sr-750 ge multilin feeder protection commissioning course

Electrical Industry Training CentreSR-750 GE Multilin Feeder Protection Commissioning Course

Table of Content

Headings Page

Introduction1 Getting Started1.1 Initial Inspection1.2 Using The Relay1.2.1 Menu Navigation1.2.2 Sub-Menu1.3 Settings and Setpoints1.3.1 Numerical Setpoint1.3.2 Enumeration Setpoint

Lab 1: SR-750 Interface Panel Setpoint Change

1.4 Enervista1.4.1 Introduction to EnerVista Setup

Lab 2: Installing EnerVistaLab 3: Communicating to the SR-750 via RS-232.

1.5 Relay In Service

2 Theory of Operation2.1 On Board Micro-processors2.2 Waveform Capture2.3 Frequency Tracking2.4 (reserved for future)2.5 (reserved for future)2.6 Protection Elements2.7 Logic Inputs2.8 Outputs2.9 Communication Ports

3 Installation3.1 Mechanical (reserved for future)3.2 Withdrawal and Insertion3.3 Rear Terminal Lay-out3.4 Electrical Installation

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Table of Content

Headings Page

3.4.1 CT3.4.2 VT3.4.3 Ground CT3.4.4 Sensitive Ground CT3.4.5 Grounding3.4.6 Control Power3.4.7 Breaker Control3.4.8 Coil Supervision (reserved for future)3.4.9 Analog Inputs (reserved for future)3.4.10 Analog Outputs (reserved for future)3.4.11 Rear Communication ports3.4.12 Front Communication port3.4.13 IRIG-B port

4 Interface4.1 Front Panel Interface4.1.1 LCD Display Screen4.1.2 LED Indicators4.2 Messages4.2.1 Keypad Messages4.2.2 Diagnostic Messages4.2.3 Self-Test Warning4.2.4 Flash Messages4.3 EnerVista Software4.4 Communication Ports

Lab 4:Communicating With EnerVista

5 Setpoints5.1 S1 Relay Setup (reserved for future)5.2 S2 System Setup5.3 S3 Logic Inputs5.4 S4 Output Relays5.4.1 Trip Relay5.4.2 Close Relay

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Table of Content

Headings Page

5.4.3 Auxiliary Relays5.4.4 Self-Test Warning Relay (reserved for future)5.5 S5 Protection5.5.1 Time Overcurrent Characteristics5.5.2 Phase Time Overcurrent5.5.3 Phase Instantaneous Overcurrent5.5.4 Directional Supervision5.6 Neutral Overcurrent5.7 Ground Overcurrent5.8 Sensitive Ground Overcurent5.9 Negative Sequence Overcurrent5.10 Voltage5.11 Frequency5.12 Breaker Failure6 Commissioning6.1 Installation Checks6.2 Metering Test6.3 Logic Input Test6.4 Output Test6.5 Phase Time Overcurrent Pickup test6.5.1 Phase Time Overcurrent Timing test6.5.2 Phase Instantaneous Pick-up test:6.5.3 Phase Directional MTA test:6.5.4 Phase Directional Min Polarizing Voltage test:6.5.5 Phase Time OC Voltage Restraint Test:6.6 Negative Sequence Time OC Pickup Test:6.6.1 Negative Sequence Time OC Timing test:6.6.2 Negative Sequence Directional test:6.6.3 Negative Sequence Instant OC Pick-up test:6.7 Bus Undervoltage Pickup test:6.7.1 Bus Undervoltage Timing test:

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Table of Content

Headings Page

6.8 UnderFrequency Pickup Test:6.8.1 UnderFrequency Timing Test:6.8.2 Underfrequency Min Operating Voltage test:6.8.3 Underfrequency Minimum Operating Current6.9 Breaker failure Timing Test:6.10 Breaker Failure Minimum Current Test:

End of session

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Introduction:This course will describe the features of the SR-750 Feeder Management Relay, the external front panel interface screen, key pads, LED indicators and the rear terminal connections. A brief look at the internal hardware configuration, an analysis of the protection logic and its setpoint setting is required for establishing the variables needed for testing the protection elements.

The Enervista software will be used to communicate with the relay, for entering the relay settings, performing status checks and an aid in testing of the relay. An exercise on the front panel operation will demonstrate the operator interface features which can be use as a tool for monitoring and testing purposes.

1. Getting StartedCompile all the required material for testing

• Communication: Computer laptop, Enervista program, relay setting file or setting sheets and USB to serial adapter cable.

• Drawings: Complete set of schematics and wiring diagrams, SR-750 logic diagrams as found in the manual or the relay manual.

• Equipment: 3-phase test set, test leads, multi-meter and standard hand tools.• Special hardware: Breaker simulator unit.

1.1. Initial Inspection.For relay out of the box:

• Inspect the unit for physical damage• Verify that the correct model has been ordered

For installed relay:• Verify order code matches the drawing or bill of material list• Verify power supply polarity is connected correctly• Verify control circuit wiring• Verify CT / VT polarity connections

• Verify CT / VT secondary ratings match the current and voltage input ratings

1.2 Using the RelayThe front panel is provided with a two-line, 40 character display screen, associated numeric keypad, push buttons and cursor control keys which can be used for setpoint programming, metering and data access. Information and access control is accomplished by the MENU button and the four MESSAGE ↑→↓← buttons for

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navigation. Only the arrow symbols (↑→↓←) will be used in this document to represent the four MESSAGE buttons.

On earlier version, the relay was provided with a SETPOINT and ACTUAL button instead of the MENU button plus and ↑↓ buttons for navigation.

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1.2.1 Menu NavigationThe top layer of information is the menu screen. There are 3 menu screens.

• Setpoints• Actual values• Target Messages

The menus screens can be displayed by pressing the MENU key. Movement to the other screens is achieved by pressing the ↓↑ buttons.

1.2.2 Sub-Menu:The sub-menu contains the page headers within the menu. Sub-menu contains relay setting pages that have been grouped together for functionality or functions under a sub-menu.

Sub-menu levels are entered by pressing the → button for the active MENU screen.

• Once inside the sub-menu, Page Headers are access by pressing the ↓↑ buttons.

• The top page is Page 1.• The very bottom is indicated by END OF PAGE n.• To exit a sub-menu or go back to the menu screen, use the ← button.• When a square box ■ and → appears on the screen, it indicates sub-pages to

the current page. Pressing the → key will enter the lower level screen.- Lower level screens can be access by the ↓↑ buttons.- To exit a sub-page and return to the sub-menu, Use the ← button

On earlier version, the sub-menu was scrolled through by pressing the ACTUAL or SETPOINT button repeated. Entering the sub-menu was done by pressing the ENTER key.

Pressing the HELP key will display context related information such as range of values and ways of changing the setpoint. Pressing the HELP key repeatedly will scroll through all the related information for the setpoint.

Note:→ button use to enter a lower level screen← button to enter a higher level screen↓↑ buttons to scroll through the various screens on any level

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Setpoint Sub-menu:Setpoints are programmable setting entered by the user. These settings are used by the various protection or control elements to define its operating characteristics.

See appendix for a listing of the various setpoint sub-menus and its respective setting pages. Actual value sub-menu:Actual values are active data that are being used by the relay or historical data that are stored in memory. These include:

• Status of logic inputs (both virtual and hardware), last trip information, fault location, relay date and time.

• Metering values such as current, voltage, frequency, power, energy, demand and analog inputs.

• Maintenance Data such as trip counters and accumulated arcing currents.• Event recorder down loading tool.• Product information including model number, firmware version, product

information and calibration dates.• Oscillograph data and down loading tool• List of active conditions.

Message sub-menu:Target messages show the active conditions for alarms, trip conditions, diagnostics and system flash messages.

1.3 Setting and SetpointSetpoint is a setting that is displayed in a sub-menu. Each setpoint is distinguished by the way their values are displayed and edited. Setpoint can be numerical or an enumeration variable.

The settings are arranged in pages with each page containing its related settings associated with its functions.

Settings fall into the following categories:• Device settings• Relay / System settings• Logic input settings• Output relay settings

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• Protection settings• Control settings• Testing settings

CAUTION: Entered settings are stored and immediately used by the relay. Caution is warranted when entering any setting when the relay is active and the breaker is Close. A setting within the operating limits of the relay will trip the relay and initiate breaker tripping and other functions.

Data that are entered in the setting page are called setpoint.There are 2 types of setpoint:

• Numerical setpoint• Enumeration setpoint

1.3.1 Numerical Setpoint• Numerical setpoints has its own minimum and maximum value within

allowable increments. Entered values that exceeds the setpoint accuracy will be rounded-off.

• Numerical setpoints can be entered via the numerical keypad and pressing ENTER or by using the VALUE ↑↓ button to the desired value and then pressing ENTER.

• Pressing the ESCAPE key before the ENTER key will return the original value to the display.

1.3.2 Enumeration SetpointEnumeration setpoints are data sets whose variables that are defined by a name. A data set will contains two or more variable names.Example: Wye, Delta

Disable, alarm, trip or control.

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Lab 1: Setpoint Entry via The Interface Panel

This lab is an introduction for operating the interface panel.

NOTE:A hardware jumper between rear terminals C10 – C11 must be installed to allow setpoint via the interface panel. This provision has been made available through the key switch on the relay trainer unit. Turn the key switch to the ON position.

1. System Setup Setpoint Entry

Refer to Table 1: S2 System Setup

• Press the SETPOINT button until the S2 System Setup page header is displayed

• Press ↑↓ MESSAGE to display the various setting pages• Press ENTER for access to the desired setting page• Press ↑↓ MESSAGE to display the various setpoint within the setting page• Press ↑↓ VALUE to change the setpoint value or the numeric keypad.

Press ENTER to accept or ESCAPE to abort• Enter all S2 System Setup setpoint values via the interface panel• NEW SETPOINT HAS BEEN STORED Flash Message will appear when a

new value has been entered• Enter all S2 System Setup setpoint values as shown on Table 1.

Note: Make use of the HELP key once a setpoint is displayed.

2. Breaker Function setpoints Entry

Refer to Table 4: S3 Breaker Function• Press the SETPOINT button until the S3 Logic Input Setup page header is

displayed• Enter all S3 Breaker Function setpoint values via the interface panel• NEW SETPOINT HAS BEEN STORED Flash Message will appear when a

new value has been entered• Enter all S3 Breaker Function setpoint values as shown on Table 4.

3. End of Lab 1.

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1.4 Enervista

1.4.1 Introduction to EnerVista SetupEnerVista is a graphical user interface software for communicating with the GE Multilin realys. It provides a single platform to configure, monitor, maintain, and trouble-shoot relay operations via serial communication. EnerVista can be used in on-line or off-line mode. Settings files can be created in off-line mode for downloading to the relay. Communication in on-line mode is performed in real-time.

Major operations using Enervista are:• 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• Trip and Close breaker

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Lab 2: Installing EnerVista

This lab will prepare the laptop for the EnerVista software and how to download specific relays’ IED set-up files.

