File: SuggSpec Gen Protect 70809.doc
Generator Protection
Suggested Specifications
Protection, metering, and monitoring for the generator shall be provided by a microprocessor-based package. The microprocessor-based package shall be suitable for synchronous or induction machines, using any prime mover, any type of connection (bus, unit) and any type of grounding (direct ground; low impedance, high impedance), and any type of excitation (brushed or brushless).
Protection:
Protection functions shall include the following:
· Phase Distance (21) Three-zone impedance elements shall be provided for system phase fault back up protection. Load encroachment blinders may be applied for any zone. Selectable out-of-step blocking of zone 1 or zone 2 shall be provided. The elements shall be able to compensate for phase shift that occurs through a delta/wye step up transformer.
· Overexcitation (24) Overexcitation protection shall be provided based on volts/hertz measurement. Two definite-time and one selectable curve inverse-time element shall be provided to match the generator and transformer limit curve. The inverse-time element shall have an adjustable reset timer to account for the thermal effects of repeated violation of the setting. The overexcitation protection function shall operate properly over a range of frequency from 2 Hz to 80Hz.
· Sync Check (25) A synchronism check element shall be provided employing phase angle/slip limit criteria and voltage limits. Dead voltage limits shall also be provided.
· Phase Undervoltage (27) Three phase undervoltage elements shall be provided.
· Directional Power (32) Three power elements shall be provided, selectable as forward/reverse and over/under. For medium to large steam generator units, this function shall have a pickup sensitivity from 0.003 to 0.005pu. In addition, one of the elements may be configured for real or reactive power.
· Loss of Field (40) A Two-zone, positive-sequence impedance mho element for loss-of-field detection shall be provided. Each zone shall have a selectable undervoltage supervision for accelerated tripping. Each element may be offset individually, and a directional blinder shall be provided to restrict tripping in the VAr output region. The loss of field function shall work properly over a frequency range from 50 to 70 Hz.
· Negative Sequence Overcurrent (46) Negative-sequence overcurrent protection shall be provided with definite-time and inverse-time elements. The element will have an adjustable reset timer to account for the thermal effects of repeated violation of the setting. The negative sequence element shall have a programmable definite maximum time to reduce tripping time for modest unbalances. In order to prevent misoperations during fault conditions the negative sequence element shall have a fixed minimum definite time of around 12 cycles.
· Stator Overload (49) Thermal overload protection shall be provided employing the IEC-255-8 thermal model for stator overload protection
· Breaker Failure (50BF, 50N-BF) Breaker failure protection shall be provided employing current detection and breaker status inputs and means to detect open breaker pole-flashover.
· Definite Time Overcurrent (50DT) A three-phase definite time overcurrent element shall be provided for use in split phase differential protection applications or as current detectors for flexible logic schemes.
· Inadvertent energizing (50/27) Inadvertent energizing protection shall be provided employing an instantaneous overcurrent function (50) and an undervoltage function (27) with individual pick up and drop out timers for arming.
· Instantaneous Phase and Neutral Overcurrent (50, 50N or 50G) Phase, residual or ground instantaneous, definite-time nondirectional overcurrent elements shall be provided. For protection during generator startup and shutdown, these functions shall operate over a frequency range from 2 to 80Hz.
· Inverse Time Neutral Overcurrent (51N or 51G) Residual or ground, inverse-time nondirectional overcurrent elements shall be provided.
· Inverse Time Phase Overcurrent with Voltage Control or Voltage Restraint (51VC, 51VR) Voltage controlled or voltage restrained time overcurrent elements shall be provided for system back up protection. The use of restraint or control is selectable. The elements shall be able to compensate for phase shift that occurs through a delta/wye step up transformer. During a VT fuse loss condition, the pickup value of the voltage restrained function shall reset to its nominal setting rather than blocking the entire function.
· Phase Overvoltage (59) Three phase overvoltage elements shall be provided. The phase overvoltage function should operate properly over a frequency range from 50 to 120 Hz.
· Neutral Overvoltage (59N) Three neutral overvoltage elements shall be provided.
· Voltage (59X) An independent voltage input shall be provided that may be used for inter-turn protection or ungrounded bus ground-fault protection.
