault current,
followed by a step decrease in magnitude, due to a recloser opening. After the first
detection of an external reclose, the shot counter is incremented by one, protection
setpoints are changed, and the autoreclose scheme reset timer is initiated.
If the fault is permanent and the recloser continues to trip and reclose, the coordination
feature will continue to increment the shot counter. If this continues to the maximum
number of shots programmed in the 760, the autoreclose scheme will go to lockout. If the
fault is transient, then the autoreclose scheme and shot counter will eventually be reset by
the normal reset mechanism.
The PHASE CURRENT INCREASE and NEUTRAL CURRENT INCREASE setpoints select the
minimum phase and neutral current step increases that signify downstream faults. These
currents may be quite low for an end fault on a long feeder with a weak source. The MAX
FAULT CLEARING TIME setpoint is intended to reset the memory of an increasing current
caused by an increase in feeder load since the new load current will not drop to operate
the decreasing current detector. This delay must be set longer than the maximum fault
clearing time on the recloser.
Note
NOTE
For correct operation of the coordination scheme, the 760 instantaneous protection
elements must be set to have time delays longer than the maximum fault clearing time of
the downstream recloser. In addition, the autoreclose reset timer must be set longer than
the maximum time for the recloser to reach lockout.
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CHAPTER 5: SETPOINTS
FIGURE 5–79: Autoreclose Zone Coordination Logic
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Reclosure Shots 1 to 4
PATH: SETPOINTS  S7 CONTROL  AUTORECLOSE  RECLOSURE 1(4)

RECLOSURE 1
DEADTIME BEFORE
RECLOSURE:
0.50 s
Range: 0.00 to 300.00 s in
steps of 0.01
MESSAGE
PHASE INST OC 1
BLOCKING: Disabled
Range: Enabled, Disabled
MESSAGE
NEUTRAL INST OC 1
BLOCKING: Disabled
Range: Enabled, Disabled
MESSAGE
GND INST OC
BLOCKING: Disabled
Range: Enabled, Disabled
MESSAGE
SENSTV GND INST OC
BLOCKING: Disabled
Range: Enabled, Disabled
MESSAGE
NEG SEQ INST OC
BLOCKING: Disabled
Range: Enabled, Disabled
MESSAGE
PHASE TIME OC 1
RAISED PICKUP: 0%
Range: 0 to 100% in steps of
1
MESSAGE
NEUTRAL TIME OC 1
RAISED PICKUP: 0%
Range: 0 to 100% in steps of
1
MESSAGE
GND TIME OC
RAISED PICKUP: 0%
Range: 0 to 100% in steps of
1
MESSAGE
SENSTV GND TIME OC
RAISED PICKUP: 0%
Range: 0 to 100% in steps of
1
MESSAGE
NEG SEQ TIME OC
RAISED PICKUP: 0%
Range: 0 to 100% in steps of
1
MESSAGE
SELECT SETPOINT
GROUP: Active
Range: Group 1, Group 2,
Group 3, Group 4,
[]
The above setpoints are programmed independently and are repeated for each of the
Reclosure Shots 1 through 4. These setpoints determine the dead time for a given shot and
the overcurrent characteristics during that shot. Selections for shots, that are greater than
the maximum number of shots programmed in the scheme setup, will not be used by the
scheme.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
5 - 167
S7 CONTROL
CHAPTER 5: SETPOINTS
FIGURE 5–80: Autoreclosure Shots 1 to 4 Logic
Autoreclosure Application Example
Utility statistics indicate that a large percentage of feeder faults (about 80%) are of a
transient nature. Typically, once the feeder is tripped an autorecloser automatically
reclosures the feeder breaker after a short time delay. If the fault was transient, the entire
feeder is returned to normal service and customers experience a very short disturbance. If
the fault is permanent and on the load side of another protection point, the reclosure
scheme delays another trip of the breaker until this other device clears the fault so that
service is disrupted only for loads beyond this other protection point.
A common phase protection scheme uses instantaneous elements in conjunction with
automatic reclosing. The design goal is to select setpoints that will detect faults out to the
most distant (in impedance terms) point of the feeder and provide fast operation. Typically
‘lo-set’ overcurrent elements are programmed to be blocked after the first reclosure. This
gives downstream devices, such as fuses, time to interrupt a permanent fault, especially
on a feeder tap. Lo-set elements would then be re-enabled after the scheme is reset. ‘Hi-
5 - 168
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S7 CONTROL
set’ elements may also be blocked on a subsequent shot with a faster time overcurrent
curve selected to allow the fault to burn off. In this case a permanent fault would then
cause a time overcurrent trip.
A typical autoreclose scheme as implemented in the 760 would respond to faults as
follows:
1.
With the breaker closed and protection enabled, a transient fault produces a
current above the pickup of both Instantaneous Overcurrent 1 (lo-set) and
Time Overcurrent 1 elements.
2.
The Time Overcurrent element begins to time, and the Instantaneous
Overcurrent element operates, signaling the breaker to trip and initiate a
reclosure.
3.
The breaker trips and signals the autoreclose scheme that it is now open. The
Instantaneous Overcurrent 1 and Time Overcurrent 1 elements automatically
reset because the breaker is open.
4.
If all requirements of the autoreclose scheme are fulfilled, autoreclose signals
the breaker to close and advances the shot counter. Shot 1 setpoints block the
Instantaneous Overcurrent element from further operation.
5.
The breaker closes resulting in an inrush current of the feeder loads.
6.
If the fault was transient, the current reduces to the load level before a trip
occurs. The autoreclose scheme eventually resets and the cycle begins again
at Step 1.
7.
If the fault is permanent, a current above the pickup of both the
Instantaneous Overcurrent 1 and the Time Overcurrent 1 elements is
produced. However, the Instantaneous Overcurrent 1 element is blocked from
operating.
8.
While the Time Overcurrent 1 element is timing, any protection devices
between this relay and the fault location are provided an opportunity to
isolate the fault.
9.
If no protection downstream from the relay clears the fault, the Time
Overcurrent 1 element will time-out, signaling the breaker to trip and initiate
the autoreclose scheme again.
10. If the shot counter has not reached its maximum allowed value then the cycle
begins at step 6 using protection setpoints for the current shot.
11. If the shot counter has reached its maximum then the scheme goes to
lockout.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
5 - 169
S8 TESTING
5.9
CHAPTER 5: SETPOINTS
S8 Testing
5.9.1
Output Relays
PATH: SETPOINTS  S8 TESTING  OUTPUT RELAYS

OUTPUT RELAYS
FORCE OUTPUT RELAYS
FUNCTION: Disabled
Range: Enabled, Disabled
MESSAGE
FORCE 1 TRIP
RELAY: De-energized
Range: Energized, Deenergized
MESSAGE
FORCE 2 CLOSE
RELAY: De-energized
Range: Energized, Deenergized
MESSAGE
FORCE 3 AUX
RELAY: De-energized
Range: Energized, Deenergized
MESSAGE
FORCE 4 AUX
RELAY: De-energized
Range: Energized, Deenergized
MESSAGE
FORCE 5 AUX
RELAY: De-energized
Range: Energized, Deenergized
MESSAGE
FORCE 6 AUX
RELAY: De-energized
Range: Energized, Deenergized
MESSAGE
FORCE 7 AUX
RELAY: De-energized
Range: Energized, Deenergized
MESSAGE
FORCE 8 SELF-TEST
RELAY: De-energized
Range: Energized, Deenergized
MESSAGE
FORCE SOLID STATE
OUTPUT: De-energized
Range: Energized, Deenergized
[]
For testing purposes, the relay provides the ability to override the normal function of the
solid state and output contacts. This is done by forcing each to energize or de-energize.
Set FORCE OUTPUT RELAYS FUNCTION to “Enabled” to override the normal operation of the
solid state and output contacts, with the state programmed in the messages that follow.
Note that this setpoint will always be defaulted to the “Disabled” state at power up.
Select “De-energized” for the remaining setpoints to force the output relays to the deenergized state while FORCE OUTPUT RELAYS FUNCTION is set to “Enabled”. Selecting
“Energized” forces the output relay to the energized state while the FORCE OUTPUT RELAYS
FUNCTION setpoint is “Enabled”.
5 - 170
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
5.9.2
S8 TESTING
Pickup Test
PATH: SETPOINTS  S8 TESTING  PICKUP TEST

PICKUP TEST
[]
MESSAGE
PICKUP TEST
FUNCTION: Disabled
Range: Enabled, Disabled.
Defaults to
PICKUP TEST
RELAYS (3-7): -----
Range: Any combination of
the 3 to 7 Auxiliary
The relay provides the ability to operate any or all of the 3 to 7 Auxiliary output relays upon
the pickup of any protection element. The pickup test feature is especially useful for
automated testing. Through a 750/760 output contact, test equipment can monitor a
pickup threshold.
FIGURE 5–81: Pickup Test Logic
5.9.3
Analog Outputs
PATH: SETPOINTS  S8 TESTING  ANALOG OUTPUTS

ANALOG OUTPUTS
[]
MESSAGE
FORCE ANALOG OUTPUTS
FUNCTION: Disabled
Range: Enabled, Disabled
FORCE A/O 1
0%
Range: 0 to 100% in steps of
1
↓
MESSAGE
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
FORCE A/O 8
0%
Range: 0 to 100% in steps of
1
5 - 171
S8 TESTING
CHAPTER 5: SETPOINTS
The relay provides the ability to override the normal function of analog outputs, forcing
each to any level from 0 to 100% of the output range. Enter the percentage of the DC mA
output range to be signaled by the Analog Output 1 (2 to 8) for the FORCE A/O 1(8) setpoints.
For example, if the relay has been ordered with 4 to 20 mA analog outputs, setting this
value to “100%” will output 20 mA, “0%” will output 4 mA, and “50%” will output 12 mA.
The FORCE A/O FUNCTION Always defaults to “Disabled” on power-up
5.9.4
Simulation
Main Menu
PATH: SETPOINTS  S8 TESTING  SIMULATION

SIMULATION
[]
MESSAGE
MESSAGE
MESSAGE

SETUP
[]

PREFAULT
VALUES
[]

FAULT
VALUES

POST FAULT
VALUES
[]
[]
See page 5–174
See page 5–175
See page 5–175
See page 5–176
When in Simulation Mode, the normal protection and control features are not
operational. This is indicated by the 8 Self-Test Warning relay being de-energized. If
Simulation Mode is used for field testing on equipment, the operator must provide
other means of protection and control.
A simulation feature is provided for testing the functionality of the relay in response to
program conditions, without the need of external AC voltage and current inputs. First time
users will find this to be a valuable training tool. System parameters such as currents and
voltages, phase angles, and system frequency are entered as setpoints. When placed in
simulation mode, the relay suspends reading actual AC inputs, generates samples to
represent the programmed phasors, and loads these samples into the memory to be
processed by the relay. Both normal and fault conditions can be simulated to exercise a
variety of relay features. There are three sets of input parameters used during simulation,
each providing a particular state of the system, as shown below:
5 - 172
•
Prefault State: This state simulates the normal operating condition of a feeder
carrying load current, by replacing the normal input parameters with programmed
prefault values. Voltages are automatically set to the nominal value programmed in
the BUS VT NOMINAL SECONDARY VOLTAGE setpoint. The neutral current is set to zero.
Phase currents are balanced and set to the value programmed in the PREFAULT PHASE
A/B/C CURRENT setpoint. The phase angle of each phase current relative to its
corresponding phase neutral voltage is set to the value programmed in the PREFAULT
PWR FACTOR ANGLE setpoint. The frequency of voltages and currents are
automatically set to the values programmed in the NOMINAL FREQ setpoint.
•
Fault State: This state simulates the faulted operating condition of a feeder by
replacing the normal prefault feeder input parameters with programmed fault values.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S8 TESTING
The magnitude and angle of each bus voltage and current, polarizing current, system
frequency and analog input are set to the values programmed under the FAULT
VALUES setpoints. The neutral current is calculated from the vector sum of the phase
currents, and 3V0 from the vector sum of the phase voltages.
•
Postfault State: This state is intended to simulate a feeder that has tripped. Current is
automatically set to 0 A. Bus voltages are automatically balanced and set to Phase AN at 0°, B-N at 120°, and C-N at 240°. The bus voltage magnitude and frequency are
set to the entered values. The synchronizing voltage is set to the entered values of
magnitude, angle (with respect to phase A-N bus voltage) and frequency.
There are two methods of running simulations. If the feeder circuit breaker is connected to
the relay and can be opened and closed, a full operating sequence can be performed. If a
breaker is not available, as is often the case, the relay can be made to simulate a breaker
and allow the 760 to exercise its autoreclose feature. The operation of each method is
described below.
1.
If simulation of the feeder breaker is required set the CIRCUIT BRKR SIMULATION
setpoint to “Enabled”. After the required simulation setpoints have been entered, the
relay is placed in the Prefault State by setting the SIMULATION STATE setpoint to
“Prefault”. The relay replaces the normal AC inputs with those programmed on the
PREFAULT VALUES setpoint page. Logic inputs, except for the 52a and 52b contacts,
are monitored normally throughout the simulation. The relay’s simulation of a circuit
breaker is indicated by the status of the Breaker Open and Breaker Closed front panel
indicators.
The relay remains in the Prefault State until a command is received to enter the Fault
State, either by setting the SIMULATION STATE setpoint to the Fault State, or a contact
closure on a logic input whose function setpoint is set to Simulate Fault. The logic
input makes the measurement of feature operating times possible when output relays
are allowed to operate.
In the Fault State, relay features respond to the programmed fault values, generating
a trip, alarms, event records, triggers of trace memory and data logger, and front
panel indications as necessary. Output relays only operate if permitted by the ALLOW
OPERATION OF RELAYS (3-7) setpoint. The relay remains in the Fault State until it has
detected a trip condition. Note that the Trip Relay is not allowed to operate. At this
time the simulated breaker is opened (as indicated by front panel indicators) and the
relay is placed in Postfault State.
The relay remains in the Postfault State until either a close command received or the
760 autoreclose scheme has all requirements met and is ready to close. At this time
the relay returns to the Prefault State. Note that the Close Relay is not allowed to
operate. Setting the SIMULATION STATE setpoint to “Disabled” also terminates
simulation.
2.
If simulation of the feeder breaker is not required set the Circuit Breaker Simulation
setpoint to Disabled. After the required simulation setpoints have been entered, the
relay is placed in simulation mode by setting the SIMULATION STATE setpoint to “Prefault”. The relay replaces the normal AC inputs with those programmed on the Prefault
Values setpoint page. All logic inputs are monitored normally throughout the simulation including any set to monitor the 52a/52b contacts by which the front panel
Breaker Open and Breaker Closed indicators are set.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
5 - 173
S8 TESTING
CHAPTER 5: SETPOINTS
Operation is similar to that described in Method 1 above except that the Trip Relay will
operate if a trip condition is declared and the Close Relay will operate in response to
any form of close request. As well, the Simulation State is controlled by the monitored
state of the breaker.
Setup
PATH: SETPOINTS  S8 TESTING  SIMULATION  SETUP

SETUP
SIMULATION STATE:
Disabled
Range: Disabled, Prefault,
Fault, Postfault
MESSAGE
CIRCUIT BRKR
SIMULATION: Enabled
Range: Enabled, Disabled
MESSAGE
ALLOW OPERATION OF
RELAYS (3-7): -----
Range: Any combination of
the 3 to 7 Auxiliary
[]
Program SIMULATION STATE to “Disabled” if actual system inputs are to be monitored. If
programmed to any other value, the relay is in simulation mode and actual system
parameters are not monitored. The system parameters simulated by the relay will be those
in the section below that corresponds to the programmed value of this setpoint. For
example, if programmed to “Fault”, then the system parameters will be set to those
defined by the Fault Values setpoints on page –175.
Note
NOTE
The simulation state may change due to a change in the operational state of the relay. For
example, if set to “Fault” and a trip opens the breaker (either simulated or actual), the
simulation state and this setpoint will automatically change to “Postfault”.
An operator can use the simulation feature to provide a complete functional test of the
relay’s protection features, except for the measurement of external input values. As this
feature may be used for on-site testing, provision is made to block the operation of the
output relays so the operation of other equipment is prevented. Set CIRCUIT BRKR
SIMULATION to “Enabled” to block the Trip and Close Relays from operating, and ignore the
52a/52b auxiliary contacts, even if installed. In this mode, the circuit breaker will be
simulated. Set CIRCUIT BRKR SIMULATION to “Disabled” to allow the Trip and Close Relays
to open and close an actual circuit breaker connected to the relay. In this mode, the 52a/
52b auxiliary contacts, if installed, will be read for feedback from the breaker.
The Trip and Close relays are allowed to operate by setting CIRCUIT BRKR SIMULATION to
“Disabled”. Auxiliary Relays 3 to 7 can also be allowed to operate if selected by the ALLOW
OPERATION OF RELAYS (3-7) setpoint. The 8 Self-Test Warning relay is always allowed to
operate. Note that the default value blocks the operation of all output relays. For timing
tests, a selected output relay can be set to be operational, to provide a signal to stop a
timer.
5 - 174
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S8 TESTING
Prefault Values
PATH: SETPOINTS  S8 TESTING  SIMULATION  PREFAULT VALUES

PREFAULT
VALUES
[]
MESSAGE
PHASE A/B/C CURRENT
LEVEL: 0.50 x CT
Range: 0.00 to 20.00 x CT in
steps of 0.01
PWR FACTOR ANGLE:
0° Lag
Range: 0 to 359° Lag in steps
of 1
For proper simulation, values entered here should be below the minimum trip setting of
any protection feature. The relay will use these values when in the Prefault State. For delta
or wye systems, the relay automatically sets the voltages to the setpoint value of VT
nominal secondary voltage, with balanced voltage phase positions.
Fault Values
PATH: SETPOINTS  S8 TESTING  SIMULATION  FAULT VALUES

FAULT
VALUES
PHASE A-N VOLTAGE
LEVEL: 1.00 x VT
Range: 0.00 to 2.00 x VT in
steps of 0.01
MESSAGE
PHASE A-N VOLTAGE
POSITION:
0° Lag
Range: 0 to 359° Lag in steps
of 1
MESSAGE
PHASE B-N VOLTAGE
LEVEL: 1.00 x VT
Range: 0.00 to 2.00 x VT in
steps of 0.01
MESSAGE
PHASE B-N VOLTAGE
POSITION: 120° Lag
Range: 0 to 359° Lag in steps
of 1
MESSAGE
PHASE C-N VOLTAGE
LEVEL: 1.00 x VT
Range: 0.00 to 2.00 x VT in
steps of 0.01
MESSAGE
PHASE C-N VOLTAGE
POSITION: 240° Lag
Range: 0 to 359° Lag in steps
of 1
MESSAGE
PHASE A CURRENT
LEVEL: 1.00 x CT
Range: 0.00 to 20.00 x CT in
steps of 0.01
MESSAGE
PHASE A CURRENT
POSITION: 60° Lag
Range: 0 to 359° Lag in steps
of 1
MESSAGE
PHASE B CURRENT
LEVEL: 1.00 x CT
Range: 0.00 to 20.00 x CT in
steps of 0.01
MESSAGE
PHASE B CURRENT
POSITION: 180° Lag
Range: 0 to 359° Lag in steps
of 1
MESSAGE
PHASE C CURRENT
LEVEL: 1.00 x CT
Range: 0.00 to 20.00 x CT in
steps of 0.01
MESSAGE
PHASE C CURRENT
POSITION: 300° Lag
Range: 0 to 359° Lag in steps
of 1
MESSAGE
GND CURRENT
LEVEL: 0.00 x CT
Range: 0.00 to 20.00 x CT in
steps of 0.01
[]
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
5 - 175
S8 TESTING
CHAPTER 5: SETPOINTS
MESSAGE
GND CURRENT
POSITION:
0° Lag
Range: 0 to 359° Lag in steps
of 1
MESSAGE
SENSTV GND CURRENT
LEVEL: 0.100 x CT
Range: 0.000 to 1.000 x CT in
steps of 0.001
MESSAGE
SENSTV GND CURRENT
POSITION:
0° Lag
Range: 0 to 359° Lag in steps
of 1
MESSAGE
SYSTEM FREQ:
60.00 Hz
Range: 20.00 to 65.00 Hz in
steps of 0.01
MESSAGE
A/I
CURRENT: 0.00 mA
Range: 0.00 to 20.00 mA in
steps of 0.01
The Fault Simulation State allows adjustment of all current and voltage phasors so that a
wide variety of system disturbances can be simulated. The frequency and the analog input
values can also be adjusted to give complete flexibility. Fault bus voltage values are always
entered as Wye values, even if the relay is set to Delta. The relay will calculate the
equivalent line voltages. Voltage magnitudes are entered in per unit values relative to the
nominal system voltage that is defined by the NOMINAL VT SECONDARY VOLTAGE and VT
RATIO setpoints. Phase current magnitudes are entered in per unit values relative to the
nominal system current that is defined by the PHASE CT PRIMARY setpoint. All phasor
angles are referenced to the prefault A-N bus voltage at 0°.
Postfault Values
PATH: SETPOINTS  S8 TESTING  SIMULATION  POSTFAULT VALUES

POST FAULT
VALUES
BUS VOLTAGE
LEVEL: 1.00 x VT
Range: 0.00 to 2.00 x VT in
steps of 0.01
MESSAGE
BUS VOLTAGE
FREQ: 60.00 Hz
Range: 20.00 to 65.00 Hz in
steps of 0.01
MESSAGE
SYNC VOLTAGE
LEVEL: 1.00 x VT
Range: 0.00 to 2.00 x VT in
steps of 0.01
MESSAGE
SYNC VOLTAGE
POSITION:
0° Lag
Range: 0 to 359° Lag in steps
of 1
MESSAGE
SYNC VOLTAGE
FREQ: 60.00 Hz
Range: 20.00 to 65.00 Hz in
steps of 0.01
[]
The Postfault State allows adjustment of the bus and line voltages in order to simulate an
open breaker condition and allow testing of the synchrocheck feature. All phasor angles
are referenced to the prefault A-N bus voltage at 0°.
5.9.5
Factory Service
PATH: SETPOINTS  S8 TESTING  FACTORY SERVICE

5 - 176
FACTORY
SERVICE
[]
ENTER FACTORY
PASSCODE: 
Range: Restricted access for
GE personnel only
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 5: SETPOINTS
S8 TESTING
These messages are intended for factory use only, to perform testing and diagnostics.
Entering the factory service passcode in the first message allows access to the command
messages.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
5 - 177
S8 TESTING
5 - 178
CHAPTER 5: SETPOINTS
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
GE
Digital Energy
750/760 Feeder Management
Relay
Chapter 6: Actual Values
Actual Values
6.1
6.1.1
Actual Values
Main Menu
Overview
Measured values, maintenance, and fault analysis information are accessed in actual
values mode. Actual value messages are organized into logical groups for easy reference
as shown below. Actual values may be accessed as follows:
1.
Front panel, using the keys and display.
2. Front program port, and a portable computer running the EnerVista 750/760
Setup software supplied with the relay.
3. Rear RS485/RS422 COM 1 port or RS485 COM 2 port with a SCADA system
running user-designed software.
4. Ethernet network connection to the rear RJ-45 port and a computer running
the EnerVista 750/760 Setup software supplied with the relay.

ACTUAL VALUES
A1 STATUS
[]
MESSAGE
MESSAGE
MESSAGE
MESSAGE
MESSAGE
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL

VIRTUAL INPUTS
[]

HARDWARE
INPUTS
[]

LAST TRIP DATA
[]

FAULT
LOCATIONS
[]

CLOCK
[]

AUTORECLOSE
[]
See page 6–6
See page 6–6
See page 6–7
See page 6–8
See page 6–8
See page 6–8
6-1
OVERVIEW
CHAPTER 6: ACTUAL VALUES
MESSAGE

END OF PAGE A1

CURRENT
[]

VOLTAGE
[]

FREQUENCY
[]

SYNCHRONIZING
VOLTAGE
[]

POWER
[]

ENERGY
[]

DEMAND
[]

ANALOG INPUT
[]

END OF PAGE A2

TRIP COUNTERS
[]

ARCING CURRENT
[]

END OF PAGE A3

E128: Nov 17/03 []
<Cause>

E127: Nov 16/03 []
<Cause>
MESSAGE

ACTUAL VALUES
A2 METERING
[]
MESSAGE
MESSAGE
MESSAGE
MESSAGE
MESSAGE
MESSAGE
MESSAGE
MESSAGE
See page 6–11
See page 6–12
See page 6–13
See page 6–14
See page 6–14
See page 6–15
See page 6–16
See page 6–17
MESSAGE

ACTUAL VALUES
A3 MAINTENANCE
[]
MESSAGE
MESSAGE
See page 6–18
See page 6–19
MESSAGE

ACTUAL VALUES
[]
A4 EVENT RECORDER
MESSAGE
See page 6–20
↓
MESSAGE
MESSAGE
6-2

E1: Nov 10/03
<Cause>
[]

LAST RESET
DATE
[]
See page 6–24
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 6: ACTUAL VALUES
OVERVIEW
MESSAGE

END OF PAGE A4

TECHNICAL
SUPPORT
[]

REVISION CODES
[]

CALIBRATION
DATES
[]

END OF PAGE A5
MESSAGE

ACTUAL VALUES
[]
A5 PRODCUT INFO
MESSAGE
MESSAGE
MESSAGE
See page 6–25
See page 6–25
See page 6–26
The following two figures show block diagrams from the Actual Values messages.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
6-3
OVERVIEW
CHAPTER 6: ACTUAL VALUES
FIGURE 6–1: Actual Values Block Diagram (1 of 2)
6-4
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 6: ACTUAL VALUES
OVERVIEW
FIGURE 6–2: Actual Values Block Diagram (2 of 2)
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
6-5
A1 STATUS
CHAPTER 6: ACTUAL VALUES
6.2
6.2.1
Virtual Inputs

A1 Status
PATH: ACTUAL VALUES  A1 STATUS  VIRTUAL INPUTS
VIRTUAL INPUTS
[]
2 VIRTUAL INPUTS
ARE ACTIVE
Range: 0 to 20 Virtual Inputs
Logic Input 1
Off
Range: On, Off. Reflects the userprogrammed name.
The state of all active virtual inputs as well as the ability to set their state is displayed here.
In some applications, these displays can be used instead of panel switches for controlling
operations within the relay. The ability to have user defined names for the inputs allows
the operator interface to be easily understood. See S3 Logic Inputs on page 5–26 for
complete details on virtual inputs, their setpoints and application.
The first value displays how many logic inputs have a virtual condition selected as part of
their asserted logic. The states of Virtual Inputs 1 through 20 are displayed in this menu.
The Logic Input 1 display heading is user-programmable. Note that only ‘active’ virtual
inputs are displayed; active virtual inputs are those that have their INPUT N ASSERTED
LOGIC setpoint programmed to monitor the state of the virtual input. There are
subsequent displays for the remaining virtual inputs.
6.2.2
Hardware
Inputs

HARDWARE
INPUTS
PATH: ACTUAL VALUES  A1 STATUS  HARDWARE INPUTS
[]
MESSAGE
CONTACT 1 STATE:
Open
Range: Open, Closed
CONTACT 2 STATE:
Open
Range: Open, Closed
↓
MESSAGE
CONTACT 14 STATE:
Open
Range: Open, Closed
MESSAGE
SETPOINT ACCESS
STATE: Restricted
Range: Restricted, Allowed
MESSAGE
Trip Coil Monitor
STATE: Open
Range: Open, Closed
MESSAGE
Close Coil Monitor
STATE: Open
Range: Open, Closed
These messages display the state of all hardware inputs. The top line in the last two values
above reflect the names programmed in the S6 MONITORING  EQUIPMENT  COIL
MONITOR 1  COIL 1 MON NAME and COIL 2 MON NAME setpoints, respectively.
6-6
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 6: ACTUAL VALUES
6.2.3
Last Trip Data

A1 STATUS
PATH: ACTUAL VALUES  A1 STATUS  LAST TRIP DATA
LAST TRIP DATA
DATE OF LAST TRIP:
Nov 17 2003
Range: Date in format shown
MESSAGE
TIME OF LAST TRIP:
12:34:56.789
Range: Time in format shown
MESSAGE
TRIP: <Φ>
<Cause>
Range: See A4 Event Recorder on page
6–20.
MESSAGE
A:
C:
MESSAGE
GND CURRENT:
0 A
Range: 0 to 65535 A
MESSAGE
SENSTV GND CURRENT:
0.00 A
Range: 0 to 655.35 A
MESSAGE
NEUTRAL CURRENT:
0 A
Range: 0 to 65535 A
MESSAGE
AN:
CN:
0.00
0.00
BN: 0.00
kVolts
Range: 0 to 655.35 kV
MESSAGE
AB:
CA:
0.00
0.00
BC: 0.00
kVolts
Range: 0 to 655.35 kV
MESSAGE
NEUTRAL VOLTAGE:
0.00 kV
Range: 0 to 655.35 kV
MESSAGE
SYSTEM FREQ:
0.00 Hz
Range: 0.00 to 65.00 Hz
MESSAGE
ANALOG INPUT:
0 μA
Range: 0 to 65535 units.
[]
0
0
B:
Amps
0
Range: 0 to 65535 A
Independent of the event recorder, the relay captures the system information at the time of
the last trip event. This information includes a time and date stamp, trip cause, phase
current, ground current, sensitive ground current, neutral current, voltages, system
frequency, and the analog input. If more than one protection element trips for a fault (for
example, both the Phase and Neutral Instantaneous Overcurrent 1 elements) then only the
first trip event detected by the relay will have Last Trip Data captured. This information
cannot be cleared; data for a new trip overwrites the previous trip data.
The AN, BN, and CN voltage values are seen only if the S2 SYSTEM SETUP  BUS VT
SENSING  VT CONNECTION TYPE setting is “Wye”. The AB, BC, and CA voltage values are
seen only if this setpoint is “Delta” or “None”. The units for ANALOG INPUT are set by the S6
MONITORING  ANALOG INPUT  ANALOG INPUT SETUP  A/I UNITS setting.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
6-7
A1 STATUS
6.2.4
CHAPTER 6: ACTUAL VALUES
Fault
Locations

FAULT
LOCATION 0
PATH: ACTUAL VALUES  A1 STATUS  FAULT LOCATIONS  FAULT LOCATION 0(9)
DATE OF FAULT 0:
Nov 17 2003
Range: Date in format shown
MESSAGE
TIME OF FAULT 0:
12:34:56.789
Range: Time in format shown
MESSAGE
TYPE OF FAULT:
n/a
Range: Phase A, Phase B, Phase C,
Ground
MESSAGE
DISTANCE TO FAULT:
0.00 km
Range: –327.68 to 327.68 km/mi
MESSAGE
Zpos (INDUCTIVE)
OHM TO FAULT: 0.00
Range: 0.00 to 655.35 Ω.
[]
The data for ten faults detected by overcurrent elements is stored under headings
beginning with FAULT LOCATION 0. This information cannot be cleared; data for new events
is always stored as fault 0. The data for each previous fault is shifted to the next highest
number, and Event 9 is discarded.
The DISTANCE TO FAULT and Zpos (INDUCTIVE) OHM TO FAULT values are seen only if a fault
location calculation has been performed.
6.2.5
Clock

CLOCK
PATH: ACTUAL VALUES  A1 STATUS  CLOCK
[]
MESSAGE
CURRENT DATE:
November 17 2003
Range: Date in format shown
CURRENT TIME:
16:30:00
Range: Time in format shown
The date and time are displayed in the format shown. These values are shown as
“Unavailable” if the date and/or time has not been programmed.
6.2.6
Autoreclose
(760 only)

6-8
AUTORECLOSE
PATH: ACTUAL VALUES  A1 STATUS  AUTORECLOSE
AR SHOT
NUMBER IN EFFECT: 0
Range: 0 to 4
MESSAGE
AR SHOTS
REMAINING: 4
Range: 0 to 4
MESSAGE
AR SHOT
RATE: 0 /hr
Range: 0 to 4
MESSAGE
AR SHOT
COUNT: 0
Range: 0 to 4
MESSAGE
AR SHOT COUNT LAST
RESET: Nov 17 2003
Range: Date in format shown
[]
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 6: ACTUAL VALUES
A1 STATUS
The present shot number which the autoreclose scheme is using to control protection
settings is displayed in the AR SHOT NUMBER IN EFFECT value. If the scheme has reached
Lockout, the display is the shot number after which a trip caused lockout. The AR SHOTS
REMAINING value displays the number of reclose shots that can still be performed. After
this point, the reclose system will be either reset or locked-out. The value displayed is
contained in the Shot Limit memory. Each time a reclose shot is performed, in a given
sequence, this Shot Limit is reduced by one. The Shot Limit can also be reduced to any
given value less than the programmed value by the current supervision function.
The number of reclosures in the past hour is shown in the AR SHOT RATE value. This value
will be cleared by a RESET AR RATE DATA command via the front panel or communications.
The AR SHOT COUNT value shows the total number of reclosures since the AR SHOT COUNT
LAST RESET date. The AR SHOT COUNT LAST RESET displays “Unavailable” if the date has
never been programmed.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
6-9
A2 METERING
CHAPTER 6: ACTUAL VALUES
6.3
6.3.1
Metering
Conventions
A2 Metering
The relay measures all RMS currents and voltages, frequency, and an auxiliary analog
input. Other values like average and neutral current, average line and phase voltage,
symmetrical components, frequency decay rate, synchrocheck delta, power factor, power
(real, reactive, apparent), energy (real, reactive), running and maximum demands (current,
real power, reactive power, apparent power), and analog input rate of change are derived.
All quantities are recalculated every power system cycle and perform protection and
monitoring functions. Displayed metered quantities are updated approximately three (3)
times a second for readability. All phasors and symmetrical components are referenced to
the A-N voltage phasor for wye-connected VTs; to the A-B voltage phasor for deltaconnected VTs; or to the phase A current phasor when no voltage signals are present.
POWER PLANE DIAGRAMS
ONE LINE DIAGRAM
I2
I1
I3
I4
+Q
POSITIVE
DIRECTION
P1
-P
+P
Q1
^
S1=EI
1
-Q
SOURCE
LOAD
+Q
RELAY
P2
-P
+P
Q2
^
S2=EI
2
PER IEEE DEFINITIONS
-Q
PHASOR DIAGRAM
^
S3=EI
+Q
3
(POSITIVE ROTATION)
Q3
S2
S1
- Watt
- Var
PF=Lag
+ Watt
- Var
PF=Lead
-P
P3
+P
I1
I2
-Q
+Q
Bus Voltage E
^
S4=EI
4
S3
- Watt
+ Var
PF=Lead
4
I3
4
I4
Q4
S4
+ Watt
+ Var
PF=Lag
-P
4
P4
+P
= Angle By Which Voltage Leads Current
-Q
818773AC.CDR
FIGURE 6–3: Power Quantity Relationships
6 - 10
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 6: ACTUAL VALUES
6.3.2
Current

CURRENT
A2 METERING
PATH: ACTUAL VALUES  A2 METERING  CURRENT
[]
A:
C:
0
0
B:
Amps
0
Range: 0 to 65535 A
MESSAGE
% OF LOAD-TO-TRIP:
0%
Range: 0 to 2000%
MESSAGE
AVERAGE CURRENT:
0 A
Range: 0 to 65535 A
MESSAGE
PHASE A CURRENT:
0 A
0° Lag
Range: 0 to 65535 A, 0 to 359° Lag
MESSAGE
PHASE B CURRENT:
0 A
0° Lag
Range: 0 to 65535 A, 0 to 359° Lag
MESSAGE
PHASE C CURRENT:
0 A
0° Lag
Range: 0 to 65535 A, 0 to 359° Lag
MESSAGE
NEUTRAL CURRENT:
0 A
0° Lag
Range: 0 to 65535 A, 0 to 359° Lag
MESSAGE
GND CURRENT:
0 A
0° Lag
Range: 0 to 65535 A, 0 to 359° Lag
MESSAGE
SENSTV GND CURRENT:
0.00 A
0° Lag
Range: 0 to 655.35 A, 0 to 359° Lag
MESSAGE
POS SEQ CURRENT:
0 A
0° Lag
Range: 0 to 65535 A, 0 to 359° Lag
MESSAGE
NEG SEQ CURRENT:
0 A
0° Lag
Range: 0 to 65535 A, 0 to 359° Lag
MESSAGE
ZERO SEQ CURRENT:
0 A
0° Lag
Range: 0 to 65535 A, 0 to 359° Lag
MESSAGE
POLARIZING CURRENT:
0 A
0° Lag
Range: 0 to 65535 A, 0 to 359° Lag
Measured values of phase current magnitudes and phasors are displayed here. In addition,
several calculated values are also displayed. The AVERAGE CURRENT displays the
calculated averages of the Phase A, B, and C RMS currents:
( Ia + Ib + Ic )
I avg = ------------------------------------3
(EQ 6.1)
The NEUTRAL CURRENT value displays the calculated neutral current RMS phasor given by:
3I 0 = I a + I b + I c
(EQ 6.2)
The POS SEQ CURRENT displays the calculated positive-sequence current RMS phasor as
given by:
2
I a + aI b + a I c
I a1 = ---------------------------------- for ABC phase sequence
3
2
I a1
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
I a + a I b + aI c
= ---------------------------------3
(EQ 6.3)
for ACB phase sequence
6 - 11
A2 METERING
CHAPTER 6: ACTUAL VALUES
The NEG SEQ CURRENT displays the calculated negative-sequence current RMS phasor as
given by:
2
I a + a I b + aI c
I a2 = ---------------------------------- for ABC phase sequence
3
2
I a2
I a + aI b + a I c
= ---------------------------------3
(EQ 6.4)
for ACB phase sequence
The ZERO SEQ CURRENT displays the calculated zero-sequence current RMS phasor:
Ia + Ib + Ic
I a0 = -----------------------3
6.3.3
Voltage