1. Check for Hardware minimum requirements.• P3 1 GHz or higher processor• Microsoft Windows 2000, XP• Internet Explorer version 5.5 or higher• 256 Mb of RAM (512 Mb recommended)• Minimum of 200 Mb hard disk space• Video capable of displaying 800x600 or higher in 16-bit Colour• RS-232 and/or Ethernet communication port to Relay

2. Install the EnerVista 750 Setup software from GE EnerVista CD.• Insert the GE EnerVista CD into your CD-ROM drive.• Click the Install Now button and follow the installation instructions to

install the no-charge EnerVista software on the local PC.• When installation is complete, start the EnerVista Launchpad application.• Click the IED Setup section of the Launch Pad window.

3. Add new Hardware for the IED set-up program for the SR-750 Relay

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• EnerVista Launchpad will obtain the latest installation software from the internet and start the installation process. A status window with a progress bar will be shown during the downloading process

• Select the complete path, including the new directory name, where the EnerVista 750 Setup software will be installed.

• 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 Setup software to the Windows start menu.

• Click Finish to end the installation. The 750 device will be added to the list of installed IEDs in the EnerVista Launchpad window,

4. Once installation is complete communication with the relay can be establish.

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5. Add the SR-750 Feeder Management relay manual to the Document Library section.

• From the launch pad, select the Document Library• On the Document Library screen, d-click the Manuals icon• Select Add/Edit Products• Check off the

- *750 Feeder Management Relay under the Select Product to Add- Manuals under the Document file type

• When downloading is complete 750 will appear on the Manual directory and a copy of the SR-750 manual in PDF format is displayed on the File Title page.

• D-click on 750/760 Instruction manual to open up the manual.

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6. End of Lab 2.

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Lab Task 3: Communicating to the SR-750 via RS-232.

This lab will provide the skills for initializing communication with the SR-750 via the front panel RS-232 port.

Communication with the relay can be accomplished in three ways: RS232, RS485, and Ethernet communications.

Note: Only RS-232 communication process will be shown in this lab.

1. Obtain the serial port communication parameters from the front panel.

The Communication setting page is under the S1 Relay Setup sub-menu page.

Note:The Enervista serial communication settings must be set to the relay settings. A mismatch of settings will prevent access to the relay.

Copy the setpoints from the S1 relay Set-up page:Slave Address: __________Baud Rate: __________Parity: __________Bits: __________

2. Connect the USB to Serial cable adapter to the laptop. Ensure that the computer recognize the new hardware and determine the COM port designation for the USB port location.

• Got to start button• Select Control Panel• D-click System• Select Hardware, Device Manager• Open Ports (COM and LPT) and check that the USB-to-Serial Comm Port is

recognized• Make a note of the port number

COM __________

3. Configuring Serial Communication• Open Enervista launchpad• Select IED (Intelligent External Device) Setup

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• Select the SR750/760 relay type• Select Device Setup• Select Add Site; A New Site 1 dialog box will appear

Enter EITCA on the site name field, enter OK

A new site location, EITCA will be generated on the On-line Device Setup screen on the top left directory structure.

• Select Device Setup; A Device Setup screen will appear• Select the site location; EITCA• Select Add Device; A Device Name dialog box will appear• Enter a Device name for the new device “SR-750-EITCA”• Select Serial on the Interface option menu; a communication screen will

appear• Enter the Slave Address and Baud Rate on the communication screen

Leave all other default parameter as found; Parity, Bits and Stop Bits• Select the Read Order Code button• A new SR-750EITCA device file name will appear on the on-line and off-

line directory tree

Note: If communication is successful, the relay order code number and firmware version number will be displayed. If communication fails, review the computer serial communication settings and retry.

• Select OK

Successful communication status should be displayed on the bottom left

• When communication has been established give yourself a pat on the back ! The hardest part of testing is to first establish communication with the relay.

4. End of Lab 3

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1.5 Relay In ServiceThe SR-750 Operations is defaulted to the NOT READY state from the factory. During the initial energization, the SELF TEST WARNING – relay not ready status will be displayed on the interface panel.

To place the SR-750 Operation into the READY state, use the indicated front panel key punch sequence to change the setting from NOT READY to READY in the Installation setting page in the S1 Relay Setup sub-menu under the Setting menu.

S1 RELAY SETUP →↓ INSTALLATION → 750 OPERATION→ VALUE ↑ READY press ENTER

The RELAY IN SERVICE indication should be ON.

SELF TEST WARNING indication should be OFF.

The relay is ready for service.

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Figure 1: Hardware Block Diagram

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2 Theory of Operation

2.1 On Board Micro-processorsCircuit functions are controlled by two Motorola 68332 – 32 bit μpmeasures all analog signals, digital inputs and control all output relays. Operator’s front panel key pads, LCD screen display, LED indications and RS-232 serial communication is controlled by DSTni-LX Turbo 186 16-bit μp which pass information to each other via RS485 serial communication bus.

2.2 Waveform CaptureCTs and VTs secondary terminals are connected to the AC input terminals where internal isolating transformers scale down the values to printed circuit board levels. The low level AC signal is passed through a 400 Hz low pass anti-aliasing filter.

The resulting AC signals are simultaneously captured by sample and hold buffers which ensure that no phases shift are introduced from sampling time delays. The 12 bit A/D converter send the digital values to the M-68332 – 32 bit μp for analysis.

AC waveforms are sampled with a asampling rate of 16 time per cycle. Raw samples are scaled in software, placed in the waveform capture buffer emulating a fault recorder.

Current waveforms are processed twice every cycle with a DC offset filter and a Discrete Fourier Transform algorithm which produces phasor values at the fundamental frequency. The resulting phasor is without transients and harmonics resulting in a relay that will not overreach

Figure: Effects of DC offset filter to Asymmetrical current signal

The DC Offset filter removes the DC component from the assymerical current at the moment a fault occurs. This is done for all current signals used for overcurrent protection. The filter introduces an over all time delay between (0 to 50 ms) for

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fault marginally over the pick-up level. Voltage signals are not processed by the DC Offset filter.

The Fast Fourier Transform algorithm uses exactly one cycle of samples to calculate the fundamental phasor quantities. The RMS current and voltage phasor values are used in calculating the all metering and energy demand resulting in values without harmonic content.

The Protection elements are processed once per power cycle to determine if a pickup has occurred or a timer has expired. Protection elements use RMS phasor values and unaffected by harmonics and DC transients.

2.3 Frequency trackingSystem frequency is measured by the zero crossing of both Bus VT A and Line VT voltage inputs. Frequency tracking utilize the measured frequency to set the sampling rate for the AC input signals.

From the low pass anti-aliasing filter, voltage signals are pass through a 72 Hz low pass filter. Frequency reading is discarded if the rate of change ΔF/sec is > 10 Hz/sec. Sampling is synchronized to the Van zero voltage crossing.

2.4 Analog Inputs (Reserved for future)

2.5 Analog Outputs (Reserved for future)

2.6 Protection ElementsAll protection elements are processed once every cycle to ascertain if a pick-up or a time delay setpoint has expired.

The elements use the RMS phasor values making the elements unaffected by harmonics and DC transients. The phase and ground current inputs are calculated once per quarter cycle for its RMS phasor values for the all Phase and Ground Overcurrent elements

The time delay functions use an independent time base frequency making the timers unaffected by the system frequency.

The tripping times of the overcurrent elements can vary by ± 4 ms from the mean time. This is due to the process time for the RMS phasor calculations which require 4 samples of information from the point of sampling within the AC waveform

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cycle. Operating time can differ by 8 ms between the slowest and the fastest time over the total operating range.

Figure: Instantaneous Overcurrent element operating time

2.7 Logic InputsContact inputs are de-bounced and must be stable for 3 input samples before a change of state is recognize; samples are performed at 16 times per power cycle. Contact inputs are fed to opto-isolator circuits for isolation between the external circuit and the internal circuitry.

2.8 OutputsAll relay outputs are opto-isolated. Eight dry contacts are provided for relay operation. Breaker trip and close output contacts are form-a, the remaining 6 auxiliary output contacts are form-c comprising of an “a” and “b” contact with a common.

2.9 Communication PortsSerial communication ports are opto-isolated; COM1, COM2, RS-232 and IRIG-B input.

Ethernet port are not opto-isolated.

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3. Installation:

3.1 Mechanical Installation (reserved for future)

3.2 Withdrawal and InsertionThe relay can be safely removed or inserted to its case. the case configuration pin will prevent full insertion if an incorrect relay is inserted into a different case.

CT shorting terminal connections allows safe removal of the relay from an energized panel. Minute amount of electrical contact lubricant should be applied sparingly on all mating surfaces since removal and insertion period may be long.

Note:Before removing an active relay from its case perform the following:

• Check the output settings via the front panel ↑←→↓ keys. • Ensure that auxiliary output (relay 3 to 7) NON-OPERATED STATE

setpoint is NOT set to the Energized value.• Outputs set to be Energized in the Non-operated State should be blocked

before the relay is removed from its case. This can prevent undesirable events from occurring since the relay contacts will change state once power is removed.

• Check the rear terminal connections for wiring connected to the “b” contact. Table below identifies the NC contact terminals.

E5 - F4 3 AUXILIARY RELAY NCE6 - F6 4 AUXILIARY RELAY NCE7 - F7 5 AUXILIARY RELAY NCE9 - F9 6 AUXILIARY RELAY NCE10 - F10 7 AUXILIARY RELAY NC

Note:Turn off the power before removing or re-inserting the relay from its case. The Self Test Alarm relay will de-energize and “alarm” if connected to the alarm scheme.

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3.3 Rear Terminal Layout

Figure: SR-750 Rear Terminal View

Table: 13 Group A & B Terminal AssignmentANALOG INPUT / OUTPUTS COMMUNICATIONA1 ANALOG INPUT + B1 COM 1 RS485 +A2 ANALOG INPUT - B2 COM 1 RS485 -A3 SHIELD (GROUND) B3 COM 1 RS485 COMA4 ANALOG OUTPUT - B4 COM1 RS422 TX +A5 ANALOG OUTPUT 1 + B5 COM1 RS422 TX -

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A6 ANALOG OUTPUT 2 + B6 COM 2 RS485 +A7 ANALOG OUTPUT 3 + B7 COM 2 RS485 -A8 ANALOG OUTPUT 4 + B8 COM 2 RS485 COMA9 ANALOG OUTPUT 5 + B9 SHIELD (GROUND)A10 ANALOG OUTPUT 6 + B10 IRIG-B +A11 ANALOG OUTPUT 7 + B11 IRIG-B -A12 ANALOG OUTPUT 8 + B12 RESERVED

Table: 14 Group C & D Terminal AssignmentLOGIC INPUTS LOGIC INPUTSC1 LOGIC INPUT 1 D1 LOGIC INPUT 8C2 LOGIC INPUT 2 D2 LOGIC INPUT 9C3 LOGIC INPUT 3 D3 LOGIC INPUT 10C4 LOGIC INPUT 4 D4 LOGIC INPUT 11C5 LOGIC INPUT 5 D5 LOGIC INPUT 12C6 LOGIC INPUT 6 D6 LOGIC INPUT 13C7 LOGIC INPUT 7 D7 LOGIC INPUT 14C8 RESERVED D8 RESERVEDC9 RESERVED D9 RESERVEDC10 SETPOINT ACCESS - D10 RESERVEDC11 SETPOINT ACCESS + D11 RESERVEDC12 +32 VDC D12 DC NEGATIVE

