Page 1 Grid Solutions Plus Line Distance Protection System Instruction Manual Product version: 1.6x GE publication code: 1601-9019-C4 (GEK-113258D) 1601-9019-C4...
Page 2 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.
Page 3: Table Of Contents
Plus Line Distance Protection System Table of contents 1 GETTING STARTED Important procedures ....................1 Cautions and warnings..........................1 Inspection checklist............................1 Plus Introduction to the UR -series.................2 Hardware architecture ..........................3 Firmware architecture ..........................4 Communications overview ........................6 EnerVista software......................7 Software requirements..........................8 Plus Installing the EnerVista UR Setup software.................8 Software access............................
Page 4 TABLE OF CONTENTS Dimensions ..............................45 Module withdrawal and insertion ......................46 Rear terminal layout ...........................47 Electrical installation ....................48 Typical wiring ..............................49 Dielectric strength ............................50 Main processor module ..........................50 Power supply module..........................52 AC modules..............................53 Contact inputs and outputs ........................55 4 INTERFACES Front panel overview ....................61 Front panel interface operation......................62 Metering menu..............................63 Control menu ..............................63...
Page 5 TABLE OF CONTENTS FlexState settings ............................. 126 FlexState actual values.......................... 126 Real time clock......................127 User-programmable self-tests ................129 Serial port ........................130 Shared operands ....................... 131 Shared communication operands....................132 Communication logic operands ......................133 7 PROTECTION Protection overview....................135 Introduction to protection elements ....................
Page 6 TABLE OF CONTENTS 8 AUTOMATION Automation controller overview................373 Input and output structure........................374 Breakers ........................375 Breaker control ............................375 Breaker interlocking..........................378 Disconnects ........................ 380 Disconnect configuration........................380 Disconnect control ...........................385 Disconnect interlocking .........................388 Automation control....................390 Front panel status and control ......................390 Local-remote control scheme......................392 Synchrocheck .............................394 Selector switch ............................399...
Page 7 TABLE OF CONTENTS 11 METERING Metering source......................473 Phasor measurement unit ..................473 Phasor measurement unit configuration..................474 Phasor measurement unit calibration.................... 475 Phasor measurement unit communications................476 Phasor measurement unit triggering ..................... 479 Phasor measurement unit recording....................488 Phasor measurement unit reporting over network ..............492 Phasor measurement unit one-shot ....................
Page 8 TABLE OF CONTENTS Phase distance applied to power transformers ..........553 Example system with power transformers...................556 Ground directional overcurrent theory..............558 Ground directional overcurrent example ..................559 Series compensated lines ..................559 Memory polarized directional comparators.................560 Dynamic reach control...........................561 Single-pole tripping....................563 SLG fault scenario for single-pole tripping..................565 SLG fault evolving into an LLG fault scenario for single-pole tripping......566 Phase selection ............................567...
Page 9: Getting Started
Plus Line Distance Protection System Chapter 1: Getting started Getting started Plus Please read this section to help guide you through the initial setup of the D90 Line Distance Protection System. Important procedures It is highly recommended that the following sections are reviewed before placing the Plus in service.
Page 10: Introduction To The Ur Plus -Series
This new generation of equipment must also be easily incorporated into automation systems, at both the station and enterprise levels. The GE Multilin Advanced Universal Protection System Plus -series) has been developed to meet these goals.
Page 11: Hardware Architecture
Plus CHAPTER 1: GETTING STARTED INTRODUCTION TO THE UR -SERIES Plus The D90 is the sub-cycle distance protection and advanced automation controller for Plus the UR -series platform. Hardware architecture Plus The D90 is a microprocessor-based device. It has a modular design consisting of a chassis containing discrete modules that interface over a common bus.
Page 12: Firmware Architecture
Plus INTRODUCTION TO THE UR -SERIES CHAPTER 1: GETTING STARTED Plus Figure 1: D90 block diagram Plus Figure 2: D90 hardware overview Firmware architecture Plus The D90 is organized into six major functions. • Protection. • Automation. • Metering. PLUS LINE DISTANCE PROTECTION SYSTEM –...
Page 13 Plus CHAPTER 1: GETTING STARTED INTRODUCTION TO THE UR -SERIES • Digital fault recorder (DFR). • Equipment manager. • Front panel interface (HMI). These functions operate autonomously from one another. Each function has its own configuration parameters and each generates it own output signals. All functions share the hardware and the communications facilities within the device.
Page 14: Communications Overview
Plus INTRODUCTION TO THE UR -SERIES CHAPTER 1: GETTING STARTED Figure 3: Functional architecture Communications overview Plus The EnerVista UR Setup software can communicate with the relay through three ports: the front panel USB port, the rear Ethernet port, and the rear RS485 port. Both rear ports are located in slot D.
Page 15: Enervista Software
To communicate through the D90 rear RS485 port from a computer’s RS232 port, the GE RS232/RS485 converter box is required. This device (catalog number F485) connects to the computer using a straight-through serial cable. A shielded twisted-pair (20, 22, or 24...
Page 16: Software Requirements
EnerVista UR Setup from the enclosed 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.
Page 17 CHAPTER 1: GETTING STARTED ENERVISTA SOFTWARE EnerVista Launchpad will obtain the software from the Web or CD and automatically start the installation program. Select the complete path, including the new directory name, where the EnerVista Plus Setup will be installed. Click on Next to begin the installation.
Page 18: Software Access
Using the Quick Connect Feature section for details on configuring the USB port. Plus Verify that the latest version of the EnerVista UR Setup software is installed (available from the GE EnerVista CD or online from http://gegridsolutions.com/multilin). See the Software Installation section for installation details. Plus Plus Select the “D90...
Page 19 Plus Verify that the latest version of the EnerVista UR Setup software is installed (available from the GE EnerVista CD or online from http://gegridsolutions.com/multilin). Plus Plus Select the “UR...
Page 20 ENERVISTA SOFTWARE CHAPTER 1: GETTING STARTED Setup. Click the Device Setup button to open the Device Setup window, then click the Add Site button to define a new site. 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.
Page 21 USB port. Plus Verify that the latest version of the EnerVista UR Setup software is installed (available from the GE EnerVista CD or online from http://gegridsolutions.com/multilin). See the Software Installation section for installation details. Plus Plus Select the “UR...
Page 22 ENERVISTA SOFTWARE CHAPTER 1: GETTING STARTED The breaker configuration window will open and a status indicator will be displayed Plus on the lower left of the EnerVista UR Setup window. If the status indicator is red, verify that the Ethernet network cable is properly connected to the Ethernet port on the back of the relay and that the relay has been properly setup for communications.
Page 23: Product Description
Plus Line Distance Protection System Chapter 2: Product description Product description This section provides a basic functional overview and the technical specifications for the Plus Device overview Plus Designed for superior performance and ease-of-use, the D90 Line Distance Protection System is a single platform solution for protecting transmission lines from medium voltage (MV) to extra high voltage (EHV) and cables of various voltage levels.
Page 24: Front Panel Interface
DEVICE OVERVIEW CHAPTER 2: PRODUCT DESCRIPTION Front panel interface Plus An intuitive and easy-to-use color graphical display is provided in the D90 front panel. The display provides easy access and visualization of device information, ranging from the large display of metered values such as voltage, current, demand, energy, and sequence components, to a comprehensive display of fault reports, sequence of events, and transient recorded waveforms.
Page 25: Protection Features
CHAPTER 2: PRODUCT DESCRIPTION DEVICE OVERVIEW Figure 7: Front panel control example Front panel USB port Plus The front panel of the D90 provides a USB 2.0 port for simple data transfer and access. This makes downloading and uploading faster and more convenient. Figure 8: Front panel USB connection Protection features Plus...
Page 26 DEVICE OVERVIEW CHAPTER 2: PRODUCT DESCRIPTION protection for generators, transformers, and reactors. The relay can be applied to power systems with different earthing conditions, lines with in-zone transformers or tapped transformer feeders and overhead lines with series compensation. Each zone element for the phase and ground distance can be set to the quadrilateral or mho characteristic with the flexibility of designing different characteristic shapes to suit for different power system conditions.
Page 27 CHAPTER 2: PRODUCT DESCRIPTION DEVICE OVERVIEW Fault locator The integrated fault locator provides distance to fault in kilometers or miles. Communication aided (pilot) schemes Plus The D90 supports different pilot scheme functions for fast fault clearance for any faults within the protected line. The following types of pilot-aided schemes are available. •...
Page 28: Automation Features
DEVICE OVERVIEW CHAPTER 2: PRODUCT DESCRIPTION • Instantaneous and timed overcurrent elements for phase, neutral, ground, and negative-sequence protection. • Directional supervision is available for phase, neutral, and negative-sequence elements. • Time overcurrent elements can individually be set to use IEEE, IEC, or custom FlexCurves™.
Page 29: Equipment Manager Features
CHAPTER 2: PRODUCT DESCRIPTION DEVICE OVERVIEW Execution of the automation logic is independent of protection elements and protection logic. The automation capability is segmented into seven independent modules to simplify implementation and testing of complex schemes in which each module is independently editable and password protected.
Page 30: Metering And Monitoring Features
DEVICE OVERVIEW CHAPTER 2: PRODUCT DESCRIPTION Figure 11: Circuit breaker monitoring example Metering and monitoring features Voltage, current, and power metering are built into the protection platform as a standard feature. Current parameters are available as total waveform RMS magnitude, or as fundamental frequency only RMS magnitude and angle (phasor).
Page 31: Digital Fault Recorder
CHAPTER 2: PRODUCT DESCRIPTION DEVICE OVERVIEW Energy metering The metered values for real, reactive, and apparent power, as well as power factor, are Plus displayed via the front panel interface or through the EnerVista UR Setup software. Phasors The metered values and phasor representations for phase current, ground current, phase voltage, and auxiliary voltage are displayed via the front panel interface or through the Plus EnerVista UR...
Page 32: Communications
ORDER CODES CHAPTER 2: PRODUCT DESCRIPTION Transient recorder The transient recorder captures critical system data during a transient event. It is tailored to capture shorter duration events such as faults at a high resolution. The transient Plus recorder can be programmed to sample at 256 samples per cycle. The D90 can store up to 64 records in nonvolatile memory with up to one minute of storage capacity for all 16 analog channels and 128 digital channels.
Page 33: Specifications
Dropout level:............>102% of pickup Level accuracy: ............±0.5% of reading from 10 to 208 V Curve shapes:............GE IAV Inverse, Definite Time Curve multiplier: ..........0.00 to 600.00 in steps of 0.01 Timing accuracy: ..........±3% of operate time or ±4 ms (whichever is greater) PLUS LINE DISTANCE PROTECTION SYSTEM –...
Page 34 SPECIFICATIONS CHAPTER 2: PRODUCT DESCRIPTION BREAKER FAILURE Mode:................ single-pole, three-pole Current supervision: .......... phase current, neutral current Supervision pickup:..........0.001 to 30.000 pu in steps of 0.001 Supervision dropout:......... <98% of pickup Supervision accuracy at 0.1 to 2.0 × CT:.. ±2% of rated Supervision accuracy at >2.0 ×...
Page 35 CHAPTER 2: PRODUCT DESCRIPTION SPECIFICATIONS GROUND DISTANCE Characteristic: ............mho (memory polarized or offset) or quad (memory polarized or non-directional), selectable individually per zone Reactance polarization:........negative-sequence or zero-sequence current Non-homogeneity angle: ........–40 to 40° in steps of 1 Zones:...............5 Directionality:............forward, reverse, or non-directional per zone Reach (secondary ohms):........0.02 to 250.00 ohms in steps of 0.01 Reach accuracy:..........±5%, including the effect of CVT transients up to an SIR of 30 for V <...
Page 36 SPECIFICATIONS CHAPTER 2: PRODUCT DESCRIPTION Figure 15: Ground distance operating curves PLUS LINE DISTANCE PROTECTION SYSTEM – INSTRUCTION MANUAL...
Page 37 CHAPTER 2: PRODUCT DESCRIPTION SPECIFICATIONS GROUND INSTANTANEOUS OVERCURRENT Pickup level: ............0.000 to 30.000 pu in steps of 0.001 Dropout level:............<98% of pickup Level accuracy at 0.1 to 2.0 × CT:....±0.5% of reading or ±1% of rated (whichever is greater) Level accuracy at >2.0 × CT:......±1.5% of reading Overreach:..............<2% Pickup delay: ............0.00 to 600.00 seconds in steps of 0.01 Reset delay: ............0.00 to 600.00 seconds in steps of 0.01...
Page 38 SPECIFICATIONS CHAPTER 2: PRODUCT DESCRIPTION NEGATIVE-SEQUENCE DIRECTIONAL OVERCURRENT Directionality:............co-existing forward and reverse Polarizing:............... voltage Polarizing voltage:..........V_2 Operating current:..........I_2 Level sensing (zero-sequence): ....|I_0| – K × |I_1| Level sensing (negative-sequence):...|I_2| – K × |I_1| Restraint, K: ............0.000 to 0.500 in steps of 0.001 Characteristic angle:.........
Page 39 CHAPTER 2: PRODUCT DESCRIPTION SPECIFICATIONS NEUTRAL DIRECTIONAL OVERCURRENT Directionality:............co-existing forward and reverse Polarizing: ...............voltage, current, dual Polarizing voltage: ..........V_0 or VX Polarizing current:..........IG Operating current:..........I_0 Level sensing: ............3 × (|I_0| – K × |I_1|), IG; independent for forward and reverse Restraint (K):............0.000 to 0.500 in steps of 0.001 Characteristic angle: .........–90 to 90°...
Page 40 SPECIFICATIONS CHAPTER 2: PRODUCT DESCRIPTION OPEN POLE DETECTOR Functionality: ............detects an open pole condition, monitoring breaker auxiliary contacts, the current in each phase and optional voltages on the line Current pickup level:.......... 0.000 to 30.000 pu in steps of 0.001 Line capacitive reactances:......
Page 41 CHAPTER 2: PRODUCT DESCRIPTION SPECIFICATIONS Figure 16: Phase distance operating curves PLUS LINE DISTANCE PROTECTION SYSTEM – INSTRUCTION MANUAL...
Page 42 Dropout level: ............>102% of pickup Level accuracy:............ ±0.5% of reading from 10 to 208 V Curve shapes:............GE IAV Inverse; Definite Time (0.1 second base curve) Curve multiplier:..........0.00 to 600.00 in steps of 0.01 Timing accuracy for operation at <0.90 ×...
Page 43 CHAPTER 2: PRODUCT DESCRIPTION SPECIFICATIONS POWER SWING DETECT Functions: ...............power swing block, out-of-step trip Characteristic: ............mho or quadrilateral Measured impedance:........positive-sequence Blocking and tripping modes: .......two-step or three-step Tripping mode: .............early or delayed Current supervision pickup: ......0.050 to 30.000 pu in steps of 0.001 Current supervision dropout: ......<98% of pickup Forward reach:.............0.10 to 500.00 ohms in steps of 0.01 (secondary ohms) Reverse reach:............0.10 to 500.00 ohms in steps of 0.01 (secondary ohms)
Page 44: Automation Specifications
SPECIFICATIONS CHAPTER 2: PRODUCT DESCRIPTION UNDERFREQUENCY Elements:..............2 Minimum signal:..........0.10 to 1.25 pu in steps of 0.01 Pickup level:............20.00 to 65.00 Hz in steps of 0.01 Dropout level: ............pickup level + 0.03 Hz Level accuracy:............ ±0.01 Hz Time delay: ............
Page 45: Equipment Manager
CHAPTER 2: PRODUCT DESCRIPTION SPECIFICATIONS AUTOMATION VIRTUAL OUTPUTS Output points:............255 Programmability: ..........output of an automation logic equation or input to an automation logic equation BREAKER CONTROL Mode:................single-pole, three-pole Control: ..............open/close, local/SCADA Control seal-in: .............0 to 2000 ms in steps of 1 BREAKER INTERLOCKING Interlocking inputs: ..........6 DISCONNECT CONTROL...
Page 46: Metering Specifications
SPECIFICATIONS CHAPTER 2: PRODUCT DESCRIPTION Metering specifications CURRENT METERING Type: ................. phase and ground RMS current Accuracy at 0.1 to 2.0 × CT: ......±0.25% of reading or ±0.1% of rated, whichever is greater Accuracy at >2.0 × CT:........±1.0% of reading DATA LOGGER Channels:..............
Page 47: Digital Fault Recorder Specifications
CHAPTER 2: PRODUCT DESCRIPTION SPECIFICATIONS Digital fault recorder specifications DISTURBANCE RECORDER Storage capacity:..........one record with all available channels at 60 samples per second for 40 seconds Maximum records: ..........64 Sampling rate:............1 sample per cycle Sampling accuracy:...........<1 ms per second of recording Analog channels: ..........64 Analog channel data:........any FlexAnalog™...
Page 48: Front Panel Interface
SPECIFICATIONS CHAPTER 2: PRODUCT DESCRIPTION TRANSIENT RECORDER Storage capacity:..........one record with all available channels at 32 samples per cycle for 1 minute Number of records:..........1 to 64 Sampling rate:............16 to 256 samples per power cycle Timestamp accuracy:........<10 μs per second of recording Analog channels: ..........
Page 49: Hardware Specifications
CHAPTER 2: PRODUCT DESCRIPTION SPECIFICATIONS METERING DISPLAY Summary: ...............displays present values of voltage, current, real power, reactive power, power factor, and frequency on a per-phase and total basis Phasors:..............digital and graphical display of present voltage and current magnitudes and angles Sequence components:........displays present magnitudes and angles of current and voltage sequence components Energy: ..............four-quadrant display of accumulated energy...
Page 50 SPECIFICATIONS CHAPTER 2: PRODUCT DESCRIPTION CONTACT OUTPUTS: SOLID-STATE RELAY Make and carry for 0.2 s: ........30 A as per ANSI C37.90 Continuous carry: ..........6 A Break at L/R of 40 ms: ........10 A at 250 V DC Operate time:............<100 μs Contact material:..........
Page 51: Communications Specifications
CHAPTER 2: PRODUCT DESCRIPTION SPECIFICATIONS RS485 PORT Baud rates:.............300, 600, 1200, 2400, 4800, 9600, 19200, 38400, 57600, 115200 Protocol: ..............Modbus RTU and DNP 3.0 Distance: ..............1200 m Isolation:..............2 kV SOLID-STATE RELAY Make and carry for 0.2 s:.........30 A as per ANSI C37.90 Carry continuous: ..........6 A Break at L/R of 40 ms:........10.0 A DC at 250 V DC Operate time:............<...
Page 52: Environmental Specifications
SPECIFICATIONS CHAPTER 2: PRODUCT DESCRIPTION Environmental specifications OPERATING TEMPERATURE Cold: ................IEC 60028-2-1, 16 hours at –40°C Dry heat: ..............IEC 60028-2-2, 16 hours at 85°C OTHER ENVIRONMENTAL SPECIFICATIONS Altitude: ..............up to 2000 m Installation category:........II IP rating:..............IP30 Noise:................
Page 53: Installation
Plus Line Distance Protection System Chapter 3: Installation Installation Plus This section describes the physical and electrical installation of the D90 Physical installation Plus The D90 is designed as a 19-inch rack horizontal mount unit. The modular design allows the relay to be easily upgraded or repaired by a qualified service person. The faceplate is hinged to allow easy access to the removable modules.
Page 54: Module Withdrawal And Insertion
PHYSICAL INSTALLATION CHAPTER 3: INSTALLATION Plus Figure 18: D90 dimensions Module withdrawal and insertion Prior to removal of the AC module, the CT secondary circuit must be shorted in order to DANGER: prevent an open-circuit condition on a CT. Module withdrawal and insertion may only be performed when control power has been DANGER: removed from the unit.
Page 55: Rear Terminal Layout
CHAPTER 3: INSTALLATION PHYSICAL INSTALLATION Figure 19: Module withdrawal and insertion To withdrawal a module, simultaneously pull the ejector-inserter clips located at the top and bottom of each module. Before performing this action, ensure that control power is removed from the relay. Record the original location of the module to ensure that the same or replacement module is inserted into the correct slot.
Page 56: Electrical Installation
ELECTRICAL INSTALLATION CHAPTER 3: INSTALLATION Figure 20: Rear terminal view Figure 21: Example of modules in G slot Electrical installation Plus This section describes the electrical installation of the D90 PLUS LINE DISTANCE PROTECTION SYSTEM – INSTRUCTION MANUAL...
Page 57: Typical Wiring
CHAPTER 3: INSTALLATION ELECTRICAL INSTALLATION Typical wiring Plus A typical wiring diagram for the D90 is shown below. This diagram provides an example of how to wire the device. Actual wiring will vary according to application. Figure 22: Typical wiring diagram PLUS LINE DISTANCE PROTECTION SYSTEM –...
Page 58: Dielectric Strength
ELECTRICAL INSTALLATION CHAPTER 3: INSTALLATION Dielectric strength Plus The dielectric strength of the UR -series module hardware is shown in the following table. Plus Table 1: Dielectric strength for UR -series hardware Function Terminals Dielectric strength from Power supply module high (+), low (+), (–) chassis 2000 V AC for 1 minute...
Page 59 CHAPTER 3: INSTALLATION ELECTRICAL INSTALLATION To minimize errors from noise, the use of shielded twisted pair wire is recommended. Correct polarity must also be observed. For instance, the relays must be connected with all RS485 “+” terminals connected together, and all RS485 “–” terminals connected together. The COM terminal should be connected to the common wire inside the shield, when provided.
Page 60: Power Supply Module
ELECTRICAL INSTALLATION CHAPTER 3: INSTALLATION Figure 24: IRIG-B connection Power supply module The power supply module provides power to the relay and supplies power for dry contact input connections. It can be connected to any of the following standard power sources. •...
Page 61: Ac Modules
CHAPTER 3: INSTALLATION ELECTRICAL INSTALLATION AC modules An AC module has voltage inputs on channels 8 through 12 inclusive. Channel 10 is intended for connection to a source that represents phase A voltage of the power system (produced by a VT or CVT). Likewise, channel 11 is intended for connection to phase B, and channel 12 is intended for connection to phase C.
Page 62 ELECTRICAL INSTALLATION CHAPTER 3: INSTALLATION Figure 26: Zero-sequence core-balance CT installation The phase voltage channels are used for most metering and protection purposes. The auxiliary voltage channel is used as an input for features such as synchrocheck, volts per hertz, and auxiliary undervoltage. A typical AC module wiring diagram is shown below.
Page 63: Contact Inputs And Outputs
CHAPTER 3: INSTALLATION ELECTRICAL INSTALLATION Figure 27: Typical AC module wiring Contact inputs and outputs Every input/output module has 24 terminal connections. They are arranged in two terminals per row, with twelve rows in total. A given row of two terminals may be used for the outputs of one relay.
Page 64 ELECTRICAL INSTALLATION CHAPTER 3: INSTALLATION Form-A and solid-state relay output contacts Some form-A and solid-state relay (SSR) outputs include circuits to monitor the DC voltage across the output contact when it is open, and the DC current through the output contact when it is closed.
Page 65 CHAPTER 3: INSTALLATION ELECTRICAL INSTALLATION other contact input terminal. The maximum external source voltage for this arrangement is 300 V DC. The voltage threshold at which each group of four contact inputs will detect a closed contact input is programmable as from 24 to 250 V DC. Figure 30: Dry and wet contact input connections Wherever a tilde “~”...
Page 66 ELECTRICAL INSTALLATION CHAPTER 3: INSTALLATION Figure 31: Terminal block pin view Table 2: Module configuration Contact input/output module Type A Type B Type C Type D Type E Type F 1A Form-A output SSR output 1 + Form-A output Form-A output Contact input Form-A output 1B Form-A output...
Page 67 CHAPTER 3: INSTALLATION ELECTRICAL INSTALLATION Contact input/output module Type A Type B Type C Type D Type E Type F 6B Contact input Contact input Contact input Form-A output Contact input Form-A output 2 – 2 – 2 – 6 – 12 + 6 –...
Page 68 ELECTRICAL INSTALLATION CHAPTER 3: INSTALLATION PLUS LINE DISTANCE PROTECTION SYSTEM – INSTRUCTION MANUAL...
Page 69: Interfaces
Plus Line Distance Protection System Chapter 4: Interfaces Interfaces Plus This section describes the methods of interfacing with the D90 Front panel overview Plus The front panel provides a convenient means to interface with the D90 . The front panel interface consists of a color LCD display (annunciator) and two sets of user-programmable Plus pushbuttons.
Page 70: Front Panel Interface Operation
FRONT PANEL OVERVIEW CHAPTER 4: INTERFACES The front panel also contains a high-speed USB port that is dedicated for communications with a PC running the EnerVista software. No settings are entered on the front panel; use the software instead. Front panel interface operation The front panel interface is a color TFT panel with pushbuttons for menu navigation and dedicated pushbuttons for control functions.
Page 71: Metering Menu
CHAPTER 4: INTERFACES FRONT PANEL OVERVIEW Figure 34: Menu structure Metering menu The system metering quantities are available from the front panel in the metering menu. These values are derived automatically from the metering source. The following metering screens are available. •...
Page 72: Digital Fault Recorder Menu
FRONT PANEL OVERVIEW CHAPTER 4: INTERFACES Figure 36: Mimic page - operate example The front panel control pushbuttons can be placed under password security. When password security is enabled, the front panel will request the command password before performing any actions. Figure 37: Command password entry screen Digital fault recorder menu The digital fault recorder menu provides access to various records stored within the...
Page 73 CHAPTER 4: INTERFACES FRONT PANEL OVERVIEW Figure 38: Digital fault recorder - example summary page The sequence of events record can be accessed from this page. Using the navigations keys, the user can scroll or page through the events list. Two cursors are provided for measurement of the time difference between events.
Page 74: Equipment Manager Menu
FRONT PANEL OVERVIEW CHAPTER 4: INTERFACES Records can be retrieved and deleted and triggers can be manually generated from this screen. Figure 41: Example transient record The digital fault recorder menu disturbance record menu lists all disturbance records Plus currently stored in the D90 .
Page 75: Annunciator
CHAPTER 4: INTERFACES FRONT PANEL OVERVIEW Figure 43: Equipment manager battery monitor alarms example Annunciator The annunciator is a color TFT panel located that emulates the functionality found in a conventional annunciator unit. Annunciator operation The annunciator provides indications on the status of system alarm points. It also displays self-test messages and product information for the unit.
Page 76 FRONT PANEL OVERVIEW CHAPTER 4: INTERFACES Figure 45: Annunciator alarm sequence The annunciator states are described in the following table. Table 3: Annunciator states Line Process Pushbutton Sequence Visual indication Normal Normal Abnormal Alarm Fast flash Abnormal Acknowledge Acknowledged Normal Acknowledge To line 4 To line 4...
Page 77 CHAPTER 4: INTERFACES FRONT PANEL OVERVIEW Figure 46: Self-test page example Product information page The product information page contains all of the constituent data describing the makeup of the IED, including the order code, firmware and configuration filenames, and serial numbers of each module.
Page 78 FRONT PANEL OVERVIEW CHAPTER 4: INTERFACES PLUS LINE DISTANCE PROTECTION SYSTEM – INSTRUCTION MANUAL...
Page 79: Enervista Software Suite
Plus Line Distance Protection System Chapter 5: EnerVista software suite EnerVista software suite The EnerVista software suite is an industry-leading set of programs that simplifies every Plus aspect of the D90 . The EnerVista suite provides tools to monitor the status of your protected asset, maintain the relay, and integrate information measured by the Plus into DCS or SCADA monitoring systems.
Page 80 Plus EXTENDED ENERVISTA UR SETUP FEATURES CHAPTER 5: ENERVISTA SOFTWARE SUITE In these situations, typically 90% or greater of the settings are identical between all devices. The templates feature allows engineers to configure and test these common settings, then lock them so they are not available to users. For example, these locked down settings can be hidden from view for field engineers, allowing them to quickly identify and concentrate on the specific settings.
Page 81 Plus CHAPTER 5: ENERVISTA SOFTWARE SUITE EXTENDED ENERVISTA UR SETUP FEATURES Editing a settings template The settings template editing feature allows the user to specify which settings are Plus available for viewing and modification in EnerVista UR Setup. By default, all settings except the FlexLogic™...
Page 82 Plus EXTENDED ENERVISTA UR SETUP FEATURES CHAPTER 5: ENERVISTA SOFTWARE SUITE Figure 50: Setting template view, two settings specified as editable Click on Save to save changes to the settings template. Proceed through the settings tree to specify all viewable settings. Adding password protection to a template It is highly recommended that templates be saved with password protection to maximize security.
Page 83 Plus CHAPTER 5: ENERVISTA SOFTWARE SUITE EXTENDED ENERVISTA UR SETUP FEATURES Plus EnerVista UR Setup main screen. Select the Template Mode > View in Template Mode option (online) or the Settings File Template > View in Template Mode option (offline). Enter the template password then click OK to apply the template.
Page 84: Securing And Locking Flexlogic™ Equations
Plus EXTENDED ENERVISTA UR SETUP FEATURES CHAPTER 5: ENERVISTA SOFTWARE SUITE Removing a settings template It may be necessary at some point to remove a settings template. Once a template is removed, it cannot be reapplied and it will be necessary to define a new settings template. Select an installed device or settings file from the tree menu on the left of the Plus EnerVista UR...