6 - 12
VOLTAGE
(EQ 6.5)
PATH: ACTUAL VALUES  A2 METERING  VOLTAGE
[]
AB:
CA:
0.00
0.00
BC:
kV
0.00
Range: 0 to 655.35 kV
MESSAGE
AVERAGE LINE
VOLTAGE:
0.00 kV
Range: 0 to 655.35 kV
MESSAGE
AN:
CN:
Range: 0 to 655.35 kV
MESSAGE
AVERAGE PHASE
VOLTAGE:
0.00 kV
Range: 0 to 655.35 kV
MESSAGE
LINE A-B VOLTAGE:
0.00 kV
0° Lag
Range: 0 to 655.35 kV, 0 to 359° Lag
MESSAGE
LINE B-C VOLTAGE:
0.00 kV
0° Lag
Range: 0 to 655.35 kV, 0 to 359° Lag
MESSAGE
LINE C-A VOLTAGE:
0.00 kV
0° Lag
Range: 0 to 655.35 kV, 0 to 359° Lag
MESSAGE
LINE A-N VOLTAGE:
0.00 kV
0° Lag
Range: 0 to 655.35 kV, 0 to 359° Lag
MESSAGE
LINE B-N VOLTAGE:
0.00 kV
0° Lag
Range: 0 to 655.35 kV, 0 to 359° Lag
MESSAGE
LINE C-N VOLTAGE:
0.00 kV
0° Lag
Range: 0 to 655.35 kV, 0 to 359° Lag
MESSAGE
NEUTRAL VOLTAGE:
0.00 kV
0° Lag
Range: 0 to 655.35 kV, 0 to 359° Lag
MESSAGE
POS SEQ VOLTAGE:
0.00 kV
0° Lag
Range: 0 to 655.35 kV, 0 to 359° Lag
MESSAGE
NEG SEQ VOLTAGE:
0.00 kV
0° Lag
Range: 0 to 655.35 kV, 0 to 359° Lag
MESSAGE
ZERO SEQ VOLTAGE:
0.00 kV
0° Lag
Range: 0 to 655.35 kV, 0 to 359° Lag
0.00
0.00
BN:
kV
0.00
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 6: ACTUAL VALUES
A2 METERING
The measured values of line and phase voltage magnitudes and phasors for the Bus VT
inputs are displayed along with sequence components. In addition, several calculated
values are also displayed. The AVERAGE LINE VOLTAGE displays the calculated averages of
the RMS line voltages given by:
( V ab + V bc + V ca )
V avg = --------------------------------------------------3
(EQ 6.6)
The AVERAGE PHASE VOLTAGE displays the calculated average of the RMS phase voltages
given by:
( V an + V bn + V cn )
V avg = --------------------------------------------------3
(EQ 6.7)
The NEUTRAL VOLTAGE displays the calculated neutral RMS phasor given by:
3V 0 = V a + V b + V c
(EQ 6.8)
The POS SEQ VOLTAGE shows the calculated positive-sequence voltage RMS phasor:
2
( V a + aV b + a V c )
V a1 = -------------------------------------------3
for ABC phase sequence
(EQ 6.9)
2
V a1
( V a + a V b + aV c )
= -------------------------------------------3
for ACB phase sequence
The NEG SEQ VOLTAGE shows the calculated negative-sequence voltage RMS phasor:
2
( V a + a V b + aV c )
V a2 = -------------------------------------------- for ABC phase sequence
3
2
V a2
(EQ 6.10)
( V a + aV b + a V c )
= -------------------------------------------- for ACB phase sequence
3
The ZERO SEQ VOLTAGE value shows the calculated zero-sequence current RMS phasor:
V a0 = ( V a + V b + V c ) ⁄ 3
(EQ 6.11)
The AN, BN, CN, AVERAGE PHASE VOLTAGE, LINE A-N VOLTAGE, LINE B-N VOLTAGE, and LINE CN VOLTAGE values are seen only if the VT CONNECTION TYPE setting is “Wye”.
6.3.4
Frequency

FREQUENCY
PATH: ACTUAL VALUES  A2 METERING  FREQUENCY
[]
MESSAGE
SYSTEM FREQ:
0.00 Hz
Range: 0 to 65.00 Hz
FREQ DECAY
RATE:
0.00 Hz/s
Range: –10.00 to 10.00 Hz/s
Frequency is measured with a zero-crossing detector from the Va voltage. This measured
frequency is used for Frequency Tracking (see page Theory of Operation on page 2–5 for
details). Both of these values will read zero if the potential across the Va input terminals is
less than 10 V. When the FREQ DECAY RATE is positive, the frequency is decreasing; when it
is negative, the frequency is increasing.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
6 - 13
A2 METERING
6.3.5
CHAPTER 6: ACTUAL VALUES
Synchronizing
Voltage

PATH: ACTUAL VALUES  A2 METERING  SYNCHRO VOLTAGE
SYNCHRONIZING
VOLTAGE
SYNCHRO VOLTAGE:
0.00 kV
0° Lag
Range: 0 to 655.35 kV, 0 to 359° Lag
MESSAGE
SYNCHRO FREQ:
0.00 Hz
Range: 0 to 65.00 Hz
MESSAGE
SYNCHRO DELTA:
0°
0.00 kV 0.00 Hz
Range: 0 to 359°, 0 to 655.35 kV,
0 to 65.00 Hz
[]
The voltage magnitude, phase angle, frequency, and delta values for the line VT
synchronizing voltage input are displayed as shown above. The SYNCHRO FREQ value
displays the measured frequency of the line VT input; it will be zero if the potential across
the line VT input terminals is less than 10.0 V. The SYNCHRO DELTA value displays the
differences of phase position, voltage magnitude, and frequency between the line VT input
and its corresponding bus VT input.
6.3.6
Power

POWER
PATH: ACTUAL VALUES  A2 METERING  POWER
3Φ REAL POWER:
0.0 MW
Range: –30000 to 30000 kW. See the
table below for details.
MESSAGE
3Φ REACTIVE POWER:
0.0 Mvar
Range: –30000 to 30000 kvar. See the
table below for details.
MESSAGE
3Φ APPARENT POWER:
0.0 MVA
Range: 0 to 30000 kVA. See the table
below for details.
MESSAGE
3Φ POWER FACTOR:
0.00
Range: –0.99 to 1.00
MESSAGE
ΦA REAL POWER:
0.0 MW
Range: –30000 to 30000 kW. See the
table below for details.
MESSAGE
ΦA REACTIVE POWER:
0.0 Mvar
Range: –30000 to 30000 kvar. See the
table below for details.
MESSAGE
ΦA APPARENT POWER:
0.0 MVA
Range: 0 to 30000 kVA. See the table
below for details.
MESSAGE
ΦA POWER FACTOR:
0.00
Range: –0.99 to 1.00
[]
The actual values messages for three-phase and Phase A power are shown above. Similar
power messages follow for Phases B and C.
The relay calculates and displays the real, reactive, and apparent power of the system.
Both three phase and single phase quantities are given. The relationship of these power
quantities is illustrated in the power plane, as shown in the power quantity relationships
figure that follows. If the VT CONNECTION TYPE setpoint “None”, all three phase quantities
are displayed as zero and all single phase quantities disappear. All power quantities autorange to show units appropriate to the nominal power which is defined as:
P N = Phase CT Primary × VT Secondary Voltage × VT Ratio
6 - 14
(EQ 6.12)
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 6: ACTUAL VALUES
A2 METERING
Table 6–4: Power Quantities
6.3.7
Energy

Nominal Power (PN)
Power Units
Resolution
PN < 1 MVA
kW, kvar, kVA, kWhr, kvarhr
1
1 MVA ≤ PN < 10 MVA
MW, Mvar, MVA, MWhr,
Mvarh
0.01
10 MVA ≤ PN
MW, Mvar, MVA, MWhr,
Mvarh
0.1
PATH: ACTUAL VALUES  A2 METERING  ENERGY
ENERGY
[]
Range: 0 to 4 x 106 MWh. See table
above for details.
POSITIVE WATTHOURS:
0.0 MWh
Range: 0 to $4 x 109
MESSAGE
POSITIVE WATTHOUR
COST: $
MESSAGE
NEGATIVE WATTHOURS:
0.0 MWh
MESSAGE
NEGATIVE WATTHOUR
COST: $
MESSAGE
POSITIVE VARHOURS:
0.0 Mvarh
Range: 0 to 4 x 106 Mvarh. See table
above for details.
MESSAGE
NEGATIVE VARHOURS:
0.0 Mvarh
Range: 0 to 4 x 106 Mvarh. See table
above for details.
MESSAGE
ENERGY USE DATA LAST
RESET: Nov 17 2003
0
Range: 0 to 4 x 106 MWh. See table
above for details.
Range: 0 to $4 x 109
0
Range: Date in format shown
The relay uses three phase power quantities to determine total energy consumption. All
energy quantities can be reset to zero with the S1 RELAY SETUP  CLEAR DATA  CLEAR
ENERGY USE DATA setpoint command. Energy cost is also calculated based on the average
billing rate programmed in the S2 SYSTEM SETUP  PWR SYSTEM  COST OF ENERGY
setpoint. Although billing rate structures are usually more complex, these values provide
approximate costs. Energy quantities auto-range to show units appropriate to the nominal
power.
Power quantities in the positive direction are added to the positive values; power quantities
in the opposite direction are added to the negative values.
The 750/760 is not a revenue class meter and cannot be used for billing purposes.
Note
NOTE
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
6 - 15
A2 METERING
6.3.8
CHAPTER 6: ACTUAL VALUES
Demand
Main Menu
PATH: ACTUAL VALUES  A2 METERING  DEMAND

DEMAND
[]
MESSAGE
MESSAGE
MESSAGE
MESSAGE
MESSAGE
MESSAGE

PHASE A
CURRENT
[]

PHASE B
CURRENT
[]

PHASE C
CURRENT
[]

REAL POWER
[]

REACTIVE POWER
[]

APPARENT POWER
[]

LAST RESET
[]
See page 6–16
See page 6–16
See page 6–16
See page 6–16
See page 6–16
See page 6–16
See page 6–16
The relay measures current demand on each phase, and average three phase demand for
real, reactive, and apparent power. These parameters can be monitored to reduce supplier
demand penalties or for statistical metering purposes. Demand calculations are based on
the measurement type selected under S6 MONITORING  DEMAND. For each quantity, the
relay displays the demand over the most recent demand time interval, the maximum
demand since the last maximum demand reset, and the time and date stamp of this
maximum demand value. Maximum demand quantities can be reset to zero with the S1
RELAY SETUP  CLEAR DATA  CLEAR MAX DEMAND DATA setpoint command.
Phase A Current to Apparent Power demand
PATH: ACTUAL VALUES  A2 METERING  DEMAND  PHASE A CURRENT(APPARENT PWR)

PHASE A
CURRENT
LAST PHASE A CURRENT
DEMAND:
0 A
Range: 0 to 65535 A
MESSAGE
MAX PHASE A CURRENT
DEMAND:
0 A
Range: 0 to 65535 A
MESSAGE
LAST PHASE A CURRENT
DATE: Mar 16 1997
Range: Date in format shown
MESSAGE
LAST PHASE A CURRENT
TIME: 16:30:00
Range: Time in format shown
[]
The actual values for Phase A Current Demand are shown above. The actual values
displays for Phase B Current, Phase C Current, Real Power, Reactive Power, and Apparent
Power Demand are similar to those above.
Last Reset Date
PATH: ACTUAL VALUES  A2 METERING  DEMAND  LAST RESET DATE

6 - 16
LAST RESET
[]
DEMAND DATA LAST
RESET: Mar 16 1997
Range: Date in format shown
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 6: ACTUAL VALUES
A2 METERING
This message displays the last date the maximum demand data was cleared. If the date
has never been programmed, this relay will display “Unavailable”.
6.3.9
Analog Input

ANALOG INPUT
PATH: ACTUAL VALUES  A2 METERING  ANALOG INPUT
ANALOG INPUT:
0 μA
Range: 0 to 65535
MESSAGE
ANALOG INPUT:
0 μA
Range: 0 to 65535
MESSAGE
ANALOG INPUT:
0 μA
[]
/min
Range: 0 to 65535
/hour
The relay provides the ability to monitor any external quantity via an auxiliary current input
called the analog input.
These first actual value message displays the scaled value of the analog input, as defined
in S6 MONITORING  ANALOG INPUT  ANALOG INPUT SETUP. In this actual values display,
the name programmed in setpoint message S6 MONITORING  ANALOG INPUT  ANALOG
INPUT SETUP  A/I NAME will be displayed instead of the factory default “A/I”. The name of
the units programmed in the setpoint message S6 MONITORING  ANALOG INPUT 
ANALOG INPUT SETUP  A/I UNITS will be displayed instead of the factory default “µA”.
The subsequent actual value messages display the analog input rate of change in per
minutes and per hour.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
6 - 17
A3 MAINTENANCE
CHAPTER 6: ACTUAL VALUES
6.4
6.4.1
Trip Counters

A3 Maintenance
PATH: ACTUAL VALUES  A3 MAINTENANCE  TRIP COUNTERS
TRIP COUNTERS
BREAKER TRIPS:
0
Range: 0 to 65535
MESSAGE
GND OC TRIPS:
0
Range: 0 to 65535
MESSAGE
SENSTV GND OC TRIPS:
0
Range: 0 to 65535
MESSAGE
NEUTRAL OC TRIPS:
0
Range: 0 to 65535
MESSAGE
NEG SEQ OC TRIPS:
0
Range: 0 to 65535
MESSAGE
1Φ PHASE OC TRIPS:
0
Range: 0 to 65535
MESSAGE
2Φ PHASE OC TRIPS:
0
Range: 0 to 65535
MESSAGE
3Φ PHASE OC TRIPS:
0
Range: 0 to 65535
TRIP COUNTERS LAST
RESET: Nov 17 2003
Range: Date in format shown
[]
The total number of trips since the TRIP COUNTERS LAST RESET date are displayed. Trip
counters are used for scheduling inspections on equipment, for performing qualitative
analysis of system problems, and for spotting trends. The BREAKER TRIPS counter is
incremented every time an open breaker status is detected. If applicable, one of the more
specific trip counters available will accumulate when a Trip condition is generated. A trip
condition is generated by any feature or input which signals the Trip Relay to operate. If
the logic input assigned to the Block Breaker Statistics function is active, when a trip
condition is generated, the trip counters will not be incremented. Trip counter data can be
reset to zero with the S1 RELAY SETUP  INSTALLATION  RESET TRIP COUNTER DATA
setpoint.
6 - 18
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 6: ACTUAL VALUES
6.4.2
Arcing Current

A3 MAINTENANCE
PATH: ACTUAL VALUES  A3 MAINTENANCE  ARCING CURRENT
ARCING CURRENT
[]
TOTAL ARCING CURRENT
ΦA:
0 kA2-cycle
MESSAGE
TOTAL ARCING CURRENT
ΦB:
0 kA2-cycle
MESSAGE
TOTAL ARCING CURRENT
ΦC:
0 kA2-cycle
ARCING CURRENT LAST
RESET: Nov 17 2003
Range: 0 to 65535 kA2-cycle
Range: 0 to 65535 kA2-cycle
Range: 0 to 65535 kA2-cycle
Range: Date in format shown
The accumulated Phase A, B, and C arcing currents (in kA2-cycles) since the ARCING
CURRENT LAST RESET date are displayed. The relay calculates an estimate of the per-phase
wear on the breaker contacts. Arcing current data can be reset to zero with the S1 RELAY
SETUP  INSTALLATION  RESET ARCING CURRENT DATA setpoint command.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
6 - 19
A4 EVENT RECORDER
CHAPTER 6: ACTUAL VALUES
6.5
6.5.1
Event Records

A4 Event Recorder
PATH: ACTUAL VALUES  A4 EVENT RECORDER  E001(128)
TIME OF EVENT:
16:30:00.000
Range: Time in format shown
MESSAGE
<Event_Type>:
<Cause_of_Event>
Range: See tables on pages –21 and –
22.
MESSAGE
PHASE A CURRENT:
0 A
0° Lag
Range: 0 to 65535 A, 0 to 359° Lag
MESSAGE
PHASE B CURRENT:
0 A
0° Lag
Range: 0 to 65535 A, 0 to 359° Lag
MESSAGE
PHASE C CURRENT:
0 A
0° Lag
Range: 0 to 65535 A, 0 to 359° Lag
MESSAGE
GND CURRENT:
0 A
0° Lag
Range: 0 to 65535 A, 0 to 359° Lag
MESSAGE
SENSTV GND CURRENT:
0.00 A
0° Lag
Range: 0 to 655.35 A, 0 to 359° Lag
MESSAGE
LINE A-B VOLTAGE:
0.00 kV
0° Lag
Range: 0 to 65535 kV, 0 to 359° Lag
MESSAGE
LINE B-C VOLTAGE:
0.00 kV
0° Lag
Range: 0 to 65535 kV, 0 to 359° Lag
MESSAGE
LINE C-A VOLTAGE:
0.00 kV
0° Lag
Range: 0 to 65535 kV, 0 to 359° Lag
MESSAGE
PHASE A-N VOLTAGE:
0.00 kV
0° Lag
Range: 0 to 65535 kV, 0 to 359° Lag
MESSAGE
PHASE B-N VOLTAGE:
0.00 kV
0° Lag
Range: 0 to 65535 kV, 0 to 359° Lag
MESSAGE
PHASE C-N VOLTAGE:
0.00 kV
0° Lag
Range: 0 to 65535 kV, 0 to 359° Lag
MESSAGE
SYSTEM FREQUENCY:
0.00 Hz
Range: 0 to 90.00 Hz
MESSAGE
SYNCHRO VOLTAGE:
0.00 kV
0° Lag
Range: 0 to 65535 kV, 0 to 359° Lag
MESSAGE
SYNCHRO FREQUENCY:
0.00 Hz
Range: 0 to 90.00 Hz
ANALOG INPUT:
0 μA
Range: 0 to 65535 Analog Input Units
E128: Nov 17/03 []
<Cause>
The 750/760 has an event recorder which runs continuously, capturing and storing the last
512 events. All event recorder information is stored in non-volatile memory so the
information is maintained after losing relay control power. The last 512 events are
displayed from newest to oldest event. Each event has a header message containing a
6 - 20
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 6: ACTUAL VALUES
A4 EVENT RECORDER
summary of the event that occurred. Each event is assigned an event number equal to the
number of events that have occurred since the recorder was cleared; the event number is
incremented for each new event. Event recorder data can be cleared with the S1 RELAY
SETUP  CLEAR DATA  CLEAR EVENT RECORDER DATA setpoint.
Event information is gathered at the instant the event occurs; as such, the current and
voltage readings may reflect the transient nature of the event as opposed to steady state
values. All messages pertaining to phase voltages AN, BN, and CN are only displayed if VT
CONNECTION TYPE is programmed to “Wye”. If VT CONNECTION TYPE is programmed to
“Delta”, line voltages AB, BC, and CA are displayed.
Events are organized into several different types as shown in the table below. Several event
types can be filtered out in order to save space in the event recorder (see Event Recorder
on page 5–14 for additional details on event filtering). For every event type there are a
number of possible causes. The Cause of Events table lists all the event causes according
to which event types they can generate.
The following symbols are used in the description of the event messages: <Φ> represents
the phases involved (e.g. ΦBC) in the event if applicable and <ON> represents whether the
logic input is asserted (ON) or not asserted (OFF)
Table 6–5: Event Types
Event Type
Display
Description
General Events
None
Events that occur when a specific
operation takes place
Pickup Events
PICKUP: <Φ>
These are events that occur when a
protection element picks up and starts
timing
TRIP: <Φ>
These are events that occur when an
element whose function has been
programmed to "Trip" or "Trip & AR"
operates.
ALARM: <Φ>
These are events that occur when an
element whose function has been
programmed to "Alarm" operates or
drops out.
LATCHED ALARM:
<Φ>
These are events that occur when an
element whose function has been
programmed to "Latched Alarm"
operates or drops out.
Control Events
CONTROL: <Φ>
These are events that occur when an
element whose function has been
programmed to "Control" operates or
drops out.
Dropout Events
DROPOUT:
These are events that occur when a
protection element drops out after a
corresponding pickup event.
Contact Events
INPUT C <ON>:
These are events that occur when a
contact input is either asserted or deasserted.
Trip Events
Alarm Events
Latched Alarm
Events
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
6 - 21
A4 EVENT RECORDER
CHAPTER 6: ACTUAL VALUES
Table 6–5: Event Types
Event Type
Display
Description
These are events that occur when a
virtual input is either asserted or deasserted.
Virtual Input
Events
INPUT V <ON>:
Contact and
Virtual Input
Events
INPUT CV <ON>:
These are events that occur when both
a contact input and virtual input is
either asserted or de-asserted.
SELF-TEST
WARNING:
These are events that occur when a
self-test warning is detected or one of
the manual testing
Self-Test
Warning Events
The event causes are listed alphabetically by type of event in the following table.
Table 6–6: Cause of Events
General Event Causes
Autoreclose Reset
Breaker Closed
Breaker Not
Connected
Breaker Open
Clear Energy Use
Clear Event Record
Clear Max Demand
Close Breaker
Cls From Transfer
Control Power Off
Control Power On
Group 1 to 4 Active
Open Breaker
Reclosure 1 to 4
Reclosure Lockout
Reset
Reset AR Count
Reset AR Shot Rate
Reset Arc Current
Reset Trip Counter
Set Date
Set Time
Transfer Not Ready
Trigger Data Log
Shots Reduced to 1(3) Shots Reduced to L/
O
Trigger Trace
Transfer Initiated
Trip From Transfer
Pickup, Trip, Alarm, Latched Alarm, and Control Event Causes
Analog Rate 1 to 2
Analog Threshold 1/
2
Apparent Power
Demand
Arcing Current
Autoreclose Rate
Breaker Failure
Breaker Operation
Bus Undervoltage 1
to 2
Close Coil Monitor 1
Cold Load P/U Block
Current Demand
Frequency Decay
Ground Dir Reverse
Ground Inst OC
Ground Time OC
Line Undervoltage 3
to 4
Manual Close Block
Neg Seq Dir Reverse
Neg Seq Inst OC
Neg Seq Time OC
Neg Seq Voltage
Neutral Current
Level
Neutral Dir Reverse
Neutral
Displacement
Neutral Inst OC 1/2
Neutral Time OC 1 /
2
Out of Sync
Overfrequency
Overvoltage 1 and 2
Phase Current Level
1
The coil monitor name as programmed is displayed.
The pulse output quantity name as programmed is displayed.
3
For User Inputs A through T, the user-defined name is displayed
2
6 - 22
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 6: ACTUAL VALUES
A4 EVENT RECORDER
Table 6–6: Cause of Events
General Event Causes
Phase Dir Reverse
Phase Inst OC 1 and
2
Phase Time OC 1
Phase Time OC 2
Power Factor 1
Power Factor 2
Pulse Output 2
Reactive Power
Demand
Real Power Demand
Sens Gnd Dir
Reverse
Senstv Gnd Time OC
Senstv Gnd Inst OC
Trip Coil Monitor
Trip Counter
UFreq Restore Init
Underfrequency 1
Underfrequency 2
User Input A to T 3
UVolt Restore Init
VT Failure
Logic Input Event Causes
52a Contact
52b Contact
Block 1 Trip
Block 2 Close
Block All OC
Block Freq Decay
Block Gnd Inst OC
Block Gnd Time OC
Block Ground OC
Block Neg Seq Inst
Block Neg Seq Time
Block Neg Seq Volt
Block Neutral Disp
Block Neutral Inst
OC 1
Block Neutral Inst
OC 2
Block Neutral OC
Block Neutral Time
OC 1
Block Neutral Time
OC 2
Block Phase Inst OC
1
Block Phase Inst OC
2
Block Phase OC
Block Phase Time
OC 1
Block Phase Time
OC 2
Block Reclosure
Block Reset
Block Restoration
Block Sens Gnd Inst
OC
Block Sens Gnd OC
Block Sens Gnd
Time OC
Block Transfer
Block Trip Count
Block Undervolt 1 to
4
Block Underfreq 1
and 2
Breaker Connected
Bus Tie Closed
Bus Tie Connected
Bypass
Synchrocheck
Cancel Reclosure
Cls From Incomer 1
Cls From Incomer 2
Cold Load Pickup
Incomer 1 Closed
Incomer 2 Closed
Initiate Reclosure
Local Mode
Remote Close
Remote Open
Remote Reset
Selected To Trip
Setpoint Group 2
Setpoint Group 3
Setpoint Group 4
Simulate Fault
Source Trip
Start Demand
Interval
Trigger Data Log
Trigger Trace
User Input A to T 3
UV On Other Source
Xfmr Lockout
Warning Event Causes
A/D Virtual Ground
Analog Output +32V
Clock Not Set
Dry Contact +32V
EEPROM Corrupt
Factory Service
FLASH Corrupt
Force Analog Out
Force Relays
Internal RS485
Internal Temp
IRIG-B Failure
Not Calibrated
Pickup Test
Prototype Software
1
The coil monitor name as programmed is displayed.
The pulse output quantity name as programmed is displayed.
3
For User Inputs A through T, the user-defined name is displayed
2
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
6 - 23
A4 EVENT RECORDER
6.5.2
Last Reset
Date

LAST RESET
DATE
CHAPTER 6: ACTUAL VALUES
PATH: ACTUAL VALUES  A4 EVENT RECORDER  LAST RESET DATE
[]
EVENT RECORDER LAST
RESET: Mar 16 1997
Range: Date in format shown
After the header message for the last event is a message indicating when the event
recorder was last cleared.
6 - 24
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 6: ACTUAL VALUES
A5 PRODUCT INFO
6.6
6.6.1
Technical
Support

TECHNICAL
SUPPORT
A5 Product Info
PATH: ACTUAL VALUES  A5 PRODUCT INFO  TECHNICAL SUPPORT
[]
GE Digital Energy
650 Markland Street
Range: The address for GE Digital
Energy is indicated here.
MESSAGE
Markham, Ontario
Canada, L6C 0M1
MESSAGE
Tel: +1 905 927 7070
Fax: +1 905 927 5098
Range: Telephone and fax numbers for
GE Digital Energy are shown.
Internet Address:
www.gedigitalenergy.com
Range: The GE Digital Energy web page
address is indicated here.
This page has information on where to obtain technical support for your relay.
6.6.2
Revision Codes

PATH: ACTUAL VALUES  A5 PRODUCT INFO  REVISION CODES
REVISION CODES
GE Digital Energy
750 REVISION 7.00
Range: The product name and
software revision are indicated.
MESSAGE
HARDWARE REVISION:
K
Range: Hardware revision of the relay.
MESSAGE
SOFTWARE REVISION:
700
Range: Displays the software revision
of the relay.
MESSAGE
VERSION NUMBER:
000
Range: Displays the version number
and any relay modifications
MESSAGE
ORDER CODE: 760P5-G5-S5-HI-A20-R-E
Range: Displays the relay order code
and installed options.
MESSAGE
BOOTWARE REVISION:
500
Range: Displays the relay’s boot
software revision
MESSAGE
SERIAL NUMBER:
A2831234
Range: Displays the serial number of
the relay.
MANUFACTURING DATE:
Nov 17 2004
Range: Displays the manufacture date
in the format shown.
[]
This page specifies hardware revision and configuration, software revision, and serial
number. This information is primarily intended for GE Digital Energy service personnel.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
6 - 25
A5 PRODUCT INFO
6.6.3
Calibration
Dates