Table: 15 Group E & F Terminal AssignmentOUTPUT RELAYS OUTPUT RELAYSE1 SOLID STATE TRIP OUT + F1 SOLID STATE TRIP OUT -E2 1 TRIP RELAY NO F2 1 TRIP RELAY COME3 2 CLOSE RELAY NO F3 2 CLOSE RELAY COME4 3 AUXILIARY RELAY NO F4 3 AUXILIARY RELAY COME5 3 AUXILIARY RELAY NC F5 4 AUXILIARY RELAY NOE6 4 AUXILIARY RELAY NC F6 4 AUXILIARY RELAY COME7 5 AUXILIARY RELAY NC F7 5 AUXILIARY RELAY COME8 5 AUXILIARY RELAY NO F8 6 AUXILIARY RELAY NOE9 6 AUXILIARY RELAY NC F9 6 AUXILIARY RELAY COME10 7 AUXILIARY RELAY NC F10 7 AUXILIARY RELAY COME11 7AUXILIARY RELAY NO F11 8 SELF-TEST WARNING RELAY NOE12 8 SELF-RESET WARNING RELAY NC F12 8 SELF-TEST WARNING RELAY COM

Table: 16 Group G & H Terminal AssignmentCV AND VT INPUTS / GROUND OUTPUT RELAYSG1 COIL MONITOR 1 + H1 COIL MONITOR 1 -G2 COIL MONITOR 2 - H2 COIL MONITOR 2 +G3 SENSITIVE GROUND CT n H3 SENSITIVE GROUND CTG4 SYNCHRO VT n (LINE) H4 SYNCHRO VT (LINE)G5 PHASE A VT n (BUS) H5 PHASE B VT n (BUS)G6 PHASE C VT n (BUS) H6 PHASE VT NEUTRAL (BUS)G7 PHASE A CT n H7 PHASE A CTG8 PHASE B CT n H8 PHASE B CTG9 PHASE C CT n H9 PHASE C CTG10 GROUND CT n H10 GROUND CTG11 FILTER GROUND H11 CONTROL POWER –G12 SAFETY GROUND H12 CONTROL POWER +

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3.4 Electrical Installation:

3.4.1 CTFor the relay to work properly correct phasing of the CTs and VTs are necessary. Polarity connections affect polarity sensitive functions such as metering, restricted earth fault protection and directional elements.

Caution:Verify nominal CT secondary rating matches the relay nameplate rating.Ensure that 1A CT inputs are not connected to 5A secondary rated CTs.

3.4.2 VTVT’s can be connected either wye or delta. The more common connections are wye connected bus VT’s used for voltage or distance control of the bus overcurrent protection. These VTs can also be used for the feeder directional elements.

Figure: SR-750 with wye connected bus VTs

Delta connected VT’s require the use of jumpers between terminals H5 – H6 since the internal isolation transformers are connected in a wye configuration.

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Figure: SR-750 with delta connected bus VTs

3.4.3 Ground CTGround CT input can be sourced from the transformer neutral CT, a zero sequence CT or the summing point for the phase wye connected phase CT’s. The GROUND CT input can be used to polarized the neutral and sensitive ground directional elements.

Figure: Ground CT Input Connection options

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3.4.4 Sensitive Ground CTSensitive Ground protection is for use on high impedance grounded system or on ungrounded system. In both cases the sensitive ground fault current or the residual current should be limited to 100X the input rating for 1 second or 500A for 1 second for 5A input rating.

The Sensitive ground current input can be connected to a zero sequence CT for increased sensitivity. On ungrounded system it is connected residually with the phase current inputs.

Figure: Sensitive Ground CT Input Connection options

For applications where there are no transformer differential protection, the sensitive ground current input can be used for use as a transformer restricted earth fault protection scheme. A stabilizing resistor is required to increases the relay impedance value and aids in preventing differential current from flowing into the relay input terminals during saturated CT condition on external faults. The added impedance will aid the current to flow in the saturated CT and not into the relay for external faults. For internal faults, the relay will operate positively.

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Figure: Sensitive Ground CT Input for Restricted Earth Fault Connection

3.4.5 GroundingAll ground terminals must be connected regardless of power supply type.

Figure: SR-750 Grounding connections

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3.4.6 Control PowerControl power must be within the range of the relay power supply input rating.

LO Range: 20 – 60 Vdc20 – 48 Vac at 48 – 62 Hz

HI range: 88 – 300 Vdc88 – 265 Vac at 48 – 62 Hz

Caution:Connection of a relay with a low voltage power supply rating to a high voltage source will damage its power supply unit.

Caution:DC voltage polarities must be connected to its respective positive and negative terminals or damage to the internal power supply unit can occur.

3.4.7 Breaker controlThe relay can be used for local and remote control of the breaker. Ensure that the 1 Trip Relay and 2 Close Relay output contacts are connected properly including the trip coil monitors. The breaker 52a and 52b auxiliary contacts should be connected for the breaker status indications and other function such as breaker failure.

Contact InputsFourteen external contacts can be connected to the relay’s fourteen digital inputs in a wet or dry configuration.

• A wet contact uses an external DC power supply with a switched positive logic input with the negative power supply connected to the Contact Input Common terminal. Maximum input voltage is 300Vdc.

• A dry contact has one side connected to the internal power supply positive at terminal C12 and the other side connected to the logic input terminal.

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Figure: Logic Input Connection Diagram

3.4.8 Coil Supervision (reserved for future)

3.4.9 Analog Outputs (reserved for future)

3.4.10 Analog Outputs (reserved for future)

3.4.11 Rear Communication portsTwo rear communication ports are provided for SCADA supporting AEG Modicon protocol and Harris DNP protocol

Com1 can operate in RS485 or RS422 modeCom2 operate in RS422 mode onlyEthernet option replaces RS485 Com1 port

3.4.12 Front Communication portThe front panel RS-232 serial port is used for setpoint programming relay and firmware up-grade. Front panel access can be made with the EnerVista setup software. Firmware upgrade must use relay address 1 and baud rate of 9600

3.4.13 IRIG-B portRelay can be synchronized with a time code input for time stamping events to 1ms resolution. The IRIG-B input uses a military satellite time based signal.

4: Interface

4.1 Front Panel InterfaceThe front panel provide local operator interface

• LCD display screen

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• LED status indicator• Control keys; Selecting message for entering set-points or displaying

measured values• RS-232 programming port

4.1.1 LCD screenThe LCD display screen display messages in alpha numeric characters

• 40 characters, 2 lines LCD screen• 30 user-defined default messages• Immediate display for any trip, alarm or start block events

4.1.2 LED IndicatorsThe LED indicators are group into 3 columns / functions

• SR-750 Status indicates the state of the relayRelay in Service

Trip Alarm Pickup

Setpoint Group 1 to 4 (indicates active group)• System Status indicates the state of the breaker and the system

Breaker OpenBreaker ClosedLocalMessage

• Output Status indicates the state of the output relays1 Trip2 Close3 to 7 Auxiliary8 self Test Warning

Three illuminating colour gives functionalityGreen = General conditionAmber = Alert conditionRed = Serious Alarm or Important status

4.2 Relay MessagesThe relay communicates by displaying information on the LCD screen in addition to the LED indicators. These messages can range from acknowledging front panel key presses to metering information that has been programmed by the user or

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displaying relay trip and alarm conditions that is automatically generated when any one of its elements are asserted. In sum, the relay will display relevant information that is appropriate for the situation that is occurring.

4.2.1 Keypad MessagesA message response to keypad operations are made to display the various pages of settings / information stored in the relay, these are organized into Main Menus, Pages and Sub-pages

The three main menus are:• Setpoints• Actual Values• Target Messages

On older version, only the ACTUAL VALUE and the SETPOINT button are available.

Navigation to the sub-pages will show setting information used by the relay and it will be displayed on the LCD screen.

4.2.2 Diagnostic MessagesA flashing MESSAGE LED on the front panel indicates the presence of diagnostic messages. Diagnostic messages are automatically generated in response to any trips, alarms or asserted logic inputs and indicate the various events and relay operations.

Events are stored in a volatile memory and can be viewed by accessing the TARGET MESSAGE menu.

• Press the MENU key until the display shows TARGET MESSAGES• Press MESSAGE → key• Press MESSAGE ↓ to scroll through the messages

1. PICKUP: shows any elements that are presently picked up2. TRIP: shows any elements that has tripped, stays in queue until reset3. ALARM: shows any elements that are in alarm stage, stays in queue

until reset

On older version, only the TARGET MESSAGE menu is not provided. 4.2.3 Self-Test Warnings (see Appendix)

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There are two type of self-test warnings; major or minor.• Minor problems does not compromise protection and characterized by:

Self-Test Warning relay is de-energizedFailure mode is indicated in the diagnostic message queueFailure mode is indicated the Event Recorder

• Major problems compromise all aspects of relay operation and characterized by:

Relay In Service LED is turned OFFOutput relays operations are inhibited

4.2.4 Flash MessagesFlash messages are in response to certain key presses. The message will be displayed temporarily as in a flash. It denotes error or invalid key presses.

4.3 Enervista SoftwareThe Enervista software provides an optional interface to the front panel operation. It requires a computer supporting Microsoft Windows 95 or higher using graphical format for on-line and off-line use. Enervista can configure, monitor and trouble shoot relay operations. Its major functions are:

• Programming / modify set-points on-line or off-line• Load / save setting files from relay to computer and vice versa• Read actual values / monitor status / reset counters & events • Perform waveform capture / log data / download and playback waveforms• Initiate breaker control, trip and close• Get help on any topic• Upgrade firmware

Enervista communicates to the relay via the front panel RS-232 port.

4.4 Communication portsCommunication to relay can be established via RS-232, RS-485/422 or Ethernet port. Communication using modbus protocol, setting an internet address or communication using DNP protocol is beyond the scope of this course. Please refer to the various technical communication guide for detailed information.

Note: Only communication via the front panel RS-232 will be made.

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Lab 4: Communicating with Enervista REDUNDANT to LAB TASK 3

1. Open EnerVista program Select IED (Intelligent External Device) Setup Select the SR750/760 relay type Select Device Setup Select Add Site; A New Site 1 dialog box will appear

Enter EITCA on the site name field, enter OK

A new site location will be generated on the Device menu screen; EITCA

2. Select Device Setup; A Site Name dialog box will appear Select the site location; EITCA Select Add Device; A Device Name dialog box will appear

Enter SR-750 Select Serial on the Interface option menu; a communication screen will appear

Getting correct communication parameterAccess the SR-750 via the front panel for the Slave Address and Baud Rate

S1 RELAY SETUP →↓ COMMUNICATION →↓ PORT SETUP

3. Enter correct Slave Address and Baud Rate on the communication screenLeave all other default parameter as found; Parity, Bits and Stop Bits

Select the Read Order Code button

Note: If communication is successful, the relay order code number and firmware version number will be displayed. If communication fails, review the computer serial communication port setting on the Device Manager screen on the computer.

Select OKSuccessful communication status is displayed on the bottom left

4. End of lab 4.

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5. SetpointSetpoints can be programmed using the EnerVista program. It is a more flexible method for reviewing the setting page instead of operating through the interface panel. The pages in the Setpoint menu can be viewed more quickly using a laptop.