Page 85: Settings File Traceability
Plus CHAPTER 5: ENERVISTA SOFTWARE SUITE EXTENDED ENERVISTA UR SETUP FEATURES Figure 54: Locking FlexLogic entries through setting templates Locking FlexLogic™ equations to a serial number A settings file and associated FlexLogic™ equations can also be locked to a specific UR serial number.
Page 86 Plus EXTENDED ENERVISTA UR SETUP FEATURES CHAPTER 5: ENERVISTA SOFTWARE SUITE The traceability information is only included in the settings file if a complete settings file is Plus Plus either transferred to the D90 device or obtained from the D90 device.
Page 87 Plus CHAPTER 5: ENERVISTA SOFTWARE SUITE EXTENDED ENERVISTA UR SETUP FEATURES This information is also available in printed settings file reports as shown in the example below. Figure 57: Settings file report showing traceability data Online traceability information Plus The D90 serial number and file transfer date are available for an online device through actual values.
Page 88 Plus EXTENDED ENERVISTA UR SETUP FEATURES CHAPTER 5: ENERVISTA SOFTWARE SUITE PLUS LINE DISTANCE PROTECTION SYSTEM – INSTRUCTION MANUAL...
Page 89: Communications Communications Overview
Plus Line Distance Protection System Chapter 6: Communications Communications Plus This section describes how to program the D90 communications settings. Communications overview Plus The D90 has one Ethernet port (port 1) on the main CPU module and two additional Ethernet ports (ports 2 and 3) on the communications module. Each port supports 100Base-FX over multi-mode fiber and 10/100Base-TX over twisted-pair, with auto- negotiation.
Page 90 COMMUNICATIONS OVERVIEW CHAPTER 6: COMMUNICATIONS Figure 59: Simple network topology without communications cards The topology shown below allows SCADA, GOOSE, configuration, and monitoring functions to share a single network. No redundancy is provided in this configuration. A Plus communications processor is required in each D90 device to facilitate SCADA and GOOSE messaging.
Page 91 CHAPTER 6: COMMUNICATIONS COMMUNICATIONS OVERVIEW Figure 61: Simple single network topology with redundancy The topology below illustrates a dual LAN network. Configuration, and monitoring functions are provided on LAN 1 with no redundancy. LAN 2 is dedicated to SCADA and GOOSE communications and includes redundant hardware and media.
Page 92: Network Settings
NETWORK SETTINGS CHAPTER 6: COMMUNICATIONS Figure 63: Simple dual redundant network topology The topology below illustrates a dedicated LAN for configuration and monitoring functions Plus and dual redundant LANs for SCADA and GOOSE traffic. Each D90 device will service clients on either network as required. GOOSE messages are transmitted and received on both LANs simultaneously.
Page 93 CHAPTER 6: COMMUNICATIONS NETWORK SETTINGS The single IP redundancy configuration provides compatibility with UR-series relays and other devices with single-IP redundancy, and provides a maximum level of switchover performance. In this configuration, the port 2 IP address, subnet mask, and gateway address are used and the port 3 settings are ignored.
Page 94 NETWORK SETTINGS CHAPTER 6: COMMUNICATIONS The IP addresses are used with the DNP, Modbus/TCP, IEC 61580, IEC 60870-5-104 and TFTP protocols. When the NSAP address or any user map setting (when used with DNP) is changed, it will NOTE: not become active until power to the relay has been cycled (off-to-on). The following settings are available for each Ethernet port, except for OSI Network Address , which are not port-specific, and the...
Page 95 CHAPTER 6: COMMUNICATIONS NETWORK SETTINGS OSI Network Address (NSAP) Range: 20 alphanumeric characters Default: 00 00 00 00 00 00 00 00 00 00 00 00 00 00 00 00 49 00 00 00 This setting specifies the NSAP address used with the IEC 61850 protocol over the OSI (CLNP/TP4) stack.
Page 96: Tftp Protocol
NETWORK SETTINGS CHAPTER 6: COMMUNICATIONS – “PRT 2-3 SUBNET OVRLP”: The entered network parameters for Ethernet port 2 overlap the network parameters for Ethernet port 3. – “>1 GATEWAY DEFINED”: The user has entered more than one default gateway. Active Port 1 IP Address, Active Port 2 IP Address, Active Port 3 IP Address Range: standard IP address range These actual values display the configured IP address for each Ethernet port.
Page 97: Sntp Protocol
CHAPTER 6: COMMUNICATIONS NETWORK SETTINGS TFTP Data UDP Port Number 1, TFTP Data UDP Port Number 2, TFTP Data UDP Port Number 3, TFTP Data UDP Port Number 4 Range: 0 to 65535 in steps of 1 Default: 0 These settings specify data for UDP port numbers 1 through 4. A TFTP data port value of Plus zero specifies that the D90 will automatically assign a port number.
Page 98: Ethernet Actual Values
NETWORK SETTINGS CHAPTER 6: COMMUNICATIONS UDP Port Number Range: 0 to 65535 in steps of 1 Default: 123 This setting specifies the UDP port number for use with the SNTP protocol. Ethernet Interface Range: 1, 2, or 3 Default: 1 This setting selects the Ethernet port to use for SNTP communications.
Page 99: Modbus Communications
CHAPTER 6: COMMUNICATIONS MODBUS COMMUNICATIONS IEC 61850 Available. Range: No, Yes This actual value indicates if the IEC 61850 protocol in enabled on the Ethernet ports. Configure IP Network Status Range: OK, PORT 1 NETMASK ERROR, PORT 2 NETMASK ERROR, PORT 3 NETMASK ERROR, PORT 1 IP ADDR RSVD, PORT 2 IP ADDR RSVD, PORT 3 IP ADDR RSVD, PORT 1 IP ADDR LPBK, PORT 2 IP ADDR LPBK, PORT 3 IP ADDR LPBK, PORT 1 IP ADDR NETWK, PORT 2 IP ADDR NETWK, PORT 3 IP ADDR NETWK, PRT 1-2 SUBNET OVRLP, PRT 1-3 SUBNET OVRLP,...
Page 100: Modbus User Map
MODBUS COMMUNICATIONS CHAPTER 6: COMMUNICATIONS Modbus TCP Port Number Range: 1 to 65535 in steps of 1 Default: 502 This setting specifies the Modbus TCP port number for Ethernet communications. Power Plus to the D90 must be cycled for changes to this setting to take effect. Modbus user map The Modbus user map provides read-only access for up to 256 registers.
Page 101: Dnp Communications
CHAPTER 6: COMMUNICATIONS DNP COMMUNICATIONS DNP communications The DNP protocol allows for the optimization of control and data acquisition between the equipment in the substation and the central control center. The protocol is scalable; that is, it is designed to be compatible with the latest high speed LAN technology yet still be implemented over slower speed serial links.
Page 102 DNP COMMUNICATIONS CHAPTER 6: COMMUNICATIONS Figure 71: DNP protocol configuration settings The following settings are available for DNP protocol communications. DNP Channel 1 Port, DNP Channel 2 Port Range: None, COM1-RS485, Network-TCP, Network-UDP Default: None These settings specify the communications port assigned to the DNP protocol for each channel.
Page 103 CHAPTER 6: COMMUNICATIONS DNP COMMUNICATIONS DNP Channel Address Range: 0 to 65519 in steps of 1 Default: 1 Plus This setting specifies the DNP slave address. This number identifies the D90 on a DNP communications link. Each DNP slave should be assigned a unique address. DNP Client Address 1 through DNP Client Address 5 Range: any standard IP address Default: 0.0.0.0...
Page 104 DNP COMMUNICATIONS CHAPTER 6: COMMUNICATIONS DNP Current Default Deadband, DNP Voltage Default Deadband, DNP Power Default Deadband, DNP Power Factor Default Deadband, DNP Energy Default Deadband, DNP Other Default Deadband Range: 0 to 65535 in steps of 1 Default: 30000 These settings determine when to trigger unsolicited responses containing analog Input Plus data.
Page 105: Dnp User Point List
CHAPTER 6: COMMUNICATIONS DNP COMMUNICATIONS configuration of 0 to 32 binary output paired controls. The paired control mapping is reverse paired order, meaning that is starts backward from the end of the Control Outputs List. For example, when the DNP Number of Paired Controls setting is configured as 4, the DNP Points Lists web page shows Automation Virtual Inputs 121 to 128 are paired, as shown in the figure.
Page 106: Iec 60870-5-104 Communications
IEC 60870-5-104 COMMUNICATIONS CHAPTER 6: COMMUNICATIONS Figure 73: DNP user point list configuration settings The following settings are available for points 0 through 255. DNP Binary Input Point 0 Range: any FlexLogic™ operand Default: Off This setting represents DNP binary input point 0 and is configured by assigning an appropriate FlexLogic™...
Page 107 CHAPTER 6: COMMUNICATIONS IEC 60870-5-104 COMMUNICATIONS Figure 74: IEC 60870-5-104 protocol configuration settings The following settings are available for the IEC 60870-5-104 protocol. IEC TCP Port Number Range: 0 to 65535 in steps of 1 Default: 2404 This setting specifies the TCP port number to use for IEC 60870-5-104 communications. IEC Client Address 1 through IEC Client Address 5 Range: standard IP address format Default: 0.0.0.0...
Page 108: Iec 60870-5-104 Point Lists
IEC 60870-5-104 COMMUNICATIONS CHAPTER 6: COMMUNICATIONS floating point value) points can be used to change threshold values, from the default, for each individual M_ME_NC_1 analog point. Whenever power is removed and re-applied Plus to the D90 , the default thresholds will be in effect. IEC 60870-5-104 point lists The MSP and MME points for IEC 60870-5-104 protocol can configured to a maximum of 256 points.
Page 109: Iec 60870-5-104 Actual Values
CHAPTER 6: COMMUNICATIONS IEC 61850 COMMUNICATIONS IEC 60870-5-104 actual values Select the Actual Values > Communications > Communication menu item to open the communications actual values window. Figure 76: IEC 60870-5-104 actual values There is one actual value related to the IEC 60870-5-104 communications feature. IEC 60570-5-104 Available Range: Yes, No This actual value indicates whether the IEC 60870-5-104 communications feature is...
Page 110 IEC 61850 COMMUNICATIONS CHAPTER 6: COMMUNICATIONS Since GSSE/GOOSE messages are multicast Ethernet by specification, they will not usually NOTE: be forwarded by network routers. However, GOOSE messages may be forwarded by routers if the router has been configured for VLAN functionality. General transmission configuration Select the Settings >...
Page 111 CHAPTER 6: COMMUNICATIONS IEC 61850 COMMUNICATIONS Destination MAC Range: standard MAC address format Default: 00 00 00 00 00 00 This setting specifies the destination Ethernet MAC address for the GSSE transmission. This address must be a multicast address and the least significant bit of the first byte must be set.
Page 112 IEC 61850 COMMUNICATIONS CHAPTER 6: COMMUNICATIONS GOOSE VLAN Priority Range: 0 to 7 in steps of 1 Default: 4 This setting indicates the Ethernet priority of GOOSE messages. This allows GOOSE messages to have higher priority than other Ethernet data. This setting is required by IEC 61850.
Page 113 CHAPTER 6: COMMUNICATIONS IEC 61850 COMMUNICATIONS Figure 80: Configurable GOOSE transmission configuration settings The following settings are available for each dataset for configurable GOOSE transmission. Function Range: Enabled, Disabled Default: Disabled This setting enables and disabled the configurable GOOSE transmission functionality. Range: up to 65 ASCII characters Default: GOOSEOut_1 This setting represents the IEC 61850 GOOSE application ID (GoID) name string sent as...
Page 114 IEC 61850 COMMUNICATIONS CHAPTER 6: COMMUNICATIONS ETYPE APPID Range: 0 to 16383 in steps of 1 Default: 0 This setting allows the selection of a specific application ID for each GOOSE sending device. This value can be left at its default if the feature is not required. This setting is required by IEC 61850.
Page 115 CHAPTER 6: COMMUNICATIONS IEC 61850 COMMUNICATIONS Dataset Item 1, Dataset Item 2, Dataset Item 3,..., Dataset Item 64 Range: all valid MMS data item references for transmitted data Default: 0 These settings are used to select an MMS data item for each configurable GOOSE dataset item.
Page 116 IEC 61850 COMMUNICATIONS CHAPTER 6: COMMUNICATIONS Figure 82: Remote devices configuration settings The following settings are available for each of the 32 remote devices. Range: up to 20 alphanumeric characters Default: Remote Device 1 Up to 32 remote devices can be selected for setting purposes. A receiving relay must be programmed to capture messages from only those originating remote devices of interest.
Page 117 CHAPTER 6: COMMUNICATIONS IEC 61850 COMMUNICATIONS defined by the user selection of the FlexLogic™ operand whose state is represented in the GSSE/GOOSE message. A user must program a DNA point from the appropriate FlexLogic™ operand. Table 4: IEC 61850 DNA Assignments IEC 61850 definition FlexLogic™...
Page 118 IEC 61850 COMMUNICATIONS CHAPTER 6: COMMUNICATIONS Default State Range: On, Off, Latest/On, Latest/Off Default: Off This setting selects the logic state for this point if the local relay has just completed startup or the remote device sending the point is declared to be non-communicating. The following choices are available.
Page 119 CHAPTER 6: COMMUNICATIONS IEC 61850 COMMUNICATIONS Figure 84: Remote double-point status inputs configuration settings The following settings are available for each of the 16 remote double-point status inputs. Name Range: up to 20 alphanumeric characters Default: RemDPS Ip 1 This setting specifies specific an exact identification (ID) for each remote double-point status input.
Page 120 IEC 61850 COMMUNICATIONS CHAPTER 6: COMMUNICATIONS Table 5: IEC 61850 DNA Assignments IEC 61850 definition FlexLogic™ operand Test IEC 61850 TEST MODE ConfRev IEC 61850 CONF REV Select the Settings > Communications > IEC 61850 > GSSE/GOOSE Configuration > Inputs/Outputs > Remote Outputs DNA menu item to open the remote inputs configuration window.
Page 121 CHAPTER 6: COMMUNICATIONS IEC 61850 COMMUNICATIONS Figure 86: Remote output UserSt bit pair configuration settings The following settings are available for each of the 32 bit pairs. Operand Range: any FlexLogic™ operand Default: Off This setting specifies the FlexLogic™ operand assigned to UserSt point 1. Events Range: Enabled, Disabled Default: Disabled...
Page 122: Iec 61850 Server Configuration
IEC 61850 COMMUNICATIONS CHAPTER 6: COMMUNICATIONS The following settings are available for each of the IEC 61850 GOOSE analog inputs. Default Value Range: –1000000.000 to 1000000.000 in steps of 0.001 Default: 1000.000 This setting specifies the value of the GOOSE analog input when the sending device is offline and the Default Mode setting is set to “Default Value”.This setting is stored as an...
Page 123 CHAPTER 6: COMMUNICATIONS IEC 61850 COMMUNICATIONS Figure 88: IEC 61850 server configuration settings The following settings are available. IED Name Range: up to 32 alphanumeric characters Default: IEDName This setting represents the MMS domain name where all IEC/MMS logical nodes are located.
Page 124: Logical Node Prefixes
IEC 61850 COMMUNICATIONS CHAPTER 6: COMMUNICATIONS Logical node prefixes The IEC 61850 logical node name prefix settings are used to create name prefixes to uniquely identify each logical node. For example, the logical node “PTOC1” may have the name prefix “abc”. The full logical node name will then be “abcMMXU1”. Valid characters for the logical node name prefixes are upper and lowercase letters, numbers, and the underscore (_) character, and the first character in the prefix must be a letter.
Page 125 CHAPTER 6: COMMUNICATIONS IEC 61850 COMMUNICATIONS MMXU1 LN Prefix through MMXU4 LN Prefix Range: six character ASCII string Default: empty These settings specify the prefixes for measured quantity logical nodes 1 through 4. PIOC1 LN Prefix through PIOC14 LN Prefix Range: six character ASCII string Default: empty These settings specify the prefixes for instantaneous overcurrent logical nodes 1...
Page 126: Mmxu Deadbands
IEC 61850 COMMUNICATIONS CHAPTER 6: COMMUNICATIONS RREC1 LN Prefix Range: six character ASCII string Default: empty This setting specifies the prefix for the autoreclose logical node. RSYN1 LN Prefix, RSYN2 LN Prefix Range: six character ASCII string Default: empty This setting specifies the prefix for the synchrocheck logical nodes 1 and 2. XCBR1 LN Prefix through XCBR LN Prefix Range: six character ASCII string Default: empty...
Page 127 CHAPTER 6: COMMUNICATIONS IEC 61850 COMMUNICATIONS Figure 90: IEC 61850 MMXU deadband configuration settings The following settings are available for each of the four MMXU nodes. Total Watt Deadband Range: 0.001 to 100.000% in steps of 0.001 Default: 10.000% This setting specifies the real power deadband value. The maximum value representing 100% of deadband is 46 ×...
Page 128: Ggio1 Status Configuration
IEC 61850 COMMUNICATIONS CHAPTER 6: COMMUNICATIONS PhV Phase A Deadband, PhV Phase B Deadband, PhV Phase C Deadband Range: 0.001 to 100.000% in steps of 0.001 Default: 10.000% These settings specify the Va, Vb, and Vc phase voltage deadband values. The 100% deadband value is 275 ×...
Page 129: Ggio2 Control Configuration
CHAPTER 6: COMMUNICATIONS IEC 61850 COMMUNICATIONS generally be used for SOE logs since the buffering capability reduces the chances of missing data state changes. Unbuffered reporting should generally be used for local status display. Select the Settings > Communications > IEC 61850 > GGIO1 Status Configuration menu item to open the GGIO1 status configuration window.
Page 130: Ggio4 Analog Configuration
IEC 61850 COMMUNICATIONS CHAPTER 6: COMMUNICATIONS Figure 92: IEC 61850 GGIO2 control configuration The following setting is available for each of the 64 GGIO2 control points. Each control Plus point is mapped to a corresponding D90 virtual input. For example, GGIO2 control point SPCSO 3 is mapped to virtual input 3.
Page 131 CHAPTER 6: COMMUNICATIONS IEC 61850 COMMUNICATIONS Figure 93: IEC 61850 GGIO4 analog configuration The following settings are available. IEC 61850 GGIO4 Analogs Range: 4 to 32 in steps of 4 Default: 4 This setting specifies how many analog data points will exist in GGIO4. When this value is Plus changed, the D90 must be rebooted to allow the GGIO4 logical node to be re-...
Page 132: Report Control Configuration
IEC 61850 COMMUNICATIONS CHAPTER 6: COMMUNICATIONS IEC 61850 GGIO4 Analog 1 Maximum Range: –1000000000.000 to 1000000000.000 in steps of 0.001 Default: 0.000 These settings specify the maximum value for each analog value. Refer to IEC 61850-7-1 and IEC 61850-7-3 for additional details. This maximum value is used to determine the deadband.
Page 133: Iec 61850 Actual Values
CHAPTER 6: COMMUNICATIONS IEC 61850 COMMUNICATIONS – Bit 9: segmentation. BufTm Range: 0 to 4294967295 in steps of 1 Default: 0 This setting specifies the buffer time. TrgOps Range: 0 to 65535 in steps of 1 Default: 0 This setting specifies a bitmask that selects the trigger options. The following bits are Plus supported by the D90 –...
Page 134: Flexstates
FLEXSTATES CHAPTER 6: COMMUNICATIONS FlexStates The FlexStates feature provides a mechanism where any of 256 selected FlexLogic™ operand states can be used for efficient monitoring. The feature allows user-customized access to the FlexLogic™ operand states in the relay. The state bits are packed so that 16 states may be read out in a single Modbus register.
Page 135: Real Time Clock
CHAPTER 6: COMMUNICATIONS REAL TIME CLOCK Figure 97: FlexStates actual values The following actual values are available for each FlexState parameter. Name Range: any FlexLogic™ operand This actual value indicates the FlexLogic™ operand assigned to the FlexState parameter Value Range: OFF, ON This actual value indicates the logic state (ON, OFF) of the FlexState parameter.
Page 136 REAL TIME CLOCK CHAPTER 6: COMMUNICATIONS Figure 98: Real time clock configuration settings The following settings are available to configure the real time clock. IRIG-B Signal Type Range: None, DC Shift, Amplitude Modulated Default: None This setting selects the type of IRIG-B signal. Select “None” to disable IRIG-B. Real Time Clock Events Range: Enabled, Disabled Default: Disabled...
Page 137: User-Programmable Self-Tests
CHAPTER 6: COMMUNICATIONS USER-PROGRAMMABLE SELF-TESTS DST Start Day Instance Range: First, Second, Third, Fourth, Last Default: First This setting specifies the which instance of the day of the week to start daylight saving time. For example, if daylight saving time begins on the second Monday in April, program this setting to “Second”.
Page 138: Serial Port
SERIAL PORT CHAPTER 6: COMMUNICATIONS The following settings are available to configure the user-programmable self-tests. Ethernet Port 1 Fail Function Range: Enabled, Disabled Default: Enabled When this setting is “Disabled”, the ETHERNET PORT 1 FAILURE alarm will not assert a FlexLogic™...
Page 139: Shared Operands
CHAPTER 6: COMMUNICATIONS SHARED OPERANDS Plus ports may be connected to a computer running the EnerVista UR Setup software. This software can download and upload setting files, view measured parameters, and upgrade Plus the device firmware. A maximum of 32 D90 -series devices can be daisy-chained and connected to a DCS, PLC, or PC using the RS485 port.
Page 140: Shared Communication Operands
SHARED OPERANDS CHAPTER 6: COMMUNICATIONS • Front panel interface (HMI). However, it is often desirable for an output from an element within one function can be available to an element within another function. For instance, it may be useful for the digital fault recorder to record the output operands of any protection element.
Page 141: Communication Logic Operands
CHAPTER 6: COMMUNICATIONS SHARED OPERANDS Figure 102: Shared operands configuration window Plus The left side of this screen displays all D90 operands that are available to the protection function as shared operands. Select any operands from the other six primary features by clicking on the >>...
Page 142 SHARED OPERANDS CHAPTER 6: COMMUNICATIONS PLUS LINE DISTANCE PROTECTION SYSTEM – INSTRUCTION MANUAL...
Page 143: Protection Protection Overview
Plus Line Distance Protection System Chapter 7: Protection Protection Plus This section describes how to program the D90 protection features. Protection overview Plus The D90 is for use on transmission lines of any voltage level, without, with, and in the vicinity of series compensation, in three-pole and single-pole tripping applications.
Page 144 PROTECTION OVERVIEW CHAPTER 7: PROTECTION above the setting and sets an operate flag when the input current has been at a level above the pickup setting for the time specified by the time-current curve settings. All comparators use analog parameter actual values as the input. Protection elements are arranged into two classes, grouped and control.
Page 145: Power System
CHAPTER 7: PROTECTION POWER SYSTEM supervise the comparator. The BLOCK input is used as one of the inputs to RUN control. • setting: This setting is used to control whether the pickup, dropout or operate Events states are recorded by the event recorder. When set to “Disabled”, element pickup, dropout or operate are not recorded as events.
Page 146: Ac Input Modules
POWER SYSTEM CHAPTER 7: PROTECTION User Configuration Name Range: up to 20 alphanumeric characters Default: Initial This setting allows the user to provide a description for the settings that are loaded at a particular time (for example, “Spring-summer settings”). This description is displayed on the Product Information page of the front panel annunciator under the Configuration field.
Page 147 CHAPTER 7: PROTECTION POWER SYSTEM For three-phase channel groups, the number of the lowest numbered channel identifies the group. For example, J1 represents the three-phase channel set of J1, J2, and J3, where J is the slot letter and 1 is the first channel of the set of three channels. The first channel in the group is identified as phase A, the second channel as phase B, and the third channel as phase C.
Page 148 POWER SYSTEM CHAPTER 7: PROTECTION Phase CT Nominal Range: 0.00 to 30.00 amps in steps of 0.01 Default: 5.00 amps This setting specifies the nominal phase CT current for the corresponding current input. It is used to derive secondary current values from per-unit settings used in protection elements.
Page 149 CHAPTER 7: PROTECTION POWER SYSTEM This menu allows the user to specify the parameters for each voltage input. The Phase VT settings are used for calculation of primary metering values or Ratio Auxiliary VT Ratio matching primary voltage in a synchrocheck application. The Phase VT Nominal settings are used to derive secondary voltage values from the per- Auxiliary VT Nominal...
Page 150 POWER SYSTEM CHAPTER 7: PROTECTION Voltage Cutoff Level Range: 0.1 to 1.0 volts secondary in steps of 0.1 Default: 1.0 volts secondary This setting specifies the voltage cut-off threshold. Very low secondary voltage measurements (at the fractional volt level) can be affected by noise. Some customers prefer these low voltages to be displayed as zero, while others prefer the voltage to be displayed even when the value reflects noise rather than the actual signal.
Page 151: Power System Frequency
CHAPTER 7: PROTECTION POWER SYSTEM Figure 107: Typical power system settings We have: • CT primary = × = 20 × 5 A = 100 A. Phase CT Ratio Phase CT Secondary • VT primary = × = 208 × 66.4 V = 13811.2 V. Phase VT Ratio Phase VT Secondary The power cut-off is therefore:...
Page 152: About Ac Sources
Frequency Tracking Range: Disabled, Enabled Default: Enabled This setting should only be programmed to “Disabled” in very unusual circumstances; consult GE Grid Solutions for special variable-frequency applications. About AC sources Plus The D90 may be used on systems with breaker-and-a-half or ring bus configurations. In these applications, each of the two three-phase sets of individual phase currents (one associated with each breaker) can be used as an input to a breaker failure element.
Page 153 CHAPTER 7: PROTECTION POWER SYSTEM equipped with sufficient CT and VT input channels by selecting the appropriate parameter measurement. A mechanism is provided to specify the AC parameter (or group of parameters) used as the input to the protection and control comparators and some metering elements.
Page 154 POWER SYSTEM CHAPTER 7: PROTECTION The internal grouping of current and voltage signals forms an internal source. This source can be given a specific name through the settings, and becomes available to protection Plus and metering element in the D90 .
Page 155 CHAPTER 7: PROTECTION POWER SYSTEM Name Range: up to 20 alphanumeric characters Default: LINE This setting specifies a name for the protection source. Phase CT Range: None, J1, J4, J1+J4, etc. Default: J1+J4 This setting selects a phase CT or sum of phase CTs to represent the protection source. Ground CT Range: None, J7 Default: J7...
Page 156: Grouped Protection Elements
GROUPED PROTECTION ELEMENTS CHAPTER 7: PROTECTION Figure 112: Example use of sources Grouped protection elements Each protection element can be assigned up to six different sets of settings according to setting group designations 1 to 6. The performance of these elements is defined by the active setting group at a given time.
Page 157 CHAPTER 7: PROTECTION GROUPED PROTECTION ELEMENTS by an undervoltage condition, which in turn is controlled by the operand VT FUSE FAIL OP with a 10 ms coordination timer. Configure the operand to perform a LINE PICKUP RCL TRIP trip action if the intent is apply zone 1 extension. The zone 1 extension philosophy used normally operates from an under-reaching zone, and uses an over-reaching distance zone when reclosing the line with the other line end open.
Page 158 GROUPED PROTECTION ELEMENTS CHAPTER 7: PROTECTION Line End Open Pickup Delay Range: 0.000 to 65.535 seconds in steps of 0.001 Default: 0.150 seconds This setting specifies the time during which the line is de-energized before the line pickup logic is armed. Line End Open Reset Delay Range: 0.000 to 65.535 seconds in steps of 0.001 Default: 0.090 seconds...
Page 159 CHAPTER 7: PROTECTION GROUPED PROTECTION ELEMENTS Block Range: any FlexLogic™ operand Default: OFF Assertion of the FlexLogic™ operand assigned to this setting will block operation of the line pickup element. Events Range: Enabled, Disabled Default: Enabled This setting enables and disables the logging of line pickup events in the sequence of events recorder.
Page 160: Distance Elements
GROUPED PROTECTION ELEMENTS CHAPTER 7: PROTECTION Distance elements Four common settings are available for distance protection. Select the Settings > Protection > Elements > Group 1 > Distance > Common menu item to open the distance configuration window. Figure 115: Shared distance settings The following settings apply to all phase and ground distance elements.
Page 161 The CVT filter function should be disabled if the T1, T2, and Tx parameters are not known (the default values should not be used). Contact GE Grid Solutions for assistance in determining these settings.
Page 162 GROUPED PROTECTION ELEMENTS CHAPTER 7: PROTECTION Figure 116: Memory voltage logic Phase distance The phase mho distance function uses a dynamic 100% memory-polarized mho characteristic with additional reactance, directional, and overcurrent supervising characteristics. The phase quadrilateral distance function is comprised of a reactance characteristic, right and left blinders, and 100% memory-polarized directional and current supervising characteristics.
Page 163 CHAPTER 7: PROTECTION GROUPED PROTECTION ELEMENTS Figure 117: Phase distance configuration window The following settings are available for each phase distance zone. There are five phase distance zones of protection in each setting group. Function Range: Enabled, Disabled Default: Enabled This setting enables and disables the phase distance protection feature.
Page 164 GROUPED PROTECTION ELEMENTS CHAPTER 7: PROTECTION Figure 118: Directional mho phase distance characteristic Figure 119: Non-directional mho phase distance characteristic PLUS LINE DISTANCE PROTECTION SYSTEM – INSTRUCTION MANUAL...
Page 165 CHAPTER 7: PROTECTION GROUPED PROTECTION ELEMENTS Figure 120: Directional quadrilateral ground distance characteristic Figure 121: Non-directional quadrilateral ground distance characteristic Sample shapes for the mho and quadrilateral distance characteristics are shown below. PLUS LINE DISTANCE PROTECTION SYSTEM – INSTRUCTION MANUAL...
Page 166 GROUPED PROTECTION ELEMENTS CHAPTER 7: PROTECTION Figure 122: Mho distance characteristic sample shapes PLUS LINE DISTANCE PROTECTION SYSTEM – INSTRUCTION MANUAL...
Page 167 CHAPTER 7: PROTECTION GROUPED PROTECTION ELEMENTS Figure 123: Quadrilateral distance characteristic sample shapes Transformer Voltage Connection Range: None, Dy1, Dy3, Dy5, Dy7, Dy9, Dy11, Yd1, Yd3, Yd5, Yd7, Yd9, Yd11 Default: None The phase distance elements can be applied to look through a three-phase delta-wye or wye-delta power transformer.
Page 168 GROUPED PROTECTION ELEMENTS CHAPTER 7: PROTECTION Transformer Current Connection Range: None, Dy1, Dy3, Dy5, Dy7, Dy9, Dy11, Yd1, Yd3, Yd5, Yd7, Yd9, Yd11 Default: None This setting specifies the location of the current source with respect to the involved power transformer in the direction of the zone. In section (a) of the following figure, zone 1 is looking through a transformer from the delta into the wye winding.
Page 169 CHAPTER 7: PROTECTION GROUPED PROTECTION ELEMENTS Range: 30 to 90° in steps of 1 Default: 85° This setting specifies the characteristic angle (similar to the maximum torque angle in previous technologies) of the phase distance characteristic for the forward and reverse applications.
Page 170 GROUPED PROTECTION ELEMENTS CHAPTER 7: PROTECTION Quadrilateral Right Blinder Range: 0.02 to 500.00 ohms in steps of 0.01 Default: 0.90 ohms This setting specifies the right blinder position of the quadrilateral characteristic along the resistive axis of the impedance plane. The angular position of the blinder is adjustable with the use of the setting.