· 100% Stator Ground (59N, 27TN or 59D) 100% stator ground fault detection shall be provided employing neutral overvoltage protection (59N) and a choice of either a) third harmonic neutral undervoltage measurement with power, VAr, PF, power band and undervoltage supervision (27TN) or b) third harmonic voltage differential using a ratio comparator technique of the line and neutral terminal quantities (59D).
· VT Fuse Loss Detection (60FL) Fuse loss (loss of potential) detection logic shall be provided to selectively block voltage dependent functions from misoperation, as well as alarm on the condition. This function shall operate correctly with a single three-phase set of VTs and detect single, dual or total (3-phase) loss of potential
· Field ground (64F, 64B) Field ground protection (64F) and field and ground brush lift off detection (64B) shall be provided using a low frequency square wave injection method that measures the field-ground impedance under offline, normal operating and fault conditions. Alarm and trip setpoints are to be provided.
· 100% stator ground (64S) 100% stator ground fault detection shall be provided employing subharmonic frequency injection and detection. This may be employed in addition to the neutral overvoltage (59N) element.
· Residual Directional Overcurrent (67N) A residual directional overcurrent element shall be provided, polarized from either calculated 3V0, neutral voltage (VN) or another input from an external broken delta voltage (VX). The operating current shall be selected as either 3I0 (calculated by the relay using 3 phase currents) or IN (input to the relay from a residual “doughnut” CT).
· Out of Step (78) Out of Step protection shall be provided based on a single blinder scheme employing a single positive sequence mho element with blinders. Out of step tripping shall be selectable to trip on exit from the mho element or on exit from the blinders, and shall be subject to a pole slip counter if desired.
· Frequency (81) Four frequency elements shall be provided, selectable as either over or underfrequency.
· Frequency Accumulation (81A) Frequency accumulator protection shall be provided employing six settable bands and shall permit operation per “Scheme 1” of IEEE C37.106.
· Rate of Change of Frequency (81R) Two rate-of-change-of-frequency elements shall be provided.
· Phase Current Differential (87) Phase current differential elements shall be provided, employing a dual-slope percentage differential characteristic. CT saturation detection techniques shall be employed to dynamically increase the restraint slope to prevent misoperation during through faults. These saturation detection techniques shall not disable the differential element. The phase current differential elements shall accommodate different CT ratios for line and neutral side phase CTs. For converter start, gas turbine units, this element shall have two pickup points employed such that the higher pickup may be enabled during startup while the normal pickup will be enabled when the machine is on-line.
· Ground Differential (87GD) A ground differential element shall be provided with a directional element that shall differentiate between internal and external faults. At extremely low zero-sequence currents, this element shall become non-directional. This element shall be based on a low impedance principle that may be sourced from the ground CT input and the same set of phase CTs that supply other protective elements.
· Trip Coil Monitoring (TC) Trip Circuit monitoring shall be provided.
Application Flexibility
· Any element may be blocked or enabled by control/status input state changes to accommodate changing field conditions.
· Any element may be routed to one or more of the output contacts.
· Four setting groups shall be available.
· Programmable trip and control logic schemes may be implemented through graphical means.
· The relay shall be able to use line-to-ground, line-to-line, or line-to-ground to line-to-line potential quantities. When line-to-ground VT inputs are selected, the relay should internally calculate line-to-line quantities for protection functions and metering. However, the oscillography recording shall be based on line-to-ground voltage signals to identify the faulty phase.
· Phase rotation shall be field software selectable.
Metering and Monitoring:
The relay shall provide real time metering of voltages (phase, neutral and sequence quantities), currents (phase, neutral and sequence quantities), real power (MW), reactive power (MVAr), power factor (PF), frequency, volts per hertz and positive sequence impedance (Z) measurements. In additional, the relay will calculate and display differential quantities as detected in the differential elements, phase and ground, and the third harmonic quantities in the neutral and terminal ends of the machine, and the field impedance to ground.
Metering accuracies shall be at least:
· Voltage: 0.5 V or 0.5%, whichever is greater, or 0.8 V or 0.75%, whichever is greater if the relay is set up to calculate the line-to-line voltages from line-to-ground VTs.
· Current: 5 A rating, 0.1 A or 3%, whichever is greater; 1 A rating, 0.02 A or 3%, whichever is greater
· Power: 0.01 PU or 2%, whichever is greater
· Frequency: 0.02 Hz (from 57 to 63 Hz for 60 Hz models; from 47 to 53 Hz for 50 Hz models)
The relay shall monitor the unit breaker contact wear based on interrupted current and close-to-open operations.