Refer to Appendix for an overview of the menu structure and related setting pages.

At a minimum the S2 SYTEM SETUP settings must be entered for the relay to function correctly.

5.1 S1 RELAY SETUP (reserved for future)

5.2 S2 SYSTEM SETUPThe S2 System Setup contains the settings for the electrical system. There are 3 setting page:

• Sensing page• FlexCurve A• FlexCurve B

Sensing page settings has four setting groups:• Current Sensing• Bus VT Sensing• Line VT Sensing• Power System

Table: 1 S2 System Setup - Sensing page.SETTING PARAMETERCurrent SensingPhase CT Primary 1200 AGround CT Primary 50 ASensitive Ground CT Primary 200 A

Bus VT SensingBus VT Connection Type WyeBus Nominal VT Secondary Voltage 66.4 VBus VT Ratio 120.0 : 1

Line VT SensingLine VT Connection Van

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Line Nominal VT Secondary Voltage 120.0 VLine VT Ratio 120.0 : 1

Power SystemNominal Frequency 60 HzPhase Sequence ABCCost of energy 20.0 cents/kWh

FlexCurve A and B pages contain user defined time current characteristics.

Table: 2 S2 System Setup - FlexCurve A (B) page.SETTING PARAMETERSelect Curve Extremely InverseMultiply Point By 1.00

FlexCurve Initialization Initialize

FlexCurve Curve View Curve

FlexCurve Open from File Open

FlexCurve Save to File Save

FlexCurve Clear Data Clear Data

FlexCurve A Trip Time at 1.03 x PU 16037 msFlexCurve A Trip Time at 1.05 x PU 14747 ms• •• •• •FlexCurve A Trip Time at 19.5 x PU 60 msFlexCurve A Trip Time at 20.0 x PU 60 ms

5.3 S3 LOGIC INPUTS There are 20 logic inputs which can be used in a variety of ways

• Circuit breaker functions• Control Functions / User inputs• External trips / miscellaneous functions• Blocking functions; block Trip and Close and protection elements

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The S3 Logic Inputs contains the characteristics of the logic inputs and the virtual inputs. There are 7 setting page:

• Logic Inputs• Breaker Functions• Control Functions• User Inputs A through H• Block Functions• Block OC Function• Transfer Functions• Miscellaneous Function

Table: 3 S3 Logic Inputs - Logic Inputs Setup page.Input Name Asserted LogicLogic Input 1 Logic Input 1 (See Table 3.1)• • •• • •• • •Logic Input 14 Logic Input 14 (See Table 3.1)Logic Input 15 Logic Input 15 (See table 3.2)• • •• • •• • •Logic Input 20 Logic Input 20 (See table 3.2)

Logic Inputs setting can operate as contact inputs or virtual inputs. • 14 rear terminal contact inputs, connected as wet or dry contacts. Contact

input is either open or closed and is determined directly from the rear terminal.

• 20 maximum virtual input. The state of the virtual inputs is either on or off and can be set from serial communication. Virtual inputs are memory location which can be written to via the communication channel.

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Figure: Logic input wet and dry connection diagram

Logic input 1 through 20 has 2 setpoints• Name• Asserted logic condition

The state of the logic input is either Asserted or Not-AssertedThe state of Logic Input n (n=1-14) is determined by the combined states of Contact Input n and Virtual Input n according to the INPUT N ASSERTED LOGIC setpoint.

The state of Logic Input x (x=15-20) is determined by the state of the Virtual Input X according to the INPUT X ASSERTED LOGIC setpoint.

A logic function is invoked when its corresponding logic input is Asserted. One logic input can invoke many logic functions.

LOGIC INPUT N NAME setpoint allows a user friendly descriptor for an input point.

LOGIC INPUT N ASSERTED setpoint determine how the input contact and virtual input are put together in a logic equation to determine the Logic Input state.

Table: 3.1 S3 Logic Input Asserted LogicValue Logic Input Asserted When:Disabled NeverContact Close Contact is closedContact Open Contac is openVirtual On Virtual input is on

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Virtual Off Virtual input is offClosed & Von Contact is closed AND virtual input in onClosed & Voff Contact is closed AND virtual input in offOpen & Von Contact is open AND virtual input in onOpen & Voff Contact is open AND virtual input in offClosed | Von Contact is closed OR virtual input in onClosed | Voff Contact is closed OR virtual input in offClosed X Von Contact is closed XOR virtual input in onClosed X Voff Contact is closed XOR virtual input in offOpen X Von Contact is open XOR virtual input in onOpen X Voff Contact is open XOR virtual input in off

Table: 3.2 S3 Logical Inputs 15 through 20, the setpoints may be assigned asValue Logic Input Asserted When:Disabled NeverVirtual On Virtual input is onVirtual Off Virtual input is off

Table: 4 S3 Logic Inputs - Breaker Functions page.SETTING PARAMETER52a Contact Disabled / (Input 1 to 20)52b Contact Disabled / (Input 1 to 20)Breaker Connected Disabled / (Input 1 to 20)

Breaker functions settings determine the breaker status via the 52a and 52b contact inputs.

Breaker close via 52a Breaker open via 52b Breaker connected via isolating disconnect 89a or connected position switch When the BRKR CONNECTED is not asserted, the breaker is neither open

nor close

Table: 5 S3 Logic Inputs - Control Functions page.SETTING PARAMETERLocal Mode Disabled / (Input 1 to 20)Reset Disabled / (Input 1 to 20)Remote Open Disabled / (Input 1 to 20)Remote Close Disabled / (Input 1 to 20)

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Cold Load Pickup Disabled / (Input 1 to 20)Setpoint Group 2 Disabled / (Input 1 to 20)Setpoint Group 3 Disabled / (Input 1 to 20)Setpoint Group 4 Disabled / (Input 1 to 20)

The Control setting enables breaker control from the relay panel in LOCAL MODE or from remote mode via assertion of assigned Logic Input.

LOCAL MODE setpoint places the relay in local mode at the relay interface panel

REMOTE OPEN setpoint initiates the output relay 1 TRIP RELAY REMOTE CLOSE setpoint initiates the output relay 2 CLOSE RELAY

Remote open or close can also be a local control switch that is connected to the assigned logic inputs for the REMOTE OPEN and REMOTE CLOSE setpoint.

RESET setpoint resets the last trip indicator and latched relays COLD LOAD PICKUP setpoint initiates Cold Load Pickup blocking feature SETPOINT GROUP 2, 3 and 4 selects the active setpoint group 2, 3 and 4

respectively

Table: 6 S3 Logic Inputs - User Input A (T) page.SETTING PARAMETERUser Input A Name User Input A User Input A Source Disabled / (Input 1 to 20)User Input A Function Disabled / (Trip/Alarm/Control)User Input A: Relay 3 Do Not Operate / (Operate)• •User Input A: Relay 7 Do Not Operate / (Operate)User Input A Delay 0.00 s / (0 to 600 sec)

20 general purpose user input functions (User Inputs A through T) that is asserted on assertion of logic input

Table: 7 S3 Logic Inputs - Block Functions page.SETTING PARAMETERBlock 1 Trip Relay Disabled / (Input 1 to 20)Block 2 CLOSE Relay Disabled / (Input 1 to 20)Block Reset Disabled / (Input 1 to 20)Block Undervoltage 1 Disabled / (Input 1 to 20)

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Block Undervoltage 2 Disabled / (Input 1 to 20)Block Undervoltage 3 Disabled / (Input 1 to 20)Block Undervoltage 4 Disabled / (Input 1 to 20)Block Underfrequency 1 Disabled / (Input 1 to 20)Block Underfrequency 2 Disabled / (Input 1 to 20)Bypass Synchrocheck Disabled / (Input 1 to 20)Block Breaker Statistics Disabled / (Input 1 to 20)Block Negative Sequence Voltage Disabled / (Input 1 to 20)Block Restoration Disabled / (Input 1 to 20)Block Frequency Decay Disabled / (Input 1 to 20)Block Neutral Displacement Disabled / (Input 1 to 20)

Various protection elements can be block by Logic Input assertion. 14 blocking functions and 1 bypass function Protection elements will not operate when blocked

Table: 8 S3 Logic Inputs - Transfer Functions page.SETTING PARAMETERSelected To Trip Disabled / (Input 1 to 20)Undervoltage on Other Source Disabled / (Input 1 to 20)Incomer 1 Breaker Closed Disabled / (Input 1 to 20)Incomer 2 Breaker Closed Disabled / (Input 1 to 20)Tie Breaker Connected Disabled / (Input 1 to 20)Tie Breaker Closed Disabled / (Input 1 to 20)Block Transfer Disabled / (Input 1 to 20)Transformer Lockout Disabled / (Input 1 to 20)Source Trip Disabled / (Input 1 to 20)Close From Incomer 1 Disabled / (Input 1 to 20)Close From Incomer 2 Disabled / (Input 1 to 20)

The Transfer Function settings is used for two low voltage breaker feeding two low voltage bus supplied from two sources with a tie breaker feature for feeding both bus from one source.

11 logic functions exclusively used for a bus transfer scheme Logic inputs should be assigned as contact inputs before any other functions

to prevent conflicts.

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INCOMER 1 or 2 BREAKER CLOSED setpoints are used to track incoming breaker status to prevent paralleling or for initiating permission-to-transfer logic

CLOSE FROM INCOMER 1 or 2 setpoints are used to signal the bus tie breaker to close

TIE BREAKER CONNECTED setpoint is used to inhibit closing if the breaker is not connected or isolated

TIE BREAKER CLOSED setpoint is used for breaker status and inhibit permission-to-transfer logic and prevent paralleling

TRANSFORMER LOCKOUT and SOURCE TRIP setpoints are used to initiate a transfer.

BLOCK TRANSFER setpoint disables the transfer scheme

Table: 9 S3 Logic Inputs - Miscellaneous Functions page.SETTING PARAMETERTrigger Trace Memory Disabled / (Input 1 to 20)Trigger Data Logger Disabled / (Input 1 to 20)Simulate Fault Disabled / (Input 1 to 20)Start Demand Interval Disabled / (Input 1 to 20)

5.4 S4 OUTPUT RELAYSThe S4 Output Relays settings contain the characteristics of the output relays. There are 7 user accessible output relays:

• 1 Trip• 2 Close• 3 Auxiliary• 4 Auxiliary• 5 Auxiliary• 6 Auxiliary• 7 Auxiliary• 8 Self Test warning

Table: 10 S4 Output Relays - 1 Trip page setting view.SETTING PARAMETER1 TRIP Seal In Time 0.04 s

Table: 11 S4 Output Relays - 2 Close page setting view.SETTING PARAMETER

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2 CLOSE Seal In Time 0.04 s

The seal time setpoint is used to set the minimum output pulse duration.

On older model this time duration is not available and the contact close duration in controlled by the duration of the logic signal to the trip or close output relays.