Page 171 CHAPTER 7: PROTECTION GROUPED PROTECTION ELEMENTS The use of dynamic reach control by selection of a non-zero value for the Voltage Level NOTE: setting will disable the subcycle operating time for that particular zone. Delay Range: 0.000 to 65.535 seconds in steps of 0.001 Default: 0.000 seconds This setting allows the user to delay operation of the distance elements and implement stepped distance protection.
Page 172 GROUPED PROTECTION ELEMENTS CHAPTER 7: PROTECTION Figure 126: Phase distance zone 2 operation scheme logic The phase distance scheme logic for zone 1 is shown below. The logic is analagous for zones 2 through 5. Figure 127: Phase distance scheme logic PLUS LINE DISTANCE PROTECTION SYSTEM –...
Page 173 CHAPTER 7: PROTECTION GROUPED PROTECTION ELEMENTS Ground distance The ground mho distance function uses a dynamic 100% memory-polarized mho characteristic with additional reactance, directional, current, and phase selection supervising characteristics. The ground quadrilateral distance function is composed of a reactance characteristic, right and left blinders, and 100% memory-polarized directional, overcurrent, and phase selection supervising characteristics.
Page 174 GROUPED PROTECTION ELEMENTS CHAPTER 7: PROTECTION Figure 128: Ground distance settings configuration The following settings are available for each ground distance zone. There are five ground distance zones of protection in each setting group. Function Range: Enabled, Disabled Default: Disabled This setting enables and disables the phase distance protection feature.
Page 175 CHAPTER 7: PROTECTION GROUPED PROTECTION ELEMENTS Figure 129: Directional mho ground distance characteristic Figure 130: Non-directional mho ground distance characteristic PLUS LINE DISTANCE PROTECTION SYSTEM – INSTRUCTION MANUAL...
Page 176 GROUPED PROTECTION ELEMENTS CHAPTER 7: PROTECTION Figure 131: Directional quadrilateral ground distance characteristic Figure 132: Non-directional quadrilateral ground distance characteristic PLUS LINE DISTANCE PROTECTION SYSTEM – INSTRUCTION MANUAL...
Page 177 CHAPTER 7: PROTECTION GROUPED PROTECTION ELEMENTS Z0/Z1 Magnitude Range: 0.00 to 10.00 in steps of 0.01 Default: 2.70 This setting specifies the ratio between the zero-sequence and positive-sequence impedance required for zero-sequence compensation of the ground distance elements. This setting is available on a per-zone basis, enabling precise settings for tapped, non- homogeneous, and series compensated lines.
Page 178 GROUPED PROTECTION ELEMENTS CHAPTER 7: PROTECTION The relay internally performs zero-sequence compensation for the protected circuit based on the values entered for the settings, and if Z0/Z1 Magnitude Z0/Z1 Angle configured to do so, zero-sequence compensation for mutual coupling based on the values entered for the settings.
Page 179 CHAPTER 7: PROTECTION GROUPED PROTECTION ELEMENTS Directional RCA Range: 30 to 90° in steps of 1 Default: 85° The setting specifies the characteristic angle (or maximum torque angle) of the directional supervising function. If the mho shape is applied, the directional function is an extra supervising function, as the dynamic mho characteristic itself is a directional one.
Page 180 GROUPED PROTECTION ELEMENTS CHAPTER 7: PROTECTION Voltage Level Range: 0.000 to 5.000 pu in steps of 0.001 Default: 0.000 pu This setting is relevant for applications on series-compensated lines, or in general, if series capacitors are located between the relaying point and a point for which the zone shall not overreach.
Page 181 CHAPTER 7: PROTECTION GROUPED PROTECTION ELEMENTS Figure 134: Ground distance zone 2 operation scheme logic The ground distance scheme logic for zone 1 is shown below. Figure 135: Ground distance zone 1 scheme logic The ground distance scheme logic for zone 2 is shown below. The logic is analagous for zones 3 through 5.
Page 182 GROUPED PROTECTION ELEMENTS CHAPTER 7: PROTECTION Figure 136: Ground distance zone 2 scheme logic Ground directional supervision A dual (zero-sequence and negative-sequence) memory-polarized directional supervision applied to the ground distance protection elements has been shown to give good directional integrity. However, a reverse double-line-to-ground fault can lead to a maloperation of the ground element in a sound phase if the zone reach setting is increased to cover high resistance faults.
Page 183 CHAPTER 7: PROTECTION GROUPED PROTECTION ELEMENTS Figure 137: Ground directional supervision scheme logic Power swing detect The power swing detect element provides both power swing blocking and out-of-step tripping functions. The element measures the positive-sequence apparent impedance and traces its locus with respect to either two or three user-selectable operating characteristic boundaries.
Page 184 GROUPED PROTECTION ELEMENTS CHAPTER 7: PROTECTION first step is similar to the power swing blocking sequence. After the timer specified by the setting times out, latch 1 is set as long as the impedance stays within the Pickup Delay 1 outer characteristic.
Page 185 CHAPTER 7: PROTECTION GROUPED PROTECTION ELEMENTS Figure 139: Effect of blinders on the mho operating characteristic Figure 140: Power swing detect quadrilateral operating characteristic The FlexLogic™ output operands for the power swing detect element are described below. Power swing detection operands POWER SWING 50DD.......Asserted when the power swing detection element detects a disturbance other than a power swing.
Page 186 GROUPED PROTECTION ELEMENTS CHAPTER 7: PROTECTION POWER SWING BLOCK......Asserted when the power swing detection blocking element operates. POWER SWING INCOMING....Asserted when an unstable power swing is detected (incoming locus). POWER SWING INNER ......Asserted when the positive-sequence impedance is in the inner characteristic.
Page 187 CHAPTER 7: PROTECTION GROUPED PROTECTION ELEMENTS Function Range: Enabled, Disabled Default: Disabled This setting enables and disables the power swing detection element. The setting applies to both power swing blocking and out-of-step tripping functions. Source Range: LINE (SRC 1), BKR 1 (SRC 2), BKR 2 (SRC 3) Default: LINE (SRC 1) This setting selects the signal source for both blocking and tripping functions.
Page 188 GROUPED PROTECTION ELEMENTS CHAPTER 7: PROTECTION Quadrilateral Forward Outer Range: 0.10 to 500.00 ohms in steps of 0.01 Default: 70.00 ohms This setting specifies the forward reach of the outer quadrilateral characteristic. The angle of this reach impedance is specified by the setting.
Page 189 CHAPTER 7: PROTECTION GROUPED PROTECTION ELEMENTS Middle Limit Angle Range: 40 to 140° in steps of 1 Default: 90° This setting defines the middle power swing detect characteristic. It is relevant only for the three-step mode. A typical value would be close to the average of the outer and inner limit angles.
Page 190 GROUPED PROTECTION ELEMENTS CHAPTER 7: PROTECTION Delay 1 Pickup Range: 0.000 to 65.535 seconds in steps of 0.001 Default: 0.030 seconds All the coordinating timers are related to each other and should be set to detect the fastest expected power swing and produce out-of-step tripping in a secure manner. The timers should be set in consideration to the power swing detect characteristics, mode of power swing detect operation and mode of out-of-step tripping.
Page 191 CHAPTER 7: PROTECTION GROUPED PROTECTION ELEMENTS Seal-In Delay Range: 0.000 to 65.535 seconds in steps of 0.001 Default: 0.400 seconds The out-of-step trip FlexLogic™ operand (POWER SWING TRIP) is sealed-in for the specified period of time. The sealing-in is crucial in the delayed trip mode, as the original trip signal is a very short pulse occurring when the impedance locus leaves the outer characteristic after the out-of-step sequence is completed.
Page 192 GROUPED PROTECTION ELEMENTS CHAPTER 7: PROTECTION Figure 143: Power swing detect scheme logic, sheet 2 of 3 Figure 144: Power swing detect scheme logic, sheet 3 of 3 Load encroachment The load encroachment element responds to the positive-sequence voltage and current and applies the characteristic shown below.
Page 193 CHAPTER 7: PROTECTION GROUPED PROTECTION ELEMENTS Figure 145: Load encroachment characteristic The element operates if the positive-sequence voltage is above a user-specified level and asserts its output signal that can be used to block selected protection elements such as distance or phase overcurrent. The following figure shows an effect of the load encroachment characteristics used to block the quadrilateral distance element.
Page 194 GROUPED PROTECTION ELEMENTS CHAPTER 7: PROTECTION Figure 147: Load encroachment configuration settings The following settings are available. Function Range: Enabled, Disabled Default: Disabled This setting enables and disabled the load encroachment element. Source Range: LINE (SRC 1), BKR 1 (SRC 2), BKR 2 (SRC 3) Default: LINE (SRC 1) This setting selects the signal source for the load encroachment element.
Page 195: Current Elements
Overview of time overcurrent curves The inverse time overcurrent curves used by the time overcurrent elements are the IEEE, IEC, GE Type IAC, and I t standard curve shapes. This allows for simplified coordination with downstream devices. If however, none of these curve shapes is adequate, FlexCurves™...
Page 196 GROUPED PROTECTION ELEMENTS CHAPTER 7: PROTECTION • IAC Inverse. • IAC Short Inverse. • • FlexCurves™ A, B, C, and D. • Recloser curves. • Definite Time. A multiplier (time dial) setting allows selection of a multiple of the base curve shape (where the time dial multiplier = 1) with the curve shape setting.
Page 197 CHAPTER 7: PROTECTION GROUPED PROTECTION ELEMENTS Table 7-1: IEEE curve trip times (in seconds) Multiplier Current (I / I pickup (TDM) 10.0 IEEE extremely inverse 11.341 4.761 1.823 1.001 0.648 0.464 0.355 0.285 0.237 0.203 22.682 9.522 3.647 2.002 1.297 0.927 0.709 0.569...
Page 198 GROUPED PROTECTION ELEMENTS CHAPTER 7: PROTECTION Table 8: IEC (BS) inverse time curve constants IEC curve shape IEC curve A (BS142) 0.140 0.020 IEC curve B (BS142) 13.500 1.000 43.2 IEC curve C (BS142) 80.000 2.000 58.2 IEC short inverse 0.050 0.040 0.500...
Page 199 0.8630 0.8000 –0.4180 0.1947 0.990 IAC short inverse 0.0428 0.0609 0.6200 –0.0010 0.0221 0.222 Table 11: GE type IAC curve trip times (in seconds) Multiplier Current (I / I pickup (TDM) 10.0 IAC extremely inverse 1.699 0.749 0.303 0.178 0.123 0.093...
Page 200 GROUPED PROTECTION ELEMENTS CHAPTER 7: PROTECTION Multiplier Current (I / I pickup (TDM) 10.0 2.310 1.499 1.064 0.885 0.784 0.719 0.674 0.640 0.614 0.594 4.621 2.997 2.128 1.770 1.569 1.439 1.348 1.280 1.229 1.188 6.931 4.496 3.192 2.656 2.353 2.158 2.022 1.921 1.843...
Page 201 CHAPTER 7: PROTECTION GROUPED PROTECTION ELEMENTS FlexCurves™ The custom FlexCurve™ shapes are defined as follows. Eq. 16 Eq. 17 The terms in the above equations are defined as follows. • represents the operate time in seconds. operate • TDM represents the multiplier setting. •...
Page 202 GROUPED PROTECTION ELEMENTS CHAPTER 7: PROTECTION Figure 149: Phase time overcurrent voltage restraint characteristic Select the Settings > Protection > Elements > Group 1 > Current > Phase TOC menu item to open the phase time overcurrent configuration window. Figure 150: Phase time overcurrent configuration settings The following settings are available for each phase time overcurrent element.
Page 203 CHAPTER 7: PROTECTION GROUPED PROTECTION ELEMENTS Pickup Range: 0.000 to 30.000 pu in steps of 0.001 Default: 1.000 pu This setting specifies the phase time overcurrent pickup level in per-unit values. Curve Range: IEEE Mod Inv, IEEE Very Inv, IEEE Ext Inv, IEC Curve A, IEC Curve B, IEC Curve C, IEC Short Inv, IAC Ext Inv, IAC Very Inv, IAC Inverse, IAC Short Inv, I2t, Definite Time, FlexCurve A, FlexCurve B, FlexCurve C, FlexCurve D Default: IEEE Mod Inv...
Page 204 GROUPED PROTECTION ELEMENTS CHAPTER 7: PROTECTION The logic for the phase time overcurrent 1 element is shown below. The logic is identical for all phase instantaneous overcurrent elements. Figure 151: Phase time overcurrent 1 scheme logic Phase instantaneous overcurrent The phase instantaneous overcurrent element may be used as an instantaneous element with no intentional delay or as a definite time element.
Page 205 CHAPTER 7: PROTECTION GROUPED PROTECTION ELEMENTS Function Range: Enabled, Disabled Default: Disabled This setting enables and disables the phase instantaneous overcurrent protection element. Source Range: LINE (SRC 1), BKR 1 (SRC 2), BKR 2 (SRC 3) Default: LINE (SRC 1) This setting selects the signal source for the phase instantaneous overcurrent protection element.
Page 206 GROUPED PROTECTION ELEMENTS CHAPTER 7: PROTECTION Figure 153: Phase instantaneous overcurrent 1 scheme logic Phase directional overcurrent The phase directional elements (one for each of phases A, B, and C) determine the phase current flow direction for steady state and fault conditions and can be used to control the operation of the phase overcurrent elements via the block inputs of these elements.
Page 207 CHAPTER 7: PROTECTION GROUPED PROTECTION ELEMENTS The phase directional overcurrent element is intended to apply a block signal to an overcurrent element to prevent an operation when current is flowing in a particular direction. The direction of current flow is determined by measuring the phase angle between the current from the phase CTs and the line-line voltage from the VTs, based on the 90°...
Page 208 GROUPED PROTECTION ELEMENTS CHAPTER 7: PROTECTION Figure 155: Phase directional overcurrent configuration settings The following settings are available for each phase directional overcurrent element. Function Range: Enabled, Disabled Default: Disabled This setting enables and disables the phase directional overcurrent protection element. Source Range: LINE (SRC 1), BKR 1 (SRC 2), BKR 2 (SRC 3) Default: LINE (SRC 1)
Page 209 CHAPTER 7: PROTECTION GROUPED PROTECTION ELEMENTS Block When Voltage Memory Expires Range: Yes, No Default: No This setting is used to select the required operation upon expiration of voltage memory. When set to “Yes”, the directional element blocks the operation of any phase overcurrent element under directional control, when voltage memory expires;...
Page 210 GROUPED PROTECTION ELEMENTS CHAPTER 7: PROTECTION Select the Settings > Protection > Elements > Group 1 > Current > Neutral TOC menu item to open the neutral time overcurrent configuration window. Figure 157: Neutral time overcurrent configuration settings The following settings are available for each neutral time overcurrent element. Function Range: Enabled, Disabled Default: Disabled...
Page 211 CHAPTER 7: PROTECTION GROUPED PROTECTION ELEMENTS Reset Range: Instantaneous, Timed Default: Instantaneous The “Instantaneous” reset method is intended for applications with other relays, such as most static relays, which set the energy capacity directly to zero when the current falls below the reset threshold.
Page 212 GROUPED PROTECTION ELEMENTS CHAPTER 7: PROTECTION The positive-sequence restraint must be considered when testing for pickup accuracy and response time (multiple of pickup). The operating quantity depends on how test currents are injected into the relay. For single-phase injection, the operating quantity is: Eq.
Page 213 CHAPTER 7: PROTECTION GROUPED PROTECTION ELEMENTS Block Range: any FlexLogic™ operand or shared operand Default: Off Assertion of the operand assigned to this setting blocks operation of the neutral instantaneous overcurrent element. Events Range: Enabled, Disabled Plus Plus Default: varies with UR -series model;...
Page 214 GROUPED PROTECTION ELEMENTS CHAPTER 7: PROTECTION The positive-sequence restraint is removed for low currents. If the positive-sequence current is less than 0.8 pu, the restraint is removed by changing the constant K to zero. This facilitates better response to high-resistance faults when the unbalance is very small and there is no danger of excessive CT errors as the current is low.
Page 215 CHAPTER 7: PROTECTION GROUPED PROTECTION ELEMENTS Figure 161: Neutral directional voltage polarized characteristics The neutral directional overcurrent element incorporates a current reversal logic. If the reverse direction is indicated for at least 1.25 of a power system cycle, the prospective forward indication will be delayed by 1.5 of a power system cycle.
Page 216 GROUPED PROTECTION ELEMENTS CHAPTER 7: PROTECTION Figure 162: Neutral directional overcurrent configuration settings The following settings are available for each neutral directional overcurrent element. Function Default: Enabled, Disabled Default: Disabled This setting enables and disables the neutral directional overcurrent protection element. Source Range: LINE (SRC 1), BKR 1 (SRC 2), BKR 2 (SRC 3) Default: LINE (SRC 1)
Page 217 CHAPTER 7: PROTECTION GROUPED PROTECTION ELEMENTS it should be ensured that a reversal of the ground current does not occur for a high-side fault. The low-side system impedance should be assumed minimal when checking for this condition. A similar situation arises for a wye/delta/wye transformer, where current in one transformer winding neutral may reverse when faults on both sides of the transformer are considered.
Page 218 GROUPED PROTECTION ELEMENTS CHAPTER 7: PROTECTION Forward Limit Angle Range: 40 to 90° in steps of 1 Default: 90° This setting defines a symmetrical (in both directions from the ECA) limit angle for the forward direction. Forward Pickup Range: 0.002 to 30.000 pu in steps of 0.001 Default: 0.050 pu This setting defines the pickup level for the overcurrent unit of the element in the forward direction.
Page 219 CHAPTER 7: PROTECTION GROUPED PROTECTION ELEMENTS Figure 163: Neutral directional overcurrent 1 scheme logic Ground time overcurrent The ground time overcurrent element can provide a desired time-delay operating characteristic versus the applied current or be used as a simple definite time element. The ground current input value is the quantity measured by the ground input CT and is the fundamental phasor or RMS magnitude.
Page 220 GROUPED PROTECTION ELEMENTS CHAPTER 7: PROTECTION Figure 164: Ground time overcurrent configuration settings The following settings are available for each ground time overcurrent element. Function Range: Enabled, Disabled Default: Disabled This setting enables and disables the ground time overcurrent protection element. Source Range: LINE (SRC 1), BKR 1 (SRC 2), BKR 2 (SRC 3) Default: LINE (SRC 1)
Page 221 CHAPTER 7: PROTECTION GROUPED PROTECTION ELEMENTS Reset Range: Instantaneous, Timed Default: Instantaneous The “Instantaneous” reset method is intended for applications with other relays, such as most static relays, which set the energy capacity directly to zero when the current falls below the reset threshold.
Page 222 GROUPED PROTECTION ELEMENTS CHAPTER 7: PROTECTION Figure 166: Ground instantaneous overcurrent configuration settings The following settings are available for each ground instantaneous overcurrent element. Function Range: Enabled, Disabled Default: Disabled This setting enables and disables the ground instantaneous overcurrent protection element.
Page 223 CHAPTER 7: PROTECTION GROUPED PROTECTION ELEMENTS Events Range: Enabled, Disabled Plus Plus Default: varies with UR -series model; refer to the EnerVista UR Setup software This setting enables and disables the logging of ground instantaneous overcurrent events in the sequence of events recorder. The logic for the ground instantaneous overcurrent 1 element is shown below.
Page 224 GROUPED PROTECTION ELEMENTS CHAPTER 7: PROTECTION Source Range: LINE (SRC 1), BKR 1 (SRC 2), BKR 2 (SRC 3) Default: LINE (SRC 1) This setting selects the signal source for the negative-sequence time overcurrent protection element. Pickup Range: 0.000 to 30.000 pu in steps of 0.001 Default: 1.000 pu This setting specifies the neutral time overcurrent pickup level in per-unit values.
Page 225 CHAPTER 7: PROTECTION GROUPED PROTECTION ELEMENTS Figure 169: Negative-sequence time overcurrent scheme logic Negative-sequence instantaneous overcurrent The negative-sequence instantaneous overcurrent element may be used as an instantaneous function with no intentional delay or as a definite time function. The element responds to the negative-sequence current fundamental frequency phasor magnitude (calculated from the phase currents) and applies a positive-sequence restraint for better performance: a small portion (12.5%) of the positive-sequence current magnitude is subtracted from the negative-sequence current magnitude when forming...
Page 226 GROUPED PROTECTION ELEMENTS CHAPTER 7: PROTECTION Function Range: Enabled, Disabled Default: Disabled This setting enables and disables the negative-sequence instantaneous overcurrent protection element. Source Range: LINE (SRC 1), BKR 1 (SRC 2), BKR 2 (SRC 3) Default: LINE (SRC 1) This setting selects the signal source for the negative-sequence instantaneous overcurrent protection element.
Page 227 CHAPTER 7: PROTECTION GROUPED PROTECTION ELEMENTS Negative-sequence directional overcurrent There are two negative-sequence directional overcurrent protection elements available. The element provides both forward and reverse fault direction indications through its output operands REV, respectively. The output NEG SEQ DIR OC1 FWD NEG SEQ DIR OC1 operand is asserted if the magnitude of the operating current is above a pickup level (overcurrent unit) and the fault direction is seen as forward or reverse, respectively...
Page 228 GROUPED PROTECTION ELEMENTS CHAPTER 7: PROTECTION Figure 172: Negative-sequence directional characteristics The forward-looking function is designed to be more secure as compared to the reverse- looking function, and therefore, should be used for the tripping direction. The reverse- looking function is designed to be faster as compared to the forward-looking function and should be used for the blocking direction.
Page 229 CHAPTER 7: PROTECTION GROUPED PROTECTION ELEMENTS Figure 173: Negative-sequence directional overcurrent configuration settings The following settings are available for each negative-sequence directional overcurrent element. Function Range: Enabled, Disabled Default: Disabled This setting enables and disables the negative-sequence directional overcurrent protection element. Source Range: LINE (SRC 1), BKR 1 (SRC 2), BKR 2 (SRC 3) Default: LINE (SRC 1)
Page 230 GROUPED PROTECTION ELEMENTS CHAPTER 7: PROTECTION Pos Seq Restraint Range: 0.000 to 0.500 in steps of 0.001 Default: 0.063 This setting controls the amount of the positive-sequence restraint. Set to 0.063 (in zero- sequence mode) or 0.125 (in negative-sequence mode) for backwards compatibility with UR-series relays using firmware revision 3.40 and older.
Page 231: Voltage Elements
CHAPTER 7: PROTECTION GROUPED PROTECTION ELEMENTS Figure 174: Negative-sequence directional overcurrent scheme logic Voltage elements The voltage protection elements can be used for a variety of applications, such as undervoltage protection, permissive functions, and source transfer schemes. For voltage sensitive loads, such as induction motors, a drop in voltage increases the drawn current which may cause dangerous overheating in the motor.
Page 232 GROUPED PROTECTION ELEMENTS CHAPTER 7: PROTECTION Figure 175: Inverse time undervoltage curves At 0% of pickup, the operating time is equivalent to the undervoltage delay setting. NOTE: Phase undervoltage The phase undervoltage element may be used to give a desired time delay operating characteristic versus the applied fundamental voltage (phase-to-ground or phase-to- phase for wye VT connections, or phase-to-phase for delta VT connections) or as a definite time element.
Page 233 CHAPTER 7: PROTECTION GROUPED PROTECTION ELEMENTS Mode Range: Phase to Ground, Phase to Phase Default: Phase to Ground This setting selects the operating mode. Select phase-to-ground or phase-to-phase for wye VT connections, or phase-to-phase for delta VT connections. Pickup Range: 0.000 to 1.100 pu in steps of 0.001 Default: 1.000 pu This setting specifies the phase undervoltage pickup level in per-unit values.
Page 234 GROUPED PROTECTION ELEMENTS CHAPTER 7: PROTECTION Figure 177: Phase undervoltage scheme logic Phase overvoltage The phase overvoltage element may be used as an instantaneous element with no intentional time delay or as a definite time element. The input voltage is the phase-to- phase voltage, either measured directly from delta-connected VTs or as calculated from phase-to-ground (wye) connected VTs.
Page 235 CHAPTER 7: PROTECTION GROUPED PROTECTION ELEMENTS Pickup Range: 0.000 to 1.100 pu in steps of 0.001 Default: 1.000 pu This setting specifies the phase overvoltage pickup level in per-unit values. Delay Range: 0.00 to 600.00 seconds in steps of 0.01 Default: 1.00 seconds This setting specifies the minimum operating time of the phase overvoltage element.
Page 236 GROUPED PROTECTION ELEMENTS CHAPTER 7: PROTECTION The neutral overvoltage element can provide a time-delayed operating characteristic versus the applied voltage (initialized from FlexCurves™ A, B, or C) or be used as a definite time element. The source assigned to this element must be configured for a phase VT. VT errors and normal voltage unbalance must be considered when setting this element.
Page 237 CHAPTER 7: PROTECTION GROUPED PROTECTION ELEMENTS Block Range: any FlexLogic™ operand or shared operand Default: Off Assertion of the operand assigned to this setting blocks the neutral overvoltage element. Events Range: Enabled, Disabled Default: Disabled This setting enables and disables the logging of neutral overvoltage events in the sequence of events recorder.
Page 238 GROUPED PROTECTION ELEMENTS CHAPTER 7: PROTECTION Source Range: LINE (SRC 1), BKR 1 (SRC 2), BKR 2 (SRC 3) Default: LINE (SRC 1) This setting selects the signal source for the negative-sequence overvoltage protection element. Pickup Range: 0.000 to 1.250 pu in steps of 0.001 Default: 1.000 pu This setting specifies the negative-sequence overvoltage pickup level in per-unit values.
Page 239 CHAPTER 7: PROTECTION GROUPED PROTECTION ELEMENTS Both the settings establish the operating curve of the undervoltage Pickup Delay element. The auxiliary undervoltage element can be programmed to use either definite time delay or inverse time delay characteristics. The auxiliary undervoltage element resets instantaneously. Select the Settings >...
Page 240 GROUPED PROTECTION ELEMENTS CHAPTER 7: PROTECTION Block Range: any FlexLogic™ operand or shared operand Default: Off Assertion of the operand assigned to this setting blocks the auxiliary undervoltage element. Events Range: Enabled, Disabled Default: Disabled This setting enables and disables the logging of auxiliary undervoltage events in the sequence of events recorder.
Page 241: Breaker Failure
CHAPTER 7: PROTECTION GROUPED PROTECTION ELEMENTS Source Range: LINE (SRC 1), BKR 1 (SRC 2), BKR 2 (SRC 3) Default: LINE (SRC 1) This setting selects the signal source for the auxiliary overvoltage protection element. Pickup Range: 0.000 to 1.100 pu in steps of 0.001 Default: 0.300 pu This setting specifies the auxiliary overvoltage pickup level in per-unit values.
Page 242 GROUPED PROTECTION ELEMENTS CHAPTER 7: PROTECTION Two schemes are provided: one for three-pole tripping only and one for three pole plus single-pole operation. The philosophy used in these schemes is identical. The operation of a breaker failure element includes three stages: initiation, determination of a breaker failure condition, and output.
Page 243 CHAPTER 7: PROTECTION GROUPED PROTECTION ELEMENTS Schemes can be initiated either directly or with current level supervision. It is particularly important in any application to decide if a current-supervised initiate is to be used. The use of a current-supervised initiate results in the breaker failure element not being initiated for a breaker that has very little or no current flowing through it, which may be the case for transformer faults.
Page 244 GROUPED PROTECTION ELEMENTS CHAPTER 7: PROTECTION • FlexLogic™ operands that initiate tripping required to clear the faulted zone. The trip output can be sealed-in for an adjustable period. • Illumination of a front panel annunciator message or messages. Breaker failure settings and logic Select the Settings >...
Page 245 CHAPTER 7: PROTECTION GROUPED PROTECTION ELEMENTS Source Range: LINE (SRC 1), BKR 1 (SRC 2), BKR 2 (SRC 3) Default: LINE (SRC 1) This setting selects the signal source for the breaker failure protection element. Current Supervision Range: Yes, No Default: Yes If set to “Yes”, the breaker failure element will only be initiated if current flowing through the breaker is above the supervision pickup level.
Page 246 GROUPED PROTECTION ELEMENTS CHAPTER 7: PROTECTION Use Timer 2 Range: Yes, No Default: Yes If this setting value is “Yes”, the main path is operational. Timer 2 Pickup Delay Range: 0.000 to 65.535 seconds in steps of 0.001 Default: 0 seconds Timer 2 is set to the expected opening time of the breaker, plus a safety margin.
Page 247 CHAPTER 7: PROTECTION GROUPED PROTECTION ELEMENTS Phase Current High-Set Pickup Range: 0.001 to 30.000 pu in steps of 0.001 Default: 1.050 pu This setting specifies the phase current output supervision level. Generally, this setting should detect the lowest expected fault current on the protected breaker, before a breaker opening resistor is inserted.
Page 248 GROUPED PROTECTION ELEMENTS CHAPTER 7: PROTECTION Breaker Position 1 Phase B Range: any FlexLogic™ operand or shared operand Default: Off This setting selects the operand to represent the protected breaker early-type auxiliary switch contact on pole B. This contact is normally a non-multiplied form-A contact. The contact may even be adjusted to have the shortest possible operating time.
Page 249 CHAPTER 7: PROTECTION GROUPED PROTECTION ELEMENTS Figure 191: Breaker failure scheme logic, sheet 1 of 3 PLUS LINE DISTANCE PROTECTION SYSTEM – INSTRUCTION MANUAL...
Page 250 GROUPED PROTECTION ELEMENTS CHAPTER 7: PROTECTION Figure 192: Breaker failure single-pole logic, sheet 2 of 3 PLUS LINE DISTANCE PROTECTION SYSTEM – INSTRUCTION MANUAL...
Page 251 CHAPTER 7: PROTECTION GROUPED PROTECTION ELEMENTS Figure 193: Breaker failure single-pole logic, sheet 3 of 3 Figure 194: Breaker failure three-pole logic, sheet 1 of 3 PLUS LINE DISTANCE PROTECTION SYSTEM – INSTRUCTION MANUAL...
Page 252: Wattmetric Zero-Sequence Directional Ground Fault
GROUPED PROTECTION ELEMENTS CHAPTER 7: PROTECTION Figure 195: Breaker failure three-pole logic, sheet 2 of 3 Figure 196: Breaker failure three-pole logic, sheet 3 of 3 Wattmetric zero-sequence directional ground fault The wattmetric zero-sequence directional element responds to power derived from zero- sequence voltage and current in a direction specified by the element characteristic angle.
Page 253 CHAPTER 7: PROTECTION GROUPED PROTECTION ELEMENTS Figure 197: Wattmetric ground fault configuration window The following settings are available for each wattmetric zero-sequence directional ground fault element. Function Range: Enabled, Disabled Default: Disabled This setting enables and disables the wattmetric zero-sequence directional ground fault protection element.
Page 254 GROUPED PROTECTION ELEMENTS CHAPTER 7: PROTECTION Current Range: Calculated IN, Measured IG Default: Calculated IN The wattmetric zero-sequence directional ground fault element responds to the neutral current (that is, three times zero-sequence current), either calculated internally from the phase currents or supplied externally via the ground CT input from more accurate sources such as the core balanced CT.
Page 255 CHAPTER 7: PROTECTION GROUPED PROTECTION ELEMENTS Figure 198: Wattmetric characteristic angle response Power Pickup Delay Range: 0.00 to 600.00 seconds in steps of 0.01 Default: 0.20 seconds This setting specifies a definite time delay before the inverse time characteristic is activated.
Page 256: Control Elements