CALIBRATION
DATES
CHAPTER 6: ACTUAL VALUES
PATH: ACTUAL VALUES  A5 PRODUCT INFO  CALIBRATION DATES
[]
FACTORY CALIBRATION
DATE: Nov 17 2004
Range: Displays the initial calibration
date in the format shown.
LAST CALIBRATION
DATE: Nov 17 2004
Range: Displays the last calibration
date in the format shown.
This information is primarily intended for GE Multilin service personnel.
6 - 26
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
GE
Digital Energy
750/760 Feeder Management
Relay
Chapter 7: Commissioning
Commissioning
7.1
7.1.1
Safety
Precautions
Overview
Pay special attention to all the safety precautions listed below.
HAZARD may result if the product is not used for its intended purposes
Dangerously high voltages are present on the rear terminals of the relay. The voltages
are capable of causing DEATH or SERIOUS INJURY. Use extreme caution and follow all
safety rules when handling, testing, or adjusting the equipment.
Do not open the secondary circuit of a live CT, since the high voltage produced is
capable of causing DEATH or SERIOUS INJURY, or damage to the CT insulation.
The relay uses components that are sensitive to electrostatic discharges. When
handling the unit, care must be taken to avoid contact with terminals at the rear of the
relay.
Ensure that the control power applied to the relay, and the AC current and voltage
input, match the ratings specified on the relay nameplate. Do not apply current to the
CT inputs in excess of the Time × Current specified limits.
Ensure that the Logic Input wet contacts are connected to voltages less than the
maximum voltage specification of 300 V DC.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
7-1
OVERVIEW
7.1.2
Requirements
CHAPTER 7: COMMISSIONING
The following procedures can be used to verify the proper operation of the 750/760 Feeder
Management Relay. Although not a total functional verification, the tests in this chapter
check the major operating points. Before commissioning the relay, users should read
Chapter 3 which provides important information about wiring, mounting, and safety
concerns. One should also become familiar with the relay as described in Chapters 2 and 5.
The test procedures outlined in this section are for field verification that the relay is
operational and programmed as required for the application. It is not necessary to field
test every characteristic of every relay feature. The various features are implemented in
software, which is thoroughly tested at the factory. Our recommendation is to field test all
of the input, display, and output hardware, and features which are to be operational in the
specific application.
The setpoints considered for the measurement of parameters and the operation of
features are shown on the logic diagrams. All settings must be set to the application
requirement by the user before beginning the tests. To facilitate testing it is recommended
that all functions be initially set to “Disabled”. Every feature which will be used in the
application should be set to the required function for the test, then returned to “Disabled”
at completion. Each feature can then be testing without complications caused by
operations of other features. At the completion of all tests each feature is then set as
required.
The procedures for testing of common operations will not be repeated in every test. The
common features, and the test procedure location are as follows:
• Thermal Exponential Demand Characteristic: Measurement of Current Demand
• Block Interval Demand Characteristic: Measurement of Current Demand
• Rolling Interval Demand Characteristic: Measurement of Current Demand
• Feature Function as “Trip”, “Alarm”, or “Control”: Phase Time Overcurrent 1
• Fixed Delay Timing: Phase Time Overcurrent 1
• Front Panel RESET Key Resetting: Phase Time Overcurrent 1
• Logic Input Resetting: Phase Time Overcurrent 1
• Feature Blocking from Logic Inputs: Phase Time Overcurrent 1
• Element Operation of Output Relays: Phase Time Overcurrent 1
• Number Of Faulted Phases: Phase Instantaneous Overcurrent 1
• Feature Function as “Trip + AR”: Autoreclose (760 Only)
We also recommend that the procedures outlined in Placing the Relay In Service on page
7–92 be performed for all installations to verify proper operation and function of the
equipment.
7.1.3
Conventions
The following conventions are used for the remainder of this chapter:
• It is assumed the VT and CT inputs are wired in accordance with the Typical Wiring
Diagram on page 3–10. With these connections, and assumed where phase angles
are noted, a unity power factor current in the primary circuit flows into the relay
marked terminal, with no phase shift with respect to the corresponding phaseneutral voltage.
• The phase rotation of the relay test set is ABC.
• A current that lags a voltage has a positive phase angle.
• Phase A to neutral voltage is indicated by Van (arrowhead on the “a”).
7-2
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 7: COMMISSIONING
OVERVIEW
• Phase A to B voltage is indicated by Vab (arrowhead on the “a”).
• The sign convention for power parameters is as shown in FIGURE 6–3: Power
Quantity Relationships on page 6–10.
• The actual value display at the beginning of some sections is the display for the
measured parameter. All actual values are mentioned with their “path” as a means
of specifying the relative location of a particular message with regards to its parent
messages. For instance, the analog input, which in the message structure is
located under actual values page A2 METERING as the first message under
subheading ANALOG INPUT , would be written as: A2 METERING  ANALOG INPUT
 ANALOG INPUT .
7.1.4
Test
Equipment
Excluding data acquisition testing, tests may be performed using the simulation feature,
eliminating the need of external AC voltage and current inputs. System parameters, such
as current and voltage information, are entered as setpoints. When placed in simulation
mode, the relay suspends reading actual AC inputs and uses the programmed phasors to
generate sample values that are placed in the Trace Memory. All metering calculations and
logic associated with protection, monitoring, and control, are performed normally, using
phasors calculated from the samples placed in the memory instead of phasors generated
from the input parameter data acquisition system. The advantage of simulation is that all
metering calculations can be verified without the inaccuracies associated with current
and voltage sources.
If simulation is not used, the following equipment is necessary to perform any test included
in this chapter:
General Purpose:
• Three-phase variable AC current and voltage source (V, A, phase, Hz).
• Three-phase power multimeter (V, A, phase, Hz, W, var, VA, Wh, varh, PF).
• Variable DC mA source.
• An accurate timing device and multimeters.
Specific Purpose:
• Synchrocheck requires two single phase variable voltage sources with adjustable
frequency and phase.
• Underfrequency requires a dynamic relay test set with at least two preset modes.
• Distance-to-fault: requires a dynamic relay test set with at least three preset
modes.
• Analog Input Rate of Change requires a DC current generator with the capacity to
generate current ramps adjustable for durations from 1 minute to 2 hours, and
from 0 to 20 mA.
Optional:
• PC running the EnerVista 750/760 Setup software.
7.1.5
Installation
Checks
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
 Check the relay phase current inputs, specified on the nameplate, are
correct for the connected current transformers.
7-3
OVERVIEW
CHAPTER 7: COMMISSIONING
 Check the relay ground current input, specified on the nameplate, is
correct for the connected CT (if applicable).
 Check that the relay auxiliary voltage, specified on the nameplate, is
correct for the supplied voltage.
 Check that the installed relay agrees with the drawings, particularly the
Analog Output range.
 Check that the external wiring is correct.
 Check that all grounding terminals of the relay are properly connected
to the ground bus.
7.1.6
Wiring
Diagrams
The relay test wiring for both “Delta” and “Wye” connections are shown below.
START
TRIGGER
START
Va
Vc
–
–
–
G5 Va
H5
1 TRIP
Vb
G6 Vc
Vn
H6
3φ VARIABLE
SOURCE
G7
2 CLOSE
Vcom
3 ALARM
Va Vb Vc Vn
Ib
Ic
–
–
–
–
–
–
G8
Ia
Ib
H8
Ic
G9
POWER
MULTIMETER
H9
G10
H10
+
VARIABLE
DCmA SOURCE
A1
A2
STOP
TRIGGER
F2
E3
INTERVAL
TIMING DEVICE
F3
F4
Ω
E5
Ib
MULTIMETER
750/760
C10
Ic
Ig
ANALOG
INPUT
H12 CONTROL
H11 POWER
Ia
E2
E4
Ia
+
-
G11 FILTER GND
Vb
Vb
G12 SAFETY GND
Va
Vc
C11
BUS
818776A6.CDR
FIGURE 7–1: Relay Test Wiring – Wye Connection
7-4
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 7: COMMISSIONING
OVERVIEW
START
TRIGGER
START
Va
Vc
–
–
–
G5 Va
H5
1 TRIP
Vb
G6 Vc
Vn
H6
3φ VARIABLE
SOURCE
G7
2 CLOSE
Vcom
3 ALARM
Va Vb Vc Vn
Ib
Ic
–
–
–
–
–
–
G8
Ia
Ib
H8
Ic
G9
POWER
MULTIMETER
H9
G10
H10
+
VARIABLE
DCmA SOURCE
A1
A2
STOP
TRIGGER
F2
E3
INTERVAL
TIMING DEVICE
F3
F4
Ω
E5
Ib
MULTIMETER
750/760
C10
Ic
Ig
ANALOG
INPUT
H12 CONTROL
H11 POWER
Ia
E2
E4
Ia
+
-
G11 FILTER GND
Vb
Vb
G12 SAFETY GND
Va
Vc
C11
BUS
818777A6.CDR
FIGURE 7–2: Relay Test Wiring – Delta Connection
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
7-5
INPUTS/OUTPUTS
CHAPTER 7: COMMISSIONING
7.2
7.2.1
Logic / Virtual
Inputs 1 to 14
Inputs/Outputs
Actual Values Display
For these first tests, the INPUT 1 (14) ASSERTED LOGIC setpoints should be programmed as
“Closed | Von”. Under the A1 STATUS  VIRTUAL INPUTS  LOGIC INPUT 1 (14) subheading,
 Turn on this input and check that the display shows this state.
 Turn off this input and check that the display shows this state.
Under the A1 STATUS  HARDWARE INPUTS  CONTACT 1 (14) STATE subheading:
 Close the contact connected to this input and check that the display
shows this state.
 Open the contact connected to this input and check that the display
shows this state.
User Input A Setpoint set to “Alarm”
 Set all inputs 1 through 14, both contact and virtual, to the de-asserted
state.
 Enter (example) settings under subheading S3 LOGIC INPUTS  USER
INPUT A
USER INPUT A NAME: “User Input A”
USER INPUT A SOURCE: “Input 1”
USER INPUT A FUNCTION: “Alarm”
USER INPUT A RELAYS (3-7): “3----”
USER INPUT A DELAY: “0.00 s”
1.
For INPUT ASSERTED LOGIC setpoints set to “Contact Close”,
 Check that there is no logic input diagnostic message on the display.
 Set the monitored contact for the logic input programmed in setpoint
USER INPUT A SOURCE to the closed state.
Note that the corresponding virtual input will have no affect.
 Check that the diagnostic message, either User Input A or the name
programmed in setpoint User Input A Name, appears on the display
with the Auxiliary LED and relay activated.
Check in the Event Recorder that the selected function has been
invoked.
 Set the monitored contact for the logic input programmed in setpoint
USER INPUT A SOURCE to the open state.
Again note that the corresponding virtual input will have no affect.
 Check that the diagnostic message is removed from the display with the
Auxiliary LED and relay deactivated.
 Repeat the last 3 steps for all functions programmed to be asserted by a
Contact Close input.
2.
For INPUT ASSERTED LOGIC setpoints set to “Contact Open”:
 Check that there is no logic input diagnostic message on the display.
7-6
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 7: COMMISSIONING
INPUTS/OUTPUTS
 Set the monitored contact for the logic input programmed in the USER
INPUT A SOURCE setpoint to the open state.
Note that the corresponding virtual input will have no affect.
 Check that the diagnostic message, either User Input A or the name
programmed in setpoint User Input A Name, appears on the display
with the Auxiliary LED and relay activated.
Check in the Event Recorder that the selected function has been
invoked.
 Set the monitored contact for the logic input programmed in setpoint
User Input A Source to the closed state.
Again note that the corresponding virtual input will have no affect.
 Check that the diagnostic message is removed from the display with the
Auxiliary LED and relay deactivated.
 Repeat the last 3 steps for all functions programmed to be asserted by a
Contact Open input.
3.
For INPUT ASSERTED LOGIC setpoints set to “Virtual On”:
 Check that there is no logic input diagnostic message on the display.
 Set the monitored virtual input for the logic input programmed in
setpoint message USER INPUT A SOURCE to the on state.
Note that the corresponding contact input will have no affect.
 Check that the diagnostic message, either User Input A or the name
programmed in setpoint User Input A Name, appears on the display
with the Auxiliary LED and relay activated.
Check in the Event Recorder that the selected function has been
invoked.
 Set the virtual input for the logic input programmed in setpoint message
USER INPUT A SOURCE to the off state.
Again note that the corresponding contact input will have no affect.
 Check that the diagnostic message is removed from the display with the
Auxiliary LED and relay deactivated.
 Repeat last 3 steps for all functions programmed to be asserted by a
Virtual On input.
4.
For INPUT ASSERTED LOGIC setpoints set to “Virtual Off”:
 Check that there is no logic input diagnostic message on the display.
 Set the monitored virtual input for the logic input programmed in
setpoint message User Input A Source to the off state.
Note that the corresponding contact input will have no affect.
 Check that the diagnostic message, either “User Input A” or the name
programmed in setpoint USER INPUT A NAME, appears on the display
with the Auxiliary LED and relay activated.
Check in the Event Recorder that the selected function has been
invoked.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
7-7
INPUTS/OUTPUTS
CHAPTER 7: COMMISSIONING
 Set the virtual input for the logic input programmed in setpoint message
USER INPUT A SOURCE to the on state.
Again note that the corresponding contact input will have no effect.
 Check that the diagnostic message is removed from the display with the
Auxiliary LED and relay deactivated.
 Repeat the last 3 steps for all functions programmed to be asserted by a
Virtual Off input.
5.
For INPUT ASSERTED LOGIC setpoints set to “Closed & Von”:
 Check that there is no logic input diagnostic message on the display.
 Set the monitored contact for the logic input programmed in setpoint
message User Input A Source to the open state and the virtual input to
the off state.
Check that no diagnostic message is on the display with the 3 auxiliary
LED and relay deactivated.
 Set the monitored contact to the closed state with the virtual input
remaining in the off state.
Check that no diagnostic message is on the display with the Auxiliary
LED and relay deactivated.
 Leave the monitored contact in the closed state and put the virtual input
in the on state.
Check that the diagnostic message, either “User Input A” or the name
programmed in USER INPUT A NAME, appears on the display with the
Auxiliary LED and relay activated.
Check the event recorder that the selected function has been invoked.
 Set the monitored contact to the open state and the virtual input to the
off state.
Check that the diagnostic message is removed from the display with the
Auxiliary LED and relay deactivated.
 Repeat last 3 steps for all functions programmed to be asserted by a
“Closed & Von” input.
6.
For INPUT ASSERTED LOGIC setpoints set to “Closed & Voff”:
 Check that there is no logic input diagnostic message on the display.
 Set the monitored contact for the logic input programmed in setpoint
message User Input A Source to the open state and the virtual input to
the on state.
Check that no diagnostic message is on the display with the 3 auxiliary
LED and relay deactivated.
 Set the monitored contact to the closed state with the virtual input
remaining in the on state.
Check that no diagnostic message is on the display with the Auxiliary
LED and relay deactivated.
 Leave the monitored contact in the closed state and put the virtual input
in the off state.
Check that the diagnostic message, either User Input A or the name
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programmed in setpoint User Input A Name, appears on the display
with the Auxiliary LED and relay activated.
Check in the Event Recorder that the selected function has been
invoked.
 Set the monitored contact to the open state and the virtual input to the on
state.
Check that the diagnostic message is removed from the display with the
Auxiliary LED and relay deactivated.
 Repeat last 3 steps for all functions programmed to be asserted by a
Closed & Voff input.
7.
For INPUT ASSERTED LOGIC setpoints set to “Open & Von”:
 Check that there is no logic input diagnostic message on the display.
 Set the monitored contact for the logic input programmed in setpoint
message User Input A Source to the closed state and the virtual input to
the off state.
Check that no diagnostic message is on the display with the Auxiliary
LED and relay deactivated.
 Set the monitored contact to the open state with the virtual input
remaining in the off state.
Check that no diagnostic message is on the display with the Auxiliary
LED and relay deactivated.
 Leave the monitored contact in the open state and put the virtual input in
the on state.
Check that the diagnostic message, either User Input A or the name
programmed in setpoint User Input A Name, appears on the display
with the Auxiliary LED and relay activated.
Check in the Event Recorder that the selected function has been
invoked.
 Set the monitored contact to the closed state and the virtual input to the
off state.
Check that the diagnostic message is removed from the display with the
Auxiliary LED and relay deactivated.
 Repeat last 3 steps for all functions programmed to be asserted by a
Open & Von input.
8.
For INPUT ASSERTED LOGIC setpoints set to “Open & Voff”:
 Check that there is no logic input diagnostic message on the display.
 Set the monitored contact for the logic input programmed in setpoint
message User Input A Source to the closed state and the virtual input to
the on state.
Check that no diagnostic message is on the display with the 3 auxiliary
LED and relay deactivated.
 Set the monitored contact to the open state with the virtual input
remaining in the on state.
Check that no diagnostic message is on the display with the Auxiliary
LED and relay deactivated.
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 Leave the monitored contact in the open state and put the virtual input in
the off state.
Check that the diagnostic message, either User Input A or the name
programmed in setpoint User Input A Name, appears on the display
with the Auxiliary LED and relay activated.
Check in the Event Recorder that the selected function has been
invoked.
 Set the monitored contact to the closed state and the virtual input to the
on state.
Check that the diagnostic message is removed from the display with the
Auxiliary LED and relay deactivated.
 Repeat steps 10.3 through 10.5 for all functions programmed to be
asserted by a Open & Voff input.
9.
For INPUT ASSERTED LOGIC setpoints set to “Closed | Von”:
 Check that there is no logic input diagnostic message on the display.
 Set the monitored contact for the logic input programmed in setpoint
message User Input A Source to the closed state and the virtual input to
the off state.
Check that the diagnostic message, either User Input A or the name
programmed in setpoint User Input A Name, appears on the display
with the Auxiliary LED and relay activated.
Check in the Event Recorder that the selected function has been
invoked.
 Leave the monitored contact in the closed state and put the virtual input
in the on state.
Check that the diagnostic message, the Auxiliary LED and relay remain
activated.
 Set the monitored contact to the open state and leave the virtual input in
the on state.
Check that the diagnostic message, the Auxiliary LED and relay remain
activated.
 Leave the monitored contact in the open state and put the virtual input in
the off state.
Check that the diagnostic message is removed from the display with the
3 Auxiliary LED and relay deactivated.
 Repeat last 3 steps for all functions programmed to be asserted by a
Closed | Von input.
10. For INPUT ASSERTED LOGIC setpoints set to “Closed | Voff”:
 Check that there is no logic input diagnostic message on the display.
 Set the monitored contact for the logic input programmed in setpoint
message User Input A Source to the closed state and the virtual input to
the on state.
Check that the diagnostic message, either User Input A or the name
programmed in setpoint User Input A Name, appears on the display
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with the Auxiliary LED and relay activated.
Check in the Event Recorder that the selected function has been
invoked.
 Leave the monitored contact in the closed state and put the virtual input
in the off state.
Check that the diagnostic message, the Auxiliary LED and relay remain
activated.
 Set the monitored contact to the open state and leave the virtual input in
the off state.
Check that the diagnostic message, the Auxiliary LED and relay remain
activated.
 Leave the monitored contact in the open state and put the virtual input in
the on state.
Check that the diagnostic message is removed from the display with the
Auxiliary LED and relay deactivated.
 Repeat last 3 steps for all functions programmed to be asserted by a
Closed | Voff input.
11. For INPUT ASSERTED LOGIC setpoints set to “Open | Von”:
 Set the monitored contact for the logic input programmed in setpoint
message User Input A Source to the open state and the virtual input to
the off state.
Check that the diagnostic message, either User Input A or the name
programmed in setpoint User Input A Name, appears on the display
with the Auxiliary LED and relay activated.
Check in the Event Recorder that the selected function has been
invoked.
 Leave the monitored contact in the open state and put the virtual input in
the on state.
Check that the diagnostic message, the Auxiliary LED and relay remain
activated.
 Set the monitored contact to the closed state and leave the virtual input
in the on state.
Check that the diagnostic message, the Auxiliary LED and relay remain
activated.
 Leave the monitored contact in the closed state and put the virtual input
in the off state.
Check that the diagnostic message is removed from the display with the
Auxiliary LED and relay deactivated.
 Repeat last 3 steps for all functions programmed to be asserted by a
Open | Von input.
12. For INPUT ASSERTED LOGIC setpoints set to “Open | Voff”:
 Check that there is no logic input diagnostic message on the display.
 Set the monitored contact for the logic input programmed in setpoint
message User Input A Source to the open state and the virtual input to
the on state.
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Check that the diagnostic message, either User Input A or the name
programmed in setpoint User Input A Name, appears on the display
with the Auxiliary LED and relay activated.
Check in the Event Recorder that the selected function has been
invoked.
 Leave the monitored contact in the open state and put the virtual input in
the off state.
Check that the diagnostic message, the Auxiliary LED and relay remain
activated.
 Set the monitored contact to the closed state and leave the virtual input
in the off state.
Check that the diagnostic message, the Auxiliary LED and relay remain
activated.
 Leave the monitored contact in the closed state and put the virtual input
in the on state.
Check that the diagnostic message is removed from the display with the
Auxiliary LED and relay deactivated.
 Repeat last 3 steps for all functions programmed to be asserted by a
Open| Voff input.
13. For INPUT ASSERTED LOGIC setpoints set to “Closed X Von”:
 Check that there is no logic input diagnostic message on the display.
 Set the monitored contact for the logic input programmed in setpoint
message User Input A Source to the closed state and the virtual input to
the off state.
Check that the diagnostic message, either User Input A or the name
programmed in setpoint User Input A Name, appears on the display
with the Auxiliary LED and relay activated.
Check in the Event Recorder that the selected function has been
invoked.
 Leave the monitored contact in the closed state and put the virtual input
in the on state.
Check that the diagnostic message is removed from the display with the
Auxiliary LED and relay deactivated.
 Set the monitored contact to the open state and leave the virtual input in
the on state.
Check that the diagnostic message appears on the display with the
Auxiliary LED and relay activated.
 Leave the monitored contact in the open state and put the virtual input in
the off state.
Check that the diagnostic message is removed from the display with the
Auxiliary LED and relay deactivated.
 Repeat last 3 steps for all functions programmed to be asserted by a
Closed X Von input.
14. For INPUT ASSERTED LOGIC setpoints set to “Closed X Voff”:
 Check that there is no logic input diagnostic message on the display.
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 Set the monitored contact for the logic input programmed in setpoint
message User Input A Source to the closed state and the virtual input to
the on state.
Check that the diagnostic message, either User Input A or the name
programmed in setpoint User Input A Name, appears on the display
with the Auxiliary LED and relay activated.
Check in the Event Recorder that the selected function has been
invoked.
 Leave the monitored contact in the closed state and put the virtual input
in the off state.
Check that the diagnostic message is removed from the display with the
Auxiliary LED and relay deactivated.
 Set the monitored contact to the open state and leave the virtual input in
the off state.
Check that the diagnostic message appears on the display with the
Auxiliary LED and relay activated.
 Leave the monitored contact in the open state and put the virtual input in
the on state.
Check that the diagnostic message is removed from the display with the
Auxiliary LED and relay deactivated.
 Repeat last 3 steps for all functions programmed to be asserted by a
Closed X Voff input.
15. For INPUT ASSERTED LOGIC setpoints set to Open X Von:
 Check that there is no logic input diagnostic message on the display.
 Set the monitored contact for the logic input programmed in setpoint
message User Input A Source to the open state and the virtual input to
the off state.
Check that the diagnostic message, either User Input A or the name
programmed in setpoint User Input A Name, appears on the display
with the Auxiliary LED and relay activated.
Check in the Event Recorder that the selected function has been
invoked.
 Leave the monitored contact in the open state and put the virtual input in
the on state.
Check that the diagnostic message is removed from the display with the
Auxiliary LED and relay deactivated.
 Set the monitored contact to the closed state and leave the virtual input
in the on state.
Check that the diagnostic message appears on the display with the
Auxiliary LED and relay activated.
 Leave the monitored contact in the closed state and put the virtual input
in the off state.
Check that the diagnostic message is removed from the display with the
Auxiliary LED and relay deactivated.
 Repeat last 3 steps for all functions programmed to be asserted by a
Open X Von input.
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16. For INPUT ASSERTED LOGIC setpoints set to “Open X Voff”:
 Check that there is no logic input diagnostic message on the display.
 Set the monitored contact for the logic input programmed in setpoint
message User Input A Source to the open state and the virtual input to
the on state.
Check that the diagnostic message, either User Input A or the name
programmed in setpoint User Input A Name, appears on the display
with the Auxiliary LED and relay activated.
Check in the Event Recorder that the selected function has been
invoked.
 Leave the monitored contact in the open state and put the virtual input in
the off state.
Check that the diagnostic message is removed from the display with the
Auxiliary LED and relay deactivated.
 Set the monitored contact to the closed state and leave the virtual input
in the off state.
Check that the diagnostic message appears on the display with the
Auxiliary LED and relay activated.
 Leave the monitored contact in the closed state and put the virtual input
in the on state.
Check that the diagnostic message is removed from the display with the
Auxiliary LED and relay deactivated.
 Repeat last 3 steps for all functions programmed to be asserted by a
Open X Voff input.
User Input A Function set to “Control”
The procedure to test this element is identical to that outlined for User Input A Function
setpoint set to Alarm, with the following exceptions: there will not be any diagnostic
message or Alarm LED.
User Input A Function Set to “Trip”
The procedure to test this element is identical to that outlined for User Input A Function
setpoint set to Alarm, with the following exceptions. The Trip Relay and LED will activate
along with the Auxiliary Relay and LED. At the end of each test, a reset must be performed
in order to clear the trip diagnostic message and Trip LED.
7.2.2
Virtual Inputs
15 to 20
7.2.3
Output Relays
Follow the Virtual On and Virtual Off Input Asserted Logic procedures outlined for Logic/
Virtual Inputs 1 to 14 in the previous section.
 Enter the following settings under the S8 TESTING  OUTPUT RELAYS
subheading:
FORCE OUTPUT RELAYS FUNCTION: “Enabled”
FORCE 1 TRIP RELAY: “De-energized”
FORCE 2 CLOSE RELAY: “De-energized”
FORCE 3 AUXILIARY RELAY: “De-energized”
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FORCE 4 AUXILIARY RELAY: “De-energized”
FORCE 5 AUXILIARY RELAY: “De-energized”
FORCE 6 AUXILIARY RELAY: “De-energized”
FORCE 7 AUXILIARY RELAY: “De-energized”
FORCE 8 SELF-TEST RELAY: “De-energized”
FORCE SOLID STATE OUTPUT: “De-energized”
 Using a multimeter, check that all output relays are de-energized (i.e.
N.O. contacts open, N.C. contacts closed).
 Make the following setting change: S8 TESTING  OUTPUT RELAYS 
FORCE 1 TRIP RELAY: “Energized”.
 Check that the Trip output is energized (i.e. N.O. contacts closed), and
the Trip LED is illuminated.
 Make the following setting change: S8 TESTING  OUTPUT RELAYS 
FORCE 1 TRIP RELAY: “De-energized”.
 Repeat Steps 3 through 5 for Output Relays 2 through 8 inclusive.
 Observing polarity, connect a minimum 5 V DC source in series with a
limiting resistor that will permit a minimum current of 100 mA, in series
with the Solid State output.
Observing polarity, connect a DC voltmeter across the limiting resistor.
Check there is no voltage displayed on the voltmeter.
 Change setting to: S8 TESTING  OUTPUT RELAYS  FORCE SOLID STATE
OUTPUT: “Energized”.
 Check that a voltage has appeared on the voltmeter.
Turn off the source and disconnect the test wiring.
 Change setting to: S8 TESTING  OUTPUT RELAYS  FORCE SOLID STATE
OUTPUT: “De-energized”.
 Change setting to: S8 TESTING  OUTPUT RELAYS  FORCE OUTPUT
RELAYS FUNCTION: “Disabled”.
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METERING
CHAPTER 7: COMMISSIONING
7.3
7.3.1
Current
Metering
Metering
Phase Current Inputs
For these tests, refer to the figures on page –4 for test connections. The expected accuracy
is as follows:
For 1 A CTs: ±0.01 A for 0.01 to 1.99 A; ±0.2 A for 2.00 to 20.00 A
For 5 A CTs: ±0.05 A for 0.05 to 9.99 A; ±1.0 A for 10.00 to 100.00 A
Use the following procedure to test Phase and Neutral Current Inputs:
The relevant actual values displays are located under subheading
A2 METERING  CURRENT and are:
A: B: C: (Magnitude)
AVERAGE CURRENT: (Magnitude)
PHASE A CURRENT: (Phasor)
PHASE B CURRENT: (Phasor)
PHASE C CURRENT: (Phasor)
NEUTRAL CURRENT: (Phasor)
POS SEQ CURRENT: (Phasor)
NEG SEQ CURRENT: (Phasor)
ZERO SEQ CURRENT: (Phasor)
 Inject 1-phase current of various values into the relay phase current
input one phase at a time, and observe the magnitude.
Note that the average, positive-sequence, negative-sequence and zerosequence magnitudes are 1/3 of the phase current magnitude for this
test.
The neutral current will match the phase current magnitude.
 Inject 3-phase current of various values and angles into the relay phase
current input and note the measured current phasors and symmetrical
components.
Use the following procedure for Ground and Sensitive Ground Current Inputs:
The relevant actual values displays are located under subheading
A2 METERING  CURRENT as follows:
GND CURRENT: (Phasor)
SENSTV GND CURRENT: (Phasor)
 Inject current of various values into the relay ground input, Terminals
G10–H10, and note the current.
 Inject current of various values into the relay sensitive ground input,
Terminals G3–H3, and note the current.
Percent of Load-to-Trip
For these tests, refer to the figures on page –4 for test connections. The expected accuracy
is as follows:
Expected Accuracy: equivalent to that of phase current inputs
The relevant actual values displays are shown below:
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METERING
A2 METERING  CURRENT  % OF LOAD-TO-TRIP
Note
NOTE
Percent of load-to-trip is calculated from the phase with the highest current reading. It is
the ratio of this current to the lowest pickup setting among the phase time and
instantaneous overcurrent protection features. If all of these features are disabled, the
value displayed will be “0”.
 Inject current of various values into Phase A.
 Verify that percent load-to-trip is calculated as the correct percentage of
the most sensitive operational Phase Overcurrent element and displayed.
 Repeat for phases B and C.
7.3.2
Voltage
Metering
Bus Voltage
For these tests, refer to the figures on page –4 for test connections. The expected accuracy
is as follows:
• Phase-neutral voltages: ±0.68 V for 50 to 130 V; ±2.18 V for other voltages within
specified limits
• Phase-phase voltages (Vab and Vcb): ±0.68 V for 50 to 130 V; ±2.18 V for all other
voltages within the specified limits.
• Phase-phase voltages (calculated Vac): ±1.36 V for 50 to 130 V; ±4.36 V for other
voltages within the specified limits.
The procedure for testing the metered bus voltage is as follows:
The relevant actual values displays are located under subheading
A2 METERING  VOLTAGE and are:
AB: BC: CA: (Magnitude)
AVERAGE LINE VOLTAGE: (Magnitude)
AN: BN: CN: (Magnitude) (not available when connected Delta)
AVERAGE PHASE VOLTAGE: (Magnitude) (not available when connected Delta)
LINE A-B VOLTAGE: (Phasor)
LINE B-C VOLTAGE: (Phasor)
LINE C-A VOLTAGE: (Phasor)
PHASE A-N VOLTAGE: (Phasor) (not available when connected Delta)
PHASE B-N VOLTAGE: (Phasor) (not available when connected Delta)
PHASE C-N VOLTAGE: (Phasor) (not available when connected Delta)
POS SEQ VOLTAGE: (Phasor)
NEG SEQ VOLTAGE: (Phasor)
ZERO SEQ VOLTAGE: (Phasor)
NEUTRAL (3VO) VOLTAGE: (Phasor)
 Inject 1-phase voltage of various values into the relay bus voltage input
one phase at a time, and observe the magnitude.
Note that for Wye VTs the positive sequence, negative sequence and
zero sequence magnitudes are 1/3 of the phase voltage magnitude for
this test.
For Delta VTs the zero sequence voltage will be displayed as 0. The
positive sequence and negative sequence magnitudes will be 3 of the
line voltage magnitude.
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 Inject 3-phase voltage of various values and angles into the relay bus
voltage input and note the measured voltage phasors & symmetrical
components.
For Delta VTs the zero sequence voltage will be shown as 0.
Bus Voltage Frequency
For these tests, refer to the figures on page –4 for test connections. The expected accuracy
is as follows:
Frequency: ±0.02 Hz of injected value within the range 16.00 to 90.00 Hz
Undervoltage Inhibit: 10 V secondary
The procedure for testing the metered bus voltage frequency is as follows:
The relevant actual values display is located as follows:
A2 METERING  FREQ  SYSTEM FREQ.
 Inject a voltage of nominal value at nominal frequency into Phase A.
Check that the frequency is measured and displayed.
 Check the undervoltage inhibit level by slowly reducing the voltage
until the frequency is no longer measured, and “0.00 Hz” is displayed.
 Return the voltage to nominal.
Adjust the frequency above and below nominal, and note the frequency
measured by the relay.
The procedure for testing the metered frequency decay rate is as follows:
The relevant actual values display is located as follows:
A2 METERING  FREQ  FREQ DECAY RATE
 Vary the frequency of the phase A voltage and verify the measured
frequency decay rate.
Synchro Voltage and Frequency
For these tests, refer to the figures on page –4 for test connections. The expected accuracy
is as follows:
Voltage: ±0.68 V for 50 to 130 V
Frequency: ±0.02 Hz of injected value within the range 16.00 to 90.00 Hz
The procedure for testing the metered synchro voltage and frequency is as follows:
The relevant actual values displays are located under subheading
A2 METERING  SYNCHRO VOLTAGE and are:
SYNCHRO VOLTAGE: (Phasor)
SYNCHRO FREQ:
SYNCHRO DELTA DF: DV: DF:
 Inject voltage of various magnitudes and frequencies into the line
voltage input and verify the displays.
7.3.3
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Power
Metering
Real Power and Watthours
For these tests, refer to the figures on page –4 for test connections. The expected accuracy
is as follows:
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METERING
Real Power: ±1% of full scale at currents 5 to 199% of nominal and voltages from 50 to
130 V
Watthours: ±2% of full scale at currents 5 to 199% of nominal and voltages from 50 to
130 V
The procedure for testing the metered real power and watthours is as follows.
The relevant actual values displays are located as shown below:
A2 METERING  PWR  3Φ REAL PWR:
A2 METERING  PWR  ΦA REAL PWR: (not available when connected Delta)
A2 METERING  PWR  ΦB REAL PWR: (not available when connected Delta)
A2 METERING  PWR  ΦC REAL PWR: (not available when connected Delta)
A2 METERING  ENERGY  POSITIVE WATTHOURS:
A2 METERING  ENERGY  NEGATIVE WATTHOURS:
 To reduce the time required for watthour measurements, set the input
VT and CT ratios to high values.
 Inject 3-phase voltage and current of various values and angles into the
relay.
 Note that real power is measured and displayed.
 Maintain voltage and current at various settings for a time sufficient to
achieve a minimum of 20 MWh for each test interval.
 Check that watthours is measured and displayed.
 Note that watthours for load in the positive direction and negative
directions are stored in separate registers.
 The procedure should be performed for loads in each direction.
Reactive Power and Varhours
For these tests, refer to the figures on page –4 for test connections. The expected accuracy
is as follows:
• Reactive Power: ±1% of full scale, currents 5 to 199% of nominal, voltages 50 to
130 V
• Varhours: ± 2% of full scale, currents 5 to 199% of nominal, voltages 50 to 130 V
The procedure for metered reactive power and energy is as follows:
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The relevant actual values displays are shown below:
A2 METERING  PWR  3Φ REACTIVE PWR:
A2 METERING  PWR  ΦA REACTIVE PWR: (not available when connected
Delta)
A2 METERING  PWR  ΦB REACTIVE PWR: (not available when connected
Delta)
A2 METERING  PWR  ΦC REACTIVE PWR:
(not available when connected
Delta)