Function of the trip / close relays is governed by the state of the 52a / 52b contacts52a installed

52 b installed

1 Trip Relay Initiated

2 Close Relayinitiated

Yes Yes Trip relay remains active until 52b close

Close relay remains active until 52a opens

Yes No Trip relay remains active until 52a opens

Close relay remains active until 52a closes

No Yes Trip remains active until 52b closes

Close remains active until 52b opens

No No Trip remains active until the Breaker failure times out or 100ms after the trip command reset

Close remains active for 200 ms

Table: 12 S4 Output Relays - 3 (4) Auxiliary page setting view.SETTING PARAMETER3 AUXILIARY Name 3 AUXILIARY3 AUXILIARY Non-operated State De-energized / (Energized)3 AUXILIARY Output Type Self-Resetting / (Latched/Pulsed)

5.4.1 Trip RelayDuration of contact closure can be set by 1 TRIP RELAY SEAL IN TIME setpoint.

Trip function is asserted when:• Command Open Breaker is asserted via EnerVista• Local or Remote control mode is selected and its respective TRIP input is

asserted• Any protection element is asserted• User Input set to 1 TRIP RELAY is asserted or

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Tripping function is inhibited when:• Self Test Relay function places relay out of service or• Logic input Blocks 1 TRIP RELAY is asserted

5.4.2 Close RelayDuration of contact closure can be set by 2 CLOSE RELAY SEAL IN TIME setpoint.

Close function is asserted when:• Command Close Breaker is asserted via EnerVista• Local or Remote control mode and its respective CLOSE input is asserted• Undervoltage restore is asserted• Underfrequency restore is asserted• Transfer Bus scheme is asserted

Closing function is inhibited when:• Breaker is in breaker failure mode• Synchrocheck is not within specified limits or• Bus Transfer scheme detects unsatisfied conditions or• Logic input Blocks 2 CLOSE RELAY is asserted

5.4.3 Auxiliary RelaysFunction of the auxiliary output relays is user defined and can be assigned from the various control or protection elements.

There are three operating mode:• Latched• Self-resetting• Pulsed

5.4.4 Self-Test warning Relay (reserved for future)

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5.5 S5 ProtectionThere are phase, ground, neutral, negative sequence and sensitive ground overcurrent elements.

Phase Current elements• Phase Time OC 1• Phase Time OC 2• Phase Instantaneous OC 1• Phase Instantaneous OC 2• Phase Directional

Ground Current elements

• Ground Time OC• Ground Instantaneous OC• Ground Directional

Neutral Current elements

• Neutral Time OC 1• Neutral Time OC 2• Neutral Instantaneous OC 1• Neutral Instantaneous OC 2• Neutral Directional

Negative Sequence• Negative Sequence Time OC• Negative Sequence Instantaneous OC• Negative Sequence Voltage• Negative Sequence Directional

Sensitive Ground Current• Sensitive Ground Time• Sensitive Ground Instant OC• Sensitive Ground Directional• Restricted Earth Fault

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Time Overcurrent Curve characteristic is established by its settings:• Pick-up• Curve Shape

1. Standard CurvesANSI: Extremely, Very, Normal or Moderately InverseGE Type IAC: Extremely, Very, Short Inverse or InverseIEC: Curve A,B or C orIEC short InverseDefinite time

2. Flexcurve A or B: user defined time current characteristics• Multiplier• Reset Time

Pickup is the threshold current at which the time overcurrent element start timingAccuracy is 3% p.u. of pick-up settingDrop-out is 98% of pick-up thresholdPick-up setting corresponds to per unit x CT value

Multiplier sets the timing at multiples of the base curve time values.A multiplier setting of zero results in an instantaneous operation above the pick-up value. Instantaneous mean no intentional time delay and correspond to the relay design operating with minimum delay.

Reset time can be linear or instantaneousTime overcurrent calculations are performed with an internal energy capacity memory variable. When the variable reaches 100%, the element is asserted.A current value below the pick-up drop-out level will start to reduce the energy capacity number as per a reset time equation.Refer to manual page 5.45

Overcurrent operating time is dynamic at which the energy storage calculation will increase or decrease with any current detected above the pick-up value. For an evolving fault where the current gradually increases, the relay operating time becomes faster with larger current values.

5.5.1 Time Overcurrent Characteristics

Definite Time Curve: Time range from 100ms to 10 second in increments of 100ms

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ANSI Curves conforms to ANSI C37.90 standard. ANSI is a North American Standard. The relay operating time is given by:

T = M { A + B + D + E } (I/Ipu)-C ((I/Ipu)-C)2 ((I/Ipu)-C)3

Where: T = trip time in secondsM = multiplier valuesI = input currentIpu = pick-up current setpoint A,B,C,D,E = constants

ANSI Curve Shape A B C D EANSI Extremely Inverse .0399 .2294 .5000 3.0094 .7222ANSI Very Inverse .0615 .7989 .3400 -.2840 4.050ANSI Normally Inverse .0274 2.2614 .3000 -4.1899 9.1272ANSI Moderately Inverse .1735 .6791 .8000 -.0800 .1271

See Appendix for operating time of ANSI curves

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IEC Curves conform to IEC 255-4 and BS142 standard. IEC is a European standard and BS is a British Standard. The relay operating time is given by:

T = M { K } (I/Ipu)E-1)

Where: T = trip time in secondM = multiplier setpointI = input currentIpu = pick up current setpointK, E = constants

IEC (BS) Curve Shape K EIEC Curve A (BS142) .140 .020IEC Curve B (BS142) 13.500 1.000IEC Curve C (BS142) 80.000 2.000IEC Short Inverse .050 .040

See Appendix for operating time of IEC curves

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IAC Curves are General Electric type IAC relay curves. The relay operating time is given by:

T = M { A + B + D + E } (I/Ipu)-C ((I/Ipu)-C)2 ((I/Ipu)-C)3

Where: T = trip time in secondsM = multiplier valuesI = input currentIpu = pick-up current setpoint A,B,C,D,E = constants

IAC Curve Shape A B C D EIAC Extremely Inverse .0040 .6379 .6200 1.7872 .2461IAC Very Inverse .0900 .7955 .1000 -1.2885 7.9586IAC Inverse .2078 .8630 .8000 -.4180 .1947IAC Short Inverse .0428 .0609 .6200 -.0010 .0221

See Appendix for operating time of IAC curves

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5.5.2 Phase Time Overcurrent

Phase Time OC

Figure: SR-750 Phase Time OC trip logic diagram

Two Phase Timed elements are provided. The two elements can be enabled by Logic Inputs for high-set or low set setting purposes.

Phase Timed can be set to incorporate directional control and / or voltage restraint.

Voltage restraint sensitizes the phase timed element pick-up value on the p.u. phase-phase voltage value. Minimum pickup value is 10% of the phase timed setting at 10% phase-to-phase voltage.

The direction element is used to supervise tripping in the forward or reverse direction.

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Figure: SR-750 Phase Timed OC Voltage Restraint Characteristic

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5.5.3 Phase Instantaneous Overcurrent

Phase Instantaneous OC

Figure: SR-750 Phase Instantaneous OC Trip Logic diagram

Two Phase Instantaneous elements are provided. The two elements can be enabled by Logic inputs for high-set or low set setting purposes

Phase Instantaneous tripping can be conditionally set for 1, 2 or 3 phase overcurrent conditions.

The direction element is used to set the tripping in the forward direction.

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5.5.4 Directional SupervisionThe direction element can be enabled to supervise tripping in the forward or reverse direction. Directional supervision can be enabled for the various overcurrent elements.

• Phase Time and Instantaneous 1 (2)• Neutral Time and Instantaneous 1 (2)• Ground Time and Instantaneous• Negative Sequence Time and Instantaneous

Features of the direction elelemnts are:• Built in 1 cycle delay for directional discrimination for reliability• MTA is user settable• MIN POLARIZING VOLTAGE set at p.u. of VT for directional element

operation• A voltage memory circuit is incorporated valid of 1 second after a fault

Phase Overcurrent under directional control can be blocked by

• BLOCK OC WHEN VOLT MEM EXPIRES setpoint is Enabled1. All directional controlled element will be blocked

• BLOCK OC WHEN VOLT MEM EXPIRES setpoint is Disabled:1. Phase Overcurrent is inhibited until the polarizing voltage is restored.2. Close Into Fault feature is active

Phase Directional elementThe relay uses a 90º quadrature connection for phase directional polarization.

Phase Current Polarizing voltage ABC Polarizing voltage ACBA Ia Vbc VcbB Ib Vca VacC Ic Vab Vba

An MTA setting of 90º represents an in phase current with it phase voltage since MTA reference is taken from polarizing voltage vector.

An MTA of 30° result in a 60º PF lagging circuit.

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Phase Directional Element

Figure: Phase Directional Element Phasor Diagram

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5.6 Neutral Overcurrent

Neutral Time OC

Figure: Neutral Time OC trip Logic diagram

Four neutral overcurrent elements are provided• Time 1 (2) • Instantaneous 1 (2)

Elements can be directional controlledElements can be blocked individually or by a group by logic inputs

Neutral current is derived from the zero sequence current and calculated by:3I0 = Ia + Ib + Ic, which is the operating current

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Neutral Instantaneous OC

Figure: Neutral Instantaneous OC Trip Logic Diagram

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Neutral Directional Element

Figure: Neutral Directional Element Phasor Diagram

Neutral Directional element can be current, voltage or dual polarized.• Voltage polarizing quantity is derived from the zero sequence voltage• - V0 = - (Va + Vb + Vc) / 3• VT must be wye connected• Direction defaults to Forward if the polarizing voltage drops below MIN

OPERATING VOLTAGE• Current polarizing quantity is obtained for the Ground CT input or a

dedicated polarizing CT input (for bootware rev 3.0 or higher)• Direction is Forward when the Neutral current is within ± 90° of the

polarizing current. Otherwise the direction is Reversed.Direction defaults to Forward if the polarizing current is < 5% of CT

• Dual Polarized use the polarizing voltage as the primary source and polarizing current takes over if the polarizing voltage is insufficient and vice versa.

• Direction defaults to Forward if neither polarizing voltage nor current values are sufficient

• Angle of maximum torque is where the operating current leads the polarizing voltage.

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5.7 Ground Overcurrent

Ground Time OC

Figure: Ground Time OC Trip Logic Diagram

Two Ground overcurrent elements are provided• Gnd Time• Gnd Instantaneous

Elements can be directional controlledElements can be blocked individually or by a group by logic inputs

Ground input current from the ground CT (•G10-H10) is the operating currentGround Directional element can be current, voltage or dual polarized.

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Ground Instantaneous OC

Figure: Ground Instantaneous OC Trip Logic Diagram

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Ground Directional Element

Figure: Ground Directional Logic diagram

Voltage polarizing quantity is derived from the zero sequence voltage• -V0 = - (Va + Vb + Vc) / 3• VT must be wye connected• Direction defaults to Forward if the polarizing voltage drops below MIN

OPERATING VOLTAGE• Only Voltage polarized is provided for bootware rev 3.0 or newer where the

Ground CT input I connected to •G3-H3• Current polarizing quantity is obtained for the Ground Polarizing CT input

(•G3-H3).• Direction is Forward when the Ground current is within ± 90° of the

polarizing current. Otherwise the direction is Reversed. Direction defaults to Forward if the polarizing current is < 5% of CT

• Dual Polarized use the polarizing voltage as the primary source and polarizing current takes over if the polarizing voltage is insufficient and vice versa. Direction defaults to Forward if neither polarizing voltage nor current values are sufficient

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Ground Directional MTA and Polarizing circuit descriptionMIN POLARIZING VOLTAGE must be set to prevent operation caused by unbalanced system voltage conditions, VT ratio errors. 2% of VT for balanced systems and 1% accuracy VTs 20% of VT for high resistance grounding system or floating neutrals 5% of VT for solidly grounded system

Ground Directional MTAAngle of maximum torque is where the operating current leads the polarizing voltage.