CONTROL ELEMENTS CHAPTER 7: PROTECTION In this equation, m is a multiplier defined by the multiplier setting, S represents the pickup setting, and S represents the operating power at the time. This timer starts after the definite time timer expires. The four FlexCurves allow for custom user-programmable time characteristics.
Page 257: Pilot Schemes
CHAPTER 7: PROTECTION CONTROL ELEMENTS Pilot schemes This section contains settings for selecting and configuring protection signaling schemes. All schemes are available for single-pole tripping applications and can be used with single- bit, two-bit, or four-bit communications channels. Choices of communications channels include remote inputs, remote outputs, and telecommunications interfaces.
Page 258 CONTROL ELEMENTS CHAPTER 7: PROTECTION The following settings are available for the direct under-reaching transfer trip (DUTT) scheme. Function Range: Enabled, Disabled Default: Disabled This setting enables and disables the direct under-reaching transfer trip (DUTT) scheme. Seal-In Delay Range: 0.000 to 65.535 seconds in steps of 0.001 Default: 0.000 seconds The DUTT OP FlexLogic™...
Page 259 CHAPTER 7: PROTECTION CONTROL ELEMENTS Figure 201: DUTT scheme logic Permissive under-reaching transfer trip The permissive under-reaching transfer trip (PUTT) scheme uses an under-reaching zone 1 distance element to key transfer trip signal to the remote terminals where they are supervised by an over-reaching zone 2 distance element.
Page 260 CONTROL ELEMENTS CHAPTER 7: PROTECTION The following settings are available for the permissive under-reaching transfer trip (PUTT) scheme. Function Range: Enabled, Disabled Default: Disabled This setting enables and disables the permissive under-reaching transfer trip (PUTT) scheme. RX Pickup Delay Range: 0.000 to 65.535 seconds in steps of 0.001 Default: 0.000 seconds This setting enables the relay to cope with spurious receive signals.
Page 261 CHAPTER 7: PROTECTION CONTROL ELEMENTS Figure 203: PUTT scheme logic Permissive over-reaching transfer trip The permissive over-reaching transfer trip (POTT) scheme is intended for two-terminal line applications only. This scheme uses an over-reaching zone 2 distance element to essentially compare the direction to a fault at both terminals of the line. Ground directional overcurrent functions available in the relay can be used in conjunction with the zone 2 distance element to key the scheme and initiate its operation.
Page 262 CONTROL ELEMENTS CHAPTER 7: PROTECTION Figure 204: POTT scheme configuration settings The following settings are available for the permissive over-reaching transfer trip (POTT) scheme. Function Range: Enabled, Disabled Default: Disabled This setting enables and disables the permissive over-reaching transfer trip (POTT) scheme.
Page 263 CHAPTER 7: PROTECTION CONTROL ELEMENTS Transient Block Pickup Delay Range: 0.000 to 65.535 seconds in steps of 0.001 Default: 0.020 seconds This setting defines a transient blocking mechanism embedded in the POTT scheme for coping with the exposure of a ground directional overcurrent function (if used) to current reversal conditions.
Page 264 CONTROL ELEMENTS CHAPTER 7: PROTECTION Line End Open Pickup Delay Range: 0.000 to 65.535 seconds in steps of 0.001 Default: 0.050 seconds This setting specifies the pickup value for validation of the line end open conditions as detected by the line pickup logic through the FlexLogic™...
Page 265 CHAPTER 7: PROTECTION CONTROL ELEMENTS Events Range: Enabled, Disabled Default: Enabled This setting enables and disables the logging of permissive over-reaching transfer trip (POTT) scheme events in the sequence of events recorder. The permissive over-reaching transfer trip (POTT) scheme logic is shown below. Figure 205: POTT scheme logic Hybrid permissive over-reaching transfer trip The hybrid permissive over-reaching transfer trip (hybrid POTT) scheme generally uses an...
Page 266 CONTROL ELEMENTS CHAPTER 7: PROTECTION For proper operation, the zone 2 and 4 phase and ground distance elements must be enabled and configured according to the principles of distance relaying. The line pickup element should be enabled and configured to detect line-end-open or weak-infeed and undervoltage conditions.
Page 267 CHAPTER 7: PROTECTION CONTROL ELEMENTS Permissive Echo Range: Enabled, Custom, Disabled Default: Disabled If this setting is “Enabled”, the hybrid POTT scheme sends a permissive echo signal to the remote ends using pre-programmed logic (refer to the logic diagram below). If set to “Custom”, the echo signal is sent if the condition selected by the setting is Echo Condition...
Page 268 CONTROL ELEMENTS CHAPTER 7: PROTECTION Echo Duration Range: 0.000 to 65.535 seconds in steps of 0.001 Default: 0.100 seconds This setting specifies the guaranteed and exact duration of the echo pulse. The duration is not dependent on the duration and shape of received RX signals. This setting enables the relay to avoid a permanent lock-up of the transmit-receive loop.
Page 269 CHAPTER 7: PROTECTION CONTROL ELEMENTS either the negative sequence directional or neutral directional overcurrent element. Both these elements have separate forward and reverse output operands. The reverse indication should be used (that is, NEG SEQ DIR OC1 REV NEUTRAL DIR OC1 REV).
Page 270 CONTROL ELEMENTS CHAPTER 7: PROTECTION The hybrid permissive over-reaching transfer trip (hybrid POTT) scheme logic is shown below. Figure 207: Hybrid POTT scheme logic Directional comparison blocking The directional comparison blocking scheme compares the direction to a fault at all terminals of the line.
Page 271 CHAPTER 7: PROTECTION CONTROL ELEMENTS distance element to increase the coverage for high resistance faults. Also by default, only a reverse-looking zone 4 distance element identifies reverse faults. The ground directional overcurrent functions can be used in conjunction with the zone 4 distance element for better time and sensitivity coordination.
Page 272 CONTROL ELEMENTS CHAPTER 7: PROTECTION RX Coordination Pickup Delay Range: 0.000 to 65.535 seconds in steps of 0.001 Default: 0.010 seconds This setting specifies a time delay for the forward-looking protection elements used by the scheme for coordination with the blocking response from the remote ends. This setting should include both the response time of the protection elements used to establish a blocking signal and the total transmission time of that signal including the relay communications equipment interfacing and the communications channel itself.
Page 273 CHAPTER 7: PROTECTION CONTROL ELEMENTS Ground Directional OC Forward Range: any FlexLogic™ operand Default: OFF This setting defines the FlexLogic™ operand (if any) of a protection element used in addition to zone 2 for identifying faults on the protected line, and thus, for initiating operation of the scheme.
Page 274 CONTROL ELEMENTS CHAPTER 7: PROTECTION be de-asserted by the scheme based on the phase selection providing the peer device with more information on the fault type. Otherwise, the peer device issues a three-pole trip upon receiving the [0, 0, 0, 0] bit pattern. RX1, RX2, RX3, RX4 Range: any FlexLogic™...
Page 275 CHAPTER 7: PROTECTION CONTROL ELEMENTS Directional comparison unblocking The directional comparison unblocking scheme is available for single-pole tripping applications and can be used with one, two, or four bit communications channels. Choices of communications channel include remote inputs, remote outputs, and telecommunications interfaces.
Page 276 CONTROL ELEMENTS CHAPTER 7: PROTECTION Figure 210: Directional comparison unblocking scheme configuration settings The following settings are available for the directional comparison unblocking scheme. Function Range: Enabled, Disabled Default: Disabled This setting enables and disabled the directional comparison unblocking scheme. Block Range: any FlexLogic™...
Page 277 CHAPTER 7: PROTECTION CONTROL ELEMENTS Ground Directional OC Forward Range: any FlexLogic™ operand Default: OFF This setting selects the FlexLogic™ operand (if any) of a protection element used in addition to zone 2 for identifying faults on the protected line, and thus, for keying the communication channels and initiating operation of the scheme (both through the transient blocking logic).
Page 278 CONTROL ELEMENTS CHAPTER 7: PROTECTION However, if distance zone 1 picks up during the transient blocking condition, the blocking Plus action is removed. This allows the D90 cope with evolving faults when an external fault is followed by an internal fault. Without the zone 1 feedback, the trip would be unnecessarily delayed.
Page 279 CHAPTER 7: PROTECTION CONTROL ELEMENTS set relatively short, but long enough to ride through the transition period of loss-of- guard with the receipt of a permissive signal that occurs with a normal trip. Typical setting values are from 4 to 32 ms. For most cases, a value of 8 ms may be used. The tripping or unblocking window for loss-of-guard without permission is the difference between the timers specified by the Loss of Guard Trip Window...
Page 280 CONTROL ELEMENTS CHAPTER 7: PROTECTION RX1, RX2, RX3, RX4 Range: any FlexLogic™ operand Default: OFF These settings select FlexLogic™ operands to represent the permission receive signals for the scheme. Contact inputs interfacing with a signaling system are typically used. These settings must be used in conjunction with the loss-of-guard signals, otherwise the scheme will not unblock and thus fail to operate.
Page 281 CHAPTER 7: PROTECTION CONTROL ELEMENTS Figure 211: Directional comparison unblocking scheme logic, sheet 1 of 2 PLUS LINE DISTANCE PROTECTION SYSTEM – INSTRUCTION MANUAL...
Page 282: Setting Group Control
CONTROL ELEMENTS CHAPTER 7: PROTECTION Figure 212: Directional comparison unblocking scheme logic, sheet 2 of 2 Setting group control The setting groups control function activates and deactivates of up to six setting groups. Select the Settings > Protection > Control > Setting Group Control menu item to access the setting group control settings.
Page 283 CHAPTER 7: PROTECTION CONTROL ELEMENTS Block Range: any FlexLogic™ operand or shared operand Default: OFF This setting prevents the active setting group from changing when the assigned operand is asserted. This can be useful in applications where it is undesirable to change the settings under certain conditions, such as the breaker being open.
Page 284: Trip Output
CONTROL ELEMENTS CHAPTER 7: PROTECTION Trip output The trip output element is primarily used to collect trip requests from protection elements and other inputs to generate output operands to initiate trip operations. Three-pole trips will only initiate reclosure if programmed to do so, whereas single-pole trips will always automatically initiate reclosure.
Page 285 CHAPTER 7: PROTECTION CONTROL ELEMENTS Figure 215: Trip output configuration settings The following settings are available. Trip Mode Range: Disabled, 3 Pole Only, 3 Pole & 1 Pole Default: Disabled This setting selects the required mode of operation. If selected to “3 Pole Only”, outputs for all three phases are always set simultaneously.
Page 286 CONTROL ELEMENTS CHAPTER 7: PROTECTION operand is asserted by the autorecloser 1.5 cycles after single-pole AR FORCE 3-P TRIP reclosing is initiated. This operand calls for a three-pole trip if any protection element configured under with this setting remains picked-up. The open pole detector provides blocking inputs to distance elements;...
Page 287 CHAPTER 7: PROTECTION CONTROL ELEMENTS single-pole tripping applications when evolving faults are of importance and slightly delayed operation on evolving faults could be traded for enhanced accuracy of single- pole tripping. Trip Delay on Evolving Faults Range: 0 to 65.535 seconds in steps of 0.001 Default: 0.000 seconds This setting should be used in conjunction with the Reverse Fault...
Page 288 CONTROL ELEMENTS CHAPTER 7: PROTECTION Figure 216: Trip output scheme logic, sheet 1 of 2 PLUS LINE DISTANCE PROTECTION SYSTEM – INSTRUCTION MANUAL...
Page 289: Flexmatrix
CHAPTER 7: PROTECTION CONTROL ELEMENTS Figure 217: Trip output scheme logic, sheet 2 of 2 FlexMatrix The FlexMatrix allows up to 16 inputs to be aggregated and conditioned for tripping or auxiliary functions. Up to eight output signals can be derived from the input signals. Outputs can be configured for latching (lockout) and can also have a programmable pickup and dropout delay.
Page 290 CONTROL ELEMENTS CHAPTER 7: PROTECTION FlexMatrix inputs Select the Settings > Protection > Control > FlexMatrix > FlexMatrix Inputs menu item to access the FlexMatrix input settings. Figure 218: FlexMatrix input configuration settings The following setting is available for each of the 16 FlexMatrix inputs. Input 1, Input 2,..., Input 16 Range: any FlexLogic™...
Page 291 CHAPTER 7: PROTECTION CONTROL ELEMENTS Figure 219: FlexMatrix configuration settings The following settings are available for each of the eight FlexMatrix elements. Function Range: Enabled, Disabled Default: Disabled This setting enables or disables the FlexMatrix element. Name Range: 12 alphanumeric characters Default: Flexmat 1 This setting specifies the name associated with a particular FlexMatrix element.
Page 292: Vt Fuse Failure
CONTROL ELEMENTS CHAPTER 7: PROTECTION Dropout Delay Range: 0.000 to 60.000 seconds in steps of 0.001 Default: 0.000 seconds This setting specifies the delay by which to extend the FlexMatrix dropout. Latching Range: Enabled, Disabled Default: Disabled When this setting is enabled, the FlexMatrix output is latched until the reset input is asserted.
Page 293 CHAPTER 7: PROTECTION CONTROL ELEMENTS The VT fuse failure detector can be used to raise an alarm or block elements that may operate incorrectly for a full or partial loss of AC potential caused by one or more blown fuses. Some elements that might be blocked (via the Block setting) include voltage restrained overcurrent and directional current.
Page 294: Open Pole Detector
CONTROL ELEMENTS CHAPTER 7: PROTECTION Figure 222: VT fuse failure scheme logic Open pole detector The open pole detector is intended to identify an open pole of the line circuit breaker. The scheme monitors the breakers auxiliary contacts, current in the circuit, and voltage (optional) on the line.
Page 295 CHAPTER 7: PROTECTION CONTROL ELEMENTS Figure 223: Open pole detector configuration settings The following settings are available for the open pole detector feature. Function Range: Enabled, Disabled Default: Disabled This setting enables and disabled the open pole detector feature. Block Range: any FlexLogic™...
Page 296 CONTROL ELEMENTS CHAPTER 7: PROTECTION Open Pole Remote Current Pickup Range: 0.000 to 30.000 pu in steps of 0.001 Default: 0.050 pu This setting specifies the pickup level for the remote-end current estimated by the relay as the local current compensated by the calculated charging current. The latter is calculated based on the local voltages and the capacitive reactances of the line.
Page 297: Autoreclose
CHAPTER 7: PROTECTION CONTROL ELEMENTS Figure 225: Open pole detector scheme logic, sheet 2 of 2 Autoreclose The autoreclose scheme is intended for use on transmission lines with circuit breakers operated in both the single-pole and three-pole modes, in one or two breaker arrangements.
Page 298 CONTROL ELEMENTS CHAPTER 7: PROTECTION Autoreclose programs The autorecloser provides four programs that can cause from one to four reclose attempts (shots). After the first shot, all subsequent reclosings will always be three-pole. If the maximum number of shots selected is 1 (only one reclose attempt) and the fault is persistent, after the first reclose the scheme will go to lockout upon another initiate signal.
Page 299 CHAPTER 7: PROTECTION CONTROL ELEMENTS Figure 226: Autoreclose scheme enable logic Figure 227: Autoreclose scheme initiate logic A reclose initiate signal will send the scheme into the reclose-in-progress (RIP) state and assert the operand. Once the breaker has opened, the scheme is latched into the AR RIP reclose-in-progress state and resets only when an (autoreclose breaker 1) or...
Page 300 CONTROL ELEMENTS CHAPTER 7: PROTECTION Figure 228: Autoreclose scheme reclose-in-progress logic After entering the reclose-in-progress state, a close command will be issued after the dead time delay. The dead time for the initial reclose operation will be determined by either the , or setting, depending on the fault type 1-P Dead Time...
Page 301 CHAPTER 7: PROTECTION CONTROL ELEMENTS and the mode selected. After the dead time interval the scheme will assert the AR CLOSE operands, as determined by the sequence selected. These operands BKR 1 AR CLOSE BKR 2 are latched until the breaker closes or the scheme goes to reset or lockout. Figure 229: Autoreclose scheme breaker close logic Figure 230: Autoreclose scheme close breaker 1 or 2 logic Figure 231: Autoreclose scheme termination...
Page 302 CONTROL ELEMENTS CHAPTER 7: PROTECTION Figure 232: Autoreclose scheme shot counter logic Autoreclose pause input The autoreclose pause input offers the possibility of freezing the autoreclose cycle until the pause signal disappears. This may be done when a trip occurs and simultaneously or previously, some conditions are detected such as out-of step or loss of guard frequency, or a remote transfer trip signal is received.
Page 303 CHAPTER 7: PROTECTION CONTROL ELEMENTS Figure 234: Autoreclose scheme transfer logic When the 1-2 reclosing sequence is selected and breaker 1 is blocked (the AR BKR1 BLK operand is set) the reclose signal can be transferred direct to breaker 2 if the Transfer 1 to setting is “Yes”.
Page 304 CONTROL ELEMENTS CHAPTER 7: PROTECTION Figure 235: Autoreclose scheme failure-to-close logic Figure 236: Typical autoreclose sequence PLUS LINE DISTANCE PROTECTION SYSTEM – INSTRUCTION MANUAL...
Page 305 CHAPTER 7: PROTECTION CONTROL ELEMENTS Breaker block A reclose command to a breaker is inhibited if it receives a user-defined block input or if it is out-of-service. A logic circuit is also provided that inhibits a breaker reclose if that breaker was open in advance of a reclose initiate input to the recloser.
Page 306 CONTROL ELEMENTS CHAPTER 7: PROTECTION Autoreclose lockout When a reclose sequence is started by an initiate signal, the autoreclose scheme moves into the reclose-in-progress state and starts the incomplete sequence timer. The setting of this timer determines the maximum time interval allowed for a single reclose shot. If a close breaker 1 or 2 signal is not present before this time expires, the scheme enters the lockout state.
Page 307 CHAPTER 7: PROTECTION CONTROL ELEMENTS Figure 239: Autoreclose scheme lockout logic PLUS LINE DISTANCE PROTECTION SYSTEM – INSTRUCTION MANUAL...
Page 308 CONTROL ELEMENTS CHAPTER 7: PROTECTION Zone 1 extension in the autoreclose scheme Two approaches are available for implementation of zone 1 extension. The first method is to operate normally from an under-reaching zone and use an overreaching distance zone when reclosing the line with the other line end open. This method can be programmed via the line pickup scheme.
Page 309 CHAPTER 7: PROTECTION CONTROL ELEMENTS • Breaker 2 issues a manual close and sequence 1 is not selected and breaker 1 is either open or out-of-service. Alternately, a user-defined setting is available to generate this signal. Figure 242: Autoreclose scheme manual close logic Terminal closed The close logic uses the status of each breaker to determine whether the terminal is closed.
Page 310 CONTROL ELEMENTS CHAPTER 7: PROTECTION Figure 244: Autoreclose scheme closing logic, sheet 2 of 2 Terminal three-pole open The autoreclose scheme employs dedicated logic to determine if all three poles are opened at the local terminal. This signal is used in the preceding logic. For single breaker operation, the breaker status is sufficient to derive this signal.
Page 311 CHAPTER 7: PROTECTION CONTROL ELEMENTS Figure 245: Terminal three-pole open logic Terminal one-pole open The autoreclose scheme also has dedicated logic to determine if one pole is opened at the local terminal. For single breaker operation, the BREAKER 1 ONE P OPEN BREAKER 2 ONE P operand is used to derive this signal.
Page 312 CONTROL ELEMENTS CHAPTER 7: PROTECTION Figure 246: Terminal one-pole open logic Autoreclose settings Select the Settings > Protection > Control > Autoreclose menu item to access the autoreclose settings. PLUS LINE DISTANCE PROTECTION SYSTEM – INSTRUCTION MANUAL...
Page 313 CHAPTER 7: PROTECTION CONTROL ELEMENTS Figure 247: Autoreclose settings window The following settings are available for the autoreclose element. Function Range: Disabled, Enabled Default: Disabled This setting enables and disables the autoreclose scheme. Mode Range: 1 & 3 Pole, 1 Pole, 3 Pole-A, 3 Pole-B Default: 1 &...
Page 314 CONTROL ELEMENTS CHAPTER 7: PROTECTION Select Time Range: 1.0 to 30.0 seconds in steps of 0.1 Default: 5 seconds This setting determines the maximum permissible time from selection of autoreclose and a control action. Maximum Number of Shots Range: 1, 2, 3, 4 Default: 2 This setting specifies the number of reclosures attempted before reclosure goes to lockout when the fault is permanent.
Page 315 CHAPTER 7: PROTECTION CONTROL ELEMENTS 3-Pole TD Initiate Range: any FlexLogic™ operand or shared operand Default: Off This setting selects an operand used to initiate three-pole autoreclosure. The second timer ( ) can be used for a time-delay autoreclosure. 3-Pole Dead Time 2 Multi-Phase Fault Range: any FlexLogic™...
Page 316 CONTROL ELEMENTS CHAPTER 7: PROTECTION Extend Dead Time 1 Range: any FlexLogic™ operand or shared operand Default: Off This setting selects an operand that will adapt the duration of the dead time for the first shot to the possibility of non-simultaneous tripping at the two line ends. Typically this is the operand set when the communication channel is out-of-service.
Page 317 CHAPTER 7: PROTECTION CONTROL ELEMENTS Incomplete Sequence Time Range: 0 to 655.35 seconds in steps of 0.01 Range: 5.00 seconds This setting is used to set the maximum time interval allowed for a single reclose shot. It is started whenever a reclosure is initiated and is active until the CLOSE BKR1 CLOSE signal is sent.
Page 318 CONTROL ELEMENTS CHAPTER 7: PROTECTION Breaker 2 Failure Option Range: Continue, Lockout Default: Continue This setting establishes how the scheme performs when the breaker closing sequence is “2-1” and breaker 2 has failed to close. When set to “Continue”, the closing command will be transferred to breaker 1 which will continue the reclosing cycle until successful (the scheme will reset) or unsuccessful (the scheme will go to lockout).
Page 319 CHAPTER 7: PROTECTION CONTROL ELEMENTS Figure 248: Final autoreclose signal flow logic Front panel status and control If the autoreclose function is enabled, an indication will appear on the screen. This indication indicates the operational status of the autoreclose function as defined below. Table 20: Autoreclose front panel indications Indication FlexLogic™...
Page 320: Underfrequency
CONTROL ELEMENTS CHAPTER 7: PROTECTION Indication FlexLogic™ operand Autoreclose Locked Out AR LO Autoreclose control is available at the top level screen by pressing the AR pushbutton. If local control is not asserted for autoreclose, then the AR pushbutton will be grey and not operable.
Page 321 CHAPTER 7: PROTECTION CONTROL ELEMENTS Select the Settings > Protection > Control > Underfrequency menu item to open the underfrequency settings window. Figure 251: Underfrequency configuration settings The following settings are available for each underfrequency element. Function Range: Enabled, Disabled Default: Disabled This setting enables and disables the underfrequency function.
Page 322: Overfrequency
CONTROL ELEMENTS CHAPTER 7: PROTECTION Reset Delay Range: 0.000 to 65.535 seconds in steps of 0.001 Default: 2.000 seconds This setting specifies a time delay on dropout for the duration between the operate output state and the return to logic 0 after the input transits outside the defined pickup range.
Page 323 CHAPTER 7: PROTECTION CONTROL ELEMENTS Figure 253: Overfrequency configuration settings The following settings are available for each overfrequency element. Function Range: Enabled, Disabled Default: Disabled This setting enables and disables the overfrequency function. Source Range: LINE (SRC 1), BKR 1 (SRC 2), BKR 2 (SRC 3) Default: LINE (SRC 1) This setting selects the source for the signal to be measured.
Page 324: Breaker Configuration
CONTROL ELEMENTS CHAPTER 7: PROTECTION Figure 254: Overfrequency scheme logic Breaker configuration The breaker configuration element contains the auxiliary logic for status and serves as the interface for opening and closing of the breaker from protection and automation functions. The logic also permits a manual substitution of the position indication. Select the Settings >...
Page 325 CHAPTER 7: PROTECTION CONTROL ELEMENTS Long Name Range: 20 alphanumeric characters Default: Breaker 1 This setting is used to identify the primary device for control confirmations on the front panel interface and in the event record. Short Name Range: up to 6 alphanumeric characters Default: BKR1 This setting identifies the primary device pushbuttons and indications on the front panel interface.
Page 326 CONTROL ELEMENTS CHAPTER 7: PROTECTION Block Close Command Range: any FlexLogic™ operand or shared operand Default: Off This setting selects an operand that prevents closing of the breaker. This setting can be used for select-before-operate functionality or to block operation from a panel switch or from SCADA.
Page 327 CHAPTER 7: PROTECTION CONTROL ELEMENTS Phase C Opened Status Range: any FlexLogic™ operand or shared operand Default: Off The operand selected by this setting is used to derive the phase B breaker position indication from a normally-closed (52b) status input. If unavailable, the closed status input can be inverted to provide this signal.
Page 328 CONTROL ELEMENTS CHAPTER 7: PROTECTION Figure 256: Breaker configuration logic, sheet 1 of 4 PLUS LINE DISTANCE PROTECTION SYSTEM – INSTRUCTION MANUAL...
Page 329 CHAPTER 7: PROTECTION CONTROL ELEMENTS Figure 257: Breaker configuration logic, sheet 2 of 4 PLUS LINE DISTANCE PROTECTION SYSTEM – INSTRUCTION MANUAL...
Page 330 CONTROL ELEMENTS CHAPTER 7: PROTECTION Figure 258: Breaker configuration logic, sheet 3 of 4 PLUS LINE DISTANCE PROTECTION SYSTEM – INSTRUCTION MANUAL...
Page 331: Breaker Flashover
CHAPTER 7: PROTECTION CONTROL ELEMENTS Figure 259: Breaker configuration logic, sheet 4 of 4 Breaker flashover The detection of breaker flashover is based on the following condition. Breaker open. Voltage drop measured from either side of the breaker during the flashover period. Voltage difference drop.
Page 332 CONTROL ELEMENTS CHAPTER 7: PROTECTION Breaker flashover settings Select the Settings > Protection > Control > Breaker Flashover menu item to open the breaker flashover configuration window. Figure 260: Breaker flashover configuration settings The following settings are available for each breaker flashover element. Function Range: Enabled, Disabled Default: Disabled...
Page 333 CHAPTER 7: PROTECTION CONTROL ELEMENTS Voltage Pickup Range: 0.000 to 1.500 pu in steps of 0.001 Default: 0.850 pu This setting specifies a pickup level for the phase voltages from both sides of the breaker. If six VTs are available, opening the breaker leads to two possible combinations – live voltages from only one side of the breaker, or live voltages from both sides of the breaker.
Page 334 CONTROL ELEMENTS CHAPTER 7: PROTECTION Figure 261: Breaker flashover scheme logic, sheet 1 of 2 Figure 262: Breaker flashover scheme logic, sheet 2 of 2 Three VT breaker flashover application When only one set of VTs is available across the breaker, the setting should be Side 2 “None”.
Page 335 CHAPTER 7: PROTECTION CONTROL ELEMENTS input indicating the breaker status is off), and no flashover current is flowing. A contact showing the breaker status must be provided to the relay. The voltage difference will not be considered as a condition for open breaker in this part of the logic. Voltages must be present prior to flashover conditions.
Page 336: Digital Counters
CONTROL ELEMENTS CHAPTER 7: PROTECTION Consider the configuration below. Figure 264: Breaker flashover application example The source 1 (SRC1) phase currents are CTs and phase voltages are bus VTs. The source 2 (SRC2) phase voltages are line VTs. Contact input 1 is set as the breaker 52a contact (optional).
Page 337 CHAPTER 7: PROTECTION CONTROL ELEMENTS Function Range: Enabled, Disabled Default: Disabled This setting enables and disables the digital counter. Name Range: up to 12 alphanumeric characters Default: Counter 1 An alphanumeric name may be assigned to a digital counter for diagnostic, setting, and event recording purposes.
Page 338 CONTROL ELEMENTS CHAPTER 7: PROTECTION Set To Preset Range: any FlexLogic™ operand or shared operand Default: OFF This setting selects an operand used to set the count to the preset value and functions as follows. – The counter will be set to the preset value when the counter is enabled and the operand assigned to the setting is asserted (logic 1).
Page 339: Flexcurves
CHAPTER 7: PROTECTION CONTROL ELEMENTS Figure 266: Digital counter scheme logic FlexCurves™ Plus There are four user-programmable FlexCurves™ available with the D90 system, labeled A, B, C, and D. The curve shapes for the four FlexCurves are derived from the following equations. Eq.
Page 340 CONTROL ELEMENTS CHAPTER 7: PROTECTION Figure 267: FlexCurve configuration settings The following settings are available for each custom FlexCurve™. FlexCurve Name Range: up to 20 alphanumeric characters Default: FlexCurve A This setting specifies a user-defined name for the FlexCurve™. Initialize From Range: IEEE Moderately Inverse, IEEE Very Inverse, IEEE Extremely Inverse, IEC Curve A, IEC Curve B, IEC Curve C, IEC Short Inverse, IAC Extreme Inv, IAC Very Inverse, IAC Inverse, IAC Short Inverse, I Squared T, Recloser Curve, FlexCurve A, FlexCurve B, FlexCurve C,...
Page 341 CHAPTER 7: PROTECTION CONTROL ELEMENTS Figure 268: FlexCurve™ display example Prospective FlexCurves™ can be configured from a selection of standard curves to provide the best approximate fit, then specific data points can be edited afterwards. Click the Initialize FlexCurve button to populate the pickup values with the points from the curve specified by the setting.
Page 342 CONTROL ELEMENTS CHAPTER 7: PROTECTION Figure 269: Recloser curve initialization The multiplier and adder settings only affect the curve portion of the characteristic and not NOTE: the MRT and HCT settings. The HCT settings override the MRT settings for multiples of pickup greater than the HCT ratio.
Page 343: Protection Inputs And Outputs
CHAPTER 7: PROTECTION PROTECTION INPUTS AND OUTPUTS Figure 271: Composite recloser curve with HCT enabled Configuring a composite curve with an increase in operating time at increased pickup NOTE: Plus multiples is not allowed. If this is attempted, the EnerVista UR Setup software generates an error message and discards the proposed changes.
Page 344 PROTECTION INPUTS AND OUTPUTS CHAPTER 7: PROTECTION Figure 272: Protection virtual inputs configuration settings The following settings are available for each protection virtual input. The default values shown are for virtual input 1. Function Range: Enabled, Disabled Default: Disabled If this setting is “Disabled”, the virtual input will be forced to off (logic 0) regardless of any attempt to alter the input.
Page 345: Protection Virtual Outputs
CHAPTER 7: PROTECTION PROTECTION INPUTS AND OUTPUTS Figure 273: Protection virtual input logic Protection virtual outputs There are 96 virtual outputs that may be assigned via FlexLogic™. Virtual outputs are resolved in each pass through the evaluation of FlexLogic™ equations. Select the Settings >...