A2 METERING  ENERGY  POSITIVE VARHOURS:
A2 METERING  ENERGY  NEGATIVE VARHOURS:
 To reduce the time required for varhour measurements, set the input VT
and CT ratios to high values.
 Inject 3-phase voltage and current of various values and angles into the
relay.
 Note that reactive power is measured and displayed.
 Maintain voltage and current at various settings for a time sufficient to
achieve a minimum of 20 Mvarh for each test interval.
 Check that varhours are measured and displayed.
 Note that varhours for load in the positive direction and negative
directions are stored in separate registers.
 The procedure should be performed for loads in each direction.
Apparent Power
For these tests, refer to the figures on page –4 for test connections. The expected accuracy
is as follows:
Apparent Power: ±1% of full scale, currents 5 to 199% of nominal, voltages 50 to 130 V
The procedure for metered apparent power is as follows:
The relevant actual values displays are shown below:
A2 METERING  PWR  3Φ APPARENT PWR:
A2 METERING  PWR  ΦA APPARENT PWR: (not available when connected
Delta)
A2 METERING  PWR  ΦB APPARENT PWR: (not available when connected
Delta)
A2 METERING  PWR  ΦC APPARENT PWR: (not available when connected
Delta)
 Inject 3-phase voltage and current of various values and angles into the
relay. Note that reactive power is measured and displayed.
Power Factor
For these tests, refer to the figures on page –4 for test connections. The expected accuracy
is as follows:
Power Factor: ±0.02 of injected values, currents 5 to 199% of nominal, voltages 50 to
130 V
The procedure for metered apparent power is as follows:
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METERING
The relevant actual values displays are shown below:
A2 METERING  PWR  3Φ PWR FACTOR:
A2 METERING  PWR  ΦA PWR FACTOR: (not available when connected Delta)
A2 METERING  PWR  ΦB PWR FACTOR: (not available when connected Delta)
A2 METERING  PWR  ΦC PWR FACTOR: (not available when connected Delta)
 Inject 3-phase voltage and current of various values and angles into the
relay.
Verify that the power factor is measured and displayed correctly for
each phase. Note that:
total 3-phase real power
3-phase PF = -----------------------------------------------------------------------------total 3-phase apprarent power
7.3.4
Demand
Metering
(EQ 7.1)
Current Demand
For these tests, refer to the figures on page –4 for test connections. The expected accuracy
is as follows:
Expected Accuracy: ±2.0% of full scale
To reset the “Last Demand” reading to 0 between tests, cycle the relay power source off
and then on.
Block Interval and Rolling demand measurement types must be tested in synchronization
with the internal clock. Both of these measurements start with the first interval of the day
at 12:00:00.000 midnight. To synchronize, preset the injection levels, then turn the current
off. Select the relay display (not the EnerVista 750/760 Setup software) to A1 STATUS 
CLOCK  CURRENT TIME. Apply the test current when the clock is at the beginning of an
interval measurement period, as determined by the TIME INTERVAL setpoint for the
element.
The relevant actual values displays are shown below:
A2 METERING  DMND  PHASE A CURRENT  LAST PHASE A CURRENT DMND
A2 METERING  DMND  PHASE A CURRENT  MAX PHASE A CURRENT DMND
A2 METERING  DMND  PHASE A CURRENT  MAX PHASE A CURRENT DATE
A2 METERING  DMND  PHASE A CURRENT  MAX PHASE A CURRENT TIME
A2 METERING  DMND  PHASE B CURRENT  LAST PHASE B CURRENT DMND
A2 METERING  DMND  PHASE B CURRENT  MAX PHASE B CURRENT DMND
A2 METERING  DMND  PHASE B CURRENT  MAX PHASE B CURRENT DATE
A2 METERING  DMND  PHASE B CURRENT  MAX PHASE B CURRENT TIME
A2 METERING  DMND  PHASE C CURRENT  LAST PHASE C CURRENT DMND
A2 METERING  DMND  PHASE C CURRENT  MAX PHASE C CURRENT DMND
A2 METERING  DMND  PHASE B CURRENT  MAX PHASE C CURRENT DATE
A2 METERING  DMND  PHASE B CURRENT  MAX PHASE C CURRENT TIME
For Thermal Exponential Demand (for example, a response time setting of 5 minutes), the
procedure is as follows:
 Clear demand data registers by setting S1 RELAY SETUP  CLEAR DATA
 CLEAR MAX DMND DATA to “Yes”.
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 Inject a fixed value of current into Phase A.
Record the measured current demand at 1, 2, 3, 4, 5 and 10 minutes after
the application of current.
The demand, in percent of injected current, should be as follows:
Time (min.)
1
2
3
4
6
10
Demand (% of Input)
36.9
60.1
74.8
84.1
90.0
99.0
 For other response time settings, multiply the Row 1 times above by
[selected response time / 5].
 Check that the maximum current demand, including date and time of
occurrence, is recorded and displayed.
 Repeat last 3 steps for Phases B and C.
For Block Interval Demand (for example, a time interval setting of 5 minutes), the
procedure is as follows:
 Repeat last 4 steps above.
 Record the measured current demand at 1, 2, 3, 4, 5 and 6 minutes after
the application of current.
The demand, in percent of injected current, should be as follows:
Time (min.)
1
2
3
4
5
6
Demand (% of Input)
0.0
0.0
0.0
0.0
100.0
100.0
For Rolling Demand (for example, a time interval setting of 5 minutes), the procedure is as
follows:
 Repeat Steps 2 to 5 above from Thermal Exponential Demand above.
 Record the measured current demand at 1, 2, 3, 4, 5 and 6 minutes after
the application of current.
The demand, in percent of injected current, should be as follows:
Time (min.)
1
2
3
4
5
6
Demand (% of Input)
20.0
40.0
60.0
80.0
100.0
100.0
Real Power Demand
For these tests, refer to the figures in section 7.1.6 for test connections. The expected
accuracy is as follows:
Expected Accuracy: ±2.0% of full scale
The relevant actual values displays are shown below:
A2 METERING  DMND  REAL PWR  LAST REAL PWR DMND
A2 METERING  DMND  REAL PWR  MAX REAL PWR DMND
A2 METERING  DMND  REAL PWR  MAX REAL PWR DATE
A2 METERING  DMND  REAL PWR  MAX REAL PWR TIME
 Follow the procedure in Current Demand on page 7–21, except that the
injected and monitored parameter is watts.
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METERING
Reactive Power Demand
For these tests, refer to the figures in section 7.1.6 for test connections. The expected
accuracy is as follows:
Expected Accuracy: ±2.0% of full scale
The relevant actual values displays are shown below:
A2 METERING  DMND  REACTIVE PWR  LAST REACTIVE PWR DMND
A2 METERING  DMND  REACTIVE PWR  MAX REACTIVE PWR DMND
A2 METERING  DMND  REACTIVE PWR  MAX REACTIVE PWR DATE
A2 METERING  DMND  REACTIVE PWR  MAX REACTIVE PWR TIME
 Follow the procedure in Current Demand on page 7–21, except that the
injected and monitored parameter is vars.
Apparent Power Demand
For these tests, refer to the figures in section 7.1.6 for test connections. The expected
accuracy is as follows:
Expected Accuracy: ±2.0% of full scale
The relevant actual values displays are shown below:
A2 METERING  DMND  APPARENT PWR  LAST APPARENT PWR DMND
A2 METERING  DMND  APPARENT PWR  MAX APPARENT PWR DMND
A2 METERING  DMND  APPARENT PWR  MAX APPARENT PWR DATE
A2 METERING  DMND  APPARENT PWR  MAX APPARENT PWR TIME
Follow the procedure in Current Demand on page 7–21, except that the injected and
monitored parameter is VA.
7.3.5
Analog Input
Metering
For these tests, refer to the figures on page –4 for test connections. The expected accuracy
is as follows:
Expected Accuracy: ±1.0% of full scale
The relevant actual values displays are shown below:
A2 METERING  A/I  A/I
A2 METERING  A/I  A/I (/MIN)
A2 METERING  A/I  A/I (/HOUR)
The procedure for testing the Analog Input metering is shown below:
 Inject steady values of DC current (in mA) of various values into relay
terminals A1(+) and A2(–).
 Verify that the analog input is correctly measured and displayed in the A/
I value.
 Inject a fixed rate of ramping DC current (in mA) of various values into
relay terminals A1(+) and A2(–) for at least 2 minutes.
 At the end of this time, verify that the analog input is correctly measured
and displayed in the A/I (/MIN) value.
 Inject a fixed rate of ramping DC current (in mA) of various values into
relay terminals A1(+) and A2(–) for at least 2 hours.
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 At the end of this time, verify that the analog input is correctly measured
and displayed in the A/I (/HOUR) value.
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7.4
7.4.1
Setpoint
Groups
Protection Schemes
The Active setpoint group is indicated by a continuously illuminated LED, and the Edit
group by an intermittently illuminated LED on the relay faceplate. When changing settings
for testing be careful to check the correct group is adjusted and selected as the active
group.
Verify that settings in a particular setpoint group are being used by the protection
elements when the particular group is selected to be active. There are three alternative
strategies that can be used to provide this verification:
• Test any one protection element that has different settings in different groups
• Test a random selection of protection elements in different groups
• Test all protection elements that are not disabled in every group
Once one of the above strategies is selected, the following procedures are used to test
protection elements.
7.4.2
Phase
Overcurrent
Note
NOTE
Phase TOC 1
For these tests, refer to the figures on section 7.1.6 for test connections.
The following procedures, other than the check for Linear Reset Timing, are based on the
“Instantaneous” reset time characteristic. If the “Linear” reset time characteristic is
required, ensure that there is sufficient time between test current injections, or cycle relay
power OFF and ON to discharge the energy measurement accumulator to 0.
The following procedure checks Pickup with one phase for operation:
 Inject current at a level below the pickup level into Phase A.
 Slowly increase the current until the Pickup LED comes on.
Note the pickup value.
 Slowly reduce the current until the Pickup LED goes out.
Note the dropout level, which should be 2% of CT less than pickup
when pickup ≤ CT or 97 to 98% of pickup when pickup > CT.
 Repeat last 3 steps for Phases B and C.
The following procedure checks indications and operations caused by a Trip function, with
front panel RESET key resetting:
 Inject current to cause a pickup and wait until the element times to Trip.
 Check that the Trip and Message LEDs are flashing, the Last Trip
message is displayed, and the Output Relay 1 and any others
programmed to operate (as well as their associated LED indicators)
operate.
 Slowly reduce the current until the Pickup LED goes out.
Check that the Trip and Message LEDs are flashing, and that the Output
Relay 1 and any others programmed to operate (as well as their
associated LEDs) reset.
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 Press the front panel RESET key.
Check that the Trip and Message LEDs go off, and the Last Trip
message is no longer displayed.
 Turn current off.
The following procedure checks indications and operations caused by a Trip function, with
Logic Input resetting:
 Ensure that the reset logic input control function has been assigned to a
logic input.
 Inject current to cause a pickup and wait until the element times to Trip.
 Check that the Trip and Message LEDs are flashing, the Last Trip
message is displayed, and the Output Relay 1 and any others
programmed to operate (as well as their associated LED indicators)
operate.
 Slowly reduce the current until the Pickup LED goes out.
Check that the Trip and Message LEDs are flashing, and that the Output
Relay 1 and any others programmed to operate (as well as their
associated LEDs) reset.
 Assert a logic input to provide a reset.
Check that the Trip and Message LEDs are now off, and the Last Trip
message is no longer displayed.
 Turn current off.
The following procedure checks indications and operations caused by an Alarm function:
 Inject current to cause a pickup and wait until the element times to
Alarm.
 Check that the Alarm and Message LEDs are flashing, the Active Alarm
message is displayed, and any output relays programmed to operate (as
well as their associated LEDs) operate.
 Slowly reduce the current until the Pickup LED goes out.
 Verify that the Alarm and Message LEDs go off, and that any output
relays programmed to operate (as well as their associated LEDs) reset,
and the Active Alarm message is no longer displayed.
 Turn current off.
The following procedure checks indications and operations caused by a Control function:
 Inject current to cause a pickup and wait until the element times-out.
Check that any output relays programmed to operate (as well as their
associated LED indicators) operate.
 Slowly reduce the current until the Pickup LED goes out.
Check that any output relays programmed to operate (as well as their
associated LED indicators) reset.
 Turn current off.
The following procedure checks indications and operations caused by a Latched Alarm
function, with RESET key resetting:
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 Inject current to cause a pickup and wait until the element times to
Alarm.
 Check that the Alarm and Message LEDs are flashing, the Active Alarm
message is displayed, and any output relays programmed to operate (as
well as their associated LEDs) operate.
 Slowly reduce the current until the Pickup LED goes out. Check that the
Alarm and Message LEDs are flashing, and that any output relays
programmed to operate (as well as their associated LEDs) reset.
 Press the front panel RESET key.
Check that the Alarm and Message LEDs go off, and the Active Alarm
message is no longer displayed.
 Turn current off.
The following procedure checks blocking From Logic Inputs. Note that this procedure is
different for Phase TOC2; see the next section for details.
 Inject current to cause a pickup.
 Assert a logic input to provide a “Block Phase Time 1”.
The Pickup LED should immediately go out.
 Repeat last 2 steps for logic inputs “Block Phase O/C”, “Block All O/C”
and “Block 1 Trip Relay” as required.
The following procedure checks timing:
 Connect the Stop Trigger.
 Preset the injection current level to 2.0 × pickup.
Turn the current off, and reset the timer.
 Inject the preset current into Phase A and note the measured delay time.
Check this time against the time established by the settings and reset the
timer.
 Preset the injection current level to 4.0 × pickup.
Turn the current off, and reset the timer.
 Inject the preset current into Phase B and note the measured delay time.
Check this time against the time established by the settings and reset the
timer.
 Preset the injection current level to 7.0 × pickup.
Turn the current off, and reset the timer.
 Inject the preset current into Phase C and note the measured delay time.
Check this time against the time established by the settings.
 Turn current off and disconnect the Stop Trigger.
The following procedure checks Linear Reset Timing:
 To confirm that the TOC element is using linear reset timing, if so
programmed, inject a current above the pickup level for approximately
half the time required to Trip.
 Turn the current off, reset the interval timer, and then re-apply
immediately.
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 The time-to-trip should be much less than the trip-time established by
the settings.
The following procedure checks the voltage restrained Phase TOC function:
 Apply three-phase nominal voltage to the relay.
 Inject current below the pickup level into Phase A and slowly increase
until the Pickup LED is on.
Note the pickup value is the pickup current of the Curve in use.
 Slowly reduce the current into Phase A until the Pickup LED goes off
and note the dropout level, which should be 2% of CT less than pickup
when pickup ≤ CT or 97 to 98% of pickup when pickup > CT.
 Reduce the current to zero.
 Repeat Steps 2 to 4 for current injected into Phases B and C.
 Set all input voltages to 0 and slowly increase Phase A current until the
Pickup LED comes on.
Check that this current is 9 to 11% of the measured full voltage pickup
current.
 Increase input voltage Vab until the Pickup LED goes out.
This should be at 9 to 11% of the nominal phase-phase voltage. This test
establishes the lower knee of the operating characteristic.
 With the Pickup LED still off, increase voltage Vab to 60% of the
nominal phase-phase voltage.
 Increase the Phase A current until the Pickup LED comes on.
This should be at 59 to 61% of the full voltage measured pickup current.
 With the Pickup LED still off, increase voltage Vab to 130% of nominal.
 Increase Phase A current to 90% of normal pickup and hold this value.
Slowly decrease Vab until the Pickup LED just comes on. This should be
at 89 to 91% of nominal Vab.
This establishes the upper knee of the characteristic, and shows the
pickup is not altered above 90% voltage.
 Reduce current and voltages to 0.
 Repeat last 7 steps for current injected in Phase B and controlling
voltage Vcb.
 Repeat last 7 steps for current injected in Phase C and controlling
voltage Vca.
To check trip timing with voltage restraint, set the input voltage to a given level,
establishing a new pickup current, and then following the procedure outlined earlier under
Timing.
Phase TOC 2
The procedure to test this element is identical to that for Phase TOC 1, except for the
blocking from logic inputs, in which case the following procedure should be used:
 Inject current to cause a Pickup.
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 Assert a logic input to provide a “Block Phase Time 2”.
The Pickup LED should immediately go out.
 Repeat Steps 1 and 2 for logic inputs “Block Phase O/C”, “Block All O/
C” and “Block 1 Trip Relay” as required.
Phase IOC 1
The procedure to test this element is identical for Phase TOC 1, except for the procedures
below. Pickup, indication and operation are subject to the “phases required for operation”
test, but not subject to the “linear reset timing” and “voltage restrained Phase TOC” tests.
The following procedure checks pickup with two phases for operation:
 Inject current into Phase B at 150% of pickup.
 Inject current at a level below the pickup level into Phase A.
 Slowly increase the Phase A current until the Pickup LED comes on and
note the pickup value.
 Slowly reduce the Phase A current until the Pickup LED goes out.
Note the dropout level, which should be 2% of CT less than pickup
when pickup ≤ CT or 97 to 98% of pickup when pickup > CT.
 Repeat last 4 steps for phase pair B and C and phase pair C and A.
The following procedure checks pickup with three phases for operation:
 Inject current into Phases B and C at 150% of pickup.
 Inject current at a level below the pickup level into Phase A.
 Slowly increase the Phase A current until the Pickup LED comes on and
note the pickup value.
 Slowly reduce the Phase A current until the Pickup LED goes out and
note the dropout level, which should be 2% of CT less than pickup when
pickup ≤ CT, or 97 to 98% of pickup when pickup > CT.
 Repeat last 4 steps for current at 150% in Phases C and A and adjusted
in B.
 Repeat last 4 steps for current at 150% in Phases B and A and adjusted
in C.
The following procedure checks the blocking from logic inputs:
 Inject current into the required number of phases to cause a pickup.
 Assert a logic input to provide a “Block Phase Inst 1”.
The Pickup LED should immediately go out.
 Repeat last 2 steps for logic inputs “Block Phase O/C”, “Block All O/C”
and “Block 1 Trip Relay” as required.
The following procedure checks Phase IOC 1 timing:
 Connect the Stop Trigger to the interval timer.
 Preset the current source to a minimum of 110% of pickup current, then
turn the current off and reset the timer.
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 Inject the preset current into the required number of phases and note the
delay time, then reset the timer.
 Repeat the last step four more times and obtain an average of the time
intervals.
 Reset the relay and disconnect the “Stop Trigger.”
Phase IOC 2
The procedures to test this element are identical to those outlined for Phase IOC 1 above,
with the exception of the blocking from logic inputs check, which is performed as follows:
 Inject current into the required number of phases to cause a pickup.
 Assert a logic input to provide a “Block Phase Inst 2” and verify the
Pickup LED immediately turns off.
 Repeat last 2 steps for logic inputs “Block Phase O/C”, “Block All O/C”
and “Block 1 TRIP Relay” as required.
Phase Directional OC
A plot of the operating characteristic of the phase directional feature for various settings of
MTA for Phase A is shown below. Other characteristics for specific MTA settings can be
deduced from this diagram. Note that the diagram is plotted for the phase current referred
to both the system phase-neutral voltage and the polarizing voltage used for Phase A (the
polarizing voltages for Phases B and C are Vca and Vab respectively).
Ia LAGS Van PHASE VOLTAGE
270°
300°
330°
0°
180°
210°
240°
270°
30°
60°
90°
120°
150°
180°
210°
240°
270°
300°
330°
0°
30°
60°
90°
120°
150°
180°
MTA SETTING
90°
60°
30°
0°
330°
300°
270°
Ia LAGS Vbc PHASE VOLTAGE
= PERMITTED TRIPPING REGION
FIGURE 7–3: Phase Directional – Phase A Forward Operating Regions
Note
NOTE
The following descriptions present angles with reference to the polarizing voltage and
assume an MTA setting of 180°. For an MTA setting other than 180° alter the noted angles
to those established by the programmed MTA.
For forward tripping and Wye connected VTs, use the test connections specified in FIGURE
7–1: Relay Test Wiring – Wye Connection on page 7–4 and use the following procedure:
 Set Van = Vbn = Vcn > MIN POLARIZING VOLTAGE setpoint at 0°, 120°,
and 240°, respectively.
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 Inject Phase A current of 0.2 x CT at an angle which is in phase with the
polarizing voltage.
This angle is outside the tripping region, so tripping should be blocked.
If the function is set to “Control”, check that any output relays
programmed for this condition are operated. If the function is set to
“Alarm”, check that the Alarm and Message LEDs are flashing, the
correct Phase Directional Reverse alarm message is displayed, and any
output relays programmed for this condition are operated.
 Slowly increase the angle of the Phase A current in the lagging
direction.
The directional element should detect current flow in the tripping
direction when the Phase A current is lagging the polarizing voltage by
more than 90° ±2°.
The alarm and output relays should reset.
 Continue to increase the lagging angle until the alarm is again raised.
The Phase A current should be lagging the polarizing voltage by an
angle of 270° ± 2°.
 Continue to increase the angle until the Phase A current is once again in
phase with the polarizing voltage.
The alarm should remain.
 Repeat the last 5 steps for current angle adjusted in each of Phases B and
C.
For forward tripping and Delta connected VTs, use the test connections specified in FIGURE
7–2: Relay Test Wiring – Delta Connection on page 7–5 and use the following procedure:
 Set Vab = Vbc = Vca > MIN POLARIZING VOLTAGE setpoint at 0°, 120°,
and 240°, respectively.
 Inject Phase A current of 0.2 x CT at an angle which is in phase with the
polarizing voltage. This angle is outside the tripping region, so tripping
should be blocked.
If the function is set to “Control”, check that any output relays
programmed for this condition are operated. If the function is set to
“Alarm”, check that the Alarm and Message LEDs are flashing, the
correct Phase Directional Reverse alarm message is displayed, and any
output relays programmed for this condition are operated.
 Slowly increase the angle of the Phase A current in the lagging
direction.
The directional element should detect current flow in the tripping
direction when the Phase A current is lagging the polarizing voltage by
more than 90° ±2°.
The alarm and output relays should reset.
 Continue to increase the lagging angle until the alarm is again raised.
The Phase A current should be lagging the polarizing voltage by an
angle of 270° ±2°.
 Continue to increase the angle until the Phase A current is once again in
phase with the polarizing voltage.
The alarm should remain.
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 Repeat the last 5 steps for current angle adjusted in each of Phases B and
C.
7.4.3
Neutral
Overcurrent
Neutral TOC 1
The procedure to test this element is identical to that outlined in Phase TOC 1 on page 7–
25, except that current is injected into any one phase, and the element is not subject to the
“phases required for operation” and “voltage restrained time overcurrent” tests.
The blocking from logic inputs check is different from that for Phase TOC 1 and is
performed as follows:
 Inject current to cause a pickup.
 Assert logic input to provide a “Block Neutral Time 1”.
The Pickup LED should immediately turn off.
 Repeat Steps 1 and 2 for logic inputs “Block Neutral O/C”, “Block All
O/C” and “Block 1 Trip Relay” as required.
Neutral TOC 2
The procedure to test this element is identical to that outlined in Phase TOC 1 on page 7–
25, except that current is injected into any one phase, and the element is not subject to the
“phases required for operation” and “voltage restrained time overcurrent” checks.
The blocking from logic inputs check is different from that for Phase TOC 1 and is
performed as follows:
 Inject current to cause a pickup.
 Assert logic input to provide a “Block Neutral Time 2”.
The Pickup LED should immediately go out.
 Repeat last 2 steps for logic inputs “Block Neutral O/C”, “Block All O/
C” and “Block 1 Trip Relay” as required.
Neutral IOC 1
The procedure to test this element is identical to that outlined in Phase TOC 1 on page 7–
25, except that current is injected into any one phase, and the element is not subject to the
“phases required for operation”, “linear reset timing”, and “voltage restrained time
overcurrent” tests.
The blocking from logic inputs check is different from that for Phase TOC 1 and is
performed as follows:
 Inject current to cause a pickup.
 Assert a logic input to provide a “Block Neutral Inst 1”.
The Pickup LED should immediately go out.
 Repeat last 2 steps for logic inputs “Block Neutral O/C”, “Block All O/
C” and “Block 1 Trip Relay” as required.
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Neutral IOC 2
The procedure to test this element is identical to that outlined in Phase TOC 1 on page 7–
25, except that current is injected into any one phase, and the element is not subject to the
“phases required for operation”, “linear reset timing”, and “voltage restrained time
overcurrent” checks.
The blocking from logic inputs check is different from that for Phase TOC 1 and is
performed as follows:
 Inject current to cause a pickup.
 Assert a logic input to provide a “Block Neutral Inst 2”.
The Pickup LED should immediately go out.
 Repeat last 2 steps for logic inputs “Block Neutral O/C”, “Block All O/
C” and “Block 1 Trip Relay” as required.
Neutral Directional OC
If dual polarizing is required, check the operation of the voltage and current polarized
elements individually as outlined below, then check the overall dual polarized response as
outlined at the end of this section.
A plot of the operating characteristic of the voltage polarized neutral directional feature for
various settings of MTA is shown below. Other characteristics for specific MTA settings can
be deduced from this diagram. Note that the diagram is plotted for the residual current
referred to the system faulted-phase phase-to-neutral voltage.
Residual Current Lags Faulted Phase Voltage
30°
90°
150°
210°
270°
330°
30°
90°
MTA SETTING
0°
60°
120°
180°
240°
300°
= PERMITTED TRIPPING REGION
FIGURE 7–4: Neutral Directional Voltage Polarized Fwd Operating Regions
Note
NOTE
The following descriptions present angles with reference to the faulted phase voltage and
assume an MTA setting of 180°. For an MTA setting other than 180° alter the noted angles
to those established by the programmed MTA.
To test forward tripping with voltage polarization, use the test connections specified in
FIGURE 7–1: Relay Test Wiring – Wye Connection on page 7–4 and follow the procedure
below:
 Set Van = Vbn = Vcn = nominal voltage at 0°, 120°, and 240° respectively.
Set a current of 0.2 of nominal to lag Van by 180° (in the tripping
direction) and inject into Phase A. Note that –V0 is less than the MIN
POLARIZING VOLTAGE.
 Reduce Van until –V0 is greater than the MIN POLARIZING VOLTAGE.
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 Slowly increase the angle of the Phase A current in the lagging
direction.
At an angle lagging Van by 270° ±2°, any output relays programmed for
this condition should operate if the function is set to “Control”. If the
function is set to “Alarm”, check that the Alarm and Message LEDs are
flashing, the Neutral Directional Reverse alarm message is displayed,
and any output relays programmed for this condition are operated.
 Continue to increase the lagging angle through 0°, until the block
message disappears at an angle lagging Van by 90° ±2°.
 Turn the current off.
 If desired, repeat the above Steps for Phases B and C using Ib with
faulted phase voltage Vbn and Ic with faulted phase voltage Vcn.
To test forward tripping with current polarization, use the test connections specified and
procedure specified below:
818081A9.cdr
FIGURE 7–5: Neutral Directional Test Connection for Polarizing Current
The following description presents angles with reference to the polarizing current.
Note
NOTE
 Set a current of 0.2 of nominal and inject into the ground current input
(Terminals G10 and H10).
 Set a 3I0 current to 0.2 of nominal and in-phase with the ground current
(this is the trip direction) and inject into the relay via the phase current
inputs.
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 Increase the lagging angle of 3I0.
At an angle lagging the ground current by 90° ±2°, any output relays
programmed for this condition should operate if the function is set to
Control. If the function is set to Alarm, check that the Alarm and
Message LEDs are flashing, the Neutral Directional Reverse alarm
message is displayed, and any output relays programmed for this
condition are operated.
 Continue to increase the lagging angle until the block message
disappears at an angle lagging the ground current by 270° ±2°. Turn the
current off.
To check forward tripping with dual polarization, use the test connections specified in
FIGURE 7–5: Neutral Directional Test Connection for Polarizing Current on page 7–34 and
follow the procedure below. As operations of each neutral directional sensing element
have been checked under voltage and current polarization, it is only necessary to check
that both directional elements are operational, and that either element can block tripping
for reverse faults.
 Set Van to 60%, and Vbn = Vcn to 100% nominal voltage at phase angles
of 0°, 120°, and 240°, respectively.
 Inject a current of 0.2 x nominal into the phase current input of the relay
(3I0) at an angle outside the tripping region of the set MTA, as compared
to faulted phase voltage Van.
The Neutral Directional Reverse alarm should appear.
 Inject a current of 0.2 x nominal, lagging the 3I0 current by 180°, into
the ground current input.
The block alarm should remain.
 Increase the angle of the ground current lagging 3I0 current through a
complete 360° rotation back to the original angle of lagging by 180°.
The block alarm should remain throughout the rotation as the voltage
polarized element is still blocking.
 Maintaining the ground current angle lagging 3I0 by 180° increase the
angle of 3I0 lagging the Van voltage through a complete 360° rotation
back to the original angle.
The block alarm should remain throughout the rotation as the current
polarized element is still blocking.
 Increase the angle of the ground current lagging 3I0 current until the
currents are in-phase.
The block alarm should remain.
 Maintaining the ground current angle in-phase with 3I0 increase the
angle of 3I0 lagging the Van voltage until into the permitted region.
The block alarm should disappear when the angle reaches the tripping
region.
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7.4.4
Ground
Overcurrent
CHAPTER 7: COMMISSIONING
Ground TOC
The procedure to test this element is identical to that outlined in Phase TOC 1 on page 7–
25, except that current is injected into the ground input terminals and the element is not
subject to the “phases required for operation” and “voltage restrained time overcurrent”
checks.
The blocking from logic inputs check is different from that for Phase TOC 1 and is
performed as follows:
 Inject current to cause a pickup.
 Assert a logic input to provide a “Block Ground Time”.
The Pickup LED should immediately go out.
 Repeat Steps 1 and 2 for logic inputs “Block Ground O/C”, “Block All
O/C” and “Block 1 Trip Relay” as required.
Ground IOC
The procedure to test this element is identical to that outlined in Phase TOC 1 on page 7–
25, except that current is injected into the ground input terminals, and the element is not
subject to the “phases required for operation”, “linear reset timing”, and “voltage restrained
time overcurrent” tests.
The blocking from logic inputs check is different from that for Phase TOC 1 and is
performed as follows:
 Inject current to cause a pickup.
 Assert a logic input to provide a “Block Ground Inst”.
The Pickup LED should immediately go out.
 Repeat Steps 1 and 2 for logic inputs “Block Ground O/C”, “Block All
O/C” and “Block 1 Trip Relay” as required.
Ground Directional OC
The procedure to test this element is identical to that outlined in Neutral Directional OC on
page 7–33, except that the operating current is the ground current. Also, Ground
Directional may only be voltage polarized.
Sensitive Ground TOC
The procedure to test this element is identical to that outlined in Phase TOC 1 on page 7–
25, except that current is injected into the sensitive ground input terminals, and the
element is not subject to the “phases required for operation” and “voltage restrained time
overcurrent” tests.
The blocking from logic inputs check is different from that for Phase TOC 1 and is
performed as follows:
 Inject current to cause a pickup.
 Assert a logic input to provide a “Blk Sens Gnd Time”.
The Pickup LED should immediately go out.
 Repeat Steps 1 and 2 for logic inputs “Block Sens Gnd O/C”, “Block All
O/C” and “Block 1 Trip Relay” as required.
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Sensitive Ground IOC
The procedure to test this element is identical to that outlined in Phase IOC 1 on page 7–29,
except that the current is injected into the sensitive ground input terminals, and the
element is not subject to the “phases required for operation”, “linear reset timing”, and
“voltage restrained time overcurrent” tests.
The blocking from logic inputs check is different from that for Phase IOC 1 and is performed
as follows:
 Inject current to cause a pickup.
 Assert a logic input to provide a “Blk Sens Gnd Inst”.
The Pickup LED should immediately go out.
 Repeat Steps 1 and 2 for logic inputs “Block Sens Gnd O/C”, “Block All
O/C” and “Block 1 Trip Relay” as required.
Sensitive Ground Directional OC
The procedure to test this element is identical to that outlined in Neutral Directional OC on
page 7–33, except that the operating current is the sensitive ground current.
7.4.5
NegativeSequence
Overcurrent
and Voltage
Negative-Sequence TOC
The procedure to test this element is identical to that outlined in Phase TOC 1 on page 7–
25, except that current is injected into any one phase of the phase input terminals and the
negative sequence current magnitude is 1/3rd of the injected current. The element is not
subject to the “phases required for operation” or “voltage restrained time overcurrent”
tests.
The blocking from logic inputs check is different from that for Phase TOC 1 and is
performed as follows:
 Inject current to cause a pickup.
 Assert a logic input to provide a “Block Neg Seq Time”.
The Pickup LED should immediately go out.
 Repeat Steps 1 and 2 for logic input “Block All O/C” and “Block 1 Trip
Relay” as required.
Negative-Sequence IOC
The procedure to test this element is identical to that outlined in Phase IOC 1 on page 7–29,
except that current is injected into any one phase of the phase input terminals and the
negative sequence current magnitude is 1/3rd of the injected current. The element is not
subject to the “phases required for operation”, “linear reset timing”, and “voltage restrained
time overcurrent” tests.
The blocking from logic inputs check is different from that for Phase IOC 1 and is performed
as follows:
 Inject current to cause a pickup.
 Assert a logic input to provide a “Block Neg Seq Inst”.
The Pickup LED should immediately go out.
 Repeat Steps 1 and 2 for logic input “Block All O/C” and “Block 1 Trip
Relay” as required.
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Negative-Sequence Directional OC
The procedure to test this element is identical to that outlined in Phase Directional OC on
page 7–30, except the injected current must be a negative sequence current.
Negative-Sequence Voltage
For Wye VTs, use the test connections specified in FIGURE 7–1: Relay Test Wiring – Wye
Connection on page 7–4. A negative sequence voltage can be created by injecting a single
phase voltage or a set of three single-phase voltages with a known negative sequence
component. For single phase injection, the negative sequence voltage magnitude is the
injected voltage divided by 3.
To test pickup for Wye VTs, use the following procedure:
 Inject a negative sequence voltage of 0 into the bus voltage input of the
relay.
The Pickup LED should be off.
 Slowly raise the voltage until the Pickup LED comes on.
This is the pickup level.
 Lower the voltage until the Pickup LED goes out.
This is the reset voltage, which should be 2% of VT less than the pickup
level.
For Delta VTs, use the test connections specified in FIGURE 7–2: Relay Test Wiring – Delta
Connection on page 7–5. A negative sequence voltage can be created by injecting a single
phase-phase voltage, or a set of two phase-phase voltages with a known negative
sequence component. For a single phase-phase injection the negative sequence voltage
magnitude is the injected voltage divided by 3 .
To test Pickup for Delta VTs, use the following procedure:
 Inject a negative sequence voltage of 0 into the bus voltage input of the
relay.
The Pickup LED should be off.
 Slowly raise the voltage until the Pickup LED comes on.
This is the pickup level.
 Lower the voltage until the Pickup LED goes out.
This is the reset voltage, which should be 2% of VT less than the pickup
level.
Indications and Operations are the same as those outlined in Phase TOC 1 on page 7–25.
The following procedure checks blocking from logic inputs for Delta VTs:
 Inject voltage to cause a pickup.
 Assert a logic input to provide a “Block Neg Seq Voltage”.
The Pickup LED should immediately go out.
 Repeat last 2 steps for logic input “Block 1 TRIP Relay” as required.
The following procedure checks negative-sequence voltage timing for Delta VTs:
 Connect the “Stop Trigger”.
 Set the voltage source to the required test voltage, then turn off the
voltage.
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 Reset the timer.
 Turn the voltage on and measure the operating time.
 Repeat last 3 steps four more times and obtain an average of the time