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5.8 Sensitive Ground Overcurrent

Sensitive Ground Time OC

Figure: Sensitive Ground Time OC trip logic Diagram

Two Sensitive Ground overcurrent and a Restricted Earth Fault element are provided.

• Sensitive Gnd Time OC & Sensitive Gnd Inst OCCan be directional controlledElements can be blocked individually or a group by logic inputs

• Restricted Earth FaultAvailable for transformer that do not have dedicated protection

• Requiring installation of stabilizing resistor. Stabilizing resistor allows circulating current to flow in saturated CT for external faults and minimizing the spill current flowing in the relay.

• Non-linear resistor is required if the voltage across the inputs is greater than 2000V. (Refer to the manual for resistor value calculations)

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Sensitive Ground Instantaneous OC

Figure: Sensitive Ground Instantaneous OC trip Logic Diagram

Sensitive Ground input current from the Sensitive Ground CT (•G3-H3) is the operating current.

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Sensitive Ground Directional element

Sensitive Ground Directional element can be current, voltage or dual polarized. Voltage polarizing quantity is derived from the zero sequence voltage

- V0 = - (Va + Vb + Vc) / 3VT must be wye connectedDirection defaults to Forward if the polarizing voltage drops below MIN

OPERATING VOLTAGE Polarizing current input is obtained for the Ground CT input (•G10-H10).

Direction is Forward when the Sensitive Ground current is within ± 90° of the polarizing current. Otherwise the direction is Reversed.

Direction defaults to Forward if the polarizing current is < 5% of CT Dual Polarized use the polarizing voltage as the primary source and polarizing current takes over if the polarizing voltage is insufficient and vice versa

Direction defaults to Forward if neither polarizing voltage nor current values are sufficient

Sensitive Ground Directional MTA and Polarizing circuit descriptionMIN POLARIZING VOLTAGE must be set to prevent operation caused by unbalanced system voltage conditions, VT ratio errors. 2% of VT for balanced systems and 1% accuracy VTs 20% of VT for high resistance grounding system or floating neutrals

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5% of VT for solidly grounded system

Sensitive Ground Directional MTAAngle of maximum torque is where the operating current leads the polarizing voltage.

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5.9 Negative Sequence Overcurrent

Three Negative Sequence elements are provided• Neg Sequence Time OC, Neg Sequence Inst OC & Neg Sequence Voltage• Overcurrent elements can be directional controlled• Elements can be blocked individually or as a group by logic inputs

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Negative Sequence Instantaneous OC

Figure: Negative Sequence Instantaneous OC Trip Logic Diagram

Operating current and polarizing voltage is calculated based on the system rotation

System Rotation Operating Current Polarizing VoltageABC Ia2 = Ia + a 2 Ib + aIc

3-Va2 = Va + a 2 Vb + aVc 3

ACB Ia2 = Ia + aIb + a 2 Ic 3

-Va2 = Va + aVb + a 2 Vc 3

• VT must be wye connected• Direction defaults to Forward if the polarizing voltage drops below MIN

OPERATING VOLTAGE

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Negative Sequence Directional element

Figure: Negative Sequence Directional Logic diagram

Negative Sequence Polarizing circuit descriptionMIN POLARIZING VOLTAGE must be set to prevent operation caused by unbalanced system voltage conditions, VT ratio errors. 2% of VT for balanced systems and 1% accuracy VTs 20% of VT for high resistance grounding system or floating neutrals 5% of VT for solidly grounded system

Negative Sequence Directional MTAAngle of maximum torque is where the operating current leads the polarizing voltage.

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Negative Sequence Voltage

Figure: Negative Sequence Voltage Logic diagram

Negative sequence voltage element will operate when specified threshold is exceeded Protection for loss of 1 or 2 phases Protection for reverse phasing

5.10 VoltageFour Undervoltage, two Overvoltage & a Neutral Displacement elements are provided.

• Undervoltage elements will assert when a sustained low voltage drops below a voltage setpoint for a specified time delay.

• Undervoltage can incorporate an inverse time delay characteristic where the operating time given by:

T = D / ( 1 – V / Vpu) where: T = Operating timeD = Undervoltage delay setpointV = Voltage in p.u. of VTVpu = Pickup level

• At 0% of pick-up, the operating time equals the undervoltage delay

setpoint

• A family of curves can be generated from the equation

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Bus Undervoltage

Figure: Bus Indervoltage Auxiliary Trip Logic Diagram

Bus Undervoltage 1 and 2 are identical elements• The voltage inputs are from the Bus Vts• The elements will be asserted when an undervoltage is sustained after for the

setpoint delay time plus the curve delay time. • Definite time curve equates to zero second of curve time.

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Line Undervoltage

Figure: Line Undervoltage Auxiliary Trip Logic diagram

Line Undervoltage 3 and 4 are identical elements• The voltage inputs are from the Line Vts• Definite time curve equates to zero second of curve time

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Overvoltage

Figure: Overvoltage Auxiliary Trip Logic diagram

Line Overvoltage 1 and 2 are identical elements• The voltage inputs are from the bus VTs• The elements will be asserted when an overvoltage is sustained after the

setpoint delay time

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Neutral Displacement

Figure: Neutral Displacement Auxiliary Trip Logic Diagram

Neutral Displacement element uses the 3V0 values• Bus VT’s must be wye connected• Uses Voltage time curve identical to the current curve but except with

voltage on the x-axis• Pick-up is at p.u. of VT

3V0 values cannot be differentiated between a fault on the associated line or a fault on adjacent line.Neutral Displacement function should then be used for alarm or back-up protection.

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5.11 FrequencyThree frequency elements are provided

• Underfrequency 1 and 2 & Frequency Decay• Frequency decay is a rate of change element

Underfrequency

Figure: Underfrequency Auxiliary Trip Logic Diagram

The voltage inputs are from the bus VTsThe elements will be asserted when a low frequency is sustained below the frequency pick-up level for the setpoint delay time.

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Frequency Decay

Figure: Frequency Decay Auxiliary trip Logic Diagram

A Frequency Decay element is provided• Used for tripping, latched alarm, alarm or control function if enabled• Can be block by Logic Inputs• Uses the highest phase current inputs for the Minimum Operating Current

setpoint• Uses the bus voltage inputs for minimum operating voltage

Van for wye connected VTsVab for delta connected VTs

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5.12 Breaker Failure

Figure: Breaker Failure Auxiliary Trip Logic Diagram

The Breaker Failure element monitors the phase currents while a protection trip exists. If any phase current is still above the Breaker Failure Current after the Breaker Failure Delay time expires while a protection trip still exist, a breaker failure condition will be asserted.Two delay time are provided Breaker Failure Delay 1 begins timing once a protection trip is initiated. Breaker Failure Delay 2 begins timing once a breaker failure condition is asserted.

The auxiliary relay will be asserted once the time delay 2 has expired.Breaker Failure timing will reset when protection trip resets.

A breaker failure condition will block the auto-reclosing scheme and auxiliary output can be used to send a trip signal to adjacent zones.

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6. Commissioning

6.1 Installation ChecksCheck the relay nameplate values matches the connected devices:

Phase CTs secondary ratingGround CTs secondary ratingSupply voltage levelAnalog device output rating

Check the relay is installed as per the applicable schematicsCheck external wiring is correctCheck all ground terminal are connected to the ground bus.

6.2 Metering TestPerform Metering test:Apply balance 3-phase voltage and current, test at unity PF, 50% PF at full load and at 50% load.

Apply these quantities:50% load at Unity Power factor Va = 67 0° Ia = 2.5 A 0°Vb = 67 -120° Ib = 2.5 A -120°Vc = 67 120° Ic = 2.5 A 120°

50% load at 30% lagging Power factorVa = 67 0° Ia = 2.5 A -30°Vb = 67 -120° Ib = 2.5 A -150°Vc = 67 120° Ic = 2.5 A 90°

Full load at Unity Power factorVa = 67 0° Ia = 5.0 A 0°Vb = 67 -120° Ib = 5.0 A -120°Vc = 67 120° Ic = 5.0 A 120°

Full load at 30% Power factorVa = 67 0° Ia = 5.0 A -30°Vb = 67 -120° Ib = 5.0 A -150°Vc = 67 120° Ic = 5.0 A 90°

Metering values should be within 1%CT and VT settings can be checked off once testing is complete

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6.3 Logic Input TestApply +ve 32 Vdc available from internal power supply at terminal C12 to each Logic Input terminals. Ensure that Logic Input 1 through 14 is asserted when voltage is applied.

View the Logic Input states in the A1 Status page under the Hardware tab.Terminal Logic Input Terminal Logic Input Terminal Logic InputC1 1 C6 6 D4 11C2 2 C7 7 D5 12C3 3 D1 8 D6 13C4 4 D2 9 D7 14C5 5 D3 10The Logic Input Setup 1 through 14 can be checked off once testing is completed.

6.4 Output testInitiate Command to Trip and Close. Monitor associated output contacts and LED indicators.Terminals Contact Form OutputE2 – F2 NO 1 TRIPE3 – F3 NO 2 OPENE4 – F4 – E5 NO – Com – NC 3 AuxiliaryF5 – F6 – E6 NO – Com – NC 4 AuxiliaryE8 – F7 – E7 NO – Com – NC 5 AuxiliaryF8 – F9 – E9 NO – Com – NC 6 AuxiliaryE11 – F10 – E10 NO – Com – NC 7 AuxiliaryInitiate Command to Trip and Close. Monitor associated output contacts and LED indicators.

Program User Input A to trip and operate auxiliary relay 3 to 7. Select an useable hardware input and assert the hardware Input A with +32 Vdc control power. Monitor auxiliary output contacts 3 to 7 and LED Indicators. Reset user Input A back to normal once testing is complete.

Note: The under Setpoint and S8 Testing in Enervista, there is a FORCE function that can assert every output relay contact as an alternative testing method.

The 1 Trip, 2 Close and 3-7 Auxiliary Output Relays can be checked off once testing is complete.

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6.5 Phase Time Overcurrent Pickup test:

Phase-A Pick-up test:Inject balance voltages and Phase-A Itest at 1.05 and .95 of the Pickup setpoint value.Monitor: PICKUP LED on the front panel

Itest at 1.05 pu = 1.25 x 5A x 1.05 = 6.56 AItest at .95 pu= 1.25 x 5A = .95 = 5.94 A

Pre-fault Fault 1 (Pickup +5%) Reset (Pickup – 5%)Mag Angle Freq Mag Angle Freq Mag Angle Freq

Va 69.3 0 60 Va 69.3 0 60 Va 69.3 0 60Vb 69.3 -120 60 Vb 69.3 -120 60 Vb 69.3 -120 60Vc 69.3 120 60 Vc 69.3 120 60 Vc 69.3 120 60Ia 0 0 60 Ia 6.56 0 60 Ia 5.94 0 60Ib 0 -120 60 Ib 6.56 -120 60 Ib 5.94 -120 60Ic 0 120 60 Ic 6.56 120 60 Ic 5.94 120 60

Phase-B and C Pick-up test:Repeat single phase current injection for Phase-B and Phase-C with in phase current.