Page 346: Contact Input And Output Default Assignment
PROTECTION INPUTS AND OUTPUTS CHAPTER 7: PROTECTION Contact input and output default assignment When a new settings file is created, the available contacts are automatically assigned to the protection or automation functions according to the following convention. First I/O module → protection. •...
Page 347 CHAPTER 7: PROTECTION PROTECTION INPUTS AND OUTPUTS at 2.0 ms in the figure below; as such, the eighth sample validates the change of state (mark 1 in the figure below). Once validated (de-bounced), the contact input asserts a corresponding FlexLogic™ operand and logs an event (if event logging is enabled). A time stamp of the first sample in the sequence that validates the new state is used when logging the change of the contact input into the event recorder (mark 2 in the figure below).
Page 348 PROTECTION INPUTS AND OUTPUTS CHAPTER 7: PROTECTION The active impedance feature controls the input impedance presented to the system according to the current state of the input. When the contact input circuitry initially detects a voltage increase, it will draw 10 mA of current. If the state change is due to a transient coupled through the stray capacitance of the field wiring, then the high current sink will charge the capacitance causing the transient to rapidly decay.
Page 349 CHAPTER 7: PROTECTION PROTECTION INPUTS AND OUTPUTS Nominal Voltage Range: 24 to 250 volts in steps of 1 Default: 125 volts This setting specifies the range required to validate a closed contact input. This range is fixed at 70 to 130% of this setting value, with an absolute minimum of 20 volts and an absolute maximum of 285 volts.
Page 350: Contact Outputs
PROTECTION INPUTS AND OUTPUTS CHAPTER 7: PROTECTION Figure 279: Contact input chatter detection configuration The following settings are applied to all available protection and automation contact inputs. Function Range: Enabled, Disabled Default: Disabled This setting enables and disables the chatter detection feature. Chatter Time Range: 1 to 100 seconds in steps of 1 Default: 10 seconds...
Page 351: Shared Operands
CHAPTER 7: PROTECTION PROTECTION INPUTS AND OUTPUTS Operate Range: any FlexLogic™ operand or shared operand Default: as shown above This setting selects an operand (virtual output, element state, contact input, or virtual input) that will operate the contact output when asserted. Seal-In Range: any FlexLogic™...
Page 352 PROTECTION INPUTS AND OUTPUTS CHAPTER 7: PROTECTION Figure 281: Default operand list by function The content of each operand list is dependent on the selected order code. The shared operands functionality expands upon this system. With this feature, an output Plus from any element can be assigned as a shared operand within the EnerVista UR Setup software.
Page 353: Protection Flexlogic
CHAPTER 7: PROTECTION PROTECTION FLEXLOGIC™ Figure 282: Shared operands configuration window Plus The left side of this screen displays all D90 operands that are available to the protection function as shared operands. Select any operands from the other five primary features by clicking on the >>...
Page 354 PROTECTION FLEXLOGIC™ CHAPTER 7: PROTECTION Plus Figure 283: UR -series architecture overview Plus The states of all digital signals used in the D90 are represented by flags (or FlexLogic™ operands, which are described later in this section). A logic 1 state is represented by a set flag.
Page 355 CHAPTER 7: PROTECTION PROTECTION FLEXLOGIC™ The logic that determines the interaction of inputs, elements, schemes and outputs is field programmable through the use of logic equations that are sequentially processed. The use of virtual inputs and outputs in addition to hardware is available internally and on the communication ports for other relays to use (distributed FlexLogic™).
Page 356: Protection Flexlogic™ Gates And Operators
PROTECTION FLEXLOGIC™ CHAPTER 7: PROTECTION Type State Example Characteristics (input is logic 1 or “on” if...) Element Pickup The output operand is at logic 1. DIG ELEM 1 PKP (digital) Dropout This operand is the logical inverse of the DIG ELEM 1 DPO pickup operand.
Page 357: Flexlogic™ Rules
CHAPTER 7: PROTECTION PROTECTION FLEXLOGIC™ Type Syntax Description Operation Logic A logical NOT gate. Operates on the previous gates parameter. AND(n) An n-input AND gate, n = 1 to 16. Operates on the previous n parameters. OR(n) An n-input OR gate, n = 1 to 16. Operates on the previous n parameters.
Page 358 PROTECTION FLEXLOGIC™ CHAPTER 7: PROTECTION Figure 284: EnerVista Viewpoint Engineer typical view The Viewpoint Engineer compiler function can be used to check for problems with the logic once it has been created. Warning and error messages generated by the compiler are listed in the following tables.
Page 359: Protection Flexlogic™ Equation Editor
CHAPTER 7: PROTECTION PROTECTION FLEXLOGIC™ Table 26: Viewpoint Engineer compiler errors Message Description Affected operator Connection In not connected A connection-input symbol is not referencing an Connection input existing logic or math operator. Input not connected One or more of the inputs to an operator has no connection.
Page 360: Protection Flexlogic™ Timers
PROTECTION FLEXLOGIC™ CHAPTER 7: PROTECTION Figure 285: Protection FlexLogic™ configuration settings A graphical representation of the protection FlexLogic™ can be displayed by clicking on the View button at the top of the equation. Figure 286: Typical protection FlexLogic™ display Protection FlexLogic™ timers There are 32 identical protection FlexLogic™...
Page 361: Non-Volatile Latches
CHAPTER 7: PROTECTION PROTECTION FLEXLOGIC™ Dropout Delay Range: 0 to 3600000000 ms in steps of 1 Default: 0 This setting specifies the time delay to dropout. If a dropout delay is not required, set this value to “0”. Non-volatile latches The non-volatile latches provide a permanent logical flag that is stored safely and will not reset upon reboot after the relay is powered down.
Page 362: Protection Flexelements
PROTECTION FLEXLOGIC™ CHAPTER 7: PROTECTION Table 28: Non-volatile latch operation table Type Latch operation Reset Reset-dominant Previous state Previous state Set-dominant Previous state Previous state The logic for protection non-volatile latches is shown below. Figure 289: Non-volatile latches scheme logic Protection FlexElements™...
Page 363 CHAPTER 7: PROTECTION PROTECTION FLEXLOGIC™ Figure 290: Protection FlexElements™ configuration settings The following settings are available for each protection FlexElement™. Function Range: Enabled, Disabled Default: Disabled This setting enables and disables the corresponding FlexElement™. Name Range: up to 6 alphanumeric characters Default: FxE 1 An alphanumeric identifier may be assigned to a FlexElement™...
Page 364 PROTECTION FLEXLOGIC™ CHAPTER 7: PROTECTION Input Mode Range: Signed, Absolute Default: Signed If this setting value is “Signed”, then the FlexElement™ responds directly to the differential signal. If this setting value is “Absolute”, then the FlexElement™ responds to the absolute value of the differential signal. Sample applications for the absolute input mode include monitoring the angular difference between two phasors with a symmetrical limit angle in both directions, monitoring power regardless of its direction, or monitoring a trend regardless of whether the signal increases of decreases.
Page 365 CHAPTER 7: PROTECTION PROTECTION FLEXLOGIC™ Figure 291: Relationship of input mode and direction settings Pickup Range: –90.000 to 90.000 pu in steps of 0.001 Default: 1.000 pu This setting specifies the operating threshold for the effective operating signal of the FlexElement™.
Page 366 PROTECTION FLEXLOGIC™ CHAPTER 7: PROTECTION Element Base unit Power factor 1.00 Source current Maximum nominal primary RMS value of the +IN and –IN inputs Source power Maximum value of the product of the voltage and current base values for the +IN and –IN inputs. Source voltage Maximum nominal primary RMS value of the +IN and –IN inputs.
Page 367: Protection Flexlogic™ Operands
CHAPTER 7: PROTECTION PROTECTION FLEXLOGIC™ Block Range: any FlexLogic™ operand or shared operand Default: Off Assertion of the operand assigned to this setting blocks operation of the FlexElement™. Events Range: Enabled, Disabled Default: Disabled This setting enables and disables the logging of FlexElement™ events in the sequence of events recorder.
Page 368 PROTECTION FLEXLOGIC™ CHAPTER 7: PROTECTION AR LO...............Asserted when the autoreclose element is in the lockout state. AR RESET............Asserted when the autoreclose element has been reset manually or by the reset timer. AR RIP..............Asserted when the autoreclose element is in the reclose-in- progress state.
Page 369 CHAPTER 7: PROTECTION PROTECTION FLEXLOGIC™ BKR1A INTERMED........Asserted when breaker 1 pole A is in transition between the opened and closed states. BKR1A OPENED...........Asserted when breaker 1 pole A is opened. BKR1B BAD STATE ........Asserted when the normally open and normally closed breaker indications disagree for pole B of breaker 1.
Page 370 PROTECTION FLEXLOGIC™ CHAPTER 7: PROTECTION CONTACT IP 1 OFF ........Asserted when the field contact connected to contact input 1 is opened. CONTACT IP 1 TROUBLE OP....Asserted when there is an internal or external problem with contact input 1. CONTACT IP 1 TROUBLE DPO....Asserted when there are no problems with contact input 1. CONTACT IP 2 to 40........The operands listed above are available for the contact inputs 2 through 40.
Page 371 CHAPTER 7: PROTECTION PROTECTION FLEXLOGIC™ DIR BLOCK TX3 STOP........Asserted when the directional blocking scheme de-asserts transmit bit 3. DIR BLOCK TX4 STOP........Asserted when the directional blocking scheme de-asserts transmit bit 4. Direct underreaching transfer trip operands DUTT OP ............Asserted when the direct underreaching transfer trip scheme operates.
Page 372 PROTECTION FLEXLOGIC™ CHAPTER 7: PROTECTION GND DIST Z2 DIR SUPN ......Asserted when ground distance zone 2 directional is supervising. This operand is only available for zone 2. GND DIST Z2 to Z5........The operands listed above are also available for ground distance elements 2 through 5.
Page 373 CHAPTER 7: PROTECTION PROTECTION FLEXLOGIC™ LINE PICKUP LEO PKP.......Asserted when the line pickup element line end open feature picks up. LINE PICKUP OP ..........Asserted when the line pickup element operates. LINE PICKUP PKP ........Asserted when the line pickup element picks up. LINE PICKUP RCL TRIP......Asserted when the line pickup element operates from overreaching zone 2 when reclosing the line (zone 1 extension functionality).
Page 374 PROTECTION FLEXLOGIC™ CHAPTER 7: PROTECTION Neutral instantaneous overcurrent operands NEUTRAL IOC1 DPO........Asserted when the neutral instantaneous overcurrent 1 element drops out. NEUTRAL IOC1 OP ........Asserted when the neutral instantaneous overcurrent 1 element operates. NEUTRAL IOC1 PKP ........Asserted when the neutral instantaneous overcurrent 1 element picks up.
Page 375 CHAPTER 7: PROTECTION PROTECTION FLEXLOGIC™ OPEN POLE OP ΦC........Asserted when an open pole condition is detected in phase C. OPEN POLE REM OP ΦA......Asserted when a remote open pole condition is detected in phase A. OPEN POLE REM OP ΦB......Asserted when a remote open pole condition is detected in phase B.
Page 376 PROTECTION FLEXLOGIC™ CHAPTER 7: PROTECTION PHASE IOC1 OP A........Asserted when phase A of the phase instantaneous overcurrent 1 element operates. PHASE IOC1 OP B........Asserted when phase B of the phase instantaneous overcurrent 1 element operates. PHASE IOC1 OP C........Asserted when phase C of the phase instantaneous overcurrent 1 element operates.
Page 377 CHAPTER 7: PROTECTION PROTECTION FLEXLOGIC™ PHASE SELECT BG........Asserted when a phase B to ground fault is detected. PHASE SELECT CA ........Asserted when a phase C to A fault is detected. PHASE SELECT CAG........Asserted when a phase C to A to ground fault is detected. PHASE SELECT CG........Asserted when a phase C to ground fault is detected.
Page 378 PROTECTION FLEXLOGIC™ CHAPTER 7: PROTECTION PHASE UV1 OP C ........Asserted when phase C of the phase undervoltage 1 element operates. PHASE UV1 PKP ..........Asserted when at least one phase of the phase undervoltage 1 element picks up. PHASE UV1 PKP A ........Asserted when phase A of the phase undervoltage 1 element picks up.
Page 379 CHAPTER 7: PROTECTION PROTECTION FLEXLOGIC™ POWER SWING UN/BLOCK....Asserted when the out-of-step tripping function operates. Permissive underreach transfer trip (PUTT scheme) operands PUTT OP............Asserted when power permissive under-reaching transfer trip scheme operates. PUTT TRIP 3P ..........Asserted when power permissive under-reaching transfer trip scheme operates to trip all three phases.
Page 380 PROTECTION FLEXLOGIC™ CHAPTER 7: PROTECTION TRIP PHASE B ..........Asserted upon a breaker pole B trip, initiate phase A breaker fail and reclose. TRIP PHASE C ..........Asserted upon a breaker pole C trip, initiate phase A breaker fail and reclose. PLUS LINE DISTANCE PROTECTION SYSTEM –...
Page 381: Automation
Plus Line Distance Protection System Chapter 8: Automation Automation Plus This section describes how to program the D90 automation features. Automation controller overview Plus The D90 automation controller allows the user to easily implement a variety of custom automation schemes. The controller can access both digital and analog inputs and outputs.
Page 382: Input And Output Structure
AUTOMATION CONTROLLER OVERVIEW CHAPTER 8: AUTOMATION Input and output structure Plus The input and output structure of the D90 is shown below. Three groupings of inputs and outputs are defined: physical, shared, and virtual, with digital and analog types within each grouping.
Page 383: Breakers
CHAPTER 8: AUTOMATION BREAKERS shared operands. This allows the automation function access to a large variety of analog measurements resident in the protection functions. • Virtual inputs and outputs: A total of 64 points are available in the controller for storage of the intermediate of final results of math processing (defined as virtual analog outputs).
Page 384 BREAKERS CHAPTER 8: AUTOMATION Local Control Range: any automation logic operand or shared operand Default: L/R-L On When the operand assigned to this setting is asserted, control is enabled from the front panel interface. This setting is normally assigned to the local status of a local/remote switch.
Page 385 CHAPTER 8: AUTOMATION BREAKERS Bypass Time Range: 0.0 to 30.0 seconds in steps of 0.1 Default: 10.0 seconds This setting determines the time window during which non-interlocked control can occur once bypass has been selected. The breaker control logic is shown in the following figures. Figure 297: Breaker control logic, sheet 1 of 3 PLUS LINE DISTANCE PROTECTION SYSTEM –...
Page 386: Breaker Interlocking
BREAKERS CHAPTER 8: AUTOMATION Figure 298: Breaker control logic, sheet 2 of 3 Figure 299: Breaker control logic, sheet 3 of 3 Breaker interlocking The breaker interlocking element contains the auxiliary logic for interlocking of circuit breakers. Up to three inputs can be assigned for interlocking the open and close controls. An input is also available for supervision by a synchrocheck element.
Page 387 CHAPTER 8: AUTOMATION BREAKERS Figure 300: Breaker interlocking configuration settings The following settings are available for each breaker interlocking element. Function Range: Enabled, Disabled Default: Disabled This setting enables the breaker position indications and control logic. If disabled, all outputs and front panel indications are switched off. Tagging Range: Enabled, Disabled Default: Disabled...
Page 388: Disconnects
DISCONNECTS CHAPTER 8: AUTOMATION Events Range: Enabled, Disabled Default: Enabled The setting enables or disables the logging of breaker interlocking events in the sequence of events recorder. The breaker interlocking logic is shown below. Figure 301: Breaker interlocking logic Disconnects The disconnect element contains the auxiliary logic for status and serves as the interface for opening and closing of the disconnect from protection and automation functions.
Page 389 CHAPTER 8: AUTOMATION DISCONNECTS Figure 302: Disconnect configuration settings The following settings are available for each disconnect. Function Range: Enabled, Disabled Default: Enabled This setting enables the disconnect position indications and control logic. If disabled, all outputs and front panel indications are switched off. Long Name Range: up to 12 alphanumeric characters Default: DISCONNECT 1...
Page 390 DISCONNECTS CHAPTER 8: AUTOMATION Disconnect Local Input Range: any automation logic operand or shared operand Default: OFF Closing or opening of the disconnect through the disconnect interlock element is inhibited if the operand assigned to this setting is asserted. Indication Mode Range: 3-Pole, 1-Pole Default: 3-Pole If the “3-Pole”...
Page 391 CHAPTER 8: AUTOMATION DISCONNECTS Operate Time Range: 0.000 to 2.000 seconds in steps of 0.001 Default: 0.070 seconds This setting specifies a timer that is asserted when both the normally open and normally closed disconnect indications are reset. When the timer expires, a bad status is indicated for the disconnect.
Page 392 DISCONNECTS CHAPTER 8: AUTOMATION Figure 304: Disconnect scheme logic, sheet 2 of 4 Figure 305: Disconnect scheme logic, sheet 3 of 4 PLUS LINE DISTANCE PROTECTION SYSTEM – INSTRUCTION MANUAL...
Page 393: Disconnect Control
CHAPTER 8: AUTOMATION DISCONNECTS Figure 306: Disconnect scheme logic, sheet 4 of 4 Disconnect control The disconnect control element contains the auxiliary logic for control of circuit breakers required for SCADA and the front panel interface. The control function incorporates select- before-operate functionality.
Page 394 DISCONNECTS CHAPTER 8: AUTOMATION Figure 307: Disconnect control configuration settings The following settings are available for each disconnect. Function Range: Enabled, Disabled Default: Enabled This setting enables and disables the disconnect control feature. Pushbutton Control Range: Enabled, Disabled Default: Enabled This setting enables control of the device via the front panel and populates the front panel interface with control soft-keys.
Page 395 CHAPTER 8: AUTOMATION DISCONNECTS Automatic Open Range: any automation logic operand or shared operand Default: OFF The operand assigned to this setting is used to open the device from an automatic control scheme. Execute Time Range: 0.0 to 10.0 seconds in steps of 0.1 Default: 10.0 seconds This setting determines the duration of the open and close commands used to control the disconnect.
Page 396: Disconnect Interlocking
DISCONNECTS CHAPTER 8: AUTOMATION Figure 309: Disconnect control logic, sheet 2 of 3 Figure 310: Disconnect control logic, sheet 3 of 3 Disconnect interlocking The disconnect interlocking element contains the auxiliary logic for interlocking of disconnects. Up to three inputs can be assigned for interlocking the open and close controls.
Page 397 CHAPTER 8: AUTOMATION DISCONNECTS Figure 311: Disconnect interlocking configuration settings The following settings are available for each disconnect. Function Range: Enabled, Disabled Default: Disabled This setting enables the disconnect position indications and control logic. If “Disabled”, all outputs and front panel indications are switched off. Tagging Range: Enabled, Disabled Default: Disabled...
Page 398: Automation Control
AUTOMATION CONTROL CHAPTER 8: AUTOMATION Figure 312: Disconnect interlocking logic Automation control This section describes the control elements used for automation. Front panel status and control There can be a maximum of breakers and disconnect switches (referred to as devices) plus autoreclose and local-remote status and control.
Page 399 CHAPTER 8: AUTOMATION AUTOMATION CONTROL Figure 313: Device selected to operate A confirmation message is displayed using the full name for the device to be controlled. If no buttons are pressed, the control action is canceled in after the select time timer expires. The control action can be cancelled by pushing the CANCEL key.
Page 400: Local-Remote Control Scheme
AUTOMATION CONTROL CHAPTER 8: AUTOMATION Figure 315: Breaker 1 status substituted The following indications are provided for breakers and disconnects. Figure 316: Front panel indicators for breakers and disconnects Local-remote control scheme The local-remote control scheme is used to define the current location for operator control of power system devices (for example, breakers, disconnects, and so on).
Page 401 CHAPTER 8: AUTOMATION AUTOMATION CONTROL Figure 317: Local-remote control configuration settings The following settings are available for the local-remote control scheme. Function Range: Enabled, Disabled Default: Disabled This setting enables and disables the local-remote control scheme automation logic and front panel indications. Pushbutton Control Range: Enabled, Disabled Default: Enabled...
Page 402: Synchrocheck
AUTOMATION CONTROL CHAPTER 8: AUTOMATION Figure 318: Local-remote control scheme logic Synchrocheck The are two identical synchrocheck elements available, numbered 1 and 2. The synchrocheck (synchronism check) function is intended for supervising the paralleling of two parts of a system which are to be joined by the closure of a circuit breaker. The synchrocheck elements are typically used at locations where the two parts of the system are interconnected through at least one other point in the system.
Page 403 CHAPTER 8: AUTOMATION AUTOMATION CONTROL or V (source Y) V or V (source Z) Auto-selected combination Auto-selected voltage Source Y Source Z Phase VTs and Phase VT Phase Phase auxiliary VT Phase VT Phase VT Phase Phase Phase VT and Auxiliary VT Phase Auxiliary...
Page 404 AUTOMATION CONTROL CHAPTER 8: AUTOMATION Function Range: Enabled, Disabled Default: Disabled This setting enables the synchrocheck position indications and control logic. If disabled, all synchrocheck outputs and front panel indications are switched off. Block Range: any automation logic operand or shared operand Default: BKR1 CLOSED Assertion of the operand assigned to this setting will block operation of the synchrocheck element.
Page 405 CHAPTER 8: AUTOMATION AUTOMATION CONTROL Dead Source Select Range: None, LV1 and DV2, DV1 and LV2, DV1 or DV2, DV1 Xor DV2, DV1 and DV2 Default: LV1 and DV2 This setting selects the combination of dead and live sources that will bypass the synchronism check function and permit the breaker to be closed when one or both of the two voltages (V and V...
Page 406 AUTOMATION CONTROL CHAPTER 8: AUTOMATION Figure 320: Synchrocheck scheme logic, sheet 1 of 2 Figure 321: Synchrocheck scheme logic, sheet 2 of 2 PLUS LINE DISTANCE PROTECTION SYSTEM – INSTRUCTION MANUAL...
Page 407: Selector Switch
CHAPTER 8: AUTOMATION AUTOMATION CONTROL Selector switch The selector switch element is intended to replace a mechanical selector switch. Typical applications include setting group control or control of multiple logic sub-circuits in user- programmable logic. Selector switch operation The selector switch provides for two control inputs. The step-up control allows stepping through selector position one step at a time with each pulse of the control input, such as a user-programmable pushbutton.
Page 408 AUTOMATION CONTROL CHAPTER 8: AUTOMATION Figure 322: Time-out mode PLUS LINE DISTANCE PROTECTION SYSTEM – INSTRUCTION MANUAL...
Page 409 CHAPTER 8: AUTOMATION AUTOMATION CONTROL Figure 323: Acknowledge mode Selector switch settings Select the Settings > Automation > Control > Selector Switches menu item to open the selector switch configuration window. PLUS LINE DISTANCE PROTECTION SYSTEM – INSTRUCTION MANUAL...
Page 410 AUTOMATION CONTROL CHAPTER 8: AUTOMATION Figure 324: Selector switch configuration settings The following settings are available for each selector switch. Function Range: Enabled, Disabled Default: Disabled This setting enables and disables the selector switch. Full Range Range: 1 to 7 in steps of 1 Default: 7 This setting specifies the upper position of the selector switch.
Page 411 CHAPTER 8: AUTOMATION AUTOMATION CONTROL Step-Up Mode Range: Time-out, Acknowledge Default: Time-out This setting defines the selector mode of operation. When set to “Time-out”, the selector will change its position after a pre-defined period of inactivity at the control input. The change is automatic and does not require any explicit confirmation of the intent to change the selector's position.
Page 412 AUTOMATION CONTROL CHAPTER 8: AUTOMATION 3-Bit Mode Range: Time-out, Acknowledge Default: Time-out This setting selects the selector mode of operation. When set to “Time-out”, the selector changes its position after a pre-defined period of inactivity at the control input. The change is automatic and does not require explicit confirmation to change the selector position.
Page 413: Automation Inputs And Outputs
CHAPTER 8: AUTOMATION AUTOMATION INPUTS AND OUTPUTS SELECTOR 1 POS 4....Selector 1 changed its position to 4. SELECTOR 1 POS 5....Selector 1 changed its position to 5. SELECTOR 1 POS 6....Selector 1 changed its position to 6. SELECTOR 1 POS 7....Selector 1 changed its position to 7. SELECTOR 1 STP ALARM ..The selector position pre-selected via the stepping up control input has not been confirmed before the time out.
Page 414 AUTOMATION INPUTS AND OUTPUTS CHAPTER 8: AUTOMATION Figure 326: Automation virtual inputs configuration settings The following settings are available for each automation virtual input. The default values shown are for virtual input 1. Function Range: Enabled, Disabled Default: Disabled If this setting is “Disabled”, the virtual input will be forced to off (logic 0) regardless of any attempt to alter the input.
Page 415: Automation Virtual Outputs
CHAPTER 8: AUTOMATION AUTOMATION INPUTS AND OUTPUTS Figure 327: Automation virtual input logic Automation virtual outputs There are 255 virtual outputs that may be assigned via automation logic. Virtual outputs are resolved in each pass through the evaluation of the automation logic equations. Select the Settings >...
Page 416: Contact Input And Output Default Assignment
AUTOMATION INPUTS AND OUTPUTS CHAPTER 8: AUTOMATION Figure 329: Automation virtual output programming example Contact input and output default assignment When a new settings file is created, the available contacts are automatically assigned to the protection or automation functions according to the following convention. First I/O module →...
Page 417: Contact Input Configuration
CHAPTER 8: AUTOMATION AUTOMATION INPUTS AND OUTPUTS Figure 330: Contact input and output assignments All available contact inputs and output can be reassigned using the >> and << buttons. Contact input configuration Plus The D90 can monitor the status of up to 115 field contacts. Each input can be wetted Plus from the D90 48 volt auxiliary supply or from an external power supply.
Page 418 AUTOMATION INPUTS AND OUTPUTS CHAPTER 8: AUTOMATION Figure 331: Automation contact input debouncing mechanism and time-stamping Automation equations and timers, are executed at the automation scan rate. The automation operand reflecting the debounced state of the contact is updated at the automation pass following the validation (mark 3 in the figure above).
Page 419 CHAPTER 8: AUTOMATION AUTOMATION INPUTS AND OUTPUTS When the input detects a voltage decrease, the input circuitry will draw 10 mA of current. If the voltage decrease is due to a state change then the voltage will quickly decrease, speeding up the recognition of the reset of the field contact by quickly discharging any input capacitance.
Page 420 AUTOMATION INPUTS AND OUTPUTS CHAPTER 8: AUTOMATION Table 32: Nominal voltage setting for typical battery voltages Nominal voltage Validation threshold 24 V 20 V 48 V 33.6 V 125 V 87.5 V 250 V 175 V Events Range: Enabled, Disabled Default: Enabled If this setting is “Enabled”, every change in the contact input state will trigger an event in the sequence of events recorder.
Page 421: Contact Outputs
CHAPTER 8: AUTOMATION AUTOMATION INPUTS AND OUTPUTS The following settings are applied to all available protection and automation contact inputs. Function Range: Enabled, Disabled Default: Disabled This setting enables and disables the chatter detection feature. Chatter Time Range: 1 to 100 seconds in steps of 1 Default: 10 seconds This setting specifies the time window that the relay contacts are monitored for contact input state changes.
Page 422 AUTOMATION INPUTS AND OUTPUTS CHAPTER 8: AUTOMATION Seal-In Range: any automation logic operand or shared operand Default: OFF This setting selects an operand (virtual output, element state, contact input, or virtual input) that will seal-in the contact output when asserted. Voltage Threshold Range: 20 to 250 volts in steps of 1 Default: 20...
Page 423: Virtual Analog Outputs
CHAPTER 8: AUTOMATION AUTOMATION INPUTS AND OUTPUTS Figure 337: Trip seal-in scheme settings Virtual analog outputs There are 128 virtual analog outputs that may be assigned via automation logic. Virtual analog outputs are resolved in each pass through the evaluation of the automation logic equations.
Page 424 AUTOMATION INPUTS AND OUTPUTS CHAPTER 8: AUTOMATION • Communications. • Digital fault recorder (DFR). • Equipment manager. • Front panel interface (HMI). However, it is often desirable for an output from an element within one function can be available to an element within another function. For instance, it may be useful for the digital fault recorder to record the output operands of any protection element.
Page 425: Automation Logic
CHAPTER 8: AUTOMATION AUTOMATION LOGIC Figure 340: Shared operands configuration window Plus The left side of this screen displays all D90 operands that are available to the automation function as shared operands. Select any operands from the other five primary features by clicking on the >>...
Page 426 AUTOMATION LOGIC CHAPTER 8: AUTOMATION Plus Figure 341: UR -series architecture overview Plus The states of all digital signals used in the D90 are represented by flags (or automation logic operands, described later in this section). A logic 1 state is represented by a set flag. Any external contact change-of-state can be used to block an element from operating, as an input to a control feature in an automation logic equation, or to operate a contact output.
Page 427 CHAPTER 8: AUTOMATION AUTOMATION LOGIC The logic that determines the interaction of inputs, elements, schemes and outputs is field programmable through the use of logic equations that are sequentially processed. The use of virtual inputs and outputs in addition to hardware is available internally and on the communication ports for other relays to use (distributed logic).
Page 428: Automation Operators
AUTOMATION LOGIC CHAPTER 8: AUTOMATION Automation operators The following operators are available for the creation of automation logic. • One-shots. • Boolean operators and latches. • Math operators. • Virtual outputs. • Comparators. • Timers. Plus Unlike earlier versions of the D90 , automation timers are implemented like gates or latches and not through the specific setting menus.
Page 429 CHAPTER 8: AUTOMATION AUTOMATION LOGIC About automation virtual outputs The automation virtual output syntax is shown in the following table. Table 35: Automation virtual output operators Syntax Description Assigns the previous automation logic operand to the corresponding VDO(1) VDO(96) automation virtual digital output. Assigns the previous automation logic operand to the corresponding VAO1 VAO64...
