1 Feeder protection for overhead lines and cables in isolated neutral or compensated networks Specification
3 Feeder protection for overhead lines and cables in isolated neutral or compensated networks Version Date Pages Version 15F-AB2 B (16) 1 Feeder protection relay for outgoing feeders General Mechanical design and mounting Current connections Mounting LHMI Circuit breaker control Indications and LEDs Web server functionality Local/Remote switch Binary inputs and outputs Trip outputs and master trip Self supervision and IRF output Current input channels Protection Current based protection Non-directional overcurrent protection Admittance based or directional earth-fault protection Transient/Intermittent earth fault Negative sequence overcurrent protection Phase discontinuity protection Other protection functions Thermal overload protection Breaker-failure protection Optional protection functions Auto-reclosing ARC protection Earth-fault protection Measurements Phase currents Residual current Current sequence components Residual voltage Disturbance, fault and event recording Event registration Fault records Disturbance records Time synchronization Condition monitoring Self supervision Communication interfaces IEC GOOSE messaging User authorization Setting and configuration software Environmental conditions Quality assurance and standards... 15
4 4 (16) 1 Feeder protection relay for outgoing feeders 2 General This specification is valid for applications where the following criteria usually are applicable: Solidly earthed, via resistance earthed or isolated neutral, or compensated network Directional earth-fault protection is required for selective tripping The specification highlights constructional features and software functions that are required within the specific relay application area. The specification applies to design, manufacture, supply, testing and operation of protection, measuring and control functions intended for outgoing feeder applications in electrical power systems of either underground neutral cable or over headline construction primarily suitable for networks which directly or resistance earthed neutrals. The provided relay shall work reliably and selectively as apart of a protection system. The relay must not operate at faults occurring outside the protection zone. Internal faults or disturbances in the auxiliary supply or measurement circuits may not result in un-correct operation of the device. Each start or trip provided by the relay must generate clear and reliable indications. These indications must be transferable to an upper level system over the station bus. The relay shall be of a numerical communicating type offering extensive protection, control and measuring functions in one enclosed unit. The protection relay basic design and data modeling shall be based on the IEC standard. Special attention has to be paid in minimizing the replacement time of a defective unit, preferably by means of plug-in units. The relay shall have full flexibility in terms of assigning any binary input and output signal to the internal logic circuits. The following specification highlights the most important features of the relay. In no means the following shall be regarded as a complete specification for the relay. In addition the relay must fulfill the relevant IEC standards and be suitable for the intended applications, as described in the complete set of specifications, or otherwise communicated to the prospective Bidders.
5 5 (16) 3 Mechanical design and mounting The design shall be of plug-in type, where the plug-in unit can be withdrawn or inserted to a fixed mounted base unit. The withdrawal of the plug-in unit shall result automatic short-circuit in the supplying current transformers secondary circuits. In other words, it shall be possible to safely extract the plug-in unit from the case (base unit) after disconnecting the auxiliary voltage without adding any external jumper wires or operating any additional switches or bridges. Means shall be included to seal the plug-in unit into the base unit, to prevent accidental removal Current connections Mounting 3.2 LHMI For the current transformer secondary circuit lead connections both ring lug and compression type termination shall be supported. Each of the current terminals shall be capable of accepting at least two 2.5 mm 2 size of wires, either solid or fine stranded. The protection relay wall, flush, semi-flush, rack and tilted semi-flush mounting options shall be possible using readily defined installation kits. The kits shall be from the same manufacturer to guarantee smooth installation and uniform outlook. When flush or semi-flush installed to cabinet door IP54 level shall be reached, while door closed. Degree of protection by enclosure of flush-mounted relay Description Value Front side IP 54 Rear side, connection terminals IP 20 When flush mounted on a cabinet door, the depth of the relay shall not exceed 160mm, without any additional raising frame. Additionally, it shall be possible to mount at least two protection relays in parallel into a 4U high 19 rack. The LHMI shall support local measurement, event and alarm views through its LCD display. It shall also enable the parameter settings. It shall be possible to choose either the main menu or the measurement view as the default view. The LCD is to be fitted with at least four rows of characters with easily readable font size Circuit breaker control It shall be possible to control a circuit breaker e by means of designated control buttons. It shall be possible to interlock the circuit breaker close command directly by a binary input, by a protection relay internal interlocking logic and thermal protection operation or by a protection relay trip command output operating in lockout mode.