Level accuracy: +/- .5% of full scale at < 2 x CT; +/- 1% of full scale at > 2 x CT.

Phase Time Overcurent 1 Pick-up can be checked off once testing is completed.

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6.5.1 Phase Time Overcurrent Timing test:

Phase-A Timing test:Inject balance voltages and Phase-A Itest at 3X and 6X of the Pickup setpoint value.Contact Monitor: 1 TRIPTiming Start: Current initiateTiming Stop / Current stop: 1 TRIP closure

Itest at 3X = 1.25 x 5A x 3 = 18.75 AItest at 6X = 1.25 x 5A x 6 = 37.5 A

Pre-fault Fault 1 (Pickup 3X) Fault 2 (Pickup 6X)Mag Angle Freq Mag Angle Freq Mag Angle Freq

Va 69.3 0 60 Va 69.3 0 60 Va 69.3 0 60Vb 69.3 -120 60 Vb 69.3 -120 60 Vb 69.3 -120 60Vc 69.3 120 60 Vc 69.3 120 60 Vc 69.3 120 60Ia 0 0 60 Ia 18.7

50 60 Ia 37.5 0 60

Ib 0 -120 60 Ib 18.75

-120 60 Ib 37.5 -120 60

Ic 0 120 60 Ic 18.75

120 60 Ic 37.5 120 60

Phase-B and C Timing test:Repeat single phase current injection for Phase-B and Phase-C with in phase current.

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Timing accuracy: +/- 3% of trip time value or +/- 40 ms (whichever is greater).

Phase Time Overcurrent 1 Curve and Multiplier can be checked off once testing is completed.

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6.5.2 Phase Instantaneous Pick-up test:

Phase-A Pick-up test:Inject balance voltages and Phase-A Itest at 1.05 and .95 of the Pickup setpoint value.Monitor: 1 TRIP contactTiming Start: Current initiateTiming Stop / Current stop: 1 TRIP closure

Itest at 1.05 = 8 x 5A x 1.05 = 42.0 A, 3 cycle pulse duration.Itest at .95 = 8 x 5A x .95 = 38.0 A, 3 cycle pulse duration.

Pre-fault Fault 1 (Pickup + 5%) Fault 0 (Pickup – 5%)Mag Angle Freq Mag Angle Freq Mag Angle Freq

Va 69.3 0 60 Va 69.3 0 60 Va 69.3 0 60Vb 69.3 -120 60 Vb 69.3 -120 60 Vb 69.3 -120 60Vc 69.3 120 60 Vc 69.3 120 60 Vc 69.3 120 60Ia 0 0 60 Ia 42.0 0 60 Ia 38.0 0 60Ib 0 -120 60 Ib 42.0 -120 60 Ib 38.0 -120 60Ic 0 120 60 Ic 42.0 120 60 Ic 38.0 120 60

Repeat single phase current injection for Phase-B and Phase-C with in phase current.


Timing accuracy: +/- 20ms or +/- 1% of delay setting (whichever is greater).

Phase Instantaneous Pickup / Delay can be checked off once testing is completed.

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6.5.3 Phase Directional MTA test:

Phase-A Pick-up test:Phase Time OC 1 Direction = ForwardInject balance voltages and Itest at 1.25X of the Phase Time Pickup setpoint value.Itest = 1.25 x 5A x 1.25 = 7.81ASet current direction at ± 5º of the tripping boundaryDirectional element boundaries = -90ºref + 30ºlead ± 90º = 30º and -150º

Inject single Phase-A current at angular displacement of 25º, 35º, -145º and -155ºMonitor: PICKUP LED on the front panel

Itest at 1.25 pu = 1.25 x 5A x 1.25 = 7.81APre-fault Fault 1 ref = 25º / -145º Fault 0 ref = 35º / -155º

Mag Angle Freq Mag Angle Freq Mag Angle FreqVa 69.3 0 60 Va 69.3 0 60 Va 69.3 0 60Vb 69.3 -120 60 Vb 69.3 -120 60 Vb 69.3 -120 60Vc 69.3 120 60 Vc 69.3 120 60 Vc 69.3 120 60Ia 0 0 60 Ia 7.81 25 60 Ia 7.81 35 60Ib 0 -120 60 Ib 7.81 -95 60 Ib 7.81 -85 60Ic 0 120 60 Ic 7.81 145 60 Ic 7.81 155 60

Repeat single phase current injection for Phase-B and Phase-C.Repeat single phase current injection for Phase-A-B-C using Phase-A ref angle of --145 º and -155 º

Pickup LED should be ON during Fault 1 and OFF during Fault 0.

Angle accuracy: +/- 2°.

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Phase Directional MTA can be checked off once testing is completed.

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6.5.4 Phase Directional Minimum Polarizing Voltage test:

Phase-A Pick-up test:Set the Phase Time OC 1 Direction setpoint = EnabledInject balance voltages and Itest at 1.25 of the Phase Time Pickup setpoint value.Itest = 1.25 x 5A x 1.25 = 7.81ASet current direction at the -60 º which is the calculated MTA.Inject single Phase-A currentMonitor: PICKUP LED on the front panel

Vtest at .95 pu = (.50 x 69.3V x .95) / √3 = 19.0 VVtest at 1.05 pu = (.50 x 69.3 x 1.05) / √3 = 21.0 V

Pre-fault Fault 1 (Vpol + 5%) Fault 0 (Vpol – 5%)Mag Angle Freq Mag Angle Freq Mag Angle Freq

Va 69.3 0 60 Va 21.0 0 60 Va 19.0 0 60Vb 69.3 -120 60 Vb 21.0 -120 60 Vb 19.0 -120 60Vc 69.3 120 60 Vc 21.0 120 60 Vc 19.0 120 60Ia 0 0 60 Ia 8.71 -60 60 Ia 8.71 -60 60Ib 0 -120 60 Ib 8.71 -180 60 Ib 8.71 -180 60Ic 0 120 60 Ic 8.71 60 60 Ic 8.71 60 60

Repeat single phase current injection for Phase-B and Phase-C.


Phase Minimum Polarizing Voltage can be checked off once testing is completed.

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6.5.5 Phase Time OC Voltage Restraint Test:

Phase-A Pickup Test:Phase Time OC Voltage Restraint = EnabledInject .80 pu balance voltages and Itest at ± 5% of the calculated Pickup setpoint value.

Vtest = 69.3v x .80 = 55.44VIpickup = 1.25 x 5A x .8 = 5.00AItest at .95 pu = 5.00A x .95 = 4.75AItest at 1.05 pu = 5.00A x 1.05 = 5.25A

Pre-fault Fault 1 (Ipu + 5%) Fault 0 (Ipu – 5%)Mag Angle Freq Mag Angle Freq Mag Angle Freq

Va 69.3 0 60 Va 55.44

0 60 Va 55.44

0 60

Vb 69.3 -120 60 Vb 55.44

-120 60 Vb 55.44

-120 60

Vc 69.3 120 60 Vc 55.44

120 60 Vc 55.44

120 60

Ia 0 0 60 Ia 5.25 0 60 Ia 4.75 0 60Ib 0 -120 60 Ib 5.25 -120 60 Ib 4.75 -120 60Ic 0 120 60 Ic 5.25 120 60 Ic 4.75 120 60



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Phase Time OC Voltage Restraint can be checked off once testing is completed.

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6.6 Negative Sequence Time OC Pickup Test:

Phase-A Pick-up test:Inject balance voltages and Phase-A I2test at 1.05 and .95 of the Pickup setpoint value.Monitor: PICKUP LED on the front panel

I2test at 1.05 pu = .25 x 5A x 1.05 = 1.31 AI2test at .95 pu= .25 x 5A = .95 = 1.19 A

Pre-fault Fault 1 (Ipu + 5%) Fault 0 (Ipu – 5%)Mag Angle Freq Mag Angle Freq Mag Angle Freq

69.3 69.3 0 60 Va 69.3 0 60 Va 69.3 0 6069.3 69.3 -120 60 Vb 69.3 -120 60 Vb 69.3 -120 6069.3 69.3 120 60 Vc 69.3 120 60 Vc 69.3 120 60Ia 0 0 60 Ia 3.93 0 60 Ia 3.93 0 60Ib 0 -120 60 Ib 3.93 -120 60 Ib 3.93 -120 60Ic 0 120 60 Ic 3.93 120 60 Ic 3.93 120 60



Level Accuracy: +/- 1.5% of full scale at < 2 x CT; +/- 3% of full scale at > 2 x CT.

Negative Sequence Time OC Pickup can be checked off once testing is completed.

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6.6.1 Negative Sequence Time Overcurrent Timing test:

Three Phase Timing test:Inject balance voltages and balance I2test at 3X and 6X of the Pickup setpoint value.Contact Monitor: 1 TRIPTiming Start: Current initiateTiming Stop / Current stop: 1 TRIP closure

I2test at 3X pu= .25 x 5A x 3 = 3.75 AI2test at 6X pu= .25 x 5A x 6 = 7.5 A

Pre-fault Fault 1 (Pickup 3X) Fault 2 (Pickup 6X)Mag Angle Freq Mag Angle Freq Mag Angle Freq

Va 69.3 0 60 Va 69.3 0 60 Va 69.3 0 60Vb 69.3 -120 60 Vb 69.3 -120 60 Vb 69.3 -120 60Vc 69.3 120 60 Vc 69.3 120 60 Vc 69.3 120 60Ia 0 0 60 Ia 3.75 0 60 Ia 7.5 0 60Ib 0 -120 60 Ib 3.75 120 60 Ib 7.5 120 60Ic 0 120 60 Ic 3.75 -120 60 Ic 7.5 -120 60

Note: that rotation has been reversed to produce balanced the negative sequence currents.

Timing accuracy: +/- 3% of trip time value or +/- 40 ms (whichever is greater).

Negative Sequence Time Overcurrent Curve and Multiplier can be checked off once testing is completed.

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6.6.2 Negative Sequence Directional test:

Phase-A Forward Pick-up test:Inject balance voltages and I2test at 1.25X of the Phase Time Pickup setpoint value.

I2test = .25 x 5A x 1.25 = 1.56ASet current direction at Phase Time OC MTA.Inject single Phase-A current at angular displacement of -60º Forward and 120º Reverse.Monitor: PICKUP LED on the front panel

Itest at 1.25 pu = 1.25 x 5A x 1.25 = 7.81APre-fault Fault 1 ref = -60º Fault 0 ref = 120º

Mag Angle Freq Mag Angle Freq Mag Angle FreqVa 69.3 0 60 Va 69.3 0 60 Va 69.3 0 60Vb 69.3 -120 60 Vb 69.3 -120 60 Vb 69.3 -120 60Vc 69.3 120 60 Vc 69.3 120 60 Vc 69.3 120 60Ia 0 0 60 Ia 4.67 -60 60 Ia 4.67 120 60Ib 0 -120 60 Ib 4.68 180 60 Ib 4.67 0 60Ic 0 120 60 Ic 4.68 60 60 Ic 4.67 -120 60



Negative Sequence Time OC Direction can be checked off once testing is completed.