Page 430 AUTOMATION LOGIC CHAPTER 8: AUTOMATION Syntax Description Return the natural logarithm (base e) value of the previous operand. Return the base 10 logarithm value of the previous operand. LOG10 Return magnitude of the previous two operands, where the first operand is MAG (a, b) the real value the second operand is the imaginary value.
Page 431 CHAPTER 8: AUTOMATION AUTOMATION LOGIC Table 38: Automation logic editing operators Syntax Description Insert an operand in an equation list. INSERT Delete an operand from an equation list. DELETE The first END encountered signifies the last line in the list of processed logic operands.
Page 432: Automation Logic Equation Editor
AUTOMATION LOGIC CHAPTER 8: AUTOMATION About automation timers Plus Unlike earlier versions of the D90 , automation timers are implemented like gates or latches and not through the specific setting menus. Automation timers have the following syntax: TIMER (IN, PKP, DPO).
Page 433 CHAPTER 8: AUTOMATION AUTOMATION LOGIC Figure 349: Automation logic configuration settings A graphical representation of the automation logic can be displayed by clicking on the View button at the top of the equation. Figure 350: Typical automation logic display Automation logic rules When forming an automation logic equation, the sequence in the linear array of parameters must follow these general rules.
Page 434 AUTOMATION LOGIC CHAPTER 8: AUTOMATION Assigning the output of a math operator to a virtual analog terminates the equation. Automation logic programming example The following automation logic programming example illustrates the implementation of a voltage regulation scheme with line drop compensation. In this scheme, the Plus measures the local end positive-sequence voltage and calculates the remote end positive-sequence line voltage (the load center voltage) to compensate for the voltage...
Page 435 CHAPTER 8: AUTOMATION AUTOMATION LOGIC Figure 353: Real and imaginary component calculation logic for remote voltage The magnitude of the remote voltage is calculated next and assigned to virtual analog 9. Note that virtual analog 8 is used as an intermediate value in the automation logic. Figure 354: Remote voltage magnitude calculation logic Now that the remote voltage magnitude has been calculated, the following logic calculates the voltage difference between this and the setting voltage.
Page 436 AUTOMATION LOGIC CHAPTER 8: AUTOMATION Figure 355: Voltage difference automation logic The current on each phase is checked to ensure that it is less than the maximum allowable for a tap changer operation. Figure 356: Overcurrent check automation logic A lockout is implemented with the following logic. The lockout is asserted if the tap changer gas trip contact is picked up (63GT).
Page 437 CHAPTER 8: AUTOMATION AUTOMATION LOGIC When DELTA_V is greater than 0.5 volts for more than 30 seconds (the sum of timers 2 and 3), the tap changer control is in auto mode, no overcurrent condition exists, and there is no lockout, then a LOWER command is issued via analog virtual output 4.
Page 438 AUTOMATION LOGIC CHAPTER 8: AUTOMATION Figure 359: Raise command automation logic The following automation logic detects excessive tap changer operations. First, a TIMEOUT signal is created that produces a one second pulse once an hour. Figure 360: Timeout signal automation logic A counter is then implemented to accumulate the number of operations (indicated by the OFF TAP signal).
Page 439: Automation Logic Operands
CHAPTER 8: AUTOMATION AUTOMATION LOGIC Figure 362: Maximum operations per hour alarm automation logic Automation logic operands Plus The following automation logic operands are available for the D90 . They are listed alphabetically by operand syntax. Some operands can be re-named by the user. These include the names of breakers, contact inputs, and virtual outputs.
Page 440 AUTOMATION LOGIC CHAPTER 8: AUTOMATION Cont Op 1 IOn..........Asserted when contact output 1 with current monitoring is closed. Cont Op 1 VOff ..........Asserted when contact output 1 with voltage monitoring is opened. Cont Op 1 VOn..........Asserted when contact output 1 with voltage monitoring is closed.
Page 441 CHAPTER 8: AUTOMATION AUTOMATION LOGIC DISC1A INTERMED ........Asserted when breaker 1 pole A is in transition between the opened and closed states. DISC1A OPENED .........Asserted when disconnect 1 pole A is opened. DISC1B BAD STATE........Asserted when the normally open and normally closed breaker indications disagree for pole B of disconnect 1.
Page 442 AUTOMATION LOGIC CHAPTER 8: AUTOMATION SYNC 1 DEAD S OP ........Asserted when the synchrocheck 1 dead source has operated. SYNC 1 SYNC DPO ........Asserted when the synchrocheck 1 has dropped out while in synchronization. SYNC 1 SYNC OP.........Asserted when the synchrocheck 1 has operated while in synchronization.
Page 443: Equipment Manager
Plus Line Distance Protection System Chapter 9: Equipment manager Equipment manager A program for equipment monitoring can result in extended equipment life, improved system reliability, and increased equipment availability. Furthermore, effective equipment monitoring allows maintenance to be targeted towards the equipment in the greatest Plus need.
Page 444: Circuit Breaker Arcing
BREAKER MANAGEMENT CHAPTER 9: EQUIPMENT MANAGER Figure 363: Equipment manager block diagram Breaker management This section describes the breaker management features of the equipment manager. Circuit breaker arcing The breaker arcing function provides indications of the condition of the circuit breaker interrupter.
Page 445 CHAPTER 9: EQUIPMENT MANAGER BREAKER MANAGEMENT Figure 364: Breaker arcing current measurement Select the Settings > Equipment Manager > Breaker > Breaker Arcing menu item to open the breaker arcing current configuration window. Figure 365: Breaker arcing current configuration settings The following settings are available for each breaker arcing current element.
Page 446 BREAKER MANAGEMENT CHAPTER 9: EQUIPMENT MANAGER Exponent Range: 1.000 to 5.000 in steps of 0.001 Default: 2.000 This setting specifies the accumulated breaker wear is proportional to the following equation, Eq. 43 where x is the arcing exponent. The typical value for the arcing exponent is 2. Interruption Rating Range: 0.0 to 100.0 kA in steps of 0.1 Default: 31.5 kA...
Page 447: Battery Monitor
CHAPTER 9: EQUIPMENT MANAGER BATTERY MONITOR Figure 366: Breaker arcing current logic Battery monitor The battery monitor function monitors the health of the DC battery system. It provides an analog indication of the current DC voltage derived from a contact input wired between the positive and negative rails of the battery system.
Page 448: Battery Monitor Settings
BATTERY MONITOR CHAPTER 9: EQUIPMENT MANAGER DC GND FLT..........Indicates a battery DC ground fault. Typical wiring for the battery monitor element is shown below. Figure 367: Battery monitor wiring diagram Battery monitor settings Select the Settings > Equipment Manager > Battery Monitor menu item to open the battery monitor configuration window.
Page 449 CHAPTER 9: EQUIPMENT MANAGER BATTERY MONITOR Function Range: Enabled, Disabled Default: Disabled This setting enables and disables the battery monitor element. Input Range: any contact input or OFF Default: OFF This setting specifies the contact input used to monitor the battery voltage. High DC Volts Range: 38 to 275 volts in steps of 1 Default: 143 volts...
Page 450: Shared Operands
SHARED OPERANDS CHAPTER 9: EQUIPMENT MANAGER Events Range: Enabled, Disabled Default: Enabled This setting enables and disables the logging of battery monitoring events in the sequence of events recorder. The battery monitoring logic is shown below. Figure 369: Battery monitor scheme logic Shared operands Plus Plus...
Page 451: Shared Equipment Manager Operands
CHAPTER 9: EQUIPMENT MANAGER SHARED OPERANDS Figure 370: Default operand list by function The content of each operand list is dependent on the selected order code. The shared operands functionality expands upon this system. With this feature, an output Plus from any element can be assigned as a shared operand within the EnerVista UR Setup software.
Page 452: Equipment Manager Operands
SHARED OPERANDS CHAPTER 9: EQUIPMENT MANAGER Figure 371: Shared operands configuration window Plus The left side of this screen displays all D90 operands that are available to the equipment manager function as shared operands. Select any operands from the other five primary features by clicking on the >>...
Page 453 CHAPTER 9: EQUIPMENT MANAGER SHARED OPERANDS BAT MON HIGH VDC PKP ......Asserted when the battery high DC voltage monitor picks up. BAT MON LOW VDC DPO ......Asserted when the battery low DC voltage monitor drops out. BAT MON LOW VDC OP......Asserted when the battery low DC voltage monitor operates. BAT MON LOW VDC PKP ......Asserted when the battery low DC voltage monitor picks up.
Page 454 SHARED OPERANDS CHAPTER 9: EQUIPMENT MANAGER PLUS LINE DISTANCE PROTECTION SYSTEM – INSTRUCTION MANUAL...
Page 455: Digital Fault Recorder
Plus Line Distance Protection System Chapter 10: Digital fault recorder Digital fault recorder The digital fault recorder captures detailed information regarding abnormal occurrences in Plus the power system. The information captured by the DFR is stored in the D90 in non- volatile memory and can be accessed through the front panel interface.
Page 456: Fault Report
FAULT REPORT CHAPTER 10: DIGITAL FAULT RECORDER Figure 372: Example sequence of events record Fault report Plus The D90 device supports one fault report and an associated fault locator. The signal source and trigger condition, as well as the characteristics of the line or feeder, are entered in the fault report configuration settings.
Page 457: Fault Report Operation
CHAPTER 10: DIGITAL FAULT RECORDER FAULT REPORT • The fault report feature is enabled. • The source for the fault report is properly configured. • The block trigger input is not asserted. • A record capture is not currently in progress. The Memory Available indication is green when less than 80% of the memory has been filled.
Page 458: Fault Type Determination
FAULT REPORT CHAPTER 10: DIGITAL FAULT RECORDER Each fault report is stored as a file, and the relay capacity is 15 files. A 16th trigger overwrites the oldest file. Individual fault report features store their files in the same memory space. The 16th report will overwrite the first one regardless which fault report feature produced the 16th and the first records.
Page 459: Fault Report Settings
CHAPTER 10: DIGITAL FAULT RECORDER FAULT REPORT Inserting the I and I equations into the V equation and solving for R yields the fault resistance. Eq. 47 Assuming the fault components of the currents I and I are in phase, and observing A(F) B(F) that the fault resistance, as impedance, does not have any imaginary part gives the...
Page 460 FAULT REPORT CHAPTER 10: DIGITAL FAULT RECORDER Figure 376: Fault report configuration settings The following settings are available for the fault report. Source Range: LINE (SRC 1), BKR 1 (SRC 2), BKR 2 (SRC 3) Default: SRC1 This setting selects the source for input currents, voltages, and disturbance detection. Trigger Range: any FlexLogic™...
Page 461 CHAPTER 10: DIGITAL FAULT RECORDER FAULT REPORT Line Length Units Range: km, miles Default: km This setting selects the units used for fault location calculations. Line Length Range: 0.0 to 2000.0 in steps of 0.1 Default: 100.0 This setting specifies the length of the transmission line or feeder in the defined line length units.
Page 462: Transient Recorder
TRANSIENT RECORDER CHAPTER 10: DIGITAL FAULT RECORDER Figure 377: Fault locator scheme logic Transient recorder The transient recorder is designed to capture short duration events, such as faults at a high resolution. Under normal operation, the transient recorder continuously captures pre- fault data and stores this data in memory.
Page 463 CHAPTER 10: DIGITAL FAULT RECORDER TRANSIENT RECORDER Figure 378: Trigger and re-trigger sequence The length of a transient record is also user-configurable. The number of transient records Plus stored by the D90 is a function of the record length, the time-resolution of the recording, Plus and of the number of configured channels.
Page 464: Front Panel Indications
TRANSIENT RECORDER CHAPTER 10: DIGITAL FAULT RECORDER Front panel indications The digital fault reporter summary screen provides an indication that the transient recorder is ready to capture data and has memory available. In protected mode, the Ready to Capture indication is green when all of the following conditions hold. •...
Page 465: Transient Recorder Settings
CHAPTER 10: DIGITAL FAULT RECORDER TRANSIENT RECORDER Transient recorder settings Select the Settings > DFR > Transient Record menu item to open the transient recorder function configuration window. Figure 381: Transient recorder function settings The following settings are available. Function Range: Enabled, Disabled Default: Enabled This setting enables and disables the transient recorder function.
Page 466 TRANSIENT RECORDER CHAPTER 10: DIGITAL FAULT RECORDER Sample Rate Range: 16, 32, 64, 128, or 256 samples per cycle, or OFF Default: 32 This setting selects the time-resolution of the transient record. A larger setting necessarily results in a shorter record length. Block Trigger Range: any FlexLogic™...
Page 467 CHAPTER 10: DIGITAL FAULT RECORDER TRANSIENT RECORDER Transient recorder digital channels Up to 128 digital channels may be assigned to the transient recorder. Each channel may be individually configured by clicking the digital channels Select button in the transient recorder window to open the transient recorder digital channels window. Figure 383: Digital channel configuration settings The following settings are available for each digital channel.
Page 468 TRANSIENT RECORDER CHAPTER 10: DIGITAL FAULT RECORDER When set to “Trigger/Re-Trigger” or “Re-Trigger Only”, the transient recorder will be re- triggered if the signal is still asserted at the end of the trigger period. The resulting record will contain fault data only. A re-trigger is re-generated at the end of a transient record if the signal is still asserted and if the number of re-triggers is less than the value specified by the Maximum Re-Triggers...
Page 469 CHAPTER 10: DIGITAL FAULT RECORDER TRANSIENT RECORDER High Triggering Range: Off, Trigger Only, Trigger/Re-Trigger, Re-Trigger Only Default: Off This setting selects the high triggering function for the analog channel. When set to “Trigger Only” or “Trigger/Re-Trigger”, the transient recorder will initiate data capture when the magnitude of the signal is greater than the value of the setting.
Page 470: Disturbance Recorder
DISTURBANCE RECORDER CHAPTER 10: DIGITAL FAULT RECORDER Figure 386: Analog channel trigger logic Disturbance recorder The disturbance recorder is designed to capture short duration events, such as faults at a high resolution. Under normal operation, the disturbance recorder is continuously capturing pre-fault data and storing this data in memory.
Page 471 CHAPTER 10: DIGITAL FAULT RECORDER DISTURBANCE RECORDER Figure 387: Trigger and re-trigger sequence The length of a disturbance record is also user-configurable. The number of disturbance Plus records stored by the D90 can store is a function of the record length, the time resolution of the recording, and of the number of configured channels.
Page 472: Front Panel Indications
DISTURBANCE RECORDER CHAPTER 10: DIGITAL FAULT RECORDER The recorder has two storage modes: protected and automatic overwrite. When the memory is filled, either no new records are written to memory (protected mode) or the oldest record is overwritten (automatic overwrite mode). Front panel indications The digital fault reporter summary screen provides an indication that the disturbance recorder is ready to capture data and has memory available.
Page 473: Disturbance Recorder Settings
CHAPTER 10: DIGITAL FAULT RECORDER DISTURBANCE RECORDER Figure 389: Disturbance recorder screen Disturbance recorder settings Select the Settings > DFR > Disturbance Record menu item to open the disturbance recorder function configuration window. Figure 390: Disturbance recorder function settings The following settings are available. Function Range: Enabled, Disabled Default: Disabled...
Page 474 DISTURBANCE RECORDER CHAPTER 10: DIGITAL FAULT RECORDER Trigger Position Range: 1 to 100% in steps of 1 Default: 50% This setting specifies the amount of pre-trigger data stored in a disturbance record expressed as a percentage of the disturbance record length. Maximum Re-Triggers Range: 1 to 4 in steps of 1 Default: 2...
Page 475 CHAPTER 10: DIGITAL FAULT RECORDER DISTURBANCE RECORDER Disturbance recorder digital channels Up to 32 digital channels may be assigned to the disturbance recorder. Each channel may be individually configured by clicking the digital channels Select button in the disturbance recorder window to open the disturbance recorder digital channels window. Figure 392: Digital channel configuration settings The following settings are available for each disturbance recorder digital channel.
Page 476 DISTURBANCE RECORDER CHAPTER 10: DIGITAL FAULT RECORDER When set to “Trigger/Re-Trigger” or “Re-Trigger Only”, the disturbance recorder will be re-triggered if the signal is still asserted at the end of the trigger period. The resulting record will contain fault data only. A re-trigger is re-generated at the end of a disturbance record if the signal is still asserted and if the number of re-triggers is less than the value specified by the Maximum Re-Triggers...
Page 477 CHAPTER 10: DIGITAL FAULT RECORDER DISTURBANCE RECORDER Signal Range: any FlexAnalog™ quantity Default: Off This setting specifies the FlexAnalog™ quantity to be recorded for the channel. The size of each disturbance record depends in part on the number of parameters selected. Parameters set to “Off”...
Page 478: Shared Operands
SHARED OPERANDS CHAPTER 10: DIGITAL FAULT RECORDER Block Trigger Range: any FlexLogic™ operand Default: Off The FlexLogic™ operand assigned to this setting blocks triggering of the disturbance recorder analog channel. Figure 395: Analog channel trigger logic Shared operands Plus Plus The EnerVista UR Setup software groups the D90 system into the following seven...
Page 479: Shared Digital Fault Recorder Operands
CHAPTER 10: DIGITAL FAULT RECORDER SHARED OPERANDS Figure 396: Default operand list by function The content of each operand list is dependent on the selected order code. The shared operands functionality expands upon this system. With this feature, an output Plus from any element can be assigned as a shared operand within the EnerVista UR Setup software.
Page 480 SHARED OPERANDS CHAPTER 10: DIGITAL FAULT RECORDER Figure 397: Shared operands configuration window Plus The left side of this screen displays all D90 operands that are available to the digital fault recorder function as shared operands. Select any operands from the other five primary features by clicking on the >>...
Page 481: Metering
Plus Line Distance Protection System Chapter 11: Metering Metering Plus This section describes how to program the D90 metering features. Metering source Select the Settings > Metering > Metering Source menu item to open the metering source configuration window. Figure 398: Metering source configuration settings The following setting is available.
Page 482: Phasor Measurement Unit Configuration
Range: 16 alphanumeric characters Default: GE-UR+PMU This setting assigns an alphanumeric ID to the phasor measurement unit station. It corresponds to the STN field of the configuration frame of the C37.118 protocol. This value is a 16-character ASCII string as per the C37.118 standard.
Page 483: Phasor Measurement Unit Calibration
CHAPTER 11: METERING PHASOR MEASUREMENT UNIT both voltages and currents. When configuring communication and recording features of the phasor measurement unit, the user could select – from the above superset – the content to be sent out or recorded. Post-Filter Range: None, Symm-3-point, Symm-5-point, Symm-7-point Default: Symm-3-point This setting specifies amount of post-filtering applied to raw synchrophasor...
Page 484: Phasor Measurement Unit Communications
PHASOR MEASUREMENT UNIT CHAPTER 11: METERING setting values are effectively added to the measured angles. Therefore, enter a positive correction of the secondary signal lags the true signal; and negative value if the secondary signal leads the true signal. Ia Angle, Ib Angle, Ic Angle, Ig Angle Range: –5.00 to 5.00°...
Page 485 CHAPTER 11: METERING PHASOR MEASUREMENT UNIT Figure 401: Phasor measurement unit communications configuration The following settings are available for the communication port on each phasor measurement unit. Type Range: None, Network Default: None This setting specifies the first communication port for transmission of the phasor measurement unit data.
Page 486 PHS-1 Name, PHS-2 Name, PHS-3 Name,..., PHS-14 Name Range: 16 alphanumeric characters Default: GE-UR+PMU1-V1, GE-UR+PMU1-V2, GE-UR-PMU1+V3,..., GE-UR+PMU1-V14 These settings allow for custom naming of the synchrophasor channels. Sixteen- character ASCII strings are allowed as in the CHNAM field of the configuration frame.
Page 487: Phasor Measurement Unit Triggering
CHAPTER 11: METERING PHASOR MEASUREMENT UNIT D-CH-1 Normal State, D-CH-2 Normal State, D-CH-3 Normal State,..., D-CH-14 Normal State Range: On, Off Default: Off These settings allow for specifying a normal state for each digital channel. These states are transmitted in configuration frames to the data concentrator. Phasor measurement unit triggering Each logical phasor measurement unit (PMU) contains five triggering mechanisms to facilitate triggering of the associated PMU recorder and cross-triggering of other PMUs of...
Page 488 PHASOR MEASUREMENT UNIT CHAPTER 11: METERING Frequency triggering The trigger responds to the frequency signal of the phasor measurement unit source. The frequency is calculated from either phase voltages, auxiliary voltage, phase currents and ground current, in this hierarchy, depending on the source configuration as per Plus standards.
Page 489 CHAPTER 11: METERING PHASOR MEASUREMENT UNIT Block Range: any metering logic operand or shared operand Default: Off Assertion of the operand assigned to this setting blocks operation of the phasor measurement unit frequency triggering function. Events Range: Enabled, Disabled Default: Disabled This setting enables and disables the logging of phasor measurement unit frequency triggering events in the sequence of events recorder.
Page 490 PHASOR MEASUREMENT UNIT CHAPTER 11: METERING Function Range: Enabled, Disabled Default: Disabled This setting enables and disables the phasor measurement unit voltage triggering function. Low Voltage Range: 0.250 to 1.250 pu in steps of 0.001 Default: 0.800 pu This setting specifies the low threshold for the abnormal voltage trigger, in per-unit values of the phasor measurement unit source.
Page 491 CHAPTER 11: METERING PHASOR MEASUREMENT UNIT Figure 407: Voltage triggering scheme logic Current triggering This phasor measurement unit current triggering function responds to elevated current. The trigger responds to the phase current signal of the phasor measurement unit source. All current channel (A, B, and C) are processed independently and could trigger the recorder.
Page 492 PHASOR MEASUREMENT UNIT CHAPTER 11: METERING Dropout Time Range: 0.00 to 600.00 seconds in steps of 0.01 Default: 1.00 seconds This setting may be used to extend the trigger after the situation returned to normal. This setting is of particular importance when using the recorder in the forced mode (recording as long as the triggering condition is asserted).
Page 493 CHAPTER 11: METERING PHASOR MEASUREMENT UNIT Figure 410: Power triggering configuration settings The following settings are available for each phasor measurement unit. Function Range: Enabled, Disabled Default: Disabled This setting enables and disables the phasor measurement unit power triggering function. Active Range: 0.250 to 3.000 pu in steps of 0.001 Default: 1.250 pu...
Page 494 PHASOR MEASUREMENT UNIT CHAPTER 11: METERING Dropout Time Range: 0.00 to 600.00 seconds in steps of 0.01 Default: 1.00 seconds This setting may be used to extend the trigger after the situation returned to normal. This setting is of particular importance when using the recorder in the forced mode (recording as long as the triggering condition is asserted).
Page 495 CHAPTER 11: METERING PHASOR MEASUREMENT UNIT Figure 412: Frequency rate of change triggering configuration settings The following settings are available for each phasor measurement unit. Function Range: Enabled, Disabled Default: Disabled This setting enables and disables the phasor measurement unit frequency rate of change triggering function.
Page 496: Phasor Measurement Unit Recording
PHASOR MEASUREMENT UNIT CHAPTER 11: METERING The logic for the phasor measurement unit frequency rate of change triggering function is shown below. Figure 413: Phasor measurement unit frequency rate of change triggering logic Phasor measurement unit recording Each logical phasor measurement unit (PMU) is associated with a recorder. The triggering condition is programmed via the Settings >...
Page 497 CHAPTER 11: METERING PHASOR MEASUREMENT UNIT Figure 415: Phasor measurement unit recording configuration settings The following settings are available for each phasor measurement unit. Recording Rate Range: 1, 2, 5, 10, 12, 15, 20, 25, 30, 50, or 60 times per second Default: 10 times per second This setting specifies the recording rate for the record content.
Page 498 PHASOR MEASUREMENT UNIT CHAPTER 11: METERING Trigger Mode Range: Automatic Overwrite, Protected Default: Automatic Overwrite This setting specifies what happens when the recorder uses its entire available memory storage. If set to “Automatic Overwrite”, the last record is erased to facilitate new recording, when triggered.
Page 499 Rec PHS-1 Name, Rec PHS-2 Name, Rec PHS-3 Name,..., Rec PHS-14 Name Range: 16 character ASCII string Default: GE-UR+PMU-PHS1, GE-UR+PMU-PHS2, GE-UR+PMU-PHS3,..., GE-UR+PMU-PHS14 These settings allow for custom naming of the synchrophasor channels. Sixteen- character ASCII strings are allowed as in the CHNAM field of the configuration frame.
Page 500: Phasor Measurement Unit Reporting Over Network
PHASOR MEASUREMENT UNIT CHAPTER 11: METERING Phasor measurement unit reporting over network The phasor measurement unit Ethernet connection works simultaneously with other communication means over Ethernet. The network reporting feature is programmed via the Settings > Metering > Phasor Measurement Unit > Reporting Over Network menu. Figure 418: Phasor measurement unit reporting over network configuration settings The following settings are available for each phasor measurement unit.
Page 501: Phasor Measurement Unit One-Shot
CHAPTER 11: METERING PHASOR MEASUREMENT UNIT PDC Control Range: Enabled, Disabled Default: Disabled The synchrophasor standard allows for user-defined controls originating at the PDC, to be executed on the phasor measurement unit. The control is accomplished via an extended command frame. The relay decodes the first word of the extended field, EXTFRAME, to drive 16 dedicated FlexLogic™...
Page 502 PHASOR MEASUREMENT UNIT CHAPTER 11: METERING Function Range: Enabled, Disabled Default: Disabled This setting enables and disables the phasor measurement unit one-shot feature. Sequence Number Range: 0 to nominal frequency – 1, in steps of 1 Default: 1 When the match the Device Date Device Time...
Page 503 CHAPTER 11: METERING PHASOR MEASUREMENT UNIT Device Time Range: time in HH:MM:SS format Default: 00:00:00 Plus This value reflects the time programmed in the D90 . This time cannot be modified from this window. PMU One-Shot Date Range: date in MM/DD/YYYY format Default: 01/01/2007 When the phasor measurement unit one-shot feature is enabled, the Plus...
Page 504: Data Logger
DATA LOGGER CHAPTER 11: METERING same IRIG-B signal: either the same GPS receiver or IRIG-B generator. Otherwise, the setpoints of the test set and the phasor measurement unit measurements should not be compared as they are referenced to different time scales. Figure 421: Testing synchrophasor measurement accuracy Collecting synchronized measurements ad hoc The phasor measurement unit one-shot feature can be used for ad hoc collection of...
Page 505 CHAPTER 11: METERING DATA LOGGER Figure 422: Data logger configuration settings The following settings are available for the data logger. Function Range: Enabled, Disabled Default: Disabled This setting enables and disables the data logger. Block Range: any metering logic operand or shared operand Default: OFF Assertion of the operand assigned to this setting will block data logger functionality.
Page 506: Data Logger Channel Configuration
DATA LOGGER CHAPTER 11: METERING Figure 423: Data logger scheme logic Data logger channel configuration Select the Settings > Metering > Data Logger > Channel Configuration menu item to open the data logger configuration window. PLUS LINE DISTANCE PROTECTION SYSTEM – INSTRUCTION MANUAL...
Page 507 CHAPTER 11: METERING DATA LOGGER Figure 424: Data logger channel configuration settings The following settings are available for all 16 data logger channels. Signal Range: any FlexAnalog™ parameter Default: Off This setting selects the metering value to be recorded for the data logger channel. Name Range: up to 12 alphanumeric characters Default: Channel 1...
Page 508: Shared Operands
SHARED OPERANDS CHAPTER 11: METERING High Alarm Pickup, Low Alarm Pickup, High-High Alarm Pickup, Low-Low Alarm Pickup Range: –90.00 to 90.00 pu in steps of 0.01 Default: 1.00 pu These settings specify the pickup thresholds for the alarm in per-unit values. A fixed hysteresis of 3% is applied.
Page 509: Shared Metering Operands
CHAPTER 11: METERING SHARED OPERANDS Figure 425: Default operand list by function The content of each operand list is dependent on the selected order code. The shared operands functionality expands upon this system. With this feature, an output Plus from any element can be assigned as a shared operand within the EnerVista UR Setup software.
Page 510: Metering Logic Operands
SHARED OPERANDS CHAPTER 11: METERING Figure 426: Shared operands configuration window Plus The left side of this screen displays all D90 operands that are available to the metering function as shared operands. Select any operands from the other five primary features by clicking on the >>...
Page 511 CHAPTER 11: METERING SHARED OPERANDS PMU 1 ROCOF TRIGGER......Asserted when the rate of change of frequency trigger of phasor measurement unit 1 operates. PMU 1 VOLT TRIGGER .......Asserted when the abnormal voltage trigger of phasor measurement unit 1 operates. PMU 1 TRIGGERED........Asserted when the phasor measurement unit 1 triggers. No events or targets are generated by this operand.
Page 512 SHARED OPERANDS CHAPTER 11: METERING PLUS LINE DISTANCE PROTECTION SYSTEM – INSTRUCTION MANUAL...
Page 513: Local Interface
Plus Line Distance Protection System Chapter 12: Local interface Local interface Plus This section describes how to program the D90 local interface features. Local interface overview The local interface consists of two displays: an annunciator panel and a front panel HMI. Figure 427: Front panel interface overview Annunciator panel The annunciator is a color, TFT panel located that emulates the functionality found in a...
Page 514 ANNUNCIATOR PANEL CHAPTER 12: LOCAL INTERFACE Figure 428: Typical annunciator display There are three control buttons at the bottom of the display. • The Next Page button cycles through the pages of alarms and to the self-test page. • The Next Alarm button cycles horizontally through the current alarms, from left to right, starting with the first row of alarms.
Page 515: Annunciator Configuration