6 3.2.2 Indications and LEDs 6 (16) Each start and trip from every protection function must be clearly indicated. It must also be possible to transfer the start and trip signals to the binary outputs if required and it must be possible to transfer them to an upper level system via communication link. The resetting of indications and alarm LEDs shall be easy, preferably by pressing one button only. The LHMI shall include at least eleven (11) freely programmable alarm LEDs for status indication. It shall be possible to insert a written clarification on a paper strip beside each of the LEDs to indicate the assigned function of the LED Web server functionality The relay shall be equipped with web server functionality to cater for remote HMI features, using commonly available web browser software. The web server functionality shall utilize the same user authority handling principles, as defined later on in this specification for the LHMI functionality. Activation of the web server shall need user intervention, thus the functionality shall be disabled as a default Local/Remote switch The LHMI shall be equipped with a Local/Remote switch including status indication. The operation rights of the L/R switch shall be covered the with user authorization procedures of the relay. When in local mode, the remote control commands to the circuit breaker shall be ignored and vice versa in remote mode. 3.3 Binary inputs and outputs The number of inputs shall be enough to interface the relay to the external circuits in order to enable the full use of the protection relay functionality. The number of binary inputs shall not be less than ten (10). The threshold voltage of the binary inputs shall be settable using a dedicated parameter. Grouping of binary inputs under a common ground potential is allowed, as far as more than one common ground potential is available. The inputs shall be fully isolated from the protection relay internal circuits. The total number of binary outputs shall not be less than nine (9), excluding the dedicated relay internal fault (IRF) output. In addition to the double pole trip output contacts, two other binary outputs shall be of heavy-duty type capable of tripping a circuit breaker (also see section 3.3.1) The two binary trip outputs shall have a selectable lock-out operation mode, which locks the output relays after operation. The resetting of the lock-out state shall be possible via the LHMI, the binary input and the communication interface. Description Operating range Rated voltage Threshold voltage Reaction time Value ±20 % of the rated voltage V DC V DC <5 ms
7 7 (16) It shall be possible, by software, to freely assign the binary inputs and outputs to the protection relay internal function logic. Also possibility to introduce simple logic functions, in the form of AND and OR gates including signal inversion, in front of the binary inputs and outputs shall also be foreseen. As an example; a possibility to energize a binary output from a number of internal relay signals (OR-gate) shall be available Trip outputs and master trip Two binary outputs shall be dimensioned for circuit breaker trip purposes, introducing trip circuit supervision functionality and a possibility for double pole operation. It shall be possible to exclude the tripping circuit supervision functionality from the outputs physically by changing the protection relay terminal connections. If required it must be possible to block all trip outputs by means of a single setting (master tripin order to prevent the closing of a circuit breaker after a trip without resetting, there must be so called "lock-out" mode available. The trip circuit must be supervised Self supervision and IRF output The relay shall be equipped with extensive self-supervision capabilities. In case of internal failure, the relay shall in no case issue a false trip signal. The failure code shall be visible on the protection relay LHMI (Local Human Machine Interface) display. The failure codes shall give detailed information about the situation. The end user documentation shall support the interpretation of the failure code in detail and by simple means. A dedicated IRF (Internal Relay Fault) output must be available in order to provide IRF status to external systems. 3.4 Current input channels The same hardware shall support both 5 A and 1 A nominal energizing currents. Selecting the nominal current shall be software based (settable). All the analog input channels shall have dedicated A/D converters to enable simultaneously sampling and elimination of skew. Analogue to digital conversion shall be of such design that good linearity can be achieved during the whole lifetime of the relay. The analogue signals shall be presented to the protection relay internal function blocks as no less than 32 samples per cycle with 18 bit resolution at 50 Hz base, with a signal to quantization noise ratio (NQSR) better than 110 db.
8 4 Protection 8 (16) To handle periodic changes in the primary circuit switching conditions, i.e. the network topology, there shall be support for at least four (4) different setting banks for each of the protection functions. The change of setting bank shall take place commonly for all of the protection functions. It shall be possible to change the setting bank locally from the LHMI, using a binary input signal and remotely through the communication link. The change of setting bank shall happen rapidly and it shall not result in a protection relay restart, a relay malfunction or a communication break. The protection functions listed below shall be regarded as the compulsory basic protection features. It shall be possible to either enable or disable each protection stage, depending on the requirements of the actual application. 4.1 Current based protection Non-directional overcurrent protection The protection shall consist of four separate freely settable non-directional overcurrent stages, covering setting ranges from 0.1 to 35 times pu (per unit). The operation characteristic of the low and high set stages shall be settable to either definite time or inverse time mode, supporting various types of inverse curves, including a user definable one. The fourth stage shall work as an instantaneous stage. The instantaneous stage shall also support the peak-to-peak measurement mode and include a possibility to introduce a dedicated two times setting value peak detection for fast operation under conditions when the current transformers have saturated. During an inrush current situation when large proportions of second harmonics are detected, it shall be possible, for each of the stages, to raise the setting value by a freely settable multiplier. It shall be possible to select the number of started phases for operation between one, two or all three Admittance based or directional earth-fault protection The earth-fault protection shall consist of three different admittance based or directional earth-fault stages and an additional non-directional stage for crosscountry faults by using a calculated value of I 0.The admittance stages shall cover voltage setting ranges from 0.05 to 5 times pu. The directional and non-directional stages shall cover current setting ranges from 0.01 to 35 times pu. First two of the stages and the sensitive stage, shall include both definite and inverse time characteristics, supporting various types of inverse curves, including a user definable one. It must be possible to operate the directional stages in nondirectional mode. The operation mode must be selectable by means of a parameter. During an inrush current situation characterized by a large proportion of second harmonics it shall be possible, for each of the stages, to either block or raise the setting value by a freely settable multiplier. The third harmonic shall be attenuated at least by 40 db.