intervals.
 Reset the relay and disconnect the “Stop Trigger”.
7.4.6
Voltage
Bus Undervoltage (Wye VTs only)
To test Bus Undervoltage for Wye VTs, use the test connections specified in FIGURE 7–1:
Relay Test Wiring – Wye Connection on page 7–4.
The following procedure checks Pickup with One Phase For Operation:
 Inject Van = Vbn = Vcn = nominal voltage into the bus voltage input of
the relay.
The Pickup LED should be off.
 Slowly lower Van until the Pickup LED comes on.
This is the pickup voltage.
 Continue to lower Van until the Pickup LED goes out.
This is the MIN OPERATING VOLTAGE level minus 2% of VT.
 Raise Van until the Pickup LED comes on, and continue to increase until
the indicator goes out.
This is the reset voltage, which should be the pickup value plus 2% of
VT.
 Repeat last 4 steps, except adjust Vbn and Vcn in turn.
The following procedure checks Pickup with Two Phases For Operation:
 Inject Vcn = nominal voltage and Van = Vbn = a voltage between the MIN
OPERATING VOLTAGE and the pickup voltage into the bus voltage input
of the relay.
The Pickup LED should be on.
 Slowly raise Van until the Pickup LED goes out.
This is the reset voltage, which should be the pickup plus 2% of VT.
 Reduce Van until the Pickup LED comes on.
This is the pickup voltage of Van.
 Continue to lower Van until the Pickup LED goes out.
This is the MIN OPERATING VOLTAGE of Van minus 2% of VT.
 Slowly raise Van until the Pickup LED comes on, then reduce Vbn until
the Pickup LED goes out.
This is the programmed MIN OPERATING VOLTAGE of Vbn minus 2%
VT.
 Slowly raise Vbn until the Pickup LED first comes on and then goes out.
This is the reset voltage, which should be the pickup value plus 2% of
VT.
 Lower Vbn until the Pickup LED comes on.
This is the pickup voltage of Vbn.
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 Repeat last 7 steps, substituting Vcn for Van, Van for Vbn and Vbn for Vcn.
 Repeat last 7 steps, substituting Vbn for Van, Vcn for Vbn and Van for Vcn.
The following procedure checks Pickup with Three Phases For Operation:
 Inject Van = Vbn = Vcn = a voltage between the MIN OPERATING
VOLTAGE and the pickup voltage into the bus voltage input of the relay.
The Pickup LED should be on.
 Slowly raise Van until the Pickup LED goes out.
This reset voltage should be the pickup value plus 2% of VT.
 Reduce Van until the Pickup LED comes on.
This is the pickup voltage of Van.
 Slowly raise Vbn until the Pickup LED goes out.
This reset voltage should be the pickup value plus 2% of VT.
 Reduce Vbn until the Pickup LED comes on.
This is the pickup voltage of Vbn
 Slowly raise Vcn until the Pickup LED goes out.
This reset voltage should be the pickup value plus 2% of VT.
 Reduce Vcn until the Pickup LED comes on.
This is the pickup voltage of Vcn.
 Lower Van until the Pickup LED goes out.
This is the MIN OPERATING VOLTAGE of Van minus 2% of VT.
 Slowly raise Van until the Pickup LED comes on.
This is the MIN OPERATING VOLTAGE level.
 Reduce Vbn until the Pickup LED goes out. This is the MIN OPERATING
VOLTAGE of Vbn minus 2% of VT.
 Slowly raise Vbn until the Pickup LED comes on.
This is the MIN OPERATING VOLTAGE level.
 Reduce Vcn until the Pickup LED goes out.
This is the MIN OPERATING VOLTAGE of Vcn minus 2% of VT.
 Slowly raise Vcn until the Pickup LED comes on.
This is the MIN OPERATING VOLTAGE level.
Bus Undervoltage (Delta VTs only)
To test Bus Undervoltage for Delta VTs, use the test connections specified in FIGURE 7–2:
Relay Test Wiring – Delta Connection on page 7–5.
The following procedure tests Pickup with One Phase For Operation:
 Inject Vab = Vcb = nominal voltage into the bus voltage input of the
relay.
The Pickup LED should be off.
 Slowly lower Vab until the Pickup LED comes on.
This is the pickup voltage.
 Continue to lower Vab until the Pickup LED goes out.
This is the MIN OPERATING VOLTAGE minus 2% of VT.
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 Raise Vab until the Pickup LED comes on, and continue to increase until
the indicator goes out.
This is the reset voltage, which should be the pickup value plus 2% of
VT.
 Repeat last 4 steps except adjust Vbc.
The following procedure tests Pickup with Two or Three Phases For Operation:
 Inject Vab = nominal voltage and Vcb = a voltage between the MIN
OPERATING VOLTAGE and the pickup voltage into the bus voltage input
of the relay.
The Pickup LED should be on.
 Slowly raise Vcb until the Pickup LED goes out.
This reset voltage should be the pickup value plus 2% of VT.
 Reduce Vcb until the Pickup LED comes on.
This is the pickup voltage of Vcb.
 Continue to lower Vcb until the Pickup LED goes out.
This is the MIN OPERATING VOLTAGE of Vcb minus 2% of VT.
 Slowly raise Vcb until the Pickup LED comes on.
This is the MIN OPERATING VOLTAGE level.
 Reduce Vab until the Pickup LED goes out.
This is the MIN OPERATING VOLTAGE of Vab minus 2% of VT.
 Slowly raise Vab until the Pickup LED first comes on and then goes out.
This is the reset voltage, which should be the pickup value plus 2% of
VT.
 Lower Vab until the Pickup LED comes on.
This is the pickup voltage of Vab.
Bus Undervoltage (Wye and Delta VTs)
To test Bus Undervoltage for Wye and Delta VTs, use the test connections specified in
FIGURE 7–1: Relay Test Wiring – Wye Connection or FIGURE 7–2: Relay Test Wiring – Delta
Connection on page 7–5.
The procedures for testing Indications and Operations are the same as those outlined for
Phase TOC 1 on page 7–25.
The following procedure tests Blocking From Logic Inputs:
 Inject voltage into the required number of phases to cause a pickup.
 Assert a logic input to provide a “Block Undervolt 1(2)”.
The Pickup LED should immediately go out.
 Repeat last 2 steps for logic input “Block 1 Trip Relay” as required.
The following procedure tests the Bus Undervoltage element timing:
 Connect the “Stop Trigger.”
 Set the voltage source to nominal voltage.
 Reset the timer.
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 Turn the voltage off in the required number of phases, and measure the
operating time.
 Repeat last 3 steps four more times and obtain an average of the time
intervals.
 Reset the relay and disconnect the “Stop Trigger.”
Line Undervoltage
The following procedure tests the Line Undervoltage pickup:
 Inject nominal voltage into the line voltage input of the relay.
The Pickup LED should be off.
 Slowly lower the voltage until the Pickup LED comes on.
This is the pickup voltage.
 Continue to lower the voltage until the Pickup LED goes out.
This is the MIN OPERATING VOLTAGE minus 2% of VT.
 Raise the voltage until the Pickup LED comes on, and continue to
increase until the indicator goes out.
This is the reset voltage, which should be the pickup value plus 2% of
VT.
The procedures for testing Indications and Operations are the same as those outlined for
Phase TOC 1 on page 7–25.
The following procedure tests the Blocking From Logic Inputs:
 Inject voltage to cause a pickup.
 Assert a logic input to provide a “Block Undervolt 3(4)”.
The Pickup LED should immediately go out.
 Repeat last 2 steps for logic input “Block 1 Trip Relay” as required.
The following procedure tests the Line Undervoltage element Timing:
 Connect the “Stop Trigger”.
 Set the voltage source to nominal voltage.
 Reset the timer.
 Turn on the voltage, and measure the operating time.
 Repeat last 3 steps four more times and obtain an average of the time
intervals.
 Reset the relay and disconnect the “Stop Trigger”.
Overvoltage (Wye VTs only)
To test Overvoltage for Wye VTs, use the test connections specified in FIGURE 7–1: Relay
Test Wiring – Wye Connection on page 7–4. The following procedure tests Pickup with One
Phase For Operation:
 Inject Van = Vbn = Vcn = 0 into the bus voltage input of the relay.
The Pickup LED should be off.
 Slowly raise Van until the Pickup LED comes on.
This is the pickup voltage.
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 Lower Van until the Pickup LED goes out.
This is the reset voltage, which should be the pickup value minus 2% of
VT.
 Repeat last 3 steps except adjust Vbn and Vcn in turn.
The following procedure tests Pickup with Two Phases For Operation:
 Inject Van = Vbn = nominal voltage and Vcn = a voltage above the pickup
into the bus voltage input of the relay.
The Pickup LED should be off.
 Slowly raise Van until the Pickup LED goes on.
This is the pickup voltage of Van.
 Reduce Van until the Pickup LED goes off.
This reset voltage of Van should be the pickup value minus 2% of VT.
 Raise Van until the Pickup LED comes on.
 Repeat last 4 steps, substituting Vcn for Van, Van for Vbn and Vbn for Vcn.
 Repeat last 4 steps, substituting Vbn for Van, Vcn for Vbn and Van for Vcn.
The following procedure tests Pickup with Three Phases For Operation:
 Inject Van = Vbn = Vcn = a voltage above the pickup voltage into the bus
voltage input of the relay.
The Pickup LED should be on.
 Slowly lower Van until the Pickup LED goes out.
This reset voltage should be the pickup value minus 2% of VT.
 Raise Van until the Pickup LED comes on.
This is the pickup voltage of Van.
 Slowly lower Vbn until the Pickup LED goes out.
This reset voltage should be the pickup value minus 2% of VT.
 Raise Vbn until the Pickup LED comes on.
This is the pickup voltage of Vbn.
 Slowly lower Vcn until the Pickup LED goes out.
This reset voltage should be the pickup value minus 2% of VT.
 Raise Vcn until the Pickup LED comes on.
This is the pickup voltage of Vcn.
Overvoltage (Delta VTs only)
To test Overvoltage for Delta VTs, use the test connections specified in FIGURE 7–2: Relay
Test Wiring – Delta Connection on page 7–5. The following procedure tests Pickup with One
Phase For Operation:
 Inject Vab = Vcb = 0 into the bus voltage input of the relay.
The Pickup LED should be off.
 Slowly raise Vab until the Pickup LED comes on.
This is the pickup voltage.
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 Lower Vab until the Pickup LED goes out.
This is the reset voltage, which should be the pickup value minus 2% of
VT.
 Repeat last 3 steps, except adjust Vbc.
The following procedure tests Pickup with Two or Three Phases For Operation:
 Inject Vab = Vcb > pickup into the bus voltage input.
The Pickup LED should be on.
 Lower Vab until the Pickup LED goes out.
This is the reset voltage, which should be the pickup value minus 2% of
VT.
 Slowly raise Vab until the Pickup LED comes on.
This is the pickup voltage.
 Repeat last 3 steps, except adjust Vbc.
Overvoltage (Wye and Delta VTs)
To test Overvoltage for Delta and Wye VTs, use the test connections specified in FIGURE 7–
1: Relay Test Wiring – Wye Connection and FIGURE 7–2: Relay Test Wiring – Delta
Connection on page 7–5. The Indications and Operations are as outlined for Phase TOC 1
on page 7–25.
The following procedure tests Blocking From Logic Inputs:
 Inject voltage to cause a pickup.
 Assert a logic input to provide a “Block 1 Trip Relay”.
The following procedure tests the element Timing:
 Connect the “Stop Trigger”.
 Set the voltage source to the required test voltage, then turn off voltage.
 Reset the timer.
 Turn the voltage on in the required number of phases, and measure the
operating time.
 Repeat Steps 2, 3 and 4 four more times and obtain an average of the
time intervals.
 Reset the relay and disconnect the “Stop Trigger”.
Neutral Displacement (Wye VTs Only)
To test Neutral Displacement (Wye VTs only), use the test connections specified in FIGURE
7–1: Relay Test Wiring – Wye Connection on page 7–4.
The following procedure tests the Pickup Level:
 Apply a three phase balanced nominal voltage to the relay.
 Reduce one phase voltage slowly until the Neutral Displacement
element operates and note this voltage.
 Calculate the 3V0 (neutral voltage, i.e. residual voltage) being supplied
to the relay using the formula:
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3V 0 = V a + V b + V c
(EQ 7.2)
 Repeat last 3 steps, except adjust Vbn and Vcn in turn.
The following procedure tests Blocking From Logic Inputs:
 Cause a pickup of the Neutral Displacement element.
 Assert a logic input to provide a “Blk Ntr Displacement”.
The Pickup LED should immediately go out.
 Repeat last 2 steps for logic input “Block 1 Trip Relay” as required.
The following procedure tests element Timing:
 Connect the Stop Trigger.
 Preset the neutral (residual) voltage to be 150% of the pickup setting.
 Inject the preset neutral (residual) voltage into the relay and note the
delay time.
 Reset the timer.
 Repeat steps 3 and 4 four more times and obtain an average of the time
intervals.
 Disconnect the stop trigger when finished.
7.4.7
Frequency
Underfrequency
To test Underfrequency, use the test connections specified in FIGURE 7–1: Relay Test
Wiring – Wye Connection or FIGURE 7–2: Relay Test Wiring – Delta Connection on page 7–5.
The Indications and Operations are as outlined for Phase TOC 1 on page 7–25.
The following procedure checks Minimum Operating Voltage Supervision:
 Set the injection source well below the pickup frequency.
 Inject Va = 0 V into the bus voltage input of the relay with Ia = Ib = Ic
above the Minimum Operating Current level.
The Pickup LED should be off.
 Slowly increase the voltage in Phase A until the Pickup LED comes on.
Check that the pickup voltage is the selected Minimum Operating
Voltage.
 Slowly reduce the voltage.
Note the voltage at which the Pickup LED goes out. Check that this
dropout voltage is the pickup voltage minus 2 x VT nominal.
 Turn the injection voltage off.
The following procedure checks Minimum Operating Current Supervision:
 Set the injection source well below the pickup frequency. Inject Va = 0 V
into the bus voltage input and Ia = Ib = Ic = 0 A into the phase current
inputs of the relay.
The Pickup LED should be off.
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 Slowly increase the voltage in Phase A above the selected Minimum
Operating Voltage.
The Pickup LED should remain off.
 Slowly increase the Phase A current until the Pickup LED turns on.
This is the Minimum Operating Current level.
 Now reduce the current until the Pickup LED turns off.
Note the dropout level, which should be 2% of CT less than the
Minimum Operating Current level when the level is ≤ CT.
When the Minimum Operating Current level is > CT, the dropout level
should be 97 to 98% of the Minimum Operating Current level.
 Slowly increase the Phase B current until the Pickup LED turns on.
This is the Minimum Operating Current level.
 Now reduce the current until the Pickup LED turns off.
Note the dropout level, which should be 2% of CT less than the
Minimum Operating Current level when the level is ≤ CT.
When the Minimum Operating Current level is > CT, the dropout level
should be 97 to 98% of the Minimum Operating Current level.
 Slowly increase the Phase C current until the Pickup LED turns on.
This is the Minimum Operating Current level.
 Now reduce the current until the Pickup LED turns off.
Note the dropout level, which should be 2% of CT less than the
Minimum Operating Current level when the level is ≤ CT.
When the Minimum Operating Current level is > CT, the dropout level
should be 97 to 98% of the Minimum Operating Current level.
For the following Underfrequency test procedures, the injected voltage and currents are
always above the minimum operating levels.
Note
NOTE
The following procedure tests the Underfrequency Pickup:
 Inject voltage at a frequency above the pickup level into phase Va.
 Slowly decrease the frequency until the Pickup LED comes on.
Note the pickup value.
 Slowly increase the frequency until the Pickup LED goes out.
Note the dropout level, which should be the pickup plus 0.03 Hz.
The following procedure tests Blocking From Logic Inputs:
 Inject voltage and current above minimum at a frequency that causes a
pickup.
 Assert a logic input to provide a “Block Underfreq 1(2)”.
The Pickup LED should immediately go out.
 Repeat last 2 steps for logic input “Block 1 Trip Relay” as required.
The following procedure tests the Underfrequency element Timing:
 Connect the “Stop Trigger”.
 Set the voltage source prefault mode to nominal voltage, current and
frequency.
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 Set the voltage source fault mode to nominal voltage and current, but
with a frequency below pickup.
 Set the source to prefault mode, reset the timer, and apply to the relay.
 Jump the source to fault mode and measure the operating time.
 Repeat last 2 steps four more times and obtain an average of the time
intervals.
 Reset the relay and disconnect the “Stop Trigger”.
Frequency Decay
To test Frequency Decay, use the test connections specified in FIGURE 7–1: Relay Test
Wiring – Wye Connection or FIGURE 7–2: Relay Test Wiring – Delta Connection on page 7–5.
The Indications and Operations are as outlined for Phase TOC 1 on page 7–25.
The following procedure checks Minimum Operating Voltage Supervision:
 Inject voltage into the Va bus voltage input at a level well below the
Minimum Operating Voltage level.
 Also inject Ia = Ib = Ic at a level well above the Minimum Operating
Current level.
 Starting with the Va frequency at a level well below the FREQ DECAY
PICKUP, drop the frequency of Va at a speed greater than the FREQ
DECAY RATE setting.
The pickup indicator should remain off.
 Inject voltage into the Va bus voltage input at a level well above the
Minimum Operating Voltage level.
 Also inject Ia = Ib = Ic at a level well above the Minimum Operating
Current level.
 Starting with the Va frequency at a level well below the FREQ DECAY
PICKUP, drop the frequency of Va at a speed greater than the FREQ
DECAY RATE setting.
The pickup indicator should come on while the Va frequency is
dropping.
The following procedure checks the Minimum Operating Current Supervision:
 Inject voltage into the Va bus voltage input at a level well above the
Minimum Operating Voltage level.
 Also inject Ia = Ib = Ic at a level well below the Minimum Operating
Current level.
 Starting with the Va frequency at a level well below the Frequency
Decay Pickup, drop the frequency of Va at a speed greater than the
Frequency Decay Rate setting.
The Pickup LED should remain off.
 With the Va voltage at a level well above the Minimum Operating
Voltage level, increase Ia to a level well above the Minimum Operating
Current level.
Currents Ib and Ic should be well below the Minimum Operating
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Current level. Starting with the Va frequency at a level well below the
FREQ DECAY PICKUP, drop the frequency of Va at a speed greater than
the FREQ DECAY RATE setting.
The Pickup LED should come on while the Va frequency is dropping.
 With the Va voltage at a level well above the Minimum Operating
Voltage level, increase Ib to a level well above the Minimum Operating
Current level. Currents Ia and Ic should be well below the Minimum
Operating Current level.
Starting with the Va frequency at a level well below the FREQ DECAY
PICKUP, drop the frequency of Va at a speed greater than the FREQ
DECAY RATE setting.
The Pickup LED should come on while the Va frequency is dropping.
 With the Va voltage at a level well above the Minimum Operating
Voltage level, increase Ic to a level well above the Minimum Operating
Current level.
Currents Ia and Ib should be well below the Minimum Operating
Current level. Starting with the Va frequency at a level well below the
FREQ DECAY PICKUP, drop the frequency of Va at a speed greater than
the FREQ DECAY RATE setting.
The Pickup LED should come on while the Va frequency is dropping.
For the following Frequency Decay test procedures, the injected voltage and currents are
always above the minimum operating levels.
Note
NOTE
The following procedure checks the Frequency Decay Pickup:
 Starting with the Va frequency at a level well above the FREQ DECAY
PICKUP, drop the frequency of Va at a speed greater than the FREQ
DECAY RATE setting, to a level still well above the FREQ DECAY PICKUP.
The Pickup LED should remain off.
 Continue dropping the Va frequency at a speed greater than the FREQ
DECAY RATE.
When the frequency drops below the FREQ DECAY PICKUP, the Pickup
LED will come on.
The following procedure checks the Frequency Decay Rate:
 With the Va frequency at a level well below the FREQ DECAY PICKUP,
drop the frequency of Va at a speed less than the FREQ DECAY RATE
setting.
The pickup indicator should remain off.
 With the Va frequency at a level well below the FREQ DECAY PICKUP,
drop the frequency of Va at a speed greater than the FREQ DECAY RATE
setting.
The pickup indicator will come on.
The following procedure checks Blocking From Logic Inputs:
 Decrease the Va frequency at a rate to cause a pickup.
 Assert a logic input to provide a “Block Frequency Decay”.
The Pickup LED should immediately go out.
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 Repeat Steps 1 and 2 for logic input “Block 1 Trip Relay” as required.
The following procedure checks the Frequency Decay Timing:
 Connect the Stop Trigger.
 Preset the ramp-rate to a minimum of 110% of the pickup and reset the
timer.
 Inject the preset voltage into the Va bus voltage input and note the
measured delay time. Reset the timer.
 Repeat the last step four more times and obtain an average of the time
intervals.
 Disconnect the Stop Trigger.
7.4.8
Breaker
Failure
To test Breaker Failure, use the test connections specified in FIGURE 7–1: Relay Test Wiring
– Wye Connection or FIGURE 7–2: Relay Test Wiring – Delta Connection on page 7–5. The
Indications and Operations are as outlined for Phase TOC 1 on page 7–25. This element has
no Trip function.
 Ensure the wiring to the circuit breaker trip and close circuits is
complete.
 Energize the breaker trip and close circuits and close the breaker.
 Carefully disconnect a wire to open the trip circuit.
 Set a test current level 3% above the BRKR FAILURE CURRENT setpoint
and inject current into a phase current input (all overcurrent protection
features are “Disabled”).
 Assert a Trip logic input, which cannot be performed by the breaker.
After a delay the element should generate an output (the delay time can
be checked in the Event Recorder).
 Turn the current off and reset the relay.
 Reduce the current magnitude to 3% below the BRKR FAILURE
CURRENT setpoint and inject current into a phase current input. Assert a
Trip logic input, which cannot be performed by the breaker.
The element should not generate an output.
7.4.9
Reverse Power
To test the Reverse Power element, use the test connections specified in FIGURE 7–1: Relay
Test Wiring – Wye Connection or FIGURE 7–2: Relay Test Wiring – Delta Connection on page
7–5. The Indications and Operations are as outlined for Phase TOC 1 on page 7–25.
The following procedure tests Pickup for the Reverse Power element:
 Apply a three phase nominal voltage to the relay.
 Adjust the phase angle between the voltage and current to be 180°.
 Inject current into all three phases and increase slowly until Reverse
Power operates.
Note the pickup value.
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 Calculate the power value from the following formula:
P = 3 × VI cos ( θ ) , where V is the primary line to line voltage, I is the
pickup value expressed as a primary value, and cos(θ) is cos 180° (in
this case, 1.0).
 Express the measured power as a percentage of the rated power
calculated using rated values in the above equation.
The value should be within specifications for this element.
 Adjust the phase angle to 100°, 120°, 240°, and 260°, checking the
current pickup value for each angle.
Calculate the relay pickup power for each angle using the formula given
above.
The following procedure tests the Blocking From Logic Inputs for Reverse Power:
 Cause the reverse power element to pickup.
 Assert a logic input to provide a “Block Reverse Power”.
The Pickup LED should immediately go out.
 Repeat Steps 1 and 2 for logic input “Block 1 Trip Relay” as required.
The following procedure checks Timing for the Reverse Power Element:
 Connect the Stop Trigger.
 Preset the input voltage and current to provide a reverse real power
which is 150% of pickup.
 Inject the preset voltage and current and note the measured delay time.
 Reset the timer.
 Repeat last 2 steps four more times and obtain an average of the time
intervals.
 Disconnect the Stop Trigger.
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7.5
7.5.1
Current
Monitoring
Monitoring
Phase Current Level
To test Phase Current monitoring, use the test connections specified in FIGURE 7–1: Relay
Test Wiring – Wye Connection or FIGURE 7–2: Relay Test Wiring – Delta Connection on page
7–5. The Indications and Operations are as outlined for Phase TOC 1 on page 7–25, except
that this element has no Trip function.
 Set the Delay time to 0.
 Inject current at a level below the pickup level into Phase A.
 Slowly increase the current until pickup is reached and the element
generates an output.
 Slowly reduce the current until the element resets, which should be 2%
of CT less than pickup when pickup ≤ CT or 97 to 98% of pickup when
pickup > CT.
 Repeat Steps 2 to 4 for phase B and C current.
 Set the Delay timer to the required setting.
The following procedure checks the Phase Current Level Timing:
 Set the test source to a current at least 110% of pickup.
Turn off and reset the timer.
 Inject current into the relay and measure the time to operate.
 Repeat Step 2 four more times and obtain an average of the time
intervals
 Disconnect the Stop Trigger.
Neutral Current Level
To test Neutral Current monitoring, use the test connections specified in FIGURE 7–1: Relay
Test Wiring – Wye Connection or FIGURE 7–2: Relay Test Wiring – Delta Connection on page
7–5. The testing for this element is the same as outlined above for Phase Current Level,
except that current is the residual current injected into the phase current inputs.
7.5.2
Fault Locator
Note
NOTE
To test the Fault Locator, use the test connections specified in FIGURE 7–1: Relay Test
Wiring – Wye Connection or FIGURE 7–2: Relay Test Wiring – Delta Connection on page 7–5.
Because of the broad range of variables that can be encountered in actual systems a
representative configuration with a set of impedances and instrument transformers have
been chosen to demonstrate these tests. The model used to calculate the voltage and
current phasors for the tests is a radial, 10 km long, three phase, four wire system of 13.8
kV nominal and 600 A feeder capacity. At the relay location there are wye-connected VTs
rated 14400/120 V and CTs rated 600/5 A. A prefault load of about 8.5 MVA exists on the
feeder. The relay is a 5 A unit.
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Model Impedances (Ω)
ZPOS = ZNEG
ZZERO
Source
0.028 + j0.662
0.028 + j0.662
Feeder
1.250 + j5.450
5.280 + j15.79
The source voltage (ahead of the source impedance) is 14.0 kV∠1.6°. Any overcurrent
feature, all of which can cause a fault location calculation by tripping, set to a pickup
current below the programmed test current, can be used for the tests.
 Program the test set with the following prefault voltages and currents.
 Van = 67.8∠0°; Vbn = 67.8∠240°; Vcn = 67.8∠120°; Ia = 2.9∠330°; Ib =
2.9∠210°; Ic = 2.9∠90°
 Program the test set with the following fault voltages and currents.
This fault is from Phase A to ground, placed 5.0 km from the relay.
 Van = 59.0∠0°; Vbn = 67.4∠241°; Vcn = 67.4∠121°; Ia = 13.0∠286°; Ib
= 2.9∠210°; Ic = 2.9∠90°
 Inject the prefault voltages and currents, then apply the fault.
The relay should trip and determine the type of fault (A-G), the distance
to the fault (5.0 km) and the reactance to the fault (2.73 Ω).
 Program the test set with the following fault voltages and currents.
This fault is Phase B to ground, 6.0 km from the relay.
 Van = 67.4∠2°; Vbn = 60.3∠242°; Vcn = 67.4∠122°; Ia = 2.9∠330°; Ib =
12.0∠166°; Ic = 2.9∠90°
 Inject the prefault voltages and currents, then apply the fault.
The relay should trip and determine the type of fault (B-G), the distance
to the fault (6.0 km) and the reactance to the fault (3.27 Ω).
 Program the test set with the following fault voltages and currents.
This fault is Phase C to ground, placed 7.0 km from the relay.
 Van = 67.4∠2°; Vbn = 67.4∠242°; Vcn = 61.3∠120°; Ia = 2.9∠330°; Ib =
2.9∠210°; Ic = 9.9∠47°
 Inject the prefault voltages and currents, then apply the fault.
The relay should trip and determine the type of fault (C-G), the distance
to the fault (7.0 km) and the reactance to the fault (3.82 Ω).
 Program the test set with the following fault voltages and currents.
This fault is Phase A to C, 8.0 km from the relay.
 Van = 60.4∠4°; Vbn = 67.4∠242°; Vcn = 61.7∠117°; Ia = 11.4∠253°; Ib
= 2.9∠210°; Ic = 11.4∠73°
 Inject the prefault voltages and currents, then apply the fault parameters.
The relay should trip and determine the type of fault (A-C), the distance
to the fault (8.0 km) and the reactance to the fault (4.36 Ω).
 Program the test with the following fault voltages and currents.
This fault is Phase A to B, placed 9.0 km from the relay.
 Van = 62.2∠358°; Vbn = 61.0∠244°; Vcn = 67.4∠122°; Ia = 10.3∠313°;
Ib = 10.3∠133°; Ic = 2.9∠90°
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 Inject the prefault voltages and currents, then apply the fault.
The relay should trip and determine the type of fault (A-B), the distance
to the fault (9.0 km) and the reactance to the fault (4.91 Ω).
 Program the test with the following fault voltages and currents.
This fault is Phase A to B to C, 10.0 km from the relay.
 Van = 60.3∠0°; Vbn = 60.3∠240°; Vcn = 60.3∠120°; Ia = 10.8∠283°; Ib
= 10.8∠163°; Ic = 10.8∠43°
 Inject the prefault voltages and currents, then apply the fault.
The relay should trip and determine the type of fault (A-B-C), the
distance to the fault (10.0 km) and the reactance to the fault (5.45 Ω).
7.5.3
Demand
Monitoring
Current Demand
To test Current Demand, use the test connections specified in FIGURE 7–1: Relay Test
Wiring – Wye Connection or FIGURE 7–2: Relay Test Wiring – Delta Connection on page 7–5.
The Indications and Operations are as outlined for Phase TOC 1 on page 7–25, except that
this element has no Trip function.
 Clear demand data registers before starting this test.
 Inject a fixed value of current.
 Monitor the actual value of the measured demand, and note the level at
which the feature generates an output.
 Turn the current off.
Real Power Demand
To test Real Power Demand, use the test connections specified in FIGURE 7–1: Relay Test
Wiring – Wye Connection or FIGURE 7–2: Relay Test Wiring – Delta Connection on page 7–5.
The Indications and Operations are as outlined for Phase TOC 1 on page 7–25, except that
this element has no Trip function.
 Clear demand data registers before starting this test.
 Inject a fixed value of watts.
 Monitor the actual value of the measured demand, and note the level at
which the feature generates an output.
 Turn the current off.
Reactive Power Demand
To test Reactive Power Demand, use the test connections specified in FIGURE 7–1: Relay
Test Wiring – Wye Connection or FIGURE 7–2: Relay Test Wiring – Delta Connection on page
7–5. The Indications and Operations are as outlined for Phase TOC 1 on page 7–25, except
that this element has no Trip function.
 Clear demand data registers before starting this test.
 Inject a fixed value of vars.
 Monitor the actual value of the measured demand, and note the level at
which the feature generates an output.
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 Turn the current off.
Apparent Power Demand
To test Apparent Power Demand, use the test connections specified in FIGURE 7–1: Relay
Test Wiring – Wye Connection or FIGURE 7–2: Relay Test Wiring – Delta Connection on page
7–5. The Indications and Operations are as outlined for Phase TOC 1 on page 7–25, except
that this element has no Trip function.
 Clear demand data registers before starting this test.
 Inject a fixed value of VA.
 Monitor the actual value of the measured demand, and note the level at
which the feature generates an output.
 Turn the current off.
7.5.4
Analog Inputs
Analog Threshold
 Inject DC mA current at a level below the pickup level into the analog
input.
 Slowly increase the current until the element generates an output.
Slowly reduce the current until the element reset.
The following procedure tests Analog Threshold Timing:
 Connect the Stop Trigger.
 Preset the DC mA current source to a minimum of 110% of the pickup
current.
 Turn the current off, and reset the timer.
 Inject the preset current into the analog input and note the measured
delay time.
 Reset the timer.
 Repeat Step 3 four more times and obtain an average of the time
intervals.
 Disconnect the Stop Trigger.
Analog In Rate
The Indications and Operations are as outlined for Phase TOC 1 on page 7–25, except that
this element has no Trip function.
 Connect the output of a DC ramping-current generator to the analog
input.
 Remove the power supply from the relay to ensure the analog input
memory is set to zero, then re-apply power.
 Set the ramp-rate below the rate-of-change pickup and inject into the
analog input.
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 Wait for 90 seconds (fast rate) or 90 minutes (slow rate) to ensure the
relay has properly measured the input ramping-rate.
The relay should not pickup.
 Cycle the relay power supply Off then On.
 Adjust the ramp-rate to a higher rate and again apply and, if the relay
doesn't pickup, cycle the relay power supply Off then On.
 Repeat this procedure until the element generates an output.
The following procedure tests Analog Input Rate Timing:
 Connect the Stop Trigger.
 Preset the ramp-rate to a minimum of 110% of the pickup.
 Turn the current off, and reset the timer.
 Inject the preset current into the analog input and note the measured
delay time.
 Reset the timer.
 Repeat Step 3 four more times and obtain an average of the time
intervals.
 Disconnect the Stop Trigger.
7.5.5
Overfrequency
Monitoring
To test Overfrequency monitoring, use the test connections specified in FIGURE 7–1: Relay
Test Wiring – Wye Connection or FIGURE 7–2: Relay Test Wiring – Delta Connection on page
7–5. The Indications and Operations are as outlined for Phase TOC 1 on page 7–25, except
that this element has no Trip function.
 Inject voltage at a frequency below the pickup level into Phase A.
 Slowly increase the frequency until the element generates an output.
 Slowly reduce the frequency until the element resets.
The following procedure checks the Overfrequency monitoring Timing:
 Connect the Stop Trigger.
 Preset the voltage source frequency to a minimum of 110% of pickup.
 Turn voltage off and reset the timer.
 Inject the preset voltage into phase A and note the measured delay time.
 Reset the timer.
 Repeat Step 3 four more times and obtain an average of the time
intervals.
 Disconnect the “Stop Trigger”.
7.5.6
Power Factor
To test Power Factor monitoring, use the test connections specified in FIGURE 7–1: Relay
Test Wiring – Wye Connection or FIGURE 7–2: Relay Test Wiring – Delta Connection on page
7–5. The Indications and Operations are as outlined for Phase TOC 1 on page 7–25, except
that this element has no Trip function.
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The following procedure checks Minimum Operating Voltage/Current Supervision:
 Inject fixed values of voltage and current at about nominal values, at
unity power factor.
 Slowly increase the lagging current angle, waiting for a time longer than
the delay before each adjustment, until the element generates an output.
 Slowly reduce voltage Va magnitude until the power factor feature
resets.
Note the dropout voltage, which should be at about 30% of the selected
nominal voltage. Return Va to nominal.
 Repeat step 3 for Vb.
 Repeat step 3 for Vc.
 Slowly reduce Ia and Ib magnitude to 0.
The power factor feature should remain operated.
 Slowly reduce Ic magnitude to 0.
The power factor feature should reset.
 Return Ia to nominal.
The power factor feature should operate again. Return Ib and Ic to
nominal.
 Decrease the angle of lagging (balanced) current until the feature dropsout and resets the output relays.
The following procedure checks Power Factor Timing:
 Connect the Stop Trigger.
 Preset the 3-phase voltage and current inputs to a power factor more
lagging than the pickup level.
 Turn voltages and currents off, and reset the timer.
 Inject the preset voltage and current and note the measured delay time.
 Reset the timer.
 Repeat step 3 four more times and obtain an average of the time
intervals.
 Disconnect the “Stop Trigger”.
7.5.7
VT Failure
To test VT Failure monitoring, use the test connections specified in FIGURE 7–1: Relay Test
Wiring – Wye Connection or FIGURE 7–2: Relay Test Wiring – Delta Connection on page 7–5.
 Set Van = Vbn = Vcn = nominal voltage at 0°, 120°, and 240° respectively,
and inject into the relay.
With these balanced voltages 120° apart, the positive sequence voltage
(V1) is greater than 0.05 x VT.
 Set Ia = Ib = Ic = 1 x CT at 0°, 120°, and 240° respectively, and inject
into the relay.
With these balanced currents 120° apart, the positive sequence current
(I1) is greater than 0.05 x CT.
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 Remove the balanced voltages so the positive sequence voltage (V1) is
less than 0.05 x VT.
If this function is set to “Control”, any output relays programmed for
this condition should operate. If the function is set to “Alarm”, check
that the Alarm and Message LEDs are flashing, the VT Failure alarm
message is displayed, and any output relays programmed for this
condition are operated.
 Apply the balanced voltages and the VT Failure condition should reset.
 Now reduce Van until the VT Failure condition returns.
 Verify the ratio of the negative sequence voltage (V2) to the positive
sequence voltage (V1) is 0.25 at this point.
 Return Van to nominal and the VT Failure condition should reset.
 Repeat last 3 steps for Vbn and Vcn.
 With Van = Vbn = Vcn returned to nominal voltage at 0°, 120°, and 240°
respectively, reduce Van until the VT Failure condition returns.
 Now reduce Ia until the VT Failure condition resets.
 Verify the ratio of the negative sequence current (I2) to the positive
sequence current (I1) > 0.20 at this point.
 Return Ia to nominal and the VT Failure condition should reset.
 Repeat last 3 steps for Ib and Ic.
7.5.8
Trip Coil
Monitor
The Indications and Operations for the Trip Coil Monitor are as outlined for Phase TOC 1 on
page 7–25, except that this element has no Trip function.
 Ensure the wiring to the circuit breaker trip and close circuits is
complete.
 Energize the breaker trip and close circuits and close the breaker.
 Carefully disconnect a wire to open the trip circuit.
After 5 seconds the element should generate an output.
 Restore the open circuit and the element should reset.
 If the Open Breaker permissive is “Enabled”, and the trip circuit wiring
has been arranged to permit this operation, open the breaker.
 Repeat last 2 steps.
7.5.9
Close Coil
Monitor
The Indications and Operations for the Close Coil Monitor are as outlined for Phase TOC 1
on page 7–25, except that this element has no Trip function.
 Ensure the wiring to the circuit breaker trip and close circuits is
complete.
 Energize the breaker trip and close circuits and open the breaker.
 Carefully disconnect a wire to open the close circuit.
After 5 seconds the element should generate an output.
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 Restore the open circuit and the element should reset.