CHAPTER 12: LOCAL INTERFACE ANNUNCIATOR PANEL If there are alarms on multiple pages, and alarms on some pages have already been acknowledged (but not cleared) by the user, then the pages with active alarms move ahead of the pages that have acknowledged alarms. The user will always have to navigate through the pages of alarms to view them.
Page 516 ANNUNCIATOR PANEL CHAPTER 12: LOCAL INTERFACE Alarm Name (Line 1) Range: up to ten alphanumeric characters Default: see above This setting specifies the message to display on the first line in the alarm indicator. Up to 10 characters can be entered. Alarm Name (Line 2) Range: up to ten alphanumeric characters Default: see above...
Page 517: Mimic Diagram Editor
CHAPTER 12: LOCAL INTERFACE MIMIC DIAGRAM EDITOR Figure 432: Annunciator configuration logic Mimic diagram editor The mimic diagram editor allows users to create customized single line diagrams (mimic diagrams) for the front panel display. Select the Settings > Local HMI > Mimic Diagram Editor menu item to open the mimic diagram editing window.
Page 518: Dynamic Symbols
MIMIC DIAGRAM EDITOR CHAPTER 12: LOCAL INTERFACE Figure 434: Mimic diagram components library The following functions are available for the mimic diagram editor. • Circuit breakers. • Disconnect and earthing switches. • Busbars. • Transformers. • Capacitor banks. • Reactors. •...
Page 519: Static Symbols
CHAPTER 12: LOCAL INTERFACE MIMIC DIAGRAM EDITOR Figure 435: Mimic diagram editor dynamic symbols A maximum of 1010 dynamic components is allowed for each mimic diagram. When a dynamic symbol is selected and added to the diagram, a window will appear to configure the device.
Page 520: Metering Blocks
MIMIC DIAGRAM EDITOR CHAPTER 12: LOCAL INTERFACE Figure 437: Mimic diagram editor static symbols For more information on these symbols, see the ANSI/IEEE 315A and IEC 617 standards. There is no limit on the number of static symbols per screen, provided they fit within the screen dimensions.
Page 521: Text Blocks
CHAPTER 12: LOCAL INTERFACE MIMIC DIAGRAM EDITOR Figure 439: Mimic diagram metering block symbol Text blocks Text blocks are used to display various control quantities. These text blocks allow the user to display specified control states in the configurable mimic diagram. The three types of text blocks available are shown below.
Page 522: Pre-Configured Mimic Diagrams
MIMIC DIAGRAM EDITOR CHAPTER 12: LOCAL INTERFACE Pre-configured mimic diagrams Plus The EnerVista UR Setup software contains a library of twelve pre-configured mimic diagrams that can be loaded into the mimic diagram editor. Click the Load button to load a pre-configured mimic diagram from the library.
Page 523 CHAPTER 12: LOCAL INTERFACE MIMIC DIAGRAM EDITOR and line disconnects) Figure 445: Pre-configured mimic diagram 4 (breaker-and-a-half scheme, with breaker, line, and ground disconnects) Figure 446: Pre-configured mimic diagram 5 (breaker-and-a-half scheme with line disconnect) Figure 447: Pre-configured mimic diagram 6 (breaker-and-a-half scheme with line and PLUS LINE DISTANCE PROTECTION SYSTEM –...
Page 524 MIMIC DIAGRAM EDITOR CHAPTER 12: LOCAL INTERFACE ground disconnects) Figure 448: Pre-configured mimic diagram 7 (double-bus bypass scheme 1) Figure 449: Pre-configured mimic diagram 8 (double-bus bypass scheme 2) Figure 450: Pre-configured mimic diagram 9 (double-bus bypass scheme with line and PLUS LINE DISTANCE PROTECTION SYSTEM –...
Page 525 CHAPTER 12: LOCAL INTERFACE MIMIC DIAGRAM EDITOR ground disconnects) Figure 451: Pre-configured mimic diagram 10 (single-bus scheme) Figure 452: Pre-configured mimic diagram 11 (single-bus scheme with line disconnect) Figure 453: Pre-configured mimic diagram 12 (single-bus scheme with line and ground PLUS LINE DISTANCE PROTECTION SYSTEM –...
Page 526: User-Programmable Pushbuttons
USER-PROGRAMMABLE PUSHBUTTONS CHAPTER 12: LOCAL INTERFACE disconnects) User-programmable pushbuttons User-programmable pushbuttons provide a simple and error-free method of entering digital state (on, off) information. There are 20 user-programmable pushbuttons available Plus for the D90 The digital state can be entered locally (by directly pressing the front panel pushbutton) or remotely (via operands) into logic equations, protection elements, and control elements.
Page 527: User-Programmable Pushbuttons Settings
CHAPTER 12: LOCAL INTERFACE USER-PROGRAMMABLE PUSHBUTTONS cause transient assertion of the operating signals. The local and remote operation of each user-programmable pushbutton can be inhibited through user settings. If local locking is applied, the pushbutton will ignore set and reset commands executed through the front panel pushbuttons.
Page 528 USER-PROGRAMMABLE PUSHBUTTONS CHAPTER 12: LOCAL INTERFACE If set to “Latched”, the pushbutton control logic alternates the state of the corresponding operand between the on-state and off-state on each button press or by virtually activating the pushbutton (assigning set and reset operands). In latched mode, the operand states are stored in non-volatile memory.
Page 529 CHAPTER 12: LOCAL INTERFACE USER-PROGRAMMABLE PUSHBUTTONS Local Lock Range: any FlexLogic™ operand or shared operand Default: OFF When the operand assigned to this setting is asserted, pushbutton operation from the front panel interface is inhibited. This locking functionality is not applicable to pushbutton autoreset.
Page 530 USER-PROGRAMMABLE PUSHBUTTONS CHAPTER 12: LOCAL INTERFACE Figure 456: User-programmable pushbutton logic, sheet 2 of 2 PLUS LINE DISTANCE PROTECTION SYSTEM – INSTRUCTION MANUAL...
Page 531: Security
Plus Line Distance Protection System Chapter 13: Security Security Plus This section describes how to program the D90 security features. Password security It is recommended that passwords be programmed for each security level and assigned to specific personnel. There are two user password security access levels: command and setting.
Page 532: Password Security Settings
PASSWORD SECURITY CHAPTER 13: SECURITY When entering a settings or command password via Ethernet or the serial USB interface, the user must enter the corresponding password level shown in the following table. Table 45: Required password levels for various connection types Connection type Password required Front panel USB...
Page 533 CHAPTER 13: SECURITY PASSWORD SECURITY Remote Command Password Range: 0 to 4294967295 in steps of 1 or null Default: null The value of the remote command password is specified here. For the password to be successfully entered, the values in the Enter New Password Confirm New Password fields must be identical.
Page 534: Password Security Operation
PASSWORD SECURITY CHAPTER 13: SECURITY Password Access Events Range: Enabled, Disabled Default: Disabled This setting enables and disables the logging of password access supervision events in the sequence of events recorder. The dual permission security access feature provides a mechanism for customers to prevent unauthorized or unintended upload of settings to a device through the local or remote interfaces.
Page 535: Enervista Security Management System
CHAPTER 13: SECURITY ENERVISTA SECURITY MANAGEMENT SYSTEM Plus The D90 provides a means to raise an alarm upon failed password entry. Should password verification fail while accessing a password-protected level of the relay (either settings or commands), the operand is asserted. The operand can be UNAUTHORIZED ACCESS programmed to raise an alarm via contact outputs or communications.
Page 536: Modifying User Privileges
ENERVISTA SECURITY MANAGEMENT SYSTEM CHAPTER 13: SECURITY • The user adding the new user must have administrator rights. • The EnerVista security management system must be enabled. Select the Security > User Management menu item to open the user management configuration window.
Page 537 CHAPTER 13: SECURITY ENERVISTA SECURITY MANAGEMENT SYSTEM • The EnerVista security management system must be enabled. Select the Security > User Management menu item to open the user management configuration window. Locate the username in the User field. Modify the user access rights by checking or clearing one or more of the fields shown. Field Description Delete Entry...
Page 538 ENERVISTA SECURITY MANAGEMENT SYSTEM CHAPTER 13: SECURITY PLUS LINE DISTANCE PROTECTION SYSTEM – INSTRUCTION MANUAL...
Page 539: Testing
Plus Line Distance Protection System Chapter 14: Testing Testing Plus This section describes the D90 testing features. Test mode Plus The D90 provides test settings to verify that functionality using simulated conditions for contact inputs and outputs. To initiate the test mode, the setting must Test Mode Function be “Enabled”...
Page 540: Force Contact Outputs
TEST MODE CHAPTER 14: TESTING Figure 458: Force contact inputs configuration settings The following settings are available. Test Mode Function Range: Enabled, Disabled Default: Disabled This setting enables and disabled the test mode functionality. Test Mode Initiate Range: any FlexLogic™ operand Default: ON The test mode will initiate when the operand assigned to this setting is logic 1.
Page 541: Self-Tests
CHAPTER 14: TESTING SELF-TESTS Figure 459: Force contact outputs configuration settings The following settings are available. Test Mode Function Range: Enabled, Disabled Default: Disabled This setting enables and disabled the test mode functionality. Test Mode Initiate Range: any FlexLogic™ operand Default: ON The test mode will initiate when the operand assigned to this setting is logic 1.
Page 542: Self-Test Error Messages
SELF-TESTS CHAPTER 14: TESTING Self-test error messages The self-test error messages are displayed on the annunciator panel. Error messages can be accessed from the self-test tab. The self-test tab becomes illuminates when there are errors to report. Figure 460: Typical self-test error page There are three soft-keys associated with the self-test summary page.
Page 543 SYSTEM TROUBLE Description: An internal error has occurred. Severity: Device is temporarily out-of-service If this message appears, reset the alarm. If the alarm recurs, contact GE Grid Solutions for further instructions. UNIT NOT PROGRAMMED Description: The unit is configured as not programmed.
Page 544 CPU CARD TROUBLE Description: There may be a problem with the CPU card. Severity: Protection is available. If this message appears, cycle the control power If the alarm recurs, contact GE Grid Solutions. DELAYED AUTOMATION EXECUTION Description: Execution of the automation logic is longer than specified.
Page 545 If this message appears after an order code update or firmware upgrade, clear the Plus message and load settings into the D90 . In all other cases, contact GE Grid Solutions. SNTP ERROR FAILURE Description: The SNTP server is not responding.
Page 546 SELF-TESTS CHAPTER 14: TESTING PLUS LINE DISTANCE PROTECTION SYSTEM – INSTRUCTION MANUAL...
Page 547: Theory Of Operation
Plus Line Distance Protection System Chapter 15: Theory of operation Theory of operation Plus This section describes the basic theoretical principles behind the operation of D90 Plus The D90 distance elements The distance element is composed of two separate algorithms. The first is a conventional frequency domain (phasor) algorithm based on the UR-series D60 implementation.
Page 548: Distance Element Time Domain Algorithm
Plus THE D90 DISTANCE ELEMENTS CHAPTER 15: THEORY OF OPERATION • Positive-sequence voltage is between 0.8 and 1.2 pu. • Source frequency differs from tracking frequency by less than 0.5 Hz. • Source frequency differs from nominal frequency by less than 5.5 Hz. •...
Page 549: Distance Supervision
Plus CHAPTER 15: THEORY OF OPERATION THE D90 DISTANCE ELEMENTS The voltage signals are pre-filtered using a special digital filter designed to cope with CVT transients. This patented filter combines filtering and memory actions enabling the relay to cope with CVT noise under high source impedance ratios (SIRs). The filter controls underestimation of the fault voltage magnitude to less than 1% of the nominal and prevents certain phase angle anomalies that can be encountered under heavy CVT noise and high SIRs.
Page 550: Distance Characteristics
Plus THE D90 DISTANCE ELEMENTS CHAPTER 15: THEORY OF OPERATION Distance characteristics The relay shapes its distance characteristics using phase angle comparators and estimated voltage and current phasors. The following distance characteristic definitions pertain to all phase and ground distance functions. Phase A, B, and C current phasors Ground current from a parallel line Phase A to ground, phase B to ground, and phase C to ground voltage phasors...
Page 551 Plus CHAPTER 15: THEORY OF OPERATION THE D90 DISTANCE ELEMENTS Element Value 1 Value 2 A ground element × Z + I_0 × K × Z + I × K × Z – V B ground element × Z + I_0 × K ×...
Page 552 Plus THE D90 DISTANCE ELEMENTS CHAPTER 15: THEORY OF OPERATION If the mho characteristic is selected, the limit angle of the comparator is adjustable concurrently with the limit angle of the mho characteristic, resulting in a tent shape complementing the lens characteristic being effectively applied. Quadrilateral reactance characteristic for directional applications The quadrilateral reactance characteristic is achieved by checking the angle between the two values for the various phase and ground distance elements shown in the table below.
Page 553 Plus CHAPTER 15: THEORY OF OPERATION THE D90 DISTANCE ELEMENTS Element Value 1 Value 2 A ground element I_0 × Z _2 × Z B ground element I_0 × Z _2 × Z C ground element I_0 × Z _2 × Z The characteristic and limit angles of the directional comparator are independently adjusted from the mho and reactance comparators.
Page 554 Plus THE D90 DISTANCE ELEMENTS CHAPTER 15: THEORY OF OPERATION The limit angle of the comparator is not adjustable and equals 50°. The fault type characteristic is intended to block ground distance elements during double-line-to-ground faults. Zero-sequence directional characteristic The extra zero-sequence characteristic is achieved by checking the angle between the two values for the elements shown in the table below.
Page 555 Plus CHAPTER 15: THEORY OF OPERATION THE D90 DISTANCE ELEMENTS Table 15-13: Directional quadrilateral phase distance functions Characteristic Comparator inputs Limit angle Input 1 Input 2 Reactance I × Z – V I × Z Comparator limit Directional I × Z V_1M Directional comparator limit Right blinder...
Page 556: Memory Polarization
Plus THE D90 DISTANCE ELEMENTS CHAPTER 15: THEORY OF OPERATION Memory polarization All distance functions use memory polarization. The positive-sequence voltage, either memorized or actual, is used as a polarizing signal. The memory is established when the positive-sequence voltage remains above 80% of its nominal value for five power system cycles.
Page 557: Distance Elements Analysis
Plus CHAPTER 15: THEORY OF OPERATION THE D90 DISTANCE ELEMENTS negative-sequence currents in extra directional comparators. Both the currents are from the protected line and are not affected by any compensation as the latter applies only to the reach defining comparators: the mho, reactance, and blinder characteristics. Distance elements analysis This subsection shows how to analyze the operation of the distance elements in steady states using the results of short circuit studies.
Page 558 Plus THE D90 DISTANCE ELEMENTS CHAPTER 15: THEORY OF OPERATION The following sub-sections describe the operation of each of the distance characteristics with respect to these values. Mho phase A to ground element analysis, before memory expires Before the memory expires, the following values are calculated for the mho phase A to ground distance element.
Page 559 Plus CHAPTER 15: THEORY OF OPERATION THE D90 DISTANCE ELEMENTS Plus When memory expires, the D90 will use the actual voltage for polarization. The following values are calculated for the mho phase A to ground distance element. Eq. 57 The ground distance element checks for the following conditions for overcurrent supervision and the difference angles.
Page 560 Plus THE D90 DISTANCE ELEMENTS CHAPTER 15: THEORY OF OPERATION Table 20: Mho phase AB element conditions Parameter Condition Supervision Overcurrent supervision | (I – I ) / √3 | > | ∠((I )) – ∠((V Comparator Limit Mho difference angle –...
Page 561: Phase Distance Applied To Power Transformers
CHAPTER 15: THEORY OF OPERATION PHASE DISTANCE APPLIED TO POWER TRANSFORMERS The results are shown in the following table. Table 23: Quadrilateral phase A to ground element analysis Parameter Calculation Requirement Condition met Overcurrent supervision 3 × 1.37 A = 4.09 A >...
Page 562 PHASE DISTANCE APPLIED TO POWER TRANSFORMERS CHAPTER 15: THEORY OF OPERATION Figure 468: Applications of the phase distance transformer settings In the following tables, the suffix “_21P” indicates current or voltage inputs to the phase NOTE: distance (ANSI 21P) element. Table 24: Phase distance input signals for delta-wye transformers Transformer Loop...
Page 563 CHAPTER 15: THEORY OF OPERATION PHASE DISTANCE APPLIED TO POWER TRANSFORMERS Transformer Loop Current transformation Voltage transformation connection _21P - _21P _21P - _21P _21P - _21P _21P - _21P _21P - _21P _21P - _21P _21P - _21P _21P - _21P _21P - _21P...
Page 564: Example System With Power Transformers
PHASE DISTANCE APPLIED TO POWER TRANSFORMERS CHAPTER 15: THEORY OF OPERATION Transformer Loop Current transformation Voltage transformation connection _21P _21P = _21P _21P = _21P _21P = _21P - _21P _21P _21P - _21P _21P - _21P = _21P _21P _21P = _21P _21P =...
Page 565 CHAPTER 15: THEORY OF OPERATION PHASE DISTANCE APPLIED TO POWER TRANSFORMERS Figure 469: Example system configuration Plus The D90 input signals at point X are shown in the following table. Table 26: Input signals at point X for example system with power transformers Input Primary Secondary...
Page 566: Ground Directional Overcurrent Theory
GROUND DIRECTIONAL OVERCURRENT THEORY CHAPTER 15: THEORY OF OPERATION Consequently, the following signals are applied to the phase AB distance element. Eq. 60 Eq. 61 This results in the following apparent impedance. Eq. 62 The apparent impedance calculated above is a correct measure of the distance from the VT location to the fault.
Page 567: Ground Directional Overcurrent Example
CHAPTER 15: THEORY OF OPERATION SERIES COMPENSATED LINES To ensure operation of the element under such circumstances, the angle comparator uses a polarizing voltage augmented by the negative-sequence current as shown in the following equations. For the forward-looking element: Eq. 64 For the reverse-looking element: Eq.
Page 568: Memory Polarized Directional Comparators
SERIES COMPENSATED LINES CHAPTER 15: THEORY OF OPERATION Voltage or current inversion may lead to false direction discrimination by directional elements. This may potentially include both a failure to operate on a forward in-zone fault as well as misoperation on a reverse fault. Both distance and overcurrent directional elements can be affected.
Page 569: Dynamic Reach Control
CHAPTER 15: THEORY OF OPERATION SERIES COMPENSATED LINES Dynamic reach control The problem of steady-state overreaching due to the negative reactance of the series Plus capacitors may be addressed in the D90 in a traditional way by shortening the reach of an underreaching distance elements to the net inductive reactance of the line between the potential source and the far end busbars.
Page 570 SERIES COMPENSATED LINES CHAPTER 15: THEORY OF OPERATION Figure 472: Dynamic reach, low-current external fault The following figure illustrates a high-current external fault. The air gaps or MOVs conduct majority of the fault current and neither steady-state nor transient overreach takes place. The relay does not reduce its reach as it is not necessary.
Page 571: Single-Pole Tripping
CHAPTER 15: THEORY OF OPERATION SINGLE-POLE TRIPPING Figure 474: Dynamic reach, high-current internal fault Single-pole tripping Plus Single-pole operations make use of many D90 features. At a minimum, the trip output, recloser, breaker control, open pole detector, and phase selector must be fully programmed and in-service;...
Page 572 SINGLE-POLE TRIPPING CHAPTER 15: THEORY OF OPERATION Figure 475: Single-pole operation The trip output element receives requests for single-pole and three-pole trips and three- pole reclose initiation. It then processes these requests to generate outputs that are used to perform the following functions. •...
Page 573: Slg Fault Scenario For Single-Pole Tripping
CHAPTER 15: THEORY OF OPERATION SINGLE-POLE TRIPPING : “GND DIST Z1 OP” Trip 1-Pole Input 1 : “PHS DIST Z1 OP” Trip 1-Pole Input 2 By default the POTT scheme will issue a single-pole trip. It is assumed that when tripping three-poles both the zone 1 and the POTT shall initiate three-pole reclosing.
Page 574: Slg Fault Evolving Into An Llg Fault Scenario For Single-Pole Tripping
SINGLE-POLE TRIPPING CHAPTER 15: THEORY OF OPERATION zone 1 operate and zone 2 pickup operands that were picked up reset immediately. The BG, CG, and BC distance elements remain operational guarding the line against evolving faults. As zone 2 or negative-sequence directional elements pickup due to the fault, the permission to trip is keyed to the remote end.
Page 575: Phase Selection
CHAPTER 15: THEORY OF OPERATION SINGLE-POLE TRIPPING If the fault evolves slowly, the sequence is different: The relay trips phase A as in the previous example. The phase selector resets, the open pole detector is activated and forces the zone 1 and zone 2 AG, AB, CA and negative-sequence overcurrent elements to reset.
Page 576: Communications Channels For Pilot-Aided Schemes
SINGLE-POLE TRIPPING CHAPTER 15: THEORY OF OPERATION The pre-fault quantities are captured and the calculations start when the disturbance detector (ANSI 50DD) operates. When the trip command is issued by the trip output logic (TRIP 1-POLE TRIP 3-POLE operands asserted) and during open pole conditions (OPEN POLE OP operand asserted), the phase selector resets all its output operands and ignores any subsequent operations of the...
Page 577 CHAPTER 15: THEORY OF OPERATION SINGLE-POLE TRIPPING Single-bit channels Single-bit communication channels for pilot-aided schemes use the RX1 and TX1 operands for each scheme. The fault data is coded as shown in the following tables. Table 28: Permissive scheme transmit codes for single-bit channels Phase selector determination of fault type Bit pattern AG, BG, CG, ABG, BCG, CAG, AB, BC, CA, and 3P...
Page 578 SINGLE-POLE TRIPPING CHAPTER 15: THEORY OF OPERATION Table 33: Unblocking scheme trip table for single-bit channels Remote data Local data Bit pattern Remote determination Local determination of Trip output of fault type fault type LOG1 0 or 1 AG fault DCUB TRIP A 0 or 1 BG fault...
Page 579 CHAPTER 15: THEORY OF OPERATION SINGLE-POLE TRIPPING Remote data Local data Bit pattern Remote determination of Local determination of fault Trip output fault type type AG, BC, or BCG TRIP PHASE B CG, AB, ABG, 3P, or CG, BC, BCG, CA, or CAG TRIP PHASE C unrecognized AG, BC, or BCG...
Page 580 SINGLE-POLE TRIPPING CHAPTER 15: THEORY OF OPERATION Remote data Local data Bit pattern Remote determination of Local determination of fault Trip output fault type type BG, CA, CAG BG, AB, ABG BC, BCG, 3P DCUB TRIP B BG, CA, CAG BG, AB, ABG BC, BCG, 3P DCUB TRIP B CG, AB, ABG, 3P,...
Page 581 CHAPTER 15: THEORY OF OPERATION SINGLE-POLE TRIPPING Phase selector determination of fault type Bit pattern AB, ABG, BC, BCG, CA, CAG, 3P, or unrecognized Table 41: Blocking scheme transmit codes for four-bit channels Phase selector determination of fault type Bit pattern Operands asserted STOP STOP...
Page 582 SINGLE-POLE TRIPPING CHAPTER 15: THEORY OF OPERATION Table 44: Blocking scheme trip table for four-bit channels Remote data Local data Bit pattern Remote Local determination Trip output determination of of fault type fault type Any while the INIT Trip as for single- signal was not bit channel established...
Page 583: Permissive Echo Signaling
CHAPTER 15: THEORY OF OPERATION SINGLE-POLE TRIPPING Remote data Local data Bit pattern Remote Local Trip output determination of determination of fault type fault type AG, AB, ABG, CA, DCUB TRIP B CAG, 3P, unrecognized DCUB TRIP B DCUB TRIP B DCUB TRIP B DCUB TRIP B MULTI-P...
Page 584: Pilot Scheme And Phase Selector Coordination
SINGLE-POLE TRIPPING CHAPTER 15: THEORY OF OPERATION used). The permissive echo is programmed as a one-shot logic. The echo is sent only once and then the echo logic locks out for a user-specified period. The duration of the echo pulse does not depend on the duration or shape of the received RX signal but is programmable with the setting.
Page 585: Cross-Country Fault Example
CHAPTER 15: THEORY OF OPERATION SINGLE-POLE TRIPPING This enhanced operation of the pilot-aided schemes is the reason to use a short pilot scheme priority time when setting the trip output logic. The timer will force the scheme to wait for a decision from the pilot scheme for a short period of time before accepting any local trip request.
Page 586 SINGLE-POLE TRIPPING CHAPTER 15: THEORY OF OPERATION Table 50: Trip table for cross-country fault example, four-bit channel Terminal Remote data Local data Bit pattern Remote Local Trip output determination of determination of fault type fault type TRIP PHASE A TRIP PHASE A PLUS LINE DISTANCE PROTECTION SYSTEM –...
Page 587: Maintenance
Plus Line Distance Protection System Chapter 16: Maintenance Maintenance This section outlines maintenance, repair, storage, and disposal of the hardware and software. General maintenance The unit requires minimal maintenance. As a microprocessor-based relay, its characteristics do not change over time. Back up and restore settings This section describes how to backup settings to a file and how to use that file to restore the settings to the original unit or to a replacement unit.
Page 588: Restore Settings
UPGRADE SOFTWARE CHAPTER 16: MAINTENANCE To save a settings file in the URS format in EnerVista Offline Window: In EnerVista, right-click in the Offline Window area and select New Settings File. A window opens. Change the file name at the end of the Path field, keeping the .urs extension. Plus From the Associate File with Device drop-down list, select the D90 device.
Page 589: Upgrade Firmware
CHAPTER 16: MAINTENANCE UPGRADE FIRMWARE After upgrading, check the version number under Help > About. If the new version does not display, try uninstalling the software and reinstalling the new versions. You can also downgrade the software; use the same procedure here. Plus A message can display in the EnerVista software when accessing a D90 device that the...
Page 590: Uninstall And Clear Files And Data
Customers are responsible for shipping costs to the factory, regardless of whether the unit is under warranty. • Fax a copy of the shipping information to the GE Grid Solutions service department in Canada at +1 905 927 5098. Use the detailed return procedure outlined at https://www.gegridsolutions.com/multilin/support/ret_proc.htm...
Page 591: Disposal
CHAPTER 16: MAINTENANCE DISPOSAL Disposal There are no special requirements for disposal of the unit at the end its service life. To prevent non-intended use of the unit, remove interior modules, dismantle the unit, and recycle the metal when possible. PLUS LINE DISTANCE PROTECTION SYSTEM –...
Page 592 DISPOSAL CHAPTER 16: MAINTENANCE PLUS LINE DISTANCE PROTECTION SYSTEM – INSTRUCTION MANUAL...
Page 593: Appendix
Warranty For products shipped as of 1 October 2013, GE Grid Solutions warrants most of its GE manufactured products for 10 years. For warranty details including any limitations and disclaimers, see the GE Grid Solutions Terms and Conditions at http://gegridsolutions.com/multilin/warranty.htm...
Page 594 REVISION HISTORY CHAPTER 17: APPENDIX PLUS LINE DISTANCE PROTECTION SYSTEM – INSTRUCTION MANUAL...
Page 595 Plus Line Distance Protection System Index Index Automation overview ................. 373 Automation virtual analog outputs description ..................... 415 AC modules settings ....................415 connections ..................... 53 Automation virtual inputs description .................... 138 description ..................... 405 Altitude ......................44 logic ......................406 Annunciator settings ....................
Page 596 INDEX Auxiliary overvoltage Breaker interlocking description .................... 232 description .....................378 logic ......................233 logic ......................380 operands ....................360 operands ....................431 settings ....................232 settings ....................378 specifications ..................25 specifications ..................37 Auxiliary undervoltage description .................... 230 logic ......................232 operands ....................360 Cautions ......................
Page 597 INDEX Disconnect configuration Event recorder description .................... 380 description ..................... 447 logic ......................383 front panel display ................447 operands ....................432 overview ....................23 settings ....................380 specifications ..................39 Disconnect control description .................... 385 logic ......................387 operands ....................432 Fault location settings ....................
Page 598 INDEX Ground directional supervision Installation ............ 174 Ground distance electrical ....................48 physical ......................45 description .................... 165 settings ....................137 logic ......................172 IRIG-B operands ....................363 settings ....................165 connections .....................51 specifications ..................27 specifications ..................42 Ground instantaneous overcurrent description .................... 213 logic ......................
Page 599 INDEX Negative-sequence instantaneous overcurrent description .................... 217 logic ......................218 Open pole detector operands ....................365 description ..................... 286 settings ....................217 logic ......................288 specifications ..................30 operands ....................366 Negative-sequence overvoltage settings ....................286 description .................... 229 specifications ..................32 logic ......................
Page 600 INDEX Phase undervoltage Protection contact inputs description .................... 224 chatter detection ................341 logic ......................225 configuration ..................338 operands ....................369 operands ....................361 settings ....................224 settings ....................340 specifications ..................34 Protection contact outputs Phasor measurement unit settings ....................342 accuracy ....................495 Protection Flex Elements calibration .....................
Page 601 INDEX Remote outputs Synchrocheck DNA bit pairs ..................112 description ..................... 394 protection specifications ..............35 logic ......................397 specifications ..................43 operands ....................433 UserSt bit pairs ..................112 overview ....................21 Repair settings ....................395 ....................582, 585 specifications ..................37 Restore ......................
Page 602 INDEX Typical wiring .....................49 Underfrequency description .................... 312 logic ......................314 settings ....................313 specifications ..................36 Uninstall files ................... 582 Upgrade firmware ................581 Upgrade software ................580 USB port specifications ..................43 User-programmable self-tests settings ....................129 Voltage cut-off level ................