The relay shall include extensive self-testing and an alarm output contact indication of self-test warning, failure conditions, or removal of input power.
Access/Communications/Integration Capabilities
The relay shall provide access via a front-panel HMI and target module. The following communication ports shall be provided:
· Two RS-232 serial ports, one located on the front of the relay, and one located on the rear of the relay. As an alternative, an Ethernet port shall be available in place of the rear RS-232 port.
· One isolated RS-485 serial port on the rear of the relay.
· RS-232, RS-485 and Ethernet ports shall support Modbus® or DNP 3.0 or IEC61850 communication.
· One IRIG-B port.
Extended Logging Capabilities
Target Log
The relay shall provide a target log for each trip operation that includes the function(s) operated, the functions picked up, input/output status, time stamp, and phase and neutral currents at the time of trip. A total of 24 target logs shall be stored in a first in, first out buffer, with the oldest records being automatically overwritten.
Event Log
The relay shall provide a sequence of events log for selectable events that includes status of all elements (picked up, tripped, reset), input/output status, time stamp, all voltages (including 3rd harmonic at terminal and neutral inputs), all currents, phase impedances. A total of 512 events shall have records created. These shall be stored in a first in, first out buffer, with the oldest records being automatically overwritten. A selectable event is defined as element pick up, trip or drop out or a change in I/O status.
Waveform Capture Capabilities
An oscillographic recorder shall provide comprehensive data recording of all monitored waveforms, and the status of inputs and outputs, storing up to 472 cycles of data. The total record length is user-configurable for up to 16 partitions. The sampling rate shall be at least 16 times the power system nominal frequency (50 or 60 Hz). The recorder shall be triggerable by either designated status inputs, trip outputs, or via serial communications or from the optional front panel HMI. The recorder shall continuously store waveform data, keeping the most recent data in memory. When triggered, the recorder shall continue to store data in memory for a user-defined, post-trigger delay period. Records may be stored in COMTRADE format.
User Software for Interface and Analysis
User interface software shall be provided that is menu-driven and Windows based. Using the software, the user shall be able to: view setpoints, set elements, configure the elements, configure the trip/block matrix, create programmable logic schemes, view metering, view the target log, view the event log, download the oscillographic files, load files from a PC to the relay, load files from the relay to the PC, and print all settings.
Waveform (oscillographic) viewing software shall be provided that can open, view and analyze capture waveforms. Graphic display of the analog voltage and current traces, as well as the status of the inputs and outputs will be viewable. In addition, harmonics and RMS values may be viewed. Analysis tools such as phasor diagrams, R-X diagrams and P-Q diagrams will be available. Zooming abilities, curser manipulation with attendant value display, and multiple cursor difference quantities shall be provided. Power factor and frequency traces will also be viewable.
I/O Count and Description
The following I/O shall be provided:
· Control/Status Inputs – 6 internally wetted inputs.
· Contact Outputs – 8 outputs; 6 form “a”, and 2 form “c”.
· Optional expanded I/O shall increase the I/O count to 14 control status inputs and 23 contact outputs.
· Voltage Inputs – 5 inputs, rated nominal voltage of 50 V ac to 140 V ac at 60 Hz or 50 Hz. Shall withstand 240 V continuous voltage and 360 V for 10 seconds. Source voltages may be line-to-ground or line-to-line connected. Phase sequence ABC or ACB shall be selectable. Voltage transformer burden shall be less than 0.2 VA at 120 V ac.
· Current Inputs – 7 inputs, rated nominal current (IR) of 5.0 A or 1.0 A at 60 Hz or 50 Hz. Shall withstand 2IR continuous current and 100IR for 1 second. Current transformer burden shall be less than 0.5 VA at 5 A, or 0.3 VA at 1 A.
· IRIG B Signal - The relay shall accept either modulated or demodulated IRIG-B time clock synchronization signal.
· A self-diagnostic contact – form “c” – shall be provided.
· Power supply failure contact – form “b” – shall be provided.
Power supply requirements
The relay shall have two power supply voltage ranges:
High voltage: Shall operate properly from 80 V dc to 312.5 V dc or 85 V ac to 265 V ac. Shall withstand 315 V dc or 300 V ac for 1 sec.