 If the Closed Breaker permissive is “Enabled”, and the close circuit
wiring has been arranged to permit this operation, close the breaker.
 Repeat last 2 steps.
7.5.10 Breaker
Operation
Failure
The Indications and Operations for the Breaker Operation Failure are as outlined for Phase
TOC 1 on page 7–25, except that this element has no Trip function.
 Ensure the wiring to the circuit breaker trip and close circuits is
complete.
 Energize the breaker trip and close circuits and open the breaker.
 Carefully disconnect a wire to open the close circuit.
 Apply a momentary Close command to the relay.
After a delay the element should generate an output (the delay time can
be checked in the Event Recorder).
 Restore the open circuit and reset the relay.
 Close the breaker.
 Carefully disconnect a wire to open the trip circuit.
 Apply a momentary Trip command to the relay.
After a delay the element should generate an output (the delay time can
be checked in the Event Recorder)
 Restore the open circuit and reset the relay.
 Open and close the breaker a number of times to confirm the delay time
provides sufficient margin to allow for normal operation of the breaker.
7.5.11 Arcing Current
This test requires equipment which is seldom readily available in the field. It is suggested
that as this feature does not require extreme levels of reliability and security it is not
necessary to be field-tested. A procedure is available upon request from GE Multilin for
those users wishing to perform this test. We suggest the following procedure to confirm
this element is operational.
The Indications and Operations for the Arcing Current are as outlined for Phase TOC 1 on
page 7–25, except that this element has no Trip function.
 Check the value displayed under A3 MAINTENANCE  ARCING CURRENT
 TOTAL ARCING CURRENT for each phase.
 Set the Total Arcing Current Limit to a level just above this value.
 Now perform a number of overcurrent element tests, with current
maintained after the Trip command, until this element generates an
output.
 Be sure to reset the Total Arcing Current memory and setpoint at the end
of this test.
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7.5.12 Analog Output
Channels
 Connect a milli-ammeter to channel output terminals as required.
7.5.13 IRIG-B
 Disconnect the IRIG-B input to the relay from the signal source.
 Follow the test procedures previously outlined for the channel
parameter observing the output on the milli-ammeter.
 Under S1 RELAY SETUP  CLOCK manually set the relay date and time to
incorrect values.
 Under A1 STATUS  CLOCK check that the relay has accepted the
programmed date and time.
 Set the IRIG-B TIME SYNC setpoint to the required signal type - the relay
should display the IRIG-B FAILURE self-test warning.
 Connect the IRIG-B input from the signal source to the relay and check
the signal is available at the relay terminals.
 The IRIG-B FAILURE self-test warning should be removed from the
display.
 Under A1 STATUS  CLOCK check that the relay clock now displays the
correct date and time.
7.5.14 Pulse Output
 Inject quantity to be used to provide a pulse output.
 Observe that the pulses occur at the proper intervals by using the actual
value measurement provided by the relay.
A counter or oscilloscope may also be used to confirm pulse timing.
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7.6
7.6.1
Control Schemes
Setpoint
Group Control
Make the test connections specified in FIGURE 7–1: Relay Test Wiring – Wye Connection or
FIGURE 7–2: Relay Test Wiring – Delta Connection on page 7–5.
NOTE
The relay is defaulted to Setpoint Group 1, and will be using this group for setpoints unless
specifically changed to another group. This procedure assumes the relay initially uses
Group 1 as indicated by the faceplate LED.
Note
 Change the S7 CONTROL  SETPOINT GROUPS  ACTIVE SETPOINT
GROUP setpoint to “Group 2” and the EDIT SETPOINT GROUP setpoint in
the same menu to “Active Group”.
The faceplate LEDs should now indicate the relay is using Setpoint
Group 2.
 Change at least one protection element setpoint from the setting in
Group 1.
 Repeat Steps 2 and 3 for active setpoint group selections of Group 3 and
Group 4, while monitoring that the LED indicators show the correct
group.
 Check that the operation of the protection feature programmed is
controlled by the setting in group 4.
 Change the S7 CONTROL  SETPOINT GROUPS  ACTIVE SETPOINT
GROUP setpoint to “Group 3”.
The LED on the faceplate should now indicate the relay is using
Setpoint Group 3.
 Check that the operation of the protection feature programmed is
controlled by the setting in Group 3.
 Change the S7 CONTROL  SETPOINT GROUPS  ACTIVE SETPOINT
GROUP setpoint to “Group 2”.
The LED on the faceplate should now indicate the relay is using
Setpoint Group 2.
 Check that the operation of the protection feature programmed is
controlled by the setting in Group 2.
 Change the S7 CONTROL  SETPOINT GROUPS  ACTIVE SETPOINT
GROUP setpoint to Group 1.
The LED on the faceplate should now indicate the relay is using
Setpoint Group 1.
 Check that the operation of the protection feature programmed is
controlled by the setting in Group 1.
 Assert logic input Setpoint Group 2, and check that the LED indicator
shows Setpoint Group 2.
 Assert logic input Setpoint Group 3, and check that the LED indicator
shows Setpoint Group 3.
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 Assert logic input Setpoint Group 4, and check that the LED indicator
shows Setpoint Group 4.
 De-assert logic input Setpoint Group 4, and check that the LED
indicator shows Setpoint Group 3.
 De-assert logic input Setpoint Group 3, and check that the LED
indicator shows Setpoint Group 2.
 De-assert logic input Setpoint Group 2, and check that the LED
indicator shows Setpoint Group 1.
 Check that the changing of setpoint groups is placed in the event
recorder.
If the BRKR OPEN INHIBIT setpoint is to be “Enabled”:
 Assert a breaker state logic input so that the relay determines the breaker
is closed.
 Assert logic input Setpoint Group 2.
The faceplate LED should indicate the relay is using Setpoint Group 2.
 De-assert the breaker state logic input so that the relay determines the
breaker is open.
 De-assert logic input Setpoint Group 2.
The faceplate LED should indicate the relay is still using Setpoint
Group 2.
 Assert the breaker state logic input so that the relay determines the
breaker is closed.
The faceplate LED should indicate the relay is now using Setpoint
Group 1.
If the OVERCURRENT P/U INHIBIT setpoint is to be “Enabled”:
 Assert logic input Setpoint Group 2.
The faceplate LED should indicate the relay is using Setpoint Group 2.
 Inject current above the pickup setting of an overcurrent element that is
not Disabled.
 De-assert logic input Setpoint Group 2.
The faceplate LED should indicate the relay is still using Setpoint
Group 2.
 Reduce the injected current until the overcurrent element resets.
The LED on the faceplate should indicate the relay is now using
Setpoint Group 1.
 Turn current off.
If the OVERVOLT P/U INHIBIT setpoint is to be “Enabled”:
 Assert logic input Setpoint Group 2.
The faceplate LED should indicate the relay is using Setpoint Group 2.
 Inject voltage above the pickup setting of an overvoltage element that is
not Disabled.
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 De-assert logic input Setpoint Group 2.
The faceplate LED should indicate the relay is still using Setpoint
Group 2.
 Reduce the injected voltage until the overvoltage element resets.
The LED on the faceplate should indicate the relay is now using
Setpoint Group 1.
 Turn voltage off.
If the UNDERVOLT P/U INHIBIT setpoint is to be “Enabled”:
 Inject voltage above the pickup setting of an undervoltage element that
is not Disabled.
 Assert logic input Setpoint Group 2.
The faceplate LED should indicate the relay is using Setpoint Group 2.
 Reduce voltage below the pickup setting of an undervoltage element
that is not Disabled.
 De-assert logic input Setpoint Group 2.
The faceplate LED should indicate the relay is still using Setpoint
Group 2.
 Increase the injected voltage until the undervoltage element resets.
The LED on the faceplate should indicate the relay is now using
Setpoint Group 1.
 Turn voltage off.
If the UNDERFREQ P/U INHIBIT setpoint is to be “Enabled”:
 Inject voltage with frequency above the pickup setting of an
underfrequency element that is not Disabled.
 Assert logic input Setpoint Group 2.
The faceplate LED should indicate the relay is using Setpoint Group 2.
 Reduce frequency below the pickup setting of an underfrequency
element that is not Disabled.
 De-assert logic input Setpoint Group 2.
The faceplate LED should indicate the relay is still using Setpoint
Group 2.
 Increase the injected frequency until the underfrequency element resets.
The LED on the faceplate should indicate the relay is now using
Setpoint Group 1.
 Turn voltage off.
7.6.2
7 - 62
Synchrocheck
 Make the test connections specified in FIGURE 7–1: Relay Test Wiring
– Wye Connection or FIGURE 7–2: Relay Test Wiring – Delta
Connection on page 7–5 and also connect a variable voltage source to
the line voltage input.
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 Initially set the function setpoint to Control, the Dead Source
Permissive setpoint to Off and the Maximum Voltage Difference
setpoint to 100 kV.
 As there are no input voltages, any selected output relays should now be
operated along with the Out Of Sync control message.
 Change the function setting to Alarm.
The alarm message and LED should be displayed, and any selected
output relays should remain operated.
 Inject a balanced three-phase voltage at nominal voltage and frequency
into the bus voltage input.
 Turn off the voltage and make parallel connections (observing polarity)
from the bus voltage input that corresponds with the selection made
under subheading S2 SYSTEM SETUP  LINE VT SENSING  VT
CONNECTION to the line voltage input.
 Turn the voltage on and check that these voltages show difference
measurements of 0 under A2 METERING  VOLTAGE  SYNCHRO DELTA
(the ΔV will not be 0 unless the bus and line VTs have identical ratings.
If the difference is not shown as 0, calculate the two equivalent primary
voltage values for the injected voltage; they should be the same.) This
checks that the relay has selected the correct bus voltage input for the
synchrocheck measurements.
 Turn the voltage off and remove the parallel connections.
 Inject a single-phase voltage at nominal voltage and frequency into the
bus voltage input that corresponds with the selection made under
subheading S2 SYSTEM SETUP  LINE VT SENSING  VT CONNECTION.
 Inject voltage and frequency into the line voltage input and adjust this
voltage until ΔV, ΔF and ΔF as shown under subheading A2 METERING 
VOLTAGE  SYNCHRO DELTA are all 0.
 Reduce the line voltage magnitude to 0.
The “Out of Sync” alarm will be displayed as the line voltage is below
the minimum voltage requirement.
 Slowly raise this voltage until the “Out of Sync” alarm is no longer
displayed.
This magnitude should be the setpoint value.
 Raise the line voltage input to the nominal value, and lower the bus
voltage magnitude to 0.
The “Out of Sync” alarm will be displayed as the bus voltage is below
the minimum voltage requirement.
 Slowly raise this voltage until the “Out of Sync” alarm is no longer
displayed.
This magnitude should be the setpoint value.
 Enter the required setting of MAX VOLTAGE DIFFERENCE.
The “Out of Sync” alarm will be displayed as the voltage difference is
above the maximum difference requirement.
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 While monitoring ΔV on the display, slowly raise the bus voltage until
the “Out of Sync” alarm is no longer displayed.
Check that the voltage difference is the selected value.
 Set the bus voltage magnitude to nominal, and the line voltage to a level
above the minimum required voltage.
 The “Out of Sync” alarm will be displayed as the voltage difference is
above the maximum difference requirement.
 While monitoring ΔV on the display, slowly raise the line voltage until
the “Out of Sync” alarm is no longer displayed.
Check that the voltage difference is the selected value.
 Set both line and bus voltage magnitude and frequency to nominal.
Adjust the line voltage phase position to lag the bus voltage by 180°.
 The “Out of Sync” alarm will be displayed as the angle difference is
above the maximum difference requirement.
 While monitoring ΔF on the display, slowly increase the line voltage
lagging phase position until the “Out of Sync” alarm is no longer
displayed. Check that the angle difference is the selected value. Return
the line voltage angle to 0°.
 Set the line voltage frequency to a value lower than allowed by the
maximum frequency difference.
 While monitoring ΔF on the display, slowly increase the line voltage
frequency until the “Out of Sync” alarm is no longer displayed. Check
that the frequency difference is the selected value.
 Set the line voltage to a frequency higher than permitted by the
maximum frequency difference.
 The “Out of Sync” alarm will be displayed as the frequency difference
is above the maximum difference requirement.
 While monitoring ΔF on the display, slowly decrease the line voltage
frequency until the “Out of Sync” alarm is no longer displayed.
Check that the frequency difference is the selected value.
 Turn voltages off.
If the Dead Source Permissive feature is to be used, set the
MAX VOLTAGE DIFFERENCE,
MAX ANGLE DIFFERENCE, and MAX FREQ DIFFERENCE setpoints to the minimum values; and
the DEAD SOURCE PERMISSIVE, DEAD BUS MAX VOLTAGE, DEAD LINE MAX VOLTAGE, LIVE BUS
MIN VOLTAGE, and LIVE LINE MIN VOLTAGE setpoints to the required settings.
For a DEAD SOURCE PERMISSIVE setpoint of “DB & DL”, perform the following steps:
 Set the bus voltage to a magnitude above the dead-bus level, and
nominal frequency and inject into the relay.
 Set the line voltage to a magnitude above the dead-line level, 180° outof-phase with the bus voltage, at the same frequency, and inject into the
relay.
This ensures that synchronism cannot be achieved.
The “Out of Sync” alarm will be displayed as both the bus and line
voltages are above their dead-setting limits.
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 Turn the bus voltage off.
The “Out of Sync” alarm will be displayed as line voltage is above the
dead limit.
 Slowly reduce the line voltage, until the “Out of Sync” alarm is no
longer displayed.
This should be at the dead line max volt limit.
 Return the voltages to the level prior to the reduction.
 The “Out of Sync” alarm will be displayed as both the bus and line
voltages are above their dead-setting limits.
 Turn the line voltage off.
The “Out of Sync” alarm will be displayed.
 Slowly reduce the bus voltage, until the “Out of Sync” alarm is no
longer displayed.
This should be at the dead bus max volt limit.
 Turn the voltages off.
For a DEAD SOURCE PERMISSIVE setpoint of “LL & DB”, perform the following steps:
 Set the line voltage to nominal magnitude and frequency and inject into
the relay.
 Set the bus voltage to a magnitude above the dead-bus level, 180° outof-phase with the line voltage, at the same frequency, and inject into the
relay.
This ensures synchronism cannot be achieved.
 The “Out of Sync” alarm will be displayed as the bus voltage is above
its dead-setting limit.
 Slowly reduce the bus voltage magnitude until the “Out of Sync” alarm
is no longer displayed.
This should be at the dead bus max volt limit.
 Turn both voltages off.
The “Out of Sync” alarm will be displayed as the line voltage is below
its minimum voltage setting limit.
 Slowly increase the line voltage magnitude until the “Out of Sync”
alarm is no longer be displayed.
This should be at the minimum live line voltage limit.
 Turn both voltages off.
For a DEAD SOURCE PERMISSIVE setpoint of “DL & LB”, perform the following steps:
 Set the bus voltage to nominal magnitude and frequency and inject into
the relay.
 Set the line voltage to a magnitude above the dead-line level, 180° outof-phase with the bus voltage, at the same frequency, and inject into the
relay.
This ensures synchronism cannot be achieved.
 The “Out of Sync” alarm will be displayed as the line voltage is above
its dead-setting limit.
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 Slowly reduce the line voltage magnitude until the “Out of Sync” alarm
is no longer displayed.
This should be at the DEAD LINE MAX VOLTAGE limit.
 Turn both voltages off.
 The “Out of Sync” alarm will be displayed as the bus voltage is below
its minimum voltage setting limit.
 Slowly increase the bus voltage magnitude until the “Out of Sync”
alarm is no longer displayed.
This should be at the minimum live bus voltage limit.
 Turn both voltages off.
For a DEAD SOURCE PERMISSIVE setpoint of “DL | DB”, perform the following steps:
 Set the bus voltage to nominal magnitude and frequency and inject into
the relay.
 Set the line voltage to nominal magnitude, 180° out-of-phase with the
bus voltage, at the same frequency, and inject into the relay.
This ensures that synchronism cannot be achieved.
 The “Out of Sync” alarm will be displayed as both voltages are above
the dead-setting limits.
 Slowly reduce the line voltage magnitude until the “Out of Sync” alarm
is no longer displayed.
This should be at the DEAD LINE MAX VOLTAGE limit.
 Increase the line voltage to nominal magnitude.
 Slowly reduce the bus voltage magnitude until the “Out of Sync” alarm
is no longer displayed.
This should be at the dead bus max volt limit.
 Turn both voltages off.
For a DEAD SOURCE PERMISSIVE setpoint of “DL X DB”, perform the following steps:
 Set the bus voltage to a magnitude above the DEAD BUS MAX VOLTAGE
limit and below the LIVE BUS MIN VOLTAGE limit at nominal frequency
and inject into the relay.
 Set the line voltage to a magnitude above the minimum live-line limit,
180° out-of-phase with the bus voltage, at the same frequency, and
inject into the relay.
This ensures that synchronism cannot be achieved.
The “Out of Sync” alarm will be displayed.
 Slowly decrease the bus voltage magnitude until the “Out of Sync”
alarm is no longer displayed.
This should be just below the DEAD BUS MAX VOLTAGE limit.
 Slowly decrease the line voltage magnitude until the “Out of Sync”
alarm is again displayed.
This should be just below the LIVE BUS MIN VOLTAGE limit.
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 Decrease the line voltage magnitude to below the DEAD LINE MAX
VOLTAGE limit.
The “Out of Sync” alarm should remain displayed.
 Increase the bus voltage magnitude to above the LIVE LINE MIN
VOLTAGE limit at which point the “Out of Sync” alarm is no longer
displayed.
 Slowly increase the line voltage magnitude.
At just above the max dead-line limit the “Out of Sync” alarm should be
displayed.
 Turn both voltages off.
7.6.3
Manual Close
Feature
Blocking
Make the test connections specified in FIGURE 7–1: Relay Test Wiring – Wye Connection or
FIGURE 7–2: Relay Test Wiring – Delta Connection on page 7–5. The following procedure
checks the Manual Close Function and Timer Control:
 Assert the 52a (or 52b) Contact logic input to simulate an open breaker.
 If in Local mode, press the front panel CLOSE key momentarily to
generate a close command; if in Remote mode assert a momentary
Remote Close logic input to cause the relay to go into manual close
blocking, and generate an output from this feature.
Check that any selected output relays have operated.
If the function is selected as Alarm, the alarm message should be
displayed with the Alarm LED turned on.
 After a time interval equal to the Manual Close Block Time, the above
indications should reset.
This interval can be checked in the Event Recorder.
The procedures below check the control of overcurrent protection features. Use the
following procedure to check Phase IOC 1 Blocking:
 Set a test current, in the number of phases required to generate an
output, to a level above the pickup of this element then turn the current
off.
 Apply a Close command, as described above, and immediately inject
the test current to the relay.
The element will not pickup as it is blocked by manual close blocking.
 Wait until the element operates, as shown by the Pickup LED coming
on, at the end of the programmed Manual Close Block Time.
 Turn the current off.
The time interval can be checked in the Event Recorder.
For Neutral IOC 1 Blocking, Ground IOC Blocking, Sensitive Ground IOC Blocking, and Neg
Seq IOC Blocking, follow the procedure described for Phase IOC 1 Blocking above, injecting
current as appropriate.
The following procedure checks Phase TOC 1 Raised Pickup:
 Ensure all other overcurrent features are “Disabled”.
Manual Close Blocking will raise the pickup setting of the curve
normally used by this feature the programmed percentage.
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 Set a test current to a level between the normal pickup setting and the
raised setting, then turn the current off.
 Apply a Close command, as described above, and immediately inject
the test current into the relay.
Phase TOC will not pickup as the pickup current is raised.
 Increase the injection current until the Pickup LED comes on, before the
manual close feature times-out and returns the pickup to normal.
Check that the raised pickup level is correct.
 Turn current off, and wait until the alarm is removed from the display.
 Set a test current to a level between the normal pickup setting and the
raised setting, then turn the current off.
 Apply a Close command, as described above, and immediately inject
the test current into the relay.
Phase TOC will not pickup as the pickup current is raised.
 At the end of the programmed MANUAL CLOSE BLOCK TIME, the Pickup
LED should come on, as the pickup setting has returned to normal.
When this happens, reduce the injection current until the Pickup LED
goes out.
The MANUAL CLOSE BLOCK TIME can be checked in the Event
Recorder.
For Neutral TOC 1 Raised Pickup, Ground TOC Raised Pickup, Sensitive Ground TOC Raised
Pickup, and Neg Seq TOC Raised Pickup, follow the procedure outlined for Phase TOC 1
Raised Pickup above, injecting current as appropriate.
To check the Select Setpoint Group function, apply a manual close and verify that the
selected setpoint group becomes active when the breaker closes. Verify that settings
return to the previous setpoint group after the MANUAL CLOSE BLOCK TIME expires.
7.6.4
Cold Load
Pickup
Blocking
Make the test connections specified in FIGURE 7–1: Relay Test Wiring – Wye Connection or
FIGURE 7–2: Relay Test Wiring – Delta Connection on page 7–5. The following procedure
checks the Cold Load Pickup Function and Timer Control:
 Enable the COLD LOAD PICKUP setpoint to cause the relay to go into
cold load pickup operation after the OUTAGE TIME BEFORE COLD LOAD
setpoint expires.
Check that any selected output relays have operated.
If the function is selected as Alarm, the alarm message and LED should
also be turned on.
 Inject a current in any phase below 10% of nominal, and slowly
increase.
The relay should go into cold load operation when the current is above
10% of nominal.
The alarm message and LED should reset and any output relays
programmed to operate should dropout after a time interval equal to the
cold load pickup block time.
This interval can be checked in the Event Recorder.
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 Reduce this current to 3% of nominal and simultaneously start a timer.
This feature should generate an output at the end of the OUTAGE TIME
BEFORE COLD LOAD setting.
The procedures below check the control of overcurrent protection features. The following
checks Phase IOC 1 Blocking:
 Set a test current, in the number of phases required to generate an
output, to a level above the pickup of this element then turn the current
off.
 Assert a Cold Load Pickup logic input, and immediately apply the test
current to the relay.
The element will not pickup as it is blocked by cold load pickup
blocking.
 Wait until the element operates, as shown by the Pickup LED coming on
at the end of the programmed COLD LOAD PICKUP BLOCK time.
 Turn the current off.
The time interval can be checked in the Event Recorder.
For Neutral IOC 1 Blocking, Ground IOC Blocking, Sensitive Ground IOC Blocking, and Neg
Seq IOC Blocking, follow the procedure described above for Phase IOC 1 Blocking, injecting
current as appropriate.
The following procedure checks Phase TOC 1 Raised Pickup for Cold Load Blocking:
 Ensure all other overcurrent features are “Disabled”.
(Cold Load Pickup Blocking will raise the pickup setting of the curve
normally used by the programmed percentage.)
 Set a test current to a level between the normal pickup setting and the
raised setting, (at least 5% of nominal current) then turn the current off.
 Assert a Cold Load Pickup logic input and immediately inject the test
current into the relay.
Phase TOC 1 will not pickup as the pickup current is raised.
 Increase the injection current until the Pickup LED comes on, before the
cold load pickup blocking feature times-out and returns the pickup to
normal.
Check that the raised pickup level is correct.
 Turn current off, and wait until the alarm is removed from the display.
 Set a test current to a level between the normal pickup setting and the
raised setting, then turn the current off.
 Assert a Cold Load Pickup logic input and immediately inject the test
current into the relay.
Phase TOC 1 will not pickup as the pickup current is raised.
At the end of the programmed COLD LOAD PICKUP BLOCK TIME the
Pickup LED should come on, as the pickup setting has returned to
normal.
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 When this happens, reduce the injection current until the Pickup LED
goes out.
The COLD LOAD PICKUP BLOCK TIME interval can be checked in the
Event Recorder.
For Neutral TOC 1 Raised Pickup, Ground TOC Raised Pickup, Sensitive Ground TOC Raised
Pickup, and Neg Seq TOC Raised Pickup, follow the procedure outlined for Phase TOC 1
Raised Pickup, injecting current as appropriate.
To check the Select Setpoint Group for Cold Load Blocking, apply a Cold Load Pickup logic
input and verify that the selected setpoint group becomes active. Verify that settings return
to the previous setpoint group after the Cold LOAD PICKUP BLOCK TIME interval expires.
7.6.5
Undervoltage
Restoration
Description
Make the test connections specified in FIGURE 7–1: Relay Test Wiring – Wye Connection or
FIGURE 7–2: Relay Test Wiring – Delta Connection on page 7–5. The following procedure
checks Logic and Timers for Undervoltage Restoration:
 Program the Undervoltage 1 function as “Trip” and the Undervoltage 2
function as “Disabled”.
 Assert or De-assert a logic input to simulate a closed breaker.
 Inject a balanced three-phase voltage at nominal voltage and frequency
into the bus voltage input.
 Initially set the undervoltage restoration function setpoint to Alarm, and
other setpoints as required.
 Turn the voltage off.
After the programmed delay Undervoltage 1 should cause a trip, which
should not initiate undervoltage restoration as the breaker is closed.
Diagnostic message “Uvolt Restore Init” should not be displayed.
 Assert or De-assert a logic input to simulate an open breaker, initiating
undervoltage restoration.
The diagnostic alarm message and LED should be displayed, and output
relays programmed to operate for this condition should operate.
 Change the Undervoltage Restoration function setpoint to Control, and
the diagnostic message should change to control and the Alarm LED
should turn off.
Return this setpoint to Alarm.
 Assert logic input Block Restoration.
The diagnostic alarm message and LED should be removed from the
display, and any output relays that operated should reset.
 De-assert the logic input.
The alarm message and LED should again be displayed and output
relays operated.
After the delay programmed in Incomplete Sequence Time the alarm
message and LED should be removed from the display and output relays
reset.
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 Return the reduced voltage to nominal, resetting both the undervoltage
trip condition and undervoltage restoration.
 Reduce voltage until Undervoltage 1 trips, then immediately return the
voltage to nominal.
The diagnostic alarm message and LED should be displayed, and output
relays operated.
 Provide a Reset to the relay, and the alarm message and LED should be
removed from the display and output relays reset.
Remove the Reset.
 Arrange the interval timer to start on appearance of voltage and stop
when the Close Relay operates.
 Turn the voltage off to cause an Undervoltage 1 trip, then reset the timer.
 Turn the voltage on.
The Close Relay should operate after the delay programmed in setpoint
Undervolt Restore Delay.
 If the Undervoltage 2 initiation is to be checked change the
Undervoltage Restoration function setpoint to “Disabled”, Undervoltage
1 function to “Disabled”, Undervoltage 2 function to “Trip” and repeat
Steps 2 through 7.
For Wye VTs
Make the test connections specified in FIGURE 7–1: Relay Test Wiring – Wye Connection on
page 7–4. The following procedure checks Minimum Voltage with One Phase For
Operation:
 Assert or De-assert a logic input to simulate an open breaker.
 Set UNDERVOLT RESTORE DELAY to “0”.
 Inject Van = Vbn = Vcn = nominal voltage into the bus voltage input of
the relay.
 Reduce the injected voltages to cause an undervoltage trip, then set Vbn
and Vcn to “0”.
 Slowly raise Van until the Close Relay operates.
This is the operating level of the UNDERVOLT RESTORE MIN VOLTS
setpoint for Van.
 Repeat last 3 steps, except adjust Vbn and Vcn in turn.
The following procedure checks Minimum Voltage with Two Phases For Operation:
 Assert or De-assert a logic input to simulate an open breaker.
 Set UNDERVOLT RESTORE DELAY to “0”.
 Inject Van = Vbn = Vcn = nominal voltage into the bus voltage input of
the relay.
 Reduce the injected voltages to cause an undervoltage trip, then set Vbn
to 0 and Vcn to nominal.
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 Slowly raise Van until the Close Relay operates.
This is the operating level of the UNDERVOLT RESTORE MIN VOLTS
setpoint for Van with Vcn.
 Inject Van = Vbn = Vcn = nominal voltage into the bus voltage input of
the relay.
 Reduce the injected voltages to cause an undervoltage trip, then set Vcn
to 0 and Vbn to nominal.
 Slowly raise Van until the Close Relay operates.
This is the operating level of the UNDERVOLT RESTORE MIN VOLTS
setpoint for Van with Vbn.
 Inject Van = Vbn = Vcn = nominal voltage into the bus voltage input of
the relay.
 Reduce the injected voltages to cause an undervoltage trip, then set Vcn
to 0 and Van to nominal.
 Slowly raise Vbn until the Close Relay operates.
This is the operating level of the UNDERVOLT RESTORE MIN VOLTS
setpoint for Vbn with Van.
 Inject Van = Vbn = Vcn = nominal voltage into the bus voltage input of
the relay.
 Reduce the injected voltages to cause an undervoltage trip, then set Van
to 0 and Vcn to nominal.
 Slowly raise Vbn until the Close Relay operates.
This is the operating level of the UNDERVOLT RESTORE MIN VOLTS
setpoint for Vbn with Vcn.
 Inject Van = Vbn = Vcn = nominal voltage into the bus voltage input of
the relay.
 Reduce the injected voltages to cause an undervoltage trip, then set Van
to 0 and Vbn to nominal.
 Slowly raise Vcn until the Close Relay operates.
This is the operating level of the UNDERVOLT RESTORE MIN VOLTS
setpoint for Vcn with Vbn.
 Inject Van = Vbn = Vcn = nominal voltage into the bus voltage input of
the relay.
 Reduce the injected voltages to cause an undervoltage trip, then set Vbn
to 0 and Van to nominal.
 Slowly raise Vcn until the Close Relay operates.
This is the operating level of the UNDERVOLT RESTORE MIN VOLTS
setpoint for Vcn with Van.
The following procedure checks Minimum Voltage with Three Phases For Operation:
 Assert or De-assert a logic input to simulate an open breaker.
 Set UNDERVOLT RESTORE DELAY to “0”.
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 Inject Van = Vbn = Vcn = nominal voltage into the bus voltage input of
the relay.
 Reduce the injected voltages to cause an undervoltage trip, then set Van
and Vcn to nominal.
 Slowly raise Van until the Close Relay operates.
This is the operating level of UNDERVOLT RESTORE MIN VOLTS for Van.
 Inject Van = Vbn = Vcn = nominal voltage into the bus voltage input of
the relay.
 Reduce the injected voltages to cause an undervoltage trip, then set Van
and Vcn to nominal.
 Slowly raise Vbn until the Close Relay operates.
This is the operating level of UNDERVOLT RESTORE MIN VOLTS for Vbn.
 Inject Van = Vbn = Vcn = nominal voltage into the bus voltage input of
the relay.
 Reduce the injected voltages to cause an undervoltage trip, then set Van
and Vbn to nominal.
 Slowly raise Vcn until the Close Relay operates.
This is the operating level of UNDERVOLT RESTORE MIN VOLTS for Vcn.
For Delta VTs
Make the test connections specified in FIGURE 7–2: Relay Test Wiring – Delta Connection on
page 7–5. The following procedure checks Minimum Voltage with One Phase For
Operation:
 Assert or De-assert a logic input to simulate an open breaker.
 Set UNDERVOLT RESTORE DELAY to 0.
 Inject Vab = Vcb = nominal voltage into the bus voltage input of the
relay.
 Reduce the injected voltages to cause an undervoltage trip, then set Vcb
to 0 V.
 Slowly raise Vab until the Close Relay operates.
This is the operating level of UNDERVOLT RESTORE MIN VOLTS for Vab.
 Repeat Steps 3 through 5 except adjust Vcb.
The following procedure checks Pickup with Two or Three Phases For Operation:
 Assert or De-assert a logic input to simulate an open breaker.
 Set UNDERVOLT RESTORE DELAY to 0.
 Inject Vab = Vcb = nominal voltage into the bus voltage input of the
relay.
 Reduce the injected voltages to cause an undervoltage trip, then set Vcb
to nominal.
 Slowly raise Vab until the Close Relay operates.
This is the operating level of UNDERVOLT RESTORE MIN VOLTS for Vab.
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 Inject Vab = Vcb = nominal voltage into the bus voltage input of the
relay.
 Reduce the injected voltages to cause an undervoltage trip, then set Vab
to nominal.
 Slowly raise Vcb until the Close Relay operates.
This is the operating level of UNDERVOLT RESTORE MIN VOLTS for Vcb.
7.6.6
Underfrequency
Restoration
Make the test connections specified in FIGURE 7–1: Relay Test Wiring – Wye Connection or
FIGURE 7–2: Relay Test Wiring – Delta Connection on page 7–5. The following procedure
checks Logic and Timers for Underfrequency Restoration:
 Program the UNDERFREQ 1 FUNCTION as “Trip”, MIN VOLTAGE as “0”,
and UNDERFREQ 2 FUNCTION as “Disabled”.
 Assert or De-assert a logic input to simulate a closed breaker.
 Inject a voltage at nominal voltage and frequency into the bus voltage
Phase A input.
 Initially set UNDERFREQ RESTORATION setpoint to Alarm, and other
setpoints as required.
 Reduce the frequency to below the underfrequency pickup level.
After the programmed delay Underfrequency 1 should cause a trip,
which should not initiate underfrequency restoration as the breaker is
closed.
Diagnostic message “Ufreq Restore Init” should not be displayed.
 Assert or De-assert a logic input to simulate an open breaker, which
should initiate underfrequency restoration.
The diagnostic alarm message and LED should be displayed, and any
output relays programmed to operate for this condition should operate.
 Change the UNDERFREQ RESTORE FUNCTION setpoint to “Control”, and
the diagnostic message should change to control and the Alarm LED
should turn off.
Return this setpoint to “Alarm”.
 Assert logic input Block Restoration.
The diagnostic alarm message and LED should be removed from the
display, and any output relays that operated should reset.
 De-assert the logic input.
The alarm message and LED should again be displayed and output
relays operated. After the delay programmed in Incomplete Sequence
Time, the alarm message and LED should be removed from the display
and output relays reset.
 Return the reduced frequency to nominal, resetting both the
underfrequency trip condition and underfrequency restoration.
 Reduce frequency until Underfrequency 1 trips, then immediately return
the frequency to nominal.
The diagnostic alarm message and LED should be displayed, and output
relays operated.
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 Provide a Reset to the relay, and the alarm message and LED should be
removed from the display and output relays reset. Remove the Reset.
 Arrange the interval timer to start on appearance of voltage and stop
when the Close Relay operates.
 Turn the voltage, of a frequency to cause an Underfrequency 1 trip, off.
 Reset the timer.
 Turn the voltage on. The Close Relay should operate after the delay
programmed in UNDERFREQ RESTORE DELAY.
 If Underfrequency 2 initiation is to be checked, change Underfrequency
Restoration to Disabled, Underfrequency 1 to Disabled,
Underfrequency 2 to Trip and repeat steps 2 through 8 in this procedure.
The following procedure checks the minimum voltage for underfrequency restoration:
 Assert or De-assert a logic input to simulate an open breaker.
 Set UNDERFREQ RESTORE DELAY to 0.
 Inject a voltage below the UNDERFREQ RESTORE MIN VOLTS level into
the bus voltage input of the relay.
 Reduce the injected frequency to cause an underfrequency trip, then
increase the frequency to nominal.
 Slowly raise Va until the Close relay operates.
This is the operating level of setpoint Underfreq Restore Min Volts.
The following procedure checks the minimum frequency for underfrequency restoration:
 Assert or De-assert a logic input to simulate an open breaker.
 Set UNDERFREQ RESTORE DELAY to 0.
 Inject nominal voltage into the bus voltage input of the relay.
 Reduce the injected frequency to cause an underfrequency trip.
 Slowly increase the frequency until the Close Relay operates.
This is the operating level of the UNDERFREQ RESTORE MIN FREQ
setpoint.
7.6.7
Transfer
Scheme
Common Logic
 Ensure that the Phase Inst O/C 1, Neutral Inst O/C 1, Line Undervoltage
3, Line Undervoltage 4, Synchrocheck and Logic Input features in the
relays programmed as Incomer 1 and Incomer 2 have been tested and
are Enabled.
 Ensure that the Synchrocheck and Logic Input features in the relay
programmed as Bus Tie has been tested and is “Enabled”.
 Ensure all circuit breakers are disconnected from their normal positions
in the primary circuit, are open and operating properly, and the close and
trip circuits have been tested and are energized.
 De-assert Logic Inputs 1, 2, 3, 4, 5, 6, 11, 12, and 13 at both Incomer
relays. De-assert Logic Inputs 1, 2, 3, 4, 5, 6, and 11 at the Bus Tie relay.
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 At this time both of the Incomer relays should have Output Relays 1 and
4 operated, Output Relays 5 through 7 reset, and be displaying the
message Transfer Not Ready.
At the Bus Tie breaker relay, Output Relays 4 through 7 should be reset
(de-energized).
 Parallel the Line to Bus voltage inputs of the Incomer 1 relay to the Bus
voltage input of the Bus Tie relay and connect this circuit to a voltage
source (Source 1 for these tests).
Do not energize the source.
 Parallel the Line to Bus voltage inputs of the Incomer 2 relay to the Line
voltage input of the Bus Tie relay and connect this circuit to a voltage
source (Source 2 for these tests).