GE D90 Plus Instruction Manual

1 Getting Started

Important Procedures

Introduction to the UR Plus -Series

Enervista Software

2 Product Description

Device Overview

Order Codes

Specifications

3 Installation

Physical Installation

Electrical Installation

4 Interfaces

5 Enervista Software Suite

6 COMMUNICATIONS Communications Overview

Network Settings

Modbus Communications

DNP Communications

IEC 60870-5-104 Communications

IEC 61850 Communications

Flexstates

Real Time Clock

User-Programmable Self-Tests

Serial Port

Shared Operands

7 PROTECTION Protection Overview

Power System

Grouped Protection Elements

Control Elements

Protection Inputs and Outputs

Protection Flexlogic

8 Automation

Breakers

Disconnects

Automation Control

Automation Inputs and Outputs

Automation Logic

9 Equipment Manager

Battery Monitor

Shared Operands

10 Digital Fault Recorder

Fault Report

Transient Recorder

Disturbance Recorder

Shared Operands

11 Metering

Metering Source

Phasor Measurement Unit

Data Logger

Shared Operands

12 Local Interface

Annunciator Panel

MIMIC Diagram Editor

User-Programmable Pushbuttons

13 Security

Password Security

Enervista Security Management System

14 Testing

Test Mode

Self-Tests

15 Theory of Operation

Plus Distance Elements

Phase Distance Applied to Power Transformers

Ground Directional Overcurrent Theory

Series Compensated Lines

Single-Pole Tripping

16 Maintenance

Back up and Restore Settings

Upgrade Software

Upgrade Firmware

Uninstall and Clear Files and Data

Repairs

Storage

Disposal

17 Appendix

APPENDIX Warranty

Revision History

Quick Links

Related Manuals for GE D90 Plus

Summary of Contents for GE D90 Plus