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6.6.3 Negative Sequence Instantaneous OC Pick-up test:

Phase-A Pick-up test:Inject balance voltages and balance I2test at 1.05 and .95 of the Pickup setpoint value.Monitor: 1 TRIP contactTiming Start: Current initiateTiming Stop / Current stop: 1 TRIP closure

Itest at 1.05 pu = 1.0 x 5A x 1.05 = 5.25 A, 3 cycle pulse duration.Itest at .95 pu = 1.0 x 5A x .95 = 4.75 A, 3 cycle pulse duration.

Pre-fault Fault 1 (Pickup + 5%) Fault 0 (Pickup – 5%)Mag Angle Freq Mag Angle Freq Mag Angle Freq

Va 69.3 0 60 Va 69.3 0 60 Va 69.3 0 60Vb 69.3 -120 60 Vb 69.3 -120 60 Vb 69.3 -120 60Vc 69.3 120 60 Vc 69.3 120 60 Vc 69.3 120 60Ia 0 0 60 Ia 5.25 0 60 Ia 4.75 0 60Ib 0 -120 60 Ib 5.25 120 60 Ib 4.75 120 60Ic 0 120 60 Ic 5.25 -120 60 Ic 4.75 -120 60

Level Accuracy: +/- 1.5% of full scale at < 2 x CT; +/- 3% of full scale at > 2 x CT.

Timing accuracy: +/- 20ms or +/- 1% of delay setting (whichever is greater).

Phase Instantaneous Pickup can be checked off once testing is completed.

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6.7 Bus Undervoltage Pickup test:

Phase-A Pick-up test:Apply three phase voltage unbalance with a single phase undervoltage.Vtest at 1.05 and .95 of the Pickup setpoint value.Monitor: PICKUP LED on the front panel

Vtest at 1.05 pu = .75 x 69.3V x 1.05 = 54.6VVtest at .95 pu= .75 x 69.3V = .95 = 49.4V

Pre-fault Fault 1 (Pickup -5%) Reset (Pickup + 5%)Mag Angle Freq Mag Angle Freq Mag Angle Freq

Va 69.3 0 60 Va 49.4 0 60 Va 54.6 0 60Vb 69.3 -120 60 Vb 49.4 -120 60 Vb 54.6 -120 60Vc 69.3 120 60 Vc 49.4 120 60 Vc 54.6 120 60Ia 0 0 60 Ia 0 0 60 Ia 0 0 60Ib 0 -120 60 Ib 0 -120 60 Ib 0 -120 60Ic 0 120 60 Ic 0 120 60 Ic 0 120 60

Phase-B and C Pick-up test:Repeat voltage unbalance for Phase-B and Phase-C undervoltage condition.

Level accuracy: +/- .25% of full scale (11 to 130V); +/- 8% of full scale (130 to 273V). For open delta connection, error is 2 times as shown.

Bus Undervoltage Pick-up can be checked off once testing is completed.

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6.7.1 Bus Undervoltage Timing test:

Three Phase Undervoltage timing Test:Apply three phase voltage balanced undervoltage.Vtest at .75 of the Pickup setpoint value and at .95 of the Minimum Operating Voltage value.Contact Monitor: 1 TRIPTiming Start: Voltage step change initiateTiming Stop / Voltage stop: 1 TRIP closureV1test at .75 pu = .75 x 69.3V x .75 = 38.9VV2test at .95 Vmin = .30 x 69.3 x .95 = 19.75V

Pre-fault Fault 1 (Pickup - 5%) Fault 0 (Vmin - 5%)Mag Angle Freq Mag Angle Freq Mag Angle Freq

Va 69.3 0 60 Va 38.9 0 60 Va 19.75

0 60

Vb 69.3 -120 60 Vb 38.9 -120 60 Vb 19.75

-120 60

Vc 69.3 120 60 Vc 38.9 120 60 Vc 19.75

120 60

Ia 0 0 60 Ia 0 0 60 Ia 0 0 60Ib 0 -120 60 Ib 0 -120 60 Ib 0 -120 60Ic 0 120 60 Ic 0 120 60 Ic 0 120 60

Confirm operating times are within 5ms of calibrated time value.


Timing accuracy: +/- 100 msec.

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Bus Undervoltage Pick-up can Minimum Operating Voltage can be checked off once testing is completed.

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6.8 UnderFrequency Pickup Test:

Three Phase Underfrequency Pickup Test:Apply three phase balanced voltage and current with an underfrequency component.Ftest at ± .10Hz of pickupMonitor: PICKUP LED on the front panel

Ftest at + .10Hz = 58.50Hz + .10Hz = 58.60HzFtest at – .10Hz = 58.50Hz – .10Hz = 58.40HzIref = 1.5A

Pre-fault Fault 1 (Pickup – .10Hz) Fault 0 (Pickup + .10Hz)Mag Angle Freq Mag Angle Freq Mag Angle Freq

Va 69.3 0 60 Va 69.3 0 58.40

Va 69.3 0 58.60

Vb 69.3 -120 60 Vb 69.3 -120 58.40

Vb 69.3 -120 58.60

Vc 69.3 120 60 Vc 69.3 120 58.40

Vc 69.3 120 58.60



Level accuracy: +/- .02 Hz.

Underfrequency Pick-up can be checked off once testing is completed.

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6.8.1UnderFrequency Timing Test:

Three Phase Underfrequency Timing Test:Apply three phase balanced voltage and current with an underfrequency component.

Ftest at –1.0Hz of pickupContact Monitor: 1 TRIPTiming Start: Current initiateTiming Stop: 1 TRIP closure.Ftest = 58.50Hz – 1.0Hz = 57.50HzIref = 1.5A

Pre-fault Fault 1 (Pickup - 25%)Mag Angle Freq Mag Angle Freq

Va 69.3 0 60 Va 69.3 0 57.50Vb 69.3 -120 60 Vb 69.3 -120 57.50Vc 69.3 120 60 Vc 69.3 120 57.50Ia 0 0 60 Ia 1.5 0 57.50Ib 0 -120 60 Ib 1.5 -120 57.50Ic 0 120 60 Ic 1.5 120 57.50

Confirm operating times are within 5ms of delay time value.


Underfrequency Delay can be checked off once testing is completed.

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6.8.2 Underfrequency Minimum Operating Voltage test:

Three Phase Minimum Operating Voltage Test:Apply three phase balanced voltage and current with an underfrequency component.Vtest at ± 5% V1test at – 5% = .70 x 69.3V x .95 = 46.1VV2test at + 5% = .70 x 69.3V x 1.05 = 50.9 VFtest = 57.50HzMonitor: PICKUP LED on the front panel

Pre-fault Fault 1 (Vtest + 5%) Fault 0 (Vtest – 5%)Mag Angle Freq Mag Angle Freq Mag Angle Freq

Va 69.3 0 60 Va 46.1 0 57.50

Va 50.9 0 57.50

Vb 69.3 -120 60 Vb 46.1 -120 57.50

Vb 50.9 -120 57.50

Vc 69.3 120 60 Vc 46.1 120 57.50

Vc 50.9 120 57.50

Ia 0 0 60 Ia 1.5 0 57.50

Ia 1.5 0 57.50

Ib 0 -120 60 Ib 1.5 -120 57.50

Ib 1.5 -120 57.50

Ic 0 120 60 Ic 1.5 120 57.50

Ic 1.5 120 57.50



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Level accuracy: +/- .25% of full scale (11 to 130V); +/- 8% of full scale (130 to 273V). For open delta connection, error is 2 times as shown.

Phase Minimum Polarizing Voltage can be checked off once testing is completed.

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6.8.3 Underfrequency Minimum Operating Current

Three Phase Minimum Operating Current Test:Apply three phase balanced voltage and current with an underfrequency component.Itest at ± 5% Minimum CurrentI1test at – 5% = .20 x 5A x .95 = .95AI2test at + 5% = .20 x 5A x 1.05 = 1.05AFtest = 57.50HzMonitor: PICKUP LED on the front panel

Pre-fault Fault 1 (Vtest + 5%) Fault 0 (Vtest – 5%)Mag Angle Freq Mag Angle Freq Mag Angle Freq

Va 69.3 0 60 Va 69.3 0 57.50

Va 69.3 0 57.50

Vb 69.3 -120 60 Vb 69.3 -120 57.50

Vb 69.3 -120 57.50

Vc 69.3 120 60 Vc 69.3 120 57.50

Vc 69.3 120 57.50

Ia 0 0 60 Ia 1.05 0 57.50

Ia .95 0 57.50

Ib 0 -120 60 Ib 1.05 -120 57.50

Ib .95 -120 57.50

Ic 0 120 60 Ic 1.05 120 57.50

Ic .95 120 57.50



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Underfrequency Minimum Operating Current can be checked off once testing is completed.

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6.9 Breaker Failure Timing Test:

Breaker Failure Timing Test:Pre-condition: Logic Input – Breaker Functions – 52a contact must be assigned.Assert 52a contact close condition.Apply any fault condition to initiate 1 Trip output. Apply Bus Undervoltage condition at .50 x VTIref = 3.0AVtest = .50 x 69.3V = 34.65V

Contact Monitor: 7 AuxiliaryTiming Start: 1 TRIPTiming Stop/Voltage Stop: 7 Auxiliary

Pre-fault Fault 1 (Vtest + 5%)Mag Angle Freq Mag Angle Freq

Va 69.3 0 60 Va 34.65

0 60

Vb 69.3 -120 60 Vb 34.65

-120 60

Vc 69.3 120 60 Vc 34.65

120 60

Ia 0 0 60 Ia 3.0 0 60Ib 0 -120 60 Ib 3.0 -120 60Ic 0 120 60 Ic 3.0 120 60

Confirm operating times are within 5ms of delay time value.


Breaker Failure Delay can be checked off once testing is completed.

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6.10 Breaker Failure Minimum Current Test:

Breaker Failure Current Test:Pre-condition: Logic Input – Breaker Functions – 52a contact must be assigned.Assert 52a contact close condition.Apply any fault condition to initiate 1 Trip output. Apply Bus Undervoltage condition at .50 x VTVref = .50 x 69.3V = 34.65VItest = ± 5%I1test = .5 x 5A x 1.05 = 2.63AI2test = .5 x 5A x .95 = 2.38A

Contact Monitor: 7 AuxiliaryTiming Start: 1 TRIPTiming Stop/Voltage Stop: 7 Auxiliary

Pre-fault Fault 1 (Itest + 5%) Fault 0 (Itest – 5%)Mag Angle Freq Mag Angle Freq Mag Angle Freq

Va 69.3 0 60 Va 34.65

0 60 Va 34.65

0 60

Vb 69.3 -120 60 Vb 34.65

-120 60 Vb 34.65

-120 60

Vc 69.3 120 60 Vc 34.65

120 60 Vc 34.65

120 60


Confirm Fault 1operating times are within 5ms of delay time value.Confirm Fault 2 did not assert 7 Auxiliary.

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Breaker Failure Current can be checked off once testing is completed.

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