Do not energize the source.
 Assert Logic Input 5 (Breaker Connected) at the Bus Tie relay; Output
Relays 4 and 6 on the Bus Tie relay should operate.
 Assert Logic Input 5 (Breaker Connected) at the Incomer 1 relay.
Nothing should happen.
 Assert Logic Input 2 (Remote Close) at the Incomer 1 relay.
Nothing should happen.
 Energize Source 1 at nominal voltage.
The Incomer 1 breaker should close, Output Relay 4 should reset and
Output Relays 5 and 7 on the Incomer 1 relay should operate.
 Assert Logic Input 5 (Breaker Connected) at the Incomer 2 relay.
Nothing should happen.
 Assert Logic Input 2 (Remote Close) at the Incomer 2 relay.
Nothing should happen.
 Energize Source 2 at nominal voltage.
The Incomer 2 breaker should close, Output Relay 4 should reset and
Output Relays 5 and 7 on the Incomer 2 relay should operate.
 De-assert Logic Input 5 (Breaker Connected) at the Bus Tie relay.
Output Relays 4 and 6 on the Bus Tie relay should reset, and at both
Incomer relays the message Transfer Not Ready should be displayed.
 Assert Logic Input 5 (Breaker Connected) at the Bus Tie relay.
Output Relays 4 and 6 on the Bus Tie relay should operate, and at both
Incomer relays the message Transfer Not Ready should be removed
from the display.
 De-assert Logic Input 5 (Breaker Connected) at the Incomer 1 relay.
At the Incomer 1 relay Output Relays 5 and 7 should reset; at both
Incomer relays the message Transfer Not Ready should be displayed.
 Assert Logic Input 5 (Breaker Connected) at the Incomer 1 relay.
At the Incomer 1 relay Output Relays 5 and 7 should operate; at both
Incomer relays the message Transfer Not Ready should be removed
from the display.
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 Momentarily assert Logic Input 3 (Remote Open) at the Incomer 1 relay.
The Incomer 1 breaker should trip and Output Relays 5 and 7 should
reset; at both Incomer relays the message Transfer Not Ready should be
displayed.
 Momentarily assert Logic Input 2 (Remote Close) at the Incomer 1
relay.
The Incomer 1 breaker should close and Output Relays 5 and 7 should
operate; at both Incomer relays the message Transfer Not Ready should
be removed.
 De-assert Logic Input 5 (Breaker Connected) at the Incomer 2 relay.
At the Incomer 2 relay Output Relays 5 and 7 should reset; at both
Incomer relays the message Transfer Not Ready should be displayed.
 Assert Logic Input 5 (Breaker Connected) at the Incomer 2 relay.
At the Incomer 2 relay Output Relays 5 and 7 should operate; at both
Incomer relays the message Transfer Not Ready should be removed
from the display.
 Momentarily assert Logic Input 3 (Remote Open) at the Incomer 2 relay.
The Incomer 2 breaker should trip and Output Relays 5 and 7 should
reset; at both Incomer relays the message Transfer Not Ready should be
displayed.
 Momentarily assert Logic Input 2 (Remote Close) at the Incomer 2
relay.
The Incomer 2 breaker should close and Output Relays 5 and 7 should
operate; at both Incomer relays, the Transfer Not Ready message should
disappear.
 Momentarily assert Logic Input 2 (Remote Close) at the Bus Tie relay.
The Bus Tie breaker should close and Output Relays 5 and 7 should
operate; at both Incomer relays the Transfer Not Ready message should
be displayed.
 Momentarily assert Logic Input 3 (Remote Open) at the Bus Tie relay.
The Bus Tie breaker should trip and Output Relays 5 and 7 should reset,
and at both Incomer relays the Transfer Not Ready message should
disappear.
 Assert Logic Input 11 (Block Transfer) at the Incomer 1 relay.
Output Relays 5 and 7 should reset; at both Incomer relays the Transfer
Not Ready message should be displayed.
 De-assert Logic Input 11 (Block Transfer) at the Incomer 1 relay.
Output Relays 5 and 7 should operate; at both Incomer relays the
Transfer Not Ready message should be removed from the display.
 Assert Logic Input 11 (Block Transfer) at the Incomer 2 relay.
Output Relays 5 and 7 should reset; at both Incomer relays the Transfer
Not Ready message should be displayed.
 De-assert Logic Input 11 (Block Transfer) at the Incomer 2 relay.
Output Relays 5 and 7 should operate; at both Incomer relays the
Transfer Not Ready message should be removed from the display.
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 Check the Event Recorders in the Incomer 1 and 2 and Bus Tie relays
for the correct messages and sequences, then clear the recorders.
Low Voltage Logic
 Slowly reduce test voltage Source 1 supplying Incomer relay 1.
At the pickup voltage of the Line Undervoltage 3 feature Output Relay 4
should operate.
At this time the Incomer 2 relay should display the Transfer Not Ready
message.
 Slowly increase test voltage Source 1.
At the reset voltage of the Line Undervoltage 3 feature Output Relay 4
should reset.
At the Incomer 2 relay after the time delay of setpoint Transfer Delay
Other Source the message Transfer Not Ready should be removed from
the display.
 Slowly reduce test voltage Source 2 supplying Incomer relay 2.
At the pickup voltage of the Line Undervoltage 3 feature Output Relay 4
should operate.
At this time the Incomer 1 relay should display the Transfer Not Ready
message.
 Slowly increase test voltage Source 2.
At the reset voltage of the Line Undervoltage 3 feature Output Relay 4
should reset.
At the Incomer 1 relay after the time delay of setpoint Transfer Delay
Other Source the message Transfer Not Ready should be removed from
the display.
 Turn voltages off.
Incomer breakers 1 and 2 should trip when Undervoltage 4 times out.
 Check the Event Recorders in both Incomers and the Bus Tie relay for
the correct messages and sequences, then clear the recorders.
Transfer Initiated by Lockout 86-1
 Energize both test sources at nominal voltage, close Incomer breakers 1
and 2, and wait until the Transfer Not Ready message is removed from
the display of both Incomer relays.
 At the Incomer 1 relay assert Logic Input 12 (Transformer Lockout).
The Incomer 1 relay should trip the Incomer 1 breaker and operate
Output Relay 6 to send a Close From Incomer 1 signal to the Bus Tie
relay.
Output Relay 6 at the Incomer 1 relay should reset when the Incomer 1
breaker trips, removing the signal to the Bus Tie relay.
The Bus Tie breaker should not close as the voltage on its Bus and Line
inputs is too high.
 Slowly reduce the test Source 1 voltage.
The Bus Tie breaker should close when the voltage is below the Dead
Bus Max Volts setpoint of its Synchrocheck feature.
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 Increase the voltage to nominal.
 At the Incomer 1 relay de-assert Logic Input No. 12 (Transformer
Lockout).
 Momentarily assert Logic Input 3 (Remote Open) at the Bus Tie relay.
The Bus Tie breaker should open.
 Momentarily assert Logic Input 2 (Remote Close) at the Incomer 1
relay.
The Incomer 1 breaker should close.
 Check the Event Recorders in the Incomer 1 and Bus Tie relays for the
correct messages and sequences, then clear the recorders.
Transfer Initiated by Lockout 86-2
 Energize both test sources at nominal voltage, and wait until the
Transfer Not Ready message is removed from the display of both
Incomer relays.
 At the Incomer 2 relay assert Logic Input 12 (Transformer Lockout).
The Incomer 2 relay should trip the Incomer 2 breaker and operate
Output Relay 6 to send a Close From Incomer 2 signal to the Bus Tie
relay.
Output Relay 6 at the Incomer 2 relay should reset when the Incomer 2
breaker trips, removing the signal to the Bus Tie relay.
The Bus Tie breaker should not close as the voltage on its Bus and Line
inputs is too high.
 Slowly reduce the test Source 2 voltage.
The Bus Tie breaker should close when the voltage is below the Dead
Line Max Volts setpoint of its Synchrocheck feature.
 Increase the voltage to nominal.
 At the Incomer 2 relay de-assert Logic Input No. 12 (Transformer
Lockout).
 Momentarily assert Logic Input 3 (Remote Open) at the Bus Tie relay.
The Bus Tie breaker should open.
 Momentarily assert Logic Input 2 (Remote Close) at the Incomer 2
relay.
The Incomer 2 breaker should close.
Check the Event Recorders in the Incomer 2 and Bus Tie relays for the
correct messages and sequences, then clear the recorders.
Transfer Initiated by Source Trip No. 1
 Energize both test sources at nominal voltage, and wait until the
Transfer Not Ready message is removed from the display of both
Incomer relays.
 At the Incomer 1 relay assert Logic Input 13 (Source Trip).
The Incomer 1 relay should trip the Incomer 1 breaker and operate
Output Relay 6 to send a Close From Incomer 1 signal to the Bus Tie
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relay.
Output Relay 6 at the Incomer 1 relay should reset when the Incomer 1
breaker trips, removing the signal to the Bus Tie relay.
The Bus Tie breaker should not close as the voltage on its Bus and Line
inputs is too high.
 Slowly reduce the test Source 1 voltage.
The Bus Tie breaker should close when the voltage is below the Dead
Bus Max Volts setpoint of its Synchrocheck feature.
 Increase the voltage to nominal.
 At the Incomer 1 relay de-assert Logic Input No. 13 (Source Trip).
 Momentarily assert Logic Input 3 (Remote Open) at the Bus Tie relay.
The Bus Tie breaker should open.
 Momentarily assert Logic Input 2 (Remote Close) at the Incomer 1
relay.
The Incomer 1 breaker should close.
 Check the Event Recorders in the Incomer 1 and Bus Tie relays for the
correct messages and sequences, then clear the recorders.
Transfer Initiated by Source Trip No. 2
 Energize both test sources at nominal voltage, and wait until the
Transfer Not Ready message is removed from the display of both
Incomer relays.
 At the Incomer 2 relay assert Logic Input 13 (Source Trip).
The Incomer 2 relay should trip the Incomer 2 breaker and operate
Output Relay 6 to send a Close From Incomer 2 signal to the Bus Tie
relay.
Output Relay 6 at the Incomer 2 relay should reset when the Incomer 2
breaker trips, removing the signal to the Bus Tie relay.
The Bus Tie breaker should not close as the voltage on its Bus and Line
inputs is too high.
 Slowly reduce the test Source 2 voltage.
The Bus Tie breaker should close when the voltage is below the Dead
Line Max Volts setpoint of its Synchrocheck feature.
 Increase the voltage to nominal.
 At the Incomer 2 relay de-assert Logic Input No. 13 (Source Trip).
 Momentarily assert Logic Input 3 (Remote Open) at the Bus Tie relay.
The Bus Tie breaker should open.
 Momentarily assert Logic Input 2 (Remote Close) at the Incomer 2
relay.
The Incomer 2 breaker should close.
 Check the Event Recorders in the Incomer 2 and Bus Tie relays for the
correct messages and sequences, then clear the recorders.
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Transfer Initiated by Undervoltage on Source 1
 Energize both test sources at nominal voltage, and wait until the
Transfer Not Ready message is removed from the display of both
Incomer relays.
 Turn test Source 1 off.
The Undervoltage 3 feature of the Incomer 1 relay should operate
Output Relay 4 immediately. At Incomer 2, Output Relay 3 operates and
the Transfer Not Ready message is displayed.
When the Undervoltage 4 feature times out, the Incomer 1 relay should
trip Breaker 1 and operate Output Relay 6 to send a Close From Incomer
1 signal to the Bus Tie relay.
Output Relay 6 should reset when Breaker 1 trips, removing the signal
to the Bus Tie relay.
Upon receiving the signal from the Incomer 1, the Bus Tie relay should
close the Bus Tie Breaker.
 Check the Event Recorders in the Incomer 1 and Bus Tie relays for the
correct messages and sequences, then clear the recorders.
Manual Restoration of Incomer 1
 Turn test Source 1 on and adjust Source 1 to be out-of-synchronism with
Source 2.
 At the Bus Tie relay assert Logic Input 6 (Selected To Trip).
 At the Incomer 1 relay assert Logic Input 2 (Remote Close).
The Incomer 1 breaker should not close as it cannot pass synchrocheck.
Adjust Source 1 until in-synchronism with Source 2.
At this time the Incomer 1 breaker should close and the Bus Tie breaker
should trip.
 Turn off both voltages.
 At the Bus Tie relay de-assert Logic Input 6 (Selected To Trip).
Check the Event Recorders in the Incomer 1 and Bus Tie relays for the
correct messages and sequences, then clear the recorders.
Transfer Initiated by Undervoltage on Source 2
 Energize both test sources at nominal voltage, and wait until the
Transfer Not Ready message is removed from the display of both
Incomer relays.
 Turn test Source 2 off.
The Undervoltage 3 feature of Incomer 2 relay should operate
immediately and operate output relay 4; at the Incomer 1 relay, Output
Relay 3 will operate and the Transfer Not Ready message will be
displayed.
When the Undervoltage 4 feature times-out the Incomer 2 relay should
trip Incomer Breaker 2 and operate Output Relay 6 to send a Close From
Incomer 2 signal to the Bus Tie relay.
Output Relay 6 should reset when Breaker 2 trips, removing the signal
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to the Bus Tie relay.
Upon receiving the signal from the Incomer 2 relay the Bus Tie relay
should close the Bus Tie Breaker.
 Check the Event Recorders in the Incomer 2 and Bus Tie relays for the
correct messages and sequences, then clear the recorders.
Manual Restoration of Incomer 2
 Turn test Source 2 on and adjust Source 2 to be out-of-synchronism with
Source 1.
 At the Bus Tie relay assert Logic Input 6 (Selected To Trip).
 At the Incomer 2 relay assert Logic Input 2 (Remote Close).
The Incomer 2 Breaker 2 should not close as it cannot pass
synchrocheck.
Adjust Source 2 until in-synchronism with Source 1.
At this time the Incomer 2 breaker should close and the Bus Tie breaker
should trip. Turn off both voltages.
 At the Bus Tie relay de-assert Logic Input 6 (Selected To Trip).
 Check the Event Recorders in the Incomer 2 and Bus Tie relays for the
correct messages and sequences, then clear the recorders.
Simultaneous Loss of Both Sources
 Energize the line voltage input of both incomer relays from a single
source at nominal voltage, and wait until the Transfer Not Ready
message is removed from the display of both relays.
 Turn the test source off.
The Undervoltage 3 element of both incomer relays should operate
immediately and operate Output Relay 4; at both incomers the Transfer
Not Ready message will be displayed.
 If the BLOCK TRIP ON DOUBLE LOSS setpoint is set to “Disabled”:
• When the Undervoltage 4 element times out, the incomer relays
should trip the incomer breakers.
The bus tie breaker should not close.
• Check the event recorders in both incomer relays for the correct
sequences, then clear the recorders.
 If the BLOCK TRIP ON DOUBLE LOSS setpoint is set to “Enabled”:
• When the Undervoltage 4 element times out, the incomer relays
should not trip the incomer breakers.
The bus tie breaker should not close.
• Check the event recorders in both incomer relays for the correct
sequences, then clear the recorders.
After-Parallel Tripping of Selected Incomer
 Energize both test sources at nominal voltage, still in-synchronism, and
wait until the Transfer Not Ready message is removed from the display
of both Incomer relays.
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 At the Incomer 1 relay assert Logic Input 6 (Selected To Trip.)
 At the Bus Tie relay assert Logic Input 2 (Remote Close.)
The Bus Tie breaker should close as the voltages are in-synchronism.
After this the Incomer 1 breaker should trip.
 At the Incomer 1 relay de-assert Logic Input 6 (Selected To Trip.)
 At the Incomer 2 relay assert Logic Input 6 (Selected To Trip.)
 At the Incomer 1 relay assert Logic Input 2 (Remote Close).
The Incomer 1 breaker should close as the voltages are in-synchronism.
After this the Incomer 2 breaker should trip.
 Turn the voltages off.
 Check the Event Recorders in the Incomer 1 and 2 and Bus Tie relays
for the correct messages and sequences, then clear the recorders.
Transfer Blocked by Overcurrent on Incomer 1
 Energize both test sources at nominal voltage, and wait until the
Transfer Not Ready message is removed from the display of both
Incomer relays.
 Disable the Neutral IOC 1 feature.
 Inject a current into the phase current input of the Incomer 1 relay.
 Slowly increase this current until the Phase IOC 1 element operates.
At the Incomer 1 relay and the Transfer Not Ready message should be
displayed.
 Slowly decrease the injected current until the Phase IOC 1 element
resets.
At the Incomer 1 relay after the delay time of setpoint Transfer Delay
This Source and the Transfer Not Ready message should be removed
from the display.
 Enable the Neutral IOC 1 feature and Disable the Phase IOC 1 feature.
 Inject a current into the phase current input of the Incomer 1 relay.
 Slowly increase this current until the Neutral IOC 1 element operates.
At the Incomer 1 relay the Transfer Not Ready message should be
displayed.
 Slowly decrease the injected current until the Neutral IOC 1 element
resets.
At the Incomer 1 relay after the delay time of the TRANSFER DELAY THIS
SOURCE setpoint and the Transfer Not Ready message should disappear
from the display.
Transfer Blocked by Overcurrent on Incomer 2
 Energize both test sources at nominal voltage, and wait until the
Transfer Not Ready message is removed from the display of both
Incomer relays.
 Disable the Neutral IOC 1 feature.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
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CONTROL SCHEMES
CHAPTER 7: COMMISSIONING
 Inject a current into the phase current input of the Incomer 2 relay.
 Slowly increase this current until the Phase IOC 1 element operates.
At the Incomer 2 relay the Transfer Not Ready message should be
displayed.
 Slowly decrease the injected current until the Phase IOC 1 element
resets.
At the Incomer 2 relay after the delay time of setpoint Transfer Delay
This Source and the Transfer Not Ready message should be removed
from the display.
 Enable the Neutral IOC 1 feature and Disable the Phase IOC 1 feature.
 Inject a current into the phase current input of the Incomer 2 relay.
 Slowly increase this current until the Neutral IOC 1 element operates.
At the Incomer 2 relay the Transfer Not Ready message should be
displayed.
 Slowly decrease the injected current until the Neutral IOC 1 element
resets.
At the Incomer 2 relay after the delay time of setpoint TRANSFER DELAY
THIS SOURCE and the Transfer Not Ready message should be removed
from the display.
7.6.8
Autoreclose
(760 only)
For autoreclose testing, make the test connections specified in FIGURE 7–6: Autoreclose
Test Connections below.
For these tests Output Relay 7 (Auxiliary) is programmed to operate when the relay trips, to
stop the timer. If this is inconvenient, use any other output auxiliary relay.
Note
NOTE
The following procedure tests overall operation of the Autoreclose feature:
 Check that the relay is in the local control mode, and the Local LED is
on.
 Open and close the breaker by pressing the OPEN and CLOSE keys.
 Check that the Breaker Open and Breaker Closed LEDs are correctly
displaying the state of the breaker.
Leave the breaker open.
 Check that Reclosure Enabled LED is lit and the Reclosure Disabled
LED is off.
 Close the breaker by pressing the CLOSE key.
The Reclosure Enabled LED should go out, and the Reclosure Disabled
LED should come on during the AR BLOCK TIME UPON MANUAL CLOSE
value.
 Immediately after this interval, check that Reclosure Enabled LED is
on, and the Reclosure in Progress and Reclosure Disabled LEDs are off.
Any output relays programmed to operate for “Reclose Enabled” should
now be operated.
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750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 7: COMMISSIONING
CONTROL SCHEMES
 Check the interval of the ‘AR block time upon manual close’ by
observing the Reclosure Enabled LED.
For all further testing, ensure that a reclose is not initiated until after the AR BLOCK TIME
Note
UPON MANUAL CLOSE value has elapsed, after a manual close.
NOTE
Assert a Block Reclosure logic input.
The Reclosure Enabled LED should go out and the Reclosure Disabled LED come on.
 De-assert the Block Reclosure logic input.
The Reclosure Enabled LED should come on and the Reclosure
Disabled LED should go out.
E11
STOP
TEST
TRIGGER
F10
CONTROL
POWER
7 AUX.
(+)
H11
(-)
G11
30
VARIABLE
CURRENT
SOURCE
G7
G12
Ia
H7
Ib
∠
∠
∠ Ia
∠ Ib
Ic
∠
∠ Ic
Ia
DYNAMIC
TEST SET
H12
G8
Ib
H8
G9
750/760
BUS
Ic
H9
POWER
MULTIMETER
C10
C11
SW10
2 CLOSE
BREAKER
CLOSE
F3
SW9
PB1
INITIATE RECLOSURE
E3
LOGIC e
SW7
E2
1 TRIP
F2
TRIP
LOGIC f
52a/52b
SW8
818790AA.CDR
FIGURE 7–6: Autoreclose Test Connections
 Assert a Cancel Reclosure logic input.
The Reclosure Enabled LED should go out and the Reclosure Disabled
LED come on.
 De-assert the Cancel Reclosure logic input.
The Reclosure Enabled LED should come on and the Reclosure
Disabled LED should go out.
 Verify that the A1 STATUS  AR  AR SHOT NUMBER IN EFFECT value is
“0”.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
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CONTROL SCHEMES
CHAPTER 7: COMMISSIONING
 Momentarily assert the Initiate Reclosure logic input.
The Reclosure In Progress LED should come on immediately, and any
output relays programmed to operate for Reclose In Progress should
now be operated.
After the delay programmed for INCOMPLETE SEQUENCE TIME, the
Reclosure In Progress LED will go out, as the breaker has not tripped,
and the incomplete sequence timer has canceled the reclose in progress.
 Any output relays operated above should now be reset.
Check the interval of the incomplete sequence timer by observing the
Reclosure In Progress LED.
 Momentarily assert the Initiate Reclosure logic input causing a reclose
in progress indication.
 Immediately assert the Block Reclosure logic input and the scheme
should become disabled, canceling the reclose in progress.
 Assert the Initiate Reclosure logic input and check that the scheme does
not become in progress.
 De-assert the Block Reclosure logic input and the scheme should
become in progress.
 Assert a Cancel Reclosure logic input and the scheme should become
disabled, canceling the reclose in progress.
 De-assert the Cancel Reclosure logic input and the scheme should
become enabled.
 Assert the Initiate Reclosure logic input then immediately after assert
the Remote Open logic input, initiating a reclose and tripping the
breaker (the Reclosure In Progress LED is now on).
 Verify that the AR SHOT NUMBER IN EFFECT value is “0”.
 Before the programmed dead-time interval for Reclosure 1 has elapsed,
press the CLOSE key.
The breaker should not close, as reclose is in progress.
The breaker should reclose at the end of the dead-time interval,
incrementing the shot counter to 1.
 Before the scheme resets, verify that the A1 STATUS  AR  AR SHOTS
REMAINING value is the number of shots programmed less one.
This reading should change to the number of shots programmed when
the scheme is automatically reset at the end of the reset interval. The
event recorder should have recorded logic input Initiate Reclosure,
Remote Open, the Reclose, and Reclosure Reset. Check the interval of
the autoreclose reset timer in the event recorder.
 ** Assert the Initiate Reclosure logic input then immediately after assert
the Remote Open logic input, initiating a reclose and tripping the
breaker.
 ** Check that the breaker trips and later recloses, and that the displayed
number of shots remaining is reduced by one.
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750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
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CONTROL SCHEMES
 ** Immediately assert the Initiate Reclosure and Remote Open logic
inputs again, to initiate another trip and reclose and the displayed
number of shots remaining is reduced by one again.
 ** Repeat this procedure until the programmed number of shots has
been performed.
 ** Initiate Reclosure once more and the scheme should go to lockout;
the Reclosure Lockout, Reclosure Disabled LEDs should now be on,
and the Reclosure Enabled LED should be off.
Any output relays programmed to operate for Lockout should now be
operated.
The event recorder should have recorded each logic input for Initiate
Reclosure, each Reclose, and Reclosure Lockout.
 Check the interval of dead time for each shot in the event recorder.
 Press the RESET key.
Lockout should be canceled and the displayed number of shots should
return to the programmed value (the event recorder should record this
reset.)
 Check that the Reclosure Lockout and Reclosure Disabled LEDs are off,
and the Reclosure Enabled LED is now on.
Any output relays operated above should now be de-energized.
 Close the breaker.
 Repeat the above 5 steps marked **.
Assert a Close command, either locally or remotely, and observe that
lockout is reset at the end of the AR BLOCK TIME UPON MANUAL CLOSE
setpoint, with indications as above.
 Set a current level above the pickup threshold of any time overcurrent
element and turn the current off.
 Repeat the above 5 steps marked **.
Assert a Close command, either locally or remotely, and turn the current
on.
Check that lockout is not reset at the end of the manual close blocking
time interval, and the breaker eventually trips.
 Turn the current off.
If Breaker Operation Failure, and/or Breaker Failure features are Operational, use the
following procedure:
 Open test switch SW9 to prevent a trip command from the relay from
operating the breaker.
 Enable one of the overcurrent elements by setting its function to “Trip +
AR”.
 Inject a current above the pickup level of both the operational
overcurrent feature and the Breaker Failure Current into the relay, until
the feature sends a trip, which will also initiate reclosure.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
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CONTROL SCHEMES
CHAPTER 7: COMMISSIONING
After the failure delay time, a breaker failure condition will be
determined, which should immediately set the reclose scheme to the
Lockout state, turning the Reclosure Lockout LED on.
 Turn the injected current off and Reset the relay.
Disable the overcurrent element and close both the breaker and SW9.
Use the following procedure to test Autoreclose Current Supervision. Note that the number
of reclosure shots setting controls the messages in this group. If four (4) shots are
programmed, all messages are available. If three (3) shots are programmed, the 3 SHOTS
FOR CURRENT ABOVE setpoint is not available on the relay. If two (2) shots are programmed,
the 3 SHOTS FOR CURRENT ABOVE and 2 SHOTS FOR CURRENT ABOVE setpoints are not
available. This procedure assumes four (4) shots are programmed.
 Close the breaker and wait until reclosure is enabled.
 Verify that the A1 STATUS  AR  AR SHOTS REMAINING value is “0”.
 Open SW9 so the breaker cannot trip. Inject current and slowly ramp
higher until an instantaneous feature sends a trip, which also initiates
reclosure.
The value displayed should be 4 (it has not yet decremented).
 Continue to very slowly increase the current until the value displayed
becomes 3.
 Continue to very slowly increase the current, until the value displayed
sequentially becomes 2 and then 1, at the currents programmed.
 Very slowly increase the current, at the current programmed, until the
relay goes to Lockout.
Use the following procedure to test Autoreclose Zone Coordination:
 Set the MAX NUMBER OF RECLOSURE SHOTS to “4”.
 Set the test set to a current level above the PHASE CURRENT INCREASE
setpoint, and ensure that the neutral current is below the NEUTRAL
CURRENT INCREASE setpoint by making this value larger.
 Turn on the current, then before the MAX FAULT CLEARING TIME has
elapsed, turn off the current.
The AR SHOT NUMBER IN EFFECT should have been incremented.
 Reset the relay.
 Turn on the current, then after the MAX FAULT CLEARING TIME has
elapsed, turn off the current.
The AR SHOT NUMBER IN EFFECT should not have been incremented.
 Reset the relay.
 Set the current level below the PHASE CURRENT INCREASE setpoint
value.
 Turn the current on and then off.
The AR SHOT NUMBER IN EFFECT value should not change.
 Set the current level above the PHASE CURRENT INCREASE setpoint
value, but below the NEUTRAL CURRENT INCREASE setpoint value.
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750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
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CONTROL SCHEMES
 Turn the current on and then off.
The AR SHOT NUMBER IN EFFECT value should increment by one.
Repeatedly turning the current on and then off should continue to
increment the AR SHOT NUMBER IN EFFECT to the MAX NUMBER OF
RECLOSURE SHOTS, and the Autoreclose scheme will go into lockout.
 Set the current level so the neutral current is below the NEUTRAL
CURRENT INCREASE setpoint and the phase current below the PHASE
CURRENT INCREASE setpoint.
 Turn the current on and then off.
The AR SHOT NUMBER IN EFFECT value should not change.
 Set the current level such that the neutral current is above the NEUTRAL
CURRENT INCREASE setpoint and the phase current is below the PHASE
CURRENT INCREASE setpoint.
 Turn the current on and then off.
The AR SHOT NUMBER IN EFFECT value should increment as above.
Use the following procedure to test Instantaneous Overcurrent Blocking for Autoreclose:
 Select the MAX NUMBER OF RECLOSURE SHOTS to be 4.
 With PHASE INST OC 1 FUNCTION selected as “Trip + AR”, set the test
set to a current level above the pickup of this element, and inject into a
phase input.
The relay should trip and reclose 4 times.
 Turn off the current, reset the relay and close the breaker.
 Enable Phase Inst OC 1 Blocking for Reclosure Shot 1.
 Turn on the current.
The relay should trip and reclose once.
The Shot in Effect display should show 1 and the Pickup LED off.
Once the AR RESET TIME has expired, the relay will then pickup, trip
and reclose until lockout as the fault current is still present.
 Turn off the current, reset the relay and close the breaker.
 Disable Phase Inst OC 1 Blocking for Reclosure Shot 1, and Enable for
Reclosure Shot 2.
 Turn on the current.
Reclosure Shot 2 should not operate, and the Pickup LED will be off.
 Turn off the current and reset the relay.
 Repeat Step 3 using Phase Inst OC 1 Blocking for each of the 4
Reclosure Shot settings.
 Repeat Steps 1 through 4 for each Instantaneous OC Blocking setpoint,
disabling each instantaneous overcurrent element before moving on to
the next.
Use the following procedure to test Raised Pickup of TOC Elements for Autoreclose:
 Keep the MAX NUMBER OF RECLOSURE SHOTS at 4.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
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CONTROL SCHEMES
CHAPTER 7: COMMISSIONING
 With the PHASE TIME OC 1 FUNCTION selected as “Trip + AR”, set the
test set to a current level above the pickup of this element.
 Turn off the current, reset the relay and close the breaker.
 In Reclosure Shot 1 settings, select the PHASE TIME OC 1 RAISED PICKUP
such that it brings the pickup level just below the actual current that is
being injected.
 Turn on the current.
The relay should trip and reclose 4 times.
 In Reclosure Shot 1 settings, select the PHASE TIME OC 1 RAISED PICKUP
such that it brings the pickup level just above the actual current that is
being injected.
 Turn on the current.
The relay should trip and reclose once.
The Shot in Effect display should show 1 and the Pickup LED off.
Once the AR RESET TIME has expired, the relay will then pickup, trip,
and reclose until lockout as the fault current is still present.
 Turn off the current, reset the relay and close the breaker.
 Return PHASE TIME OC 1 RAISED PICKUP to “0” for Reclosure Shot 1,
and set it to a level that is above the actual current for Reclosure Shot 2.
 Turn on the current.
Reclosure Shot 2 should not operate, and the Pickup LED will be off.
 Turn off the current and reset the relay.
 Repeat the last 3 steps using Phase Time OC 1 Blocking for each of the
4 Reclosure Shot settings.
 Repeat the last 12 steps (ie - from the beginning of this procedure to the
previous step) for each TIME OC RAISED PICKUP setpoint, disabling each
time overcurrent element before moving on to the next.
The following procedure tests the Select Setpoint Group function for Autoreclose:
 Keep the MAX NUMBER OF RECLOSURE SHOTS at 4.
In Setpoint Group 1, set PHASE TIME OC 1 FUNCTION to “Trip + AR”.
In Setpoint Group 2, set PHASE TIME OC 2 FUNCTION to “Trip + AR”.
In Setpoint Group 3, set PHASE INST OC 1 FUNCTION to “Trip + AR”.
In Setpoint Group 4, set PHASE INST OC 2 FUNCTION to “Trip + AR”.
Select the same pickup level for each element.
 For Reclosure Shot 1 settings, set the SELECT SETPOINT GROUP setpoint
to “Group 2”.
Similarly, set it to “Group 3” for Reclosure Shot 2, “Group 4” for
Reclosure Shot 3, and “Group 1” for Reclosure Shot 4.
 Set the test set to a current level above the pickup of these elements.
 With the current source off, Reset the relay, and clear the event recorder.
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CHAPTER 7: COMMISSIONING
CONTROL SCHEMES
 Turn on the current.
The relay will Trip and Autoreclose four times due to the following
elements, in order: Phase TOC 1, Phase TOC 2, Phase IOC 1, Phase
IOC 2, Phase TOC 1.
The event recorder will show this sequence of events.
 Turn off the current, and reset the relay.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
7 - 91
PLACING THE RELAY IN SERVICE
CHAPTER 7: COMMISSIONING
7.7
7.7.1
Placing the Relay In Service
Description
The procedure outlined in this section is explicitly confined to the operation of the relay,
and does not include the operation of any equipment external to the relay.
Note
NOTE
 Cycle through the relay setpoints and set each setpoint in each group to
the required value.
 Save all the relay setpoints to a file (or print them) for a final inspection
to confirm that all setpoints are correct.
 Set the relay clock (date and time) if IRIG-B is not used or unavailable.
 Clear all historical values stored in the relay.
Under subheading S1 RELAY SETUP  CLEAR DATA, set CLEAR ENERGY
USE DATA, CLEAR MAX DMND DATA, and CLEAR EVENT RECORDER
DATA to “Yes”.
Under subheading S1 RELAY SETUP  INSTALLATION, also set RESET
TRIP COUNTER DATA and RESET ARCING CURRENT DATA to “Yes”.
 Turn off all test voltages, and the power supply to the relay.
 Remove all test wiring connections, and restore to normal any panel
wiring disturbed for testing.
 Perform a complete visual inspection to confirm that the relay is ready
to be placed in service.
 Energize the relay power supply circuit and check that the Relay In
Service LED is on, and that the Self-Test Warning LED is off,
establishing that the relay is operating normally.
 For complete on-load checking of the relay, it is required to supply load
current to the relay in a known direction of power flow, with a known
approximate value of power factor.
The load current should be high enough to confirm that the main CTs
are connected correctly.
The power system should be arranged to fulfill these conditions before
the feeder to which the relay is connected, is energized.
Advise operators of the possibility of a trip on initial energizing.
7.7.2
On-Load
Testing
 If possible, before closing the feeder breaker to supply load, energize
the VT circuit to which the relay is connected.
Check that all relay measurements are as expected.
Under A2 METERING  VOLTAGE, verify the following:
<Magnitude>, AVERAGE LINE VOLTAGE: <Magnitude>, AN:
BN: CN: <Magnitude>, AVERAGE PHASE VOLTAGE: <Magnitude in kV>,
LINE A-B VOLTAGE: <Phasor>, LINE B-C VOLTAGE: <Phasor>, LINE C-A
AB: BC: CA:
7 - 92
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 7: COMMISSIONING
PLACING THE RELAY IN SERVICE
<Phasor>, PHASE A-N VOLTAGE: <Phasor>, PHASE B-N
<Phasor>, PHASE C-N VOLTAGE: <Phasor>, POS SEQ
VOLTAGE: <Phasor>, NEG SEQ VOLTAGE: <Phasor>, and ZERO SEQ
VOLTAGE: <Phasor>
VOLTAGE:
VOLTAGE:
 To have an immediate indication upon closing of the load level and
whether some overcurrent protection is operating, before closing the
feeder breaker display the A2 METERING  CURRENT  % OF LOAD-TOTRIP actual value.
 After the feeder circuit breaker is closed and the feeder is carrying load
current, check that all relay measurements are as expected.
 Under subheading A2 METERING  CURRENT, verify the following
actual values:
<Magnitude>, AVERAGE CURRENT: <Magnitude>, PHASE A(C)
<Phasor>, NEUTRAL CURRENT: <Phasor>, GND CURRENT:
<Phasor>, SENSTV GND CURRENT: <Phasor>, POS SEQ CURRENT:
<Phasor>, NEG SEQ CURRENT: <Phasor>, and ZERO SEQ CURRENT:
<Phasor>
A: B: C:
CURRENT:
 Under subheading A2 METERING  PWR, verify that REAL PWR,
REACTIVE PWR, APPARENT PWR, and PWR FACTOR values (for single
and three-phase values) are as expected.
 Verify that the A2 METERING  FREQ  SYSTEM FREQ actual value is as
expected.
 It is very important to confirm that the input CTs are connected properly
to provide correct directional control and metering calculations.
A first check of this connection is to note that the values of watts and
vars as calculated by the relay have the correct sign. This is done by
comparing the relay measurements, which are signed by the conventions
shown in FIGURE 6–3: Power Quantity Relationships on page 6–10, to
the known feeder load characteristics.
 After some time has passed, depending on feeder load and demand time
interval settings, check the following measured values:
Under A2 METERING  ENERGY, verify the POSITIVE WATTHOURS,
POSITIVE WATTHOUR COST, NEGATIVE WATTHOURS, NEGATIVE
WATTHOUR COST, POSITIVE VARHOURS,
and NEGATIVE VARHOURS
values.
 Under subheading A2 METERING  DMND  PHASE A(C) CURRENT,
verify the LAST PHASE A(C) CURRENT DMND and MAX PHASE A
CURRENT DMND values.
 Under subheading A2 METERING  DMND  REAL PWR, verify the LAST
REAL PWR DMND and MAX REAL PWR DMND values.
 Under subheading A2 METERING  DMND  REACTIVE PWR, verify the
LAST REACTIVE PWR DMND and MAX REACTIVE PWR DMND values.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
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PLACING THE RELAY IN SERVICE
CHAPTER 7: COMMISSIONING
 Under subheading A2 METERING  DMND  APPARENT PWR, verify the
LAST APPARENT PWR DMND and MAX APPARENT PWR DMND values.
7.7.3
Dielectric
Strength
Testing
A fully assembled production version of the relay is tested in its metal case. The dielectric
strength of all the input/output terminals are tested with respect to its grounded chassis
and Terminal G12 (safety ground). The test voltage of the tester, from the initial value of
0 V AC, is raised to 1.6 kV AC in such a manner (slowly) that no appreciable transients occur.
The voltage is maintained for 1 minute and is then reduced smoothly to zero as rapidly as
possible. According to IEC255-5, the Hi-Pot test is repeated with a voltage not less than
500 V AC.
FIGURE 7–7: Dielectric Strength Wiring
7 - 94
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
GE
Digital Energy
750/760 Feeder Management
Relay
Chapter 8: Appendix
Appendix
8.1
Relay Mods
8.1.1
Reverse Power
To upgrade the 750/760 to include Mod 008 (Reverse Power), a special 16-digit passcode
must be purchased from the GE Multilin Sales Department. As well, the firmware version
must be 5.00 or higher. The latest firmware for the 750/760 can be obtained from the GE
Multilin website at http://www.gedigitalenergy.com. Refer to Upgrading Relay Firmware on
page 4–29 for details on the firmware upgrade procedure.
To enable Mod 008:
 Press the SETPOINT key to display enter the relay setup menu:

SETPOINTS
S1 RELAY SETUP
[]
 Press the MESSAGE  key until the following message appears:

MOD 008
UPGRADE
[]
 Press the ENTER key to display the following message:
ENABLE MOD 008?
Disabled
 Press the VALUE  key once to change the setpoint value to “Enabled”:
ENABLE MOD 008?
Enabled
 Press the ENTER key to save the setpoint value.
The following message will be displayed:
NEW SETPOINT
STORED
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
8-1
RELAY MODS
CHAPTER 8: APPENDIX
 Press the MESSAGE  key once.
The following message appears:
ENTER PASSCODE:
0000000000000000
 Press the ENTER key to edit this passcode.
Use the VALUE keys to change each digit to match the 16-digit passcode
supplied by GE Multilin.
Press ENTER to move to the next digit.
After entering the last digit, the cursor will return to the first digit of the
code.
 Press the MESSAGE  key once.
The following message will be displayed:
UPGRADE OPTIONS?
No
 Press the VALUE  key once to change the message to:
UPGRADE OPTIONS?
Yes
 Press the ENTER key to save the new passcode.
The following message will be displayed:
NEW SETPOINT
STORED
 Wait at least 30 seconds and then cycle power to the relay by turning it
off then back on.
After power-up, verify that the following message is displayed:
GE Multilin
760 REV 7.00 MOD 008
The Reverse Power element is now Enabled. For details on using this element, refer to
Section 5.6.11: Reverse Power on page –92.
Should assistance be required at any time during this procedure, please contact GE Multilin
technical support at 1-800-547-8629 (within the U.S. and Canada) or +1(905) 927-7070
(outside U.S. or Canada). You can also send an e-mail to our technical support department
at multilin.tech@ge.com.
8-2
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 8: APPENDIX
8.2
CONFORMITY
Conformity
8.2.1
EU Declaration of Conformity
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
8-3
REVISION HISTORY
8.3
CHAPTER 8: APPENDIX
Revision History
8.3.1
Release Dates
Table 8–1: Release Dates
MANUAL
8-4
GE PART NO.
750/760
REVISION
RELEASE DATE
GEK-106471
1601-0120-A1
6.0x
05 January 2004
GEK-106471A
1601-0120-A2
6.0x
07 January 2004
GEK-106471B
1601-0120-A3
6.0x
17 May 2004
GEK-106471C
1601-0120-A4
7.0x
04 February 2005
GEK-106471D
1601-0120-A5
7.0x
31 August 2005
GEK-106471E
1601-0120-A6
7.0x
21 July 2006
GEK-106471F
1601-0120-A7
7.0x
9 February 2007
GEK-106471G
1601-0120-A8
7.2x
19 December 2007
GEK-106471H
1601-0120-A9
7.2x
24 March 2008
GEK-106471J
1601-0120-AA
7.2x
27 May 2008
GEK-106471K
1601-0120-AB
7.2x
28 November 2008
GEK-106471L
1601-0120-AC
7.2x
21 April 2009
GEK-106471M
1601-0120-AD
7.3x
15 January 2010
GEK-106471N
1601-0120-AE
7.4x
15 September 2011
GEK-106471P
1601-0120-AF
7.4x
23 January 2013
GEK-106471Q
1601-0120-AG
7.4x
5 November 2013
GEK-106471R
1601-0120-AH
7.4x
16 May 2014
GEK-106471S
1601-0120-AJ
7.4x
12 November 2014
GEK-106471T
1601-0120-AK
7.4x
12 February 2015
GEK-106471U
1601-0120-AL
7.4x
21 December 2015
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 8: APPENDIX
8.3.2
REVISION HISTORY
Release Notes
Table 8–2: Major Updates for GEK-106471U
SECT
(AK)
SECT
(AL)
Title
Title
Manual part number to 1601-0120-AL
Added General Safety Precautions section
1.1.1
1.1.1
Added exclamation symbol and definition
2.4.2
2.4.2
Updated Control Power specifications
2.4.11
2.4.11
Updated type test table
2.4.12
2.4.12
Updated Approvals
n/a
n/a
Removed SR references throughout
DESCRIPTION
Table 8–3: Major Updates for GEK-106471T
SECT
(AH)
SECT
(AK)
Title
Title
Manual part number to 1601-0120-AK
5.6.3
5.6.3
Updated Figure 5-10: Phase Directional Logic
5.6.4
5.6.4
Updated Figure 5-14: Neutral Directional Logic
5.6.5
5.6.5
Updated Figure 5-17: Ground Directional Overcurrent Logic
DESCRIPTION
Table 8–4: Major Updates for GEK-106471S
SECT
(AG)
SECT
(AH)
Title
Title
Manual part number to 1601-0120-AJ
2.4.11
2.4.11
Updated the Dielectric strength in Production tests
5.8.7
5.8.7
Updated the Device 43/10: Select to Trip Control Switch section
DESCRIPTION
Table 8–5: Major Updates for GEK-106471R (Sheet 1 of 2)
SECT
(AG)
SECT
(AH)
Title
Title
Manual part number to 1601-0120-AH
Cover
Cover
Added 10 year warranty logo
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
DESCRIPTION
8-5
REVISION HISTORY
CHAPTER 8: APPENDIX
Table 8–5: Major Updates for GEK-106471R (Sheet 2 of 2)
SECT
(AG)
SECT
(AH)
DESCRIPTION
4.3.3
4.3.3
Note added, for self-tests that do not de-energize the relay: Clock not
set, Internal RS485, Internal temp, and IRIG-B failure
4.3.3
4.3.3
Updated Table 4-2, removed RTC Crystal
6.5.1
6.5.1
Updated Table 6-6, removed RTC Crystal
8.4.1
8.4.1
Updated warranty information
Table 8–6: Major Updates for GEK-106471Q
SECT
(AF)
SECT
(AG)
Title
Title
Manual part number to 1601-0120-AG
Cover
Cover
Web address corrected
2.3.1
2.3.1
Order code updated. Discontinued: Basic Display
3.2
3.2
Typical Wiring Diagram updated
3.2.12
3.2.12
RS485 Wiring Diagram updated
RS422 Wiring Diagram updated
DESCRIPTION
Table 8–7: Major Updates for GEK-106471P
SECT
(AE)
SECT
(AF)
Title
Title
Manual part number to 1601-0120-AF
Cover
Cover
Address/Telno changes
5.6.1
5.6.1
Added setpoint group change examples
DESCRIPTION
Table 8–8: Major Updates for GEK-106471N
8-6
SECT
(AD)
SECT
(AE)
Title
Title
Manual part number to 1601-0120-AE
2.4.9
2.4.9
Revision: Supercap-backed internal clock information
5.2.3
5.2.3
Revision: Supercap-backed internal clock information
DESCRIPTION
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 8: APPENDIX
REVISION HISTORY
Table 8–9: Major Updates for GEK-106471M
SECT
(AC)
SECT
(AD)
Title
Title
Manual part number to 1601-0120-AD
5.5.3
5.5.3
Revised Output Relay Close Logic drawing to 818772AS.
5.8.2
5.8.2
Revised Synchrocheck Logic drawing to 818008BU.
5.8.7
5.8.7
Add "Bus Transfer Logic" setting to Settings table.
N/A
5.8.7
Add Transfer Scheme 2 text (p 5-150).
5.8.7
New drawings added as follows:
Transfer Scheme 2 Incomer No. 1 Logic 818740.DWG (p 5-151)
Transfer Scheme 2 Incomer No. 2 Logic 818741.DWG (p 5-152)
Transfer Scheme 2 Bus Tie Breaker Logic 818746.DWG (p 5-153)
N/A
DESCRIPTION
Table 8–10: Major Updates for GEK-106471L
SECT
(AB)
SECT
(AC)
Title
Title
Manual part number to 1601-0120-AC
2.4.2
2.4.2
Add CT Burden table
2.4.6
2.4.6
Add "Operate Time" to Synchrocheck section
2.4.4
2.4.5
2.4.4
2.4.5
Change Timing Accuracy in "Underfrequency" and "Overfrequency"
5.7.8
5.7.8
Add note to "Coil Monitor" section
5.7.8
5.7.8
Change "breaker operation function" and "coil monitor function"
ranges
DESCRIPTION
Table 8–11: Major Updates for GEK-106471K (Sheet 1 of 2)
SECT
(AA)
SECT
(AB)
Title
Title
Manual part number to 1601-0120-AB.
2.2.5
2.2.5
Text added
2.2.6
2.2.6
Text added
2.4.4
2.4.4
Phase / Ground / Neutral / Negative Sequence IOC changes
2.4.8
2.4.4
Trip Contact and Service Contact changes
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
DESCRIPTION
8-7
REVISION HISTORY
CHAPTER 8: APPENDIX
Table 8–11: Major Updates for GEK-106471K (Sheet 2 of 2)
SECT
(AA)
SECT
(AB)
4.7.1
4.7.1
Warning added
---
Gen
Loop wire added between case GND and safety GND, on several
wiring diagrams.
DESCRIPTION
Table 8–12: Major Updates for GEK-106471H
PAGE
(A8)
SECT
(A9)
Title
Title
2.3.1
2.4.2
2.3.1
2.4.2
CHANGE
Update
DESCRIPTION
Manual part number to 1601-0120-A9.
Change to DC power supply range
Table 8–13: Major Updates for GEK-106471G
PAGE
(A7)
8-8
SECT
(A8)
CHANGE
DESCRIPTION
Title
Title
Update
Manual part number to 1601-0120-A8.
2-14
2.4.11
Update
Electrostatic Discharge
2-6
2.3.1
Update
Order Codes (LO voltage)
2-3
2.2.1
Update
Processor type change
2-12
2.4.9
Update
CPU - 4 Ethernet sessions
3-10
3.2.5
Update
Drawing 996630 updated to version A5
4-16
4.5.3
Update
Add: Supports a maximum of 4 TCP/IP sessions
5-31
5.5.4
Update
Pulsed Output Dwell Time clarified
5-10
5.2.3
5.2.2
Update
Update
Clock (Date)
Add: Supports a maximum of 4 TCP/IP sessions
(Network Configuration section)
6-31
6.3.4
Update
Frequency Decay Rate
6-6
6.2.3
Update
Last Trip Data
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 8: APPENDIX
REVISION HISTORY
Table 8–14: Major Updates for GEK-106471F
PAGE
(A6)
PAGE
(A7)
Title
Title
2-21
2-21
CHANGE
Update
DESCRIPTION
Manual part number to 1601-0120-A7.
Changes to ELECTROSTATIC DISCHARGE value
Table 8–15: Major Updates for GEK-106471D
PAGE
(A4)
PAGE
(A5)
Title
Title
--
--
CHANGE
Update
DESCRIPTION
Manual part number to 1601-0120-A5.
Formatting changes only; no changes to content in
this revision
Table 8–16: Major Updates for GEK-106471C
PAGE
(A3)
PAGE
(A4)
CHANGE
DESCRIPTION
Title
Title
Update
Manual part number to 1601-0120-A4.
2-6
2-6
Update
Update Order Codes to indicate Ethernet option
2-11
2-11
Update
Updated specifications for Event Recorder and
Waveform Capture
2-13
2-13
Update
Updated Type Testing specifications
---
3-4
Add
Added Ethernet Connection section
---
4-16
Add
Added Configuring Ethernet Communications section
---
5-10
Add
Added Network Configuration sub-section
Table 8–17: Major Updates for GEK-106471B
PAGE
(A2)
PAGE
(A3)
Title
Title
--
--
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHANGE
Update
DESCRIPTION
Manual part number to 1601-0120-A3
Formatting changes only; no changes to content in
this revision
8-9
REVISION HISTORY
CHAPTER 8: APPENDIX
Table 8–18: Major Updates for GEK-106471A
8 - 10
PAGE
(A1)
PAGE
(A2)
Title
Title
Update
Manual part number to 1601-0120-A2
7-
--
Remove
Removed communications chapter. This will now be
available as a separate publication, GEK-106473:
750/760 Communications Guide
CHANGE
DESCRIPTION
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER 8: APPENDIX
8.4
GE MULTILIN DEVICE WARRANTY
GE Multilin Device Warranty
8.4.1
Warranty Statement
For products shipped as of 1 October 2013, GE Digital Energy warrants most of its GE
manufactured products for 10 years. For warranty details including any limitations and
disclaimers, see the GE Digital Energy Terms and Conditions at https://
www.gedigitalenergy.com/multilin/warranty.htm
For products shipped before 1 October 2013, the standard 24-month warranty applies.
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
8 - 11
GE MULTILIN DEVICE WARRANTY
8 - 12
CHAPTER 8: APPENDIX
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER I: INDEX
Index
Index
Numerics
1 TRIP RELAY
logic diagram .................................................................................................. 5-40
setpoints ......................................................................................................... 5-39
2 CLOSE RELAY
logic diagram .................................................................................................. 5-41
setpoints ......................................................................................................... 5-39
3 TO 7 AUXILIARY RELAYS
logic diagram .................................................................................................. 5-42
operation ......................................................................................................... 5-39
setpoints ......................................................................................................... 5-41
8 SELF-TEST WARNING
logic diagram .................................................................................................. 5-43
A
A1 STATUS
actual values ....................................................................................................6-6
autoreclose .......................................................................................................6-8
clock ..................................................................................................................6-8
fault locations ...................................................................................................6-8
hardware inputs ................................................................................................6-6
last trip data ......................................................................................................6-7
virtual inputs .....................................................................................................6-6
A2 METERING
actual values .................................................................................................. 6-10
analog input .................................................................................................... 6-17
current ............................................................................................................. 6-11
demand ........................................................................................................... 6-16
energy ............................................................................................................. 6-15
frequency ........................................................................................................ 6-13
last reset date ................................................................................................ 6-16
power .............................................................................................................. 6-14
synchronizing voltage .................................................................................... 6-14
voltage ............................................................................................................ 6-12
A3 MAINTENANCE
actual values .................................................................................................. 6-18
arcing current ................................................................................................. 6-19
trip counters ................................................................................................... 6-18
A4 EVENT RECORDER
actual values .................................................................................................. 6-20
event records .................................................................................................. 6-20
event types ..................................................................................................... 6-21
A5 PRODUCT INFO
actual values .................................................................................................. 6-25
calibration dates ............................................................................................. 6-26
revision codes ................................................................................................ 6-25
technical support ............................................................................................ 6-25
ACTUAL VALUES
analog input .................................................................................................... 6-17
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
1
CHAPTER I: INDEX
arcing current ................................................................................................. 6-19
autoreclose ....................................................................................................... 6-8
block diagram ............................................................................................ 6-4 , 6-5
calibration dates ............................................................................................. 6-26
clock .................................................................................................................. 6-8
current ............................................................................................................. 6-11
demand ........................................................................................................... 6-16
energy ............................................................................................................. 6-15
event records ................................................................................................. 6-20
event types ..................................................................................................... 6-21
fault locations ................................................................................................... 6-8
frequency ........................................................................................................ 6-13
hardware inputs ............................................................................................... 6-6
last reset date ................................................................................................ 6-16
last trip data ..................................................................................................... 6-7
overview ............................................................................................................ 6-1
power .............................................................................................................. 6-14
revision codes ................................................................................................ 6-25
summary ........................................................................................................... 6-1
synchronizing voltage .................................................................................... 6-14
technical support ............................................................................................ 6-25
trip counters ................................................................................................... 6-18
virtual inputs ..................................................................................................... 6-6
voltage ............................................................................................................ 6-12
ANALOG INPUT
actual values .................................................................................................. 6-17
description ...................................................................................................... 3-17
measurement .................................................................................................. 7-23
measuring ....................................................................................................... 7-23
rate of change ....................................................................................5-109 , 5-110
setpoints ....................................................................................................... 5-106
setup ............................................................................................................. 5-106
threshold ....................................................................................................... 5-108
ANALOG INPUT RATE OF CHANGE
monitoring ....................................................................................................... 7-54
setpoints ....................................................................................................... 5-109
ANALOG INPUT SETUP .................................................................................. 5-106
ANALOG OUTPUTS
channels ......................................................................................................... 7-59
characteristics .............................................................................................. 5-110
connection ...................................................................................................... 3-18
description ...................................................................................................... 3-17
parameters ................................................................................................... 5-111
setpoints .............................................................................................5-110 , 5-171
testing ........................................................................................................... 5-171
ANALOG THRESHOLD
monitoring ....................................................................................................... 7-54
setpoints ....................................................................................................... 5-107
ANSI CURVES
constants ........................................................................................................ 5-46
description ...................................................................................................... 5-46
trip times ......................................................................................................... 5-46
APPARENT POWER DEMAND
logic diagram ................................................................................................ 5-105
measurement .................................................................................................. 7-23
monitoring ....................................................................................................... 7-54
setpoints ....................................................................................................... 5-104
APPARENT POWER MEASUREMENT ............................................................... 7-20
2
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER I: INDEX
APPLICABILITY .................................................................................................. 2-11
APPLICATION EXAMPLE .................................................................................. 1-15
APPROVALS ...................................................................................................... 2-23
ARCING CURRENT
actual values .................................................................................................. 6-19
logic diagram ................................................................................................ 5-117
measurement ................................................................................................ 5-116
monitoring ....................................................................................................... 7-58
setpoints ....................................................................................................... 5-115
AUTORECLOSE
actual values ....................................................................................................6-8
application example ..................................................................................... 5-168
current supervision ...................................................................................... 5-163
description .................................................................................................... 5-157
rate supervision ............................................................................................ 5-162
reclosure shots ............................................................................................. 5-167
setpoints ......................................................................................................... 5-36
test connection diagram ................................................................................ 7-85
testing ............................................................................................................. 7-84
zone coordination ......................................................................................... 5-164
AUTORECLOSE CURRENT SUPERVISION ..................................................... 5-163
AUTORECLOSE RATE SUPERVISION
logic diagram ................................................................................................ 5-162
setpoints ....................................................................................................... 5-162
AUTORECLOSE ZONE COORDINATION ........................................................ 5-164
AUXILIARY RELAYS
operation ......................................................................................................... 5-39
B
BLOCK DIAGRAM ...............................................................................................2-8
BLOCK FUNCTIONS ......................................................................................... 5-32
BLOCK OVERCURRENT FUNCTIONS .............................................................. 5-34
BLOCKING
cold load pickup ........................................................................................... 5-131
manual close ................................................................................................ 5-129
setpoints ......................................................................................................... 5-32
BREAKER FAILURE
logic diagram .................................................................................................. 5-91
setpoints ......................................................................................................... 5-90
testing ............................................................................................................. 7-49
BREAKER FUNCTIONS ..................................................................................... 5-28
BREAKER OPERATION
logic diagram ................................................................................................ 5-118
setpoints ....................................................................................................... 5-117
BREAKER OPERATION FAILURE ...................................................................... 7-58
BUS TIE RELAYS .................................................................................. 5-144, 5-145
BUS UNDERVOLTAGE
logic diagram .................................................................................................. 5-84
setpoints ......................................................................................................... 5-83
testing ............................................................................................................. 7-39
BUS VOLTAGE
frequency ........................................................................................................ 7-18
measuring ....................................................................................................... 7-17
BUS VT SENSING SETPOINTS ......................................................................... 5-22
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
3
CHAPTER I: INDEX
C
CALIBRATION DATES ....................................................................................... 6-26
CAPACITOR BANK SWITCHING ...................................................................... 5-96
CASE
dimensions ....................................................................................................... 3-1
installation ........................................................................................................ 3-2
mounting tabs ................................................................................................... 3-3
removing unit from ........................................................................................... 3-6
CHANGES TO MANUAL .................................................. 8-5 , 8-6 , 8-7 , 8-8 , 8-9 , 8-10
CHANGING SETPOINTS ..................................................................................... 1-7
CLEAR DATA ..................................................................................................... 5-20
CLOCK
actual values .................................................................................................... 6-8
setpoints ......................................................................................................... 5-13
specifications ................................................................................................. 2-21
CLOSE COIL MONITORING .............................................................................. 7-57
CLOSE COIL SUPERVISION
connection diagram ....................................................................................... 3-16
description ...................................................................................................... 3-15
COIL MONITOR
logic diagram ................................................................................................ 5-119
setpoints ....................................................................................................... 5-118
COLD LOAD PICKUP
description .................................................................................................... 5-132
feature blocking .............................................................................................. 7-68
logic diagram ................................................................................................ 5-132
setpoints ....................................................................................................... 5-131
COMMISSIONING ............................................................................................... 7-1
COMMON SETPOINTS ........................................................................................ 5-6
COMMUNICATIONS
DNP setpoints ................................................................................................ 5-11
RS232 .......................................................................... 3-20 , 3-21 , 4-13 , 4-17 , 4-19
RS422 ............................................................................................................. 3-20
RS485 ............................................................................................4-13 , 4-17 , 4-19
setpoints ........................................................................................................... 5-9
specifications ................................................................................................. 2-20
wiring .............................................................................................................. 4-13
CONTACT INFORMATION .................................................................................. 1-2
CONTROL FUNCTIONS .................................................................................... 5-30
CONTROL POWER
connection diagram ....................................................................................... 3-15
description ...................................................................................................... 3-14
CONTROL SCHEMES
cold load pickup blocking .............................................................................. 7-68
manual close feature blocking ...................................................................... 7-67
setpoint group control .................................................................................... 7-60
specifications ................................................................................................. 2-18
synchrocheck ................................................................................................. 7-62
transfer ........................................................................................................... 7-75
underfrequency restoration ........................................................................... 7-74
undervoltage restoration ............................................................................... 7-70
COUNTERS
trip ................................................................................................................... 6-18
CTs
see CURRENT TRANSFORMER
4
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER I: INDEX
CURRENT ACTUAL VALUES ............................................................................. 6-11
CURRENT DEMAND
logic diagram ................................................................................................ 5-102
measurement .................................................................................................. 7-21
monitoring ....................................................................................................... 7-53
setpoints ....................................................................................................... 5-101
CURRENT SENSING SETPOINTS ...................................................................... 5-22
CURRENT TRANSFORMER
AC inputs ........................................................................................................ 3-11
current sensing ............................................................................................... 5-22
ground inputs .................................................................................................. 3-11
sensitive ground inputs .................................................................................. 3-11
zero sequence installation ............................................................................ 3-13
CURVES
ANSI ................................................................................................................ 5-46
definite time .................................................................................................... 5-45
IAC .................................................................................................................. 5-48
IEC .................................................................................................................. 5-47
CUTOUTS
panel .................................................................................................................3-2
D
DATA LOGGER
modes ............................................................................................................. 5-16
setpoints ......................................................................................................... 5-16
DEFAULT MESSAGES
adding ............................................................................................................. 5-19
removing ......................................................................................................... 5-19
setpoints ......................................................................................................... 5-18
DEFINITE TIME CURVE ..................................................................................... 5-45
DEMAND
actual values .................................................................................................. 6-16
apparent power ........................................................................... 5-104 , 7-23 , 7-54
current .................................................................................................. 5-101, 7-21
description ...................................................................................................... 5-99
reactive power ............................................................................. 5-103 , 7-23 , 7-53
real power .................................................................................... 5-102 , 7-22 , 7-53
thermal demand characteristic .................................................................... 5-100
DIAGNOSTIC MESSAGES ...................................................................................4-7
DIELECTRIC STRENGTH TESTING ................................................................... 7-94
DIMENSIONS ......................................................................................................3-1
DIRECTIONAL OVERCURRENT
description ...................................................................................................... 5-54
phase A polarizing ......................................................................................... 5-55
DNP COMMUNICATIONS
description ...................................................................................................... 5-11
setpoints ......................................................................................................... 5-11
DRAWOUT CASE
description ........................................................................................................3-1
installation ........................................................................................................3-1
seal ....................................................................................................................3-2
DRY CONTACT CONNECTIONS ....................................................................... 3-17
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
5
CHAPTER I: INDEX
E
EARTH FAULT, RESTRICTED ............................................................................ 5-73
ENERGY ACTUAL VALUES ............................................................................... 6-15
ENERVISTA VIEWPOINT WITH THE 750/760 ................................................ 4-39
EQUIPMENT MONITORING ............................................................................ 5-114
ETHERNET ......................................................................................................... 5-12
EVENT CAUSES
alarm ............................................................................................................... 6-22
control ............................................................................................................. 6-22
general ............................................................................................................ 6-22
logic input ....................................................................................................... 6-23
pickup .............................................................................................................. 6-22
trip ................................................................................................................... 6-22
warning ........................................................................................................... 6-23
EVENT RECORDER
event records ................................................................................................. 6-20
event types ..................................................................................................... 6-21
setpoints ......................................................................................................... 5-14
EVENT RECORDS .............................................................................................. 6-20
EVENT TYPES .................................................................................................... 6-21
F
FACTORY SERVICE ......................................................................................... 5-176
FAST FOURIER TRANSFORM
processing inputs ............................................................................................. 2-6
FAULT LOCATIONS ............................................................................................ 6-8
FAULT LOCATOR
description ...................................................................................................... 5-97
monitoring ....................................................................................................... 7-51
FAULT VALUES ............................................................................................... 5-175
FEATURES ........................................................................................................... 2-4
FFT
see FAST FOURIER TRANSFORM
FIRMWARE
upgrading via EnerVista 750/760 setup software ........................................ 4-29
FLASH MESSAGES .............................................................................................. 4-9
FLEXCURVES
setpoints ......................................................................................................... 5-24
FREQUENCY
actual values .................................................................................................. 6-13
decay .............................................................................................................. 5-89
protection elements ....................................................................................... 5-87
FREQUENCY DECAY
logic diagram .................................................................................................. 5-90
protection scheme .......................................................................................... 7-47
setpoints ......................................................................................................... 5-89
FREQUENCY TRACKING ..................................................................................... 2-5
FRONT PANEL
description ................................................................................................. 4-1 , 4-2
operation ........................................................................................................... 4-1
setpoints ......................................................................................................... 5-17
using ................................................................................................................. 1-3
6
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER I: INDEX
G
GATEWAY IP ADDRESS .................................................................................... 5-12
GETTING STARTED .............................................................................................1-1
GROUND CURRENT MEASUREMENT .............................................................. 7-16
GROUND DIRECTIONAL OVERCURRENT
control characteristics ................................................................................... 5-67
logic diagram .................................................................................................. 5-68
protection scheme .......................................................................................... 7-36
setpoints ......................................................................................................... 5-66
GROUND INPUTS ............................................................................................. 3-12
GROUND INSTANTANEOUS OVERCURRENT
logic diagram .................................................................................................. 5-66
protection scheme .......................................................................................... 7-36
setpoints ......................................................................................................... 5-65
setting example .............................................................................................. 1-27
GROUND OVERCURRENT ................................................................................ 5-64
GROUND TIME OVERCURRENT
logic diagram .................................................................................................. 5-65
protection scheme .......................................................................................... 7-36
setpoints ......................................................................................................... 5-64
setting example .............................................................................................. 1-27
H
HARDWARE BLOCK DIAGRAM ..........................................................................2-8
HARDWARE INPUTS ...........................................................................................6-6
HARMONICS .......................................................................................................2-6
HELP KEY ............................................................................................................1-8
I
IAC CURVES
constants ........................................................................................................ 5-48
description ...................................................................................................... 5-48
trip times ......................................................................................................... 5-49
IEC CURVES
constants ........................................................................................................ 5-47
description ...................................................................................................... 5-47
trip times ......................................................................................................... 5-47
IED SETUP ......................................................................................................... 4-14
INCOMER RELAYS ............................................................................... 5-144, 5-145
INPUT CURRENT MEASUREMENT ................................................................... 7-16
INPUT VOLTAGE MEASUREMENT ................................................................... 7-17
INPUTS
analog .......................................................................3-17 , 5-106 , 5-109 , 6-17 , 7-23
contact ..............................................................................................................2-7
ground ............................................................................................................. 3-12
hardware ...........................................................................................................6-6
logic ................................................................................................. 2-7, 3-17 , 5-27
restricted earth fault .............................................................................. 3-12 , 3-13
sensitive ground ............................................................................................. 3-12
signal processing .............................................................................................2-6
specifications .................................................................................................. 2-11
virtual ................................................................................................................6-6
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
7
CHAPTER I: INDEX
INSPECTION CHECKLIST ................................................................................... 1-1
INSTALLATION
case ................................................................................................................... 3-2
checks ............................................................................................................... 7-3
description ...................................................................................................... 1-27
putting the relay in Ready state .................................................................... 1-27
setpoints ......................................................................................................... 5-20
INSTALLING THE RELAY .................................................................................. 7-92
INTRODUCTION .................................................................................................. 2-1
INVERSE TIME UNDERVOLTAGE CURVES ...................................................... 5-83
IP ADDRESS ...................................................................................................... 5-12
IRIG-B
description ...................................................................................................... 3-21
monitoring ....................................................................................................... 7-59
J
JUMPER
security access ................................................................................................ 5-6
setpoint access ................................................................................................ 1-7
K
KEYPAD
help ................................................................................................................... 1-8
operation ........................................................................................................... 4-6
KEYPAD OPERATION .......................................................................................... 4-6
L
LAST RESET DATE ............................................................................................ 6-16
LAST TRIP DATA ................................................................................................. 6-7
LED INDICATORS ............................................................................................... 5-8
LINE UNDERVOLTAGE
logic diagram .................................................................................................. 5-85
protection scheme .......................................................................................... 7-42
setpoints ......................................................................................................... 5-84
LINE VT SENSING SETPOINTS ......................................................................... 5-23
LOGIC INPUTS
description ........................................................................................................ 2-7
dry and wet contact connections .................................................................. 3-17
setup ............................................................................................................... 5-27
tests .................................................................................................................. 7-6
typical wiring .................................................................................................. 3-17
LONG-TERM STORAGE .................................................................................... 2-21
M
MANUAL CLOSE BLOCKING
logic diagram ................................................................................................ 5-130
setpoints ....................................................................................................... 5-129
testing ............................................................................................................. 7-67
MEASURED PARAMETERS ............................................................................... 2-12
MESSAGES
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750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER I: INDEX
flash ..................................................................................................................4-9
METERING ......................................................................................................... 7-16
MISC FUNCTIONS SETPOINTS ........................................................................ 5-36
MODEL NUMBER ................................................................................................2-9
MONITORING .................................................................................................... 7-51
MONITORING ELEMENTS
specifications .................................................................................................. 2-17
MOUNTING TABS ...............................................................................................3-3
N
NAMEPLATE ........................................................................................................1-1
NEGATIVE SEQUENCE DIRECTIONAL OVERCURRENT
characteristics ................................................................................................ 5-80
logic diagram .................................................................................................. 5-80
protection schemes ........................................................................................ 7-38
setpoints ......................................................................................................... 5-79
NEGATIVE SEQUENCE INSTANTANEOUS OVERCURRENT
logic diagram .................................................................................................. 5-79
protection scheme .......................................................................................... 7-37
setpoints ......................................................................................................... 5-78
setting example .............................................................................................. 1-27
NEGATIVE SEQUENCE TIME OVERCURRENT
logic diagram .................................................................................................. 5-78
protection scheme .......................................................................................... 7-37
setpoints ......................................................................................................... 5-77
setting example .............................................................................................. 1-27
NEGATIVE SEQUENCE VOLTAGE
logic diagram .................................................................................................. 5-81
protection scheme .......................................................................................... 7-38
setpoints ......................................................................................................... 5-81
NETWORK CONFIGURATION .......................................................................... 5-12
NEUTRAL CURRENT
logic diagram .................................................................................................. 5-95
monitoring ....................................................................................................... 7-51
setpoints ......................................................................................................... 5-95
NEUTRAL DIRECTIONAL OVERCURRENT ....................................................... 7-33
description ...................................................................................................... 5-61
logic diagram .................................................................................................. 5-63
operating characteristics ............................................................................... 5-62
operating regions ........................................................................................... 7-33
setpoints ......................................................................................................... 5-61
test connections ............................................................................................. 7-34
voltage polarizing ........................................................................................... 5-62
NEUTRAL DISPLACEMENT
logic diagram .................................................................................................. 5-87
protection scheme .......................................................................................... 7-44
setpoints ......................................................................................................... 5-86
NEUTRAL INSTANTANEOUS OVERCURRENT
logic diagram .................................................................................................. 5-61
protection scheme .......................................................................................... 7-32
setpoints ......................................................................................................... 5-60
setting example ..................................................................................... 1-26 , 1-27
NEUTRAL OVERCURRENT
setpoints ......................................................................................................... 5-58
NEUTRAL TIME OVERCURRENT
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
9
CHAPTER I: INDEX
logic diagram .................................................................................................. 5-60
protection scheme .......................................................................................... 7-32
setpoints ......................................................................................................... 5-59
setting example .............................................................................................. 1-26
NON-LINEAR RESISTOR
in restricted earth fault .................................................................................. 5-76
NUMERICAL SETPOINTS .................................................................................... 1-8
O
ON-LOAD TESTING .......................................................................................... 7-92
ORDER CODES .................................................................................................... 2-9
OUTPUT RELAYS
operation ......................................................................................................... 5-38
setpoints .............................................................................................. 5-38 , 5-170
testing ............................................................................................................. 7-14
tests .................................................................................................................. 7-6
OUTPUT STATUS INDICATORS .......................................................................... 4-4
OUTPUTS
analog ..............................................................................5-110 , 5-111 , 5-171 , 7-59
SCR ................................................................................................................. 3-16
specifications ................................................................................................. 2-20
OVERCURRENT
blocking .......................................................................................................... 5-34
directional .............................................................................................. 5-54 , 5-55
ground ............................................................................................................. 5-64
ground directional ................................................................................. 5-66 , 5-68
ground instantaneous .................................................................................... 5-65
ground time .................................................................................................... 5-64
negative sequence directional .....................................................5-79 , 5-80 , 7-38
negative sequence instantaneous ....................................................... 5-78 , 7-37
negative sequence time ....................................................................... 5-77 , 7-37
neutral ............................................................................................................. 5-58
neutral directional .........................................................................5-61 , 5-63 , 7-33
neutral instantaneous ........................................................................... 5-60 , 7-32
neutral time ........................................................................................... 5-59 , 7-32
phase directional .................................................................. 5-54, 5-56 , 5-58 , 7-30
phase instantaneous .....................................................................5-53 , 7-29 , 7-30
phase time .....................................................................................5-51 , 7-25 , 7-28
sensitive ground directional ................................................ 5-71 , 5-72 , 5-73 , 7-37
sensitive ground instantaneous ........................................................... 5-70 , 7-37
sensitive ground time ........................................................................... 5-69 , 7-36
OVERFREQUENCY
logic diagram ................................................................................................ 5-113
monitoring ....................................................................................................... 7-55
setpoints ....................................................................................................... 5-113
OVERVIEW .......................................................................................................... 2-1
OVERVOLTAGE
logic diagram .................................................................................................. 5-86
protection scheme .......................................................................................... 7-42
setpoints ......................................................................................................... 5-85
P
PANEL CUTOUTS ................................................................................................ 3-2
PASSCODE SECURITY ........................................................................................ 5-6
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750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER I: INDEX
PASSCODE SETPOINTS ......................................................................................5-9
PHASE A CURRENT DEMAND .......................................................................... 6-16
PHASE CURRENT
logic diagram .................................................................................................. 5-94
monitoring ....................................................................................................... 7-51
setpoints ......................................................................................................... 5-94
PHASE DIRECTIONAL OVERCURRENT
forward operating regions ............................................................................. 7-30
logic diagram .................................................................................................. 5-58
operating characteristics ............................................................................... 5-56
protection scheme .......................................................................................... 7-30
setpoints ......................................................................................................... 5-54
PHASE INSTANTANEOUS OVERCURRENT
logic diagram .................................................................................................. 5-54
protection scheme ................................................................................. 7-29 , 7-30
setpoints ......................................................................................................... 5-53
setting example .............................................................................................. 1-26
PHASE OVERCURRENT .................................................................................... 5-50
PHASE SEQUENCE ........................................................................................... 3-11
PHASE TIME OVERCURRENT
logic diagram ......................................................................................... 5-52 , 5-53
protection scheme ................................................................................. 7-25 , 7-28
setpoints ......................................................................................................... 5-51
voltage restraint characteristic ...................................................................... 5-51
PHASORS ............................................................................................................2-6
PHYSICAL SPECIFICATIONS ............................................................................ 2-21
PICKUP TEST
logic diagram ................................................................................................ 5-171
setpoints ....................................................................................................... 5-171
PLACING THE RELAY IN SERVICE ................................................................... 7-92
PORT SETUP .......................................................................................................5-9
POSTFAULT VALUES ...................................................................................... 5-176
POWER
actual values .................................................................................................. 6-14
quantity relationships ..................................................................................... 6-10
POWER FACTOR
logic diagram .................................................................................................. 5-97
measurement .................................................................................................. 7-20
monitoring ....................................................................................................... 7-55
setpoints ......................................................................................................... 5-95
POWER QUANTITY RELATIONSHIPS ............................................................... 6-10
POWER SYSTEM SETPOINTS ........................................................................... 5-23
PREFAULT VALUES ......................................................................................... 5-175
PRODUCT OVERVIEW ........................................................................................2-1
PRODUCT SELECTOR .........................................................................................2-9
PROTECTION ELEMENTS
description ........................................................................................................2-6
one-line diagram ..............................................................................................2-4
specifications .................................................................................................. 2-14
theory of operation ...........................................................................................2-6
PROTECTION ONE LINE DIAGRAM ...................................................................2-4
PROTECTION SCHEMES
description ...................................................................................................... 7-25
frequency decay ............................................................................................. 7-47
ground directional overcurrent ...................................................................... 7-36
ground instantaneous overcurrent ................................................................ 7-36
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
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CHAPTER I: INDEX
ground time overcurrent ................................................................................ 7-36
line undervoltage ........................................................................................... 7-42
negative sequence directional overcurrent .................................................. 7-38
negative sequence instantaneous overcurrent ............................................ 7-37
negative sequence time overcurrent ............................................................ 7-37
negative sequence voltage ........................................................................... 7-38
neutral displacement ..................................................................................... 7-44
neutral instantaneous overcurrent ................................................................ 7-32
neutral time overcurrent ................................................................................ 7-32
overvoltage ..................................................................................................... 7-42
phase directional overcurrent ....................................................................... 7-30
phase instantaneous overcurrent ........................................................ 7-29 , 7-30
phase time overcurrent ......................................................................... 7-25 , 7-28
sensitive ground directional overcurrent ...................................................... 7-37
sensitive ground instantaneous overcurrent ................................................ 7-37
sensitive ground time overcurrent ................................................................ 7-36
setpoint groups .............................................................................................. 7-25
underfrequency .............................................................................................. 7-45
PULSE OUTPUT
logic diagram ................................................................................................ 5-122
monitoring ....................................................................................................... 7-59
setpoints ....................................................................................................... 5-121
R
REACTIVE POWER DEMAND
logic diagram ................................................................................................ 5-104
measurement .................................................................................................. 7-23
monitoring ....................................................................................................... 7-53
setpoints ....................................................................................................... 5-103
REACTIVE POWER MEASUREMENT ................................................................ 7-19
REAL POWER DEMAND
logic diagram ................................................................................................ 5-103
measurement .................................................................................................. 7-22
monitoring ....................................................................................................... 7-53
setpoints ....................................................................................................... 5-102
REAL POWER MEASUREMENT ........................................................................ 7-18
REAR TERMINAL ASSIGNMENTS ....................................................................... 3-8
REAR TERMINAL LAYOUT .................................................................................. 3-8
RECLOSURE SHOTS SETPOINTS ................................................................... 5-167
RESET DATE, LAST ........................................................................................... 6-16
RESTRICTED EARTH FAULT
description ...................................................................................................... 3-13
inputs .............................................................................................................. 3-12
logic diagram .................................................................................................. 5-76
non-linear resistor .......................................................................................... 5-76
setpoints ......................................................................................................... 5-73
stabilizing resistor .......................................................................................... 5-75
REVERSE POWER
commissioning ................................................................................................ 7-49
setpoints ......................................................................................................... 5-92
specifications ................................................................................................. 2-16
upgrade procedure ........................................................................................... 8-1
REVISION CODES ............................................................................................. 6-25
RS232
connection diagram ....................................................................................... 3-21
front panel port ............................................................................................... 3-20
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750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER I: INDEX
RS232 COMMUNICATIONS
configuring with EnerVista 750/760 Setup .......................................... 4-17 , 4-19
connections .................................................................................................... 4-13
RS422
communications ............................................................................................. 3-18
connection diagram ........................................................................................ 3-20
RS485
communications ............................................................................................. 3-18
connection diagram ........................................................................................ 3-19
RS485 COMMUNICATIONS
configuring with EnerVista 750/760 Setup .......................................... 4-17 , 4-19
connections .................................................................................................... 4-13
S
S1 RELAY SETUP ................................................................................................5-9
S2 SYSTEM SETUP
setpoints ......................................................................................................... 5-22
settings example ............................................................................................ 1-23
S3 LOGIC INPUTS
setpoints ......................................................................................................... 5-26
settings example ............................................................................................ 1-24
S4 OUTPUT RELAYS ......................................................................................... 5-38
S5 PROTECTION
setpoints ......................................................................................................... 5-44
settings example ............................................................................................ 1-26
S6 MONITORING .............................................................................................. 5-94
S7 CONTROL ................................................................................................... 5-123
S8 TESTING ..................................................................................................... 5-170
SAFETY PRECAUTIONS ......................................................................................7-1
SAMPLE APPLICATION ..................................................................................... 1-15
SCHEME SETUP SETPOINTS .......................................................................... 5-159
SCR OUTPUT ..................................................................................................... 3-16
SELF-TEST WARNINGS ............................................................................... 4-7 , 4-8
SENSITIVE GROUND CURRENT
measurement .................................................................................................. 7-16
sample application ......................................................................................... 5-74
setpoints ......................................................................................................... 5-68
SENSITIVE GROUND DIRECTIONAL OVERCURRENT
characteristics ................................................................................................ 5-72
logic diagram .................................................................................................. 5-73
protection scheme .......................................................................................... 7-37
setpoints ......................................................................................................... 5-71
SENSITIVE GROUND INPUTS .......................................................................... 3-12
SENSITIVE GROUND INSTANTANEOUS OVERCURRENT
logic diagram .................................................................................................. 5-71
protection scheme .......................................................................................... 7-37
setpoints ......................................................................................................... 5-70
SENSITIVE GROUND TIME OVERCURRENT
logic diagram .................................................................................................. 5-70
protection scheme .......................................................................................... 7-36
setpoints ......................................................................................................... 5-69
SETPOINT ACCESS JUMPER
installing ............................................................................................................1-7
programming setpoints ....................................................................................5-6
SETPOINT ACCESS SECURITY ...........................................................................5-6
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
13
CHAPTER I: INDEX
SETPOINT
SETPOINT
SETPOINT
SETPOINT
CONTROL DIAGRAM ............................................... 5-124 , 5-125 , 5-126
ENTRY METHODS ............................................................................. 5-5
GROUP CONTROL .......................................................................... 7-60
GROUPS
for protection schemes .................................................................................. 7-25
setpoints ....................................................................................................... 5-123
SETPOINTS
1 trip and 2 close relay .................................................................................. 5-39
3-7 auxiliary relays ........................................................................................ 5-41
access jumper .................................................................................................. 5-6
access security ................................................................................................ 5-6
analog input rate of change ........................................................................ 5-109
analog input setup ....................................................................................... 5-106
analog output ............................................................................................... 5-110
analog outputs .............................................................................................. 5-171
analog threshold .......................................................................................... 5-107
apparent power demand .............................................................................. 5-104
arcing current ............................................................................................... 5-115
autoreclose ..................................................................................................... 5-36
autoreclose current supervision .................................................................. 5-163
autoreclose rate supervision ....................................................................... 5-162
autoreclose zone coordination .................................................................... 5-164
block functions ............................................................................................... 5-32
block overcurrent functions ........................................................................... 5-34
breaker failure ................................................................................................ 5-90
breaker functions ........................................................................................... 5-28
breaker operation ......................................................................................... 5-117
bus undervoltage ........................................................................................... 5-83
bus VT sensing ..................................................................................... 5-22 , 5-23
changing ........................................................................................................... 1-7
clear data ........................................................................................................ 5-20
clock ................................................................................................................ 5-13
coil monitor ................................................................................................... 5-118
cold load pickup ........................................................................................... 5-131
common ............................................................................................................ 5-6
control functions ............................................................................................. 5-30
current demand ............................................................................................ 5-101
current sensing .............................................................................................. 5-22
data logger ..................................................................................................... 5-16
default messages ........................................................................................... 5-18
DNP communications .................................................................................... 5-11
entering with EnerVista 750/760 setup software ......................................... 4-22
entry methods .................................................................................................. 5-5
event recorder ................................................................................................ 5-14
factory service .............................................................................................. 5-176
fault values ................................................................................................... 5-175
flexcurves ....................................................................................................... 5-24
frequency decay ............................................................................................. 5-89
front panel ...................................................................................................... 5-17
ground directional .......................................................................................... 5-66
ground instantaneous overcurrent ................................................................ 5-65
ground time overcurrent ................................................................................ 5-64
installation ...................................................................................................... 5-20
installing the setpoint access jumper ............................................................. 1-7
line undervoltage ........................................................................................... 5-84
loading from a file .......................................................................................... 4-28
manual close blocking ................................................................................. 5-129
message summary ........................................................................................... 5-1
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750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER I: INDEX
miscellaneous functions ................................................................................ 5-36
negative sequence directional ...................................................................... 5-79
negative sequence instantaneous overcurrent ............................................ 5-78
negative sequence time overcurrent ............................................................ 5-77
negative sequence voltage ............................................................................ 5-81
neutral current ................................................................................................ 5-95
neutral directional .......................................................................................... 5-61
neutral displacement ...................................................................................... 5-86
neutral instantaneous overcurrent ................................................................ 5-60
neutral overcurrent ......................................................................................... 5-58
neutral time overcurrent ................................................................................ 5-59
numerical ..........................................................................................................1-8
output relays ................................................................................................. 5-170
overfrequency ............................................................................................... 5-113
overvoltage ..................................................................................................... 5-85
passcode ...........................................................................................................5-9
phase current ................................................................................................. 5-94
phase directional ............................................................................................ 5-54
phase instantaneous overcurrent ................................................................. 5-53
phase time overcurrent .................................................................................. 5-51
pickup test .................................................................................................... 5-171
port setup ..........................................................................................................5-9
postfault values ............................................................................................ 5-176
power factor .................................................................................................... 5-95
power system ................................................................................................. 5-23
prefault values .............................................................................................. 5-175
pulse output .................................................................................................. 5-121
reactive power demand ............................................................................... 5-103
reading logic diagrams ....................................................................................5-8
real power demand ...................................................................................... 5-102
reclosure shots ............................................................................................. 5-167
restricted earth fault ....................................................................................... 5-73
saving to a file ................................................................................................ 4-29
scheme setup ............................................................................................... 5-159
sensitive ground current ................................................................................ 5-68
sensitive ground directional .......................................................................... 5-71
sensitive ground instantaneous overcurrent ................................................ 5-70
sensitive ground time overcurrent ................................................................ 5-69
setpoint groups ............................................................................................. 5-123
simulation ..................................................................................................... 5-172
structure ............................................................................................................5-6
synchrocheck ................................................................................................ 5-127
text .................................................................................................................. 1-14
trace memory .................................................................................................. 5-15
transfer functions ........................................................................................... 5-35
transfer scheme ........................................................................................... 5-136
trip counter ................................................................................................... 5-114
underfrequency .............................................................................................. 5-88
underfrequency restoration ......................................................................... 5-134
undervoltage restoration .............................................................................. 5-133
user input functions ....................................................................................... 5-31
user text messages ........................................................................................ 5-19
VT failure ...................................................................................................... 5-119
SETPOINTS MESSAGES ......................................................................................5-1
SIGNAL PROCESSING OF AC CURRENT INPUTS .............................................2-6
SIMULATION
setpoints ....................................................................................................... 5-172
setup ............................................................................................................. 5-174
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
15
CHAPTER I: INDEX
SOFTWARE
entering setpoints .......................................................................................... 4-22
hardware requirements .................................................................................. 4-12
installation ...................................................................................................... 4-14
loading setpoints ............................................................................................ 4-28
overview .......................................................................................................... 4-12
saving setpoints ............................................................................................. 4-29
serial communications .......................................................................... 4-17 , 4-19
SOLID STATE TRIP OUTPUT
see SCR OUTPUT
SPECIFICATIONS
clock ................................................................................................................ 2-21
communications ............................................................................................. 2-20
control ............................................................................................................. 2-18
inputs .............................................................................................................. 2-11
measured parameters .................................................................................... 2-12
monitoring elements ...................................................................................... 2-17
outputs ............................................................................................................ 2-20
physical ........................................................................................................... 2-21
protection elements ....................................................................................... 2-14
technical ......................................................................................................... 2-11
STABILIZING RESISTOR
calculating values .......................................................................................... 5-75
restricted earth fault ...................................................................................... 5-74
STATUS INDICATORS .................................................................................. 4-2 , 4-3
SUBNET IP MASK ............................................................................................. 5-12
SUMMARY OF FEATURES .................................................................................. 2-4
SUPERVISION
close coil ......................................................................................................... 3-15
trip coil ............................................................................................................ 3-15
SYNCHROCHECK
control scheme ............................................................................................... 7-62
logic diagram ................................................................................................ 5-128
setpoints ....................................................................................................... 5-127
SYNCHRONIZING VOLTAGE ............................................................................ 6-14
SYSTEM FREQUENCY ....................................................................................... 5-23
T
TECHNICAL SPECIFICATIONS ......................................................................... 2-11
TECHNICAL SUPPORT ACTUAL VALUES ........................................................ 6-25
TERMINAL ASSIGNMENTS ................................................................................. 3-8
TERMINAL LAYOUT ............................................................................................ 3-8
TEST EQUIPMENT ............................................................................................... 7-3
TESTING
analog outputs .............................................................................................. 5-171
breaker failure ................................................................................................ 7-49
bus undervoltage ........................................................................................... 7-39
requirements .................................................................................................... 7-2
safety precautions ............................................................................................ 7-1
setup ................................................................................................................. 7-4
simulation ..................................................................................................... 5-172
specifications ................................................................................................. 2-22
test equipment .................................................................................................. 7-3
wiring diagrams ......................................................................................... 7-4 , 7-5
TEXT SETPOINTS .............................................................................................. 1-14
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750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
CHAPTER I: INDEX
THEORY OF OPERATION ....................................................................................2-5
THERMAL DEMAND CHARACTERISTIC ......................................................... 5-100
THRESHOLD, ANALOG ................................................................................... 5-107
TIME OVERCURRENT CURVES
see TOC CURVES and individual TOC curves indexed alphabetically
TOC CURVES
ANSI ................................................................................................................ 5-46
characteristics ................................................................................................ 5-44
definite time .................................................................................................... 5-45
IAC .................................................................................................................. 5-48
IEC .................................................................................................................. 5-47
TRACE MEMORY
setpoints ......................................................................................................... 5-15
TRANSFER FUNCTIONS SETPOINTS ............................................................... 5-35
TRANSFER SCHEME
associated elements .................................................................................... 5-143
bus tie breaker DC schematic ..................................................................... 5-149
bus tie breaker logic .................................................................................... 5-152
description ...................................................................................................... 7-75
incomer 1 DC schematic ............................................................................. 5-147
incomer 1 logic diagram .............................................................................. 5-150
incomer 2 DC schematic ............................................................................. 5-148
incomer 2 logic diagram .............................................................................. 5-151
one line diagram .......................................................................................... 5-146
setpoints ....................................................................................................... 5-136
TRANSFORMER POLARITY ............................................................................... 3-11
TRANSIENTS .......................................................................................................2-6
TRIP COIL MONITORING .................................................................................. 7-57
TRIP COIL SUPERVISION
connection diagram ........................................................................................ 3-16
description ...................................................................................................... 3-15
TRIP COUNTER
actual values .................................................................................................. 6-18
logic diagram ................................................................................................ 5-115
setpoints ....................................................................................................... 5-114
TRIP DATA
last trip data ......................................................................................................6-7
TRIP TIMES USER TABLE .................................................................................. 5-24
TYPICAL WIRING
description ........................................................................................................3-7
diagram ........................................................................................................... 3-10
U
UNDERFREQUENCY
logic diagram .................................................................................................. 5-89
protection scheme .......................................................................................... 7-45
restoration .................................................................................................... 5-134
setpoints ......................................................................................................... 5-88
UNDERFREQUENCY RESTORATION
control scheme ............................................................................................... 7-74
logic diagram ................................................................................................ 5-135
setpoints ....................................................................................................... 5-134
UNDERVOLTAGE
inverse time curves ........................................................................................ 5-83
inverse time delay characteristics ................................................................ 5-82
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
17
CHAPTER I: INDEX
line .................................................................................................................. 5-84
protection elements ....................................................................................... 5-82
restoration .................................................................................................... 5-133
UNDERVOLTAGE INVERSE TIME DELAY ......................................................... 5-82
UNDERVOLTAGE RESTORATION
control scheme ............................................................................................... 7-70
logic diagram ................................................................................................ 5-134
setpoints ....................................................................................................... 5-133
UNPACKING THE RELAY .................................................................................... 1-1
UPGRADING FIRMWARE ................................................................................. 4-29
USER INPUT FUNCTIONS SETPOINTS ............................................................ 5-31
USER TEXT MESSAGES
adding ............................................................................................................. 5-19
setpoints ......................................................................................................... 5-19
V
VARHOURS MEASUREMENT ........................................................................... 7-19
VIRTUAL INPUTS
actual values .................................................................................................... 6-6
testing ............................................................................................................. 7-14
tests .................................................................................................................. 7-6
VOLTAGE
actual values .................................................................................................. 6-12
negative sequence ......................................................................................... 5-81
synchronizing ................................................................................................. 6-14
VOLTAGE TRANSFORMER
AC inputs ........................................................................................................ 3-13
bus VT sensing ..................................................................................... 5-22 , 5-23
failure ................................................................................................... 5-119, 7-56
line connections ............................................................................................. 3-14
setting example .............................................................................................. 1-23
VT FAILURE
logic diagram ................................................................................................ 5-120
monitoring ....................................................................................................... 7-56
setpoints ....................................................................................................... 5-119
VTs
see VOLTAGE TRANSFORMER
W
WARRANTY ....................................................................................................... 8-11
WATTHOURS MEASUREMENT ......................................................................... 7-18
WAVEFORM CAPTURE
description ........................................................................................................ 2-5
WET CONTACT CONNECTIONS ....................................................................... 3-17
Z
ZERO SEQUENCE CT INSTALLATION .............................................................. 3-13
18
750 FEEDER MANAGEMENT RELAY – INSTRUCTION MANUAL
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