9 4.1.3 Transient/Intermittent earth fault 9 (16) In order to secure accurate operation, the transient/intermittent earth-fault protection must be based on a sampling function designed for the protection and clearance of intermittent and transient earth faults in distribution and subtransmission networks. Fault detection should be done from the residual current and residual voltage signals by monitoring the transients using predefined criteria. The sampling frequency shall be high enough for proper detection of transient / intermittent earth faults. The operate time characteristics must be definite time (DT) Negative sequence overcurrent protection The protection shall consist of two different stages, covering setting range from 0.10 to 5 times pu. During an inrush situation when large amount of second harmonic is detected, it shall be possible, for each of the stages, to raise the setting value by a freely settable multiplier Phase discontinuity protection In order to achieve a capability to handle different load situations the protection shall be based on monitoring the negative sequence and the positive sequence current component ration (I 2 /I 1 ). It shall be possible to block the operation of the stage by the starting signal from any of the earth- fault protection stages or by the inrush current situation detection. 4.2 Other protection functions Thermal overload protection Thermal overload protection for lines, cables and distribution transformers shall be included. The protection can utilize either one or two time constant principle Breaker-failure protection Breaker failure protection shall be included in the form of a dedicated function. It shall be possible to initiate the protection either from an internal signal of the protection relay or via a binary input. The protection shall facilitate re-tripping of its own breaker, and also back-up tripping of an up-stream breaker. In both cases the trip delays shall be adjustable. The protection shall include different operation modes, where both the current flow and the circuit breaker position are monitored, or alternatively only either the current flow or the circuit breaker position is monitored. The current level for flow detection shall be separately adjustable for phase currents and residual current. 4.3 Optional protection functions The protection functions listed below shall be regarded as optional. If the option presented is seen as a necessary part of the protection relay functionality, the features presented shall form an integrated and compulsory part of the specification.
10 4.3.1 Auto-reclosing ARC protection 10 (16) The auto-reclosing function shall support at least five shots within a sequence, consisting of a settable mixture of high-speed auto-reclosing (HSAR) and delay auto-reclosing (DAR). It shall be possible to perform at least five consecutive shots, or block the auto-reclosing function, based on the nature of the detected fault. For easy setting and handling of the auto-reclosing function, no possibility (and no settings) for single-phase auto-reclosing shall be included. Arc protection shall be based on the detection of current and light simultaneously. During maintenance work at the substation, it shall be possible to change the operation criteria to light only, by control via a binary input. The current monitoring levels shall be separately adjustable for phase currents and the residual current. It shall be possible to monitor the busbar, circuit breaker and cable compartments simultaneously by means of compartment dedicated sensors. Tripping command to the up-stream circuit breaker shall be selective, based on the location of the ARC. The operating time of the protection shall be less than 15 ms, including the inherent delay of the output relays Earth-fault protection The relay shall offer various options for different earth-fault protection methods along with the traditional directional and non-directional earth-fault protection, such as earth-fault protection based on admittance criteria, watt-metric criteria or harmonics content in earth-fault current.
11 5 Measurements 5.1 Phase currents 11 (16) There shall be measurements functions and indication in LHMI for analogue inputs (current and voltage) connected to the relay, as per the following: Momentary values for phases A, B and C selectable based either true RMS or DFT (fundamental frequency only) values. Maximum demand values for phases A, B and C with settable demand intervals of 1, 5, 10, 15, 30, 60 or 180 minutes. Settable high and low warning thresholds (two of each), including the selection of an initiating number of phases. 5.2 Residual current Momentary value, selectable based on either true RMS or DFT (fundamental frequency only) values. Settable high and low warning thresholds (two of each). 5.3 Current sequence components The momentary values of the positive, negative and zero sequence current components shall be included. 5.4 Residual voltage Momentary value, selectable based either true RMS or DFT (fundamental frequency only) values. Settable high and low warning limits (two of each).
12 6 Disturbance, fault and event recording The relay shall be capable of recording and storing at least the 1000 latest timetagged events in a non-volatile memory. 12 (16) The disturbance recorder shall be capable of recording at least 12 freely selectable analogue input signals and 64 freely selectable internal signals or binary inputs. The sample frequency shall be selectable, maximum sample frequency being no less than 1.6 khz (32 samples per cycle at 50 Hz). The recording time shall be selectable, including the pre-trigger time. All analog and binary input channels must be capable of triggering the function. There shall be a settable quarantine time for triggering channels, in order to prevent successive recordings triggered by the same source. Analogue channels must have an adjustable triggering level. For binary channels it shall be possible to choose triggering either from the rising or falling edge of the signal, or both. It shall be possible to record either wave-forms or trends of the analog channels. When the maximum number of channels is connected, utilizing the highest sampling frequency, at least two recordings, each with a length of 10 seconds, shall be supported. For uploading the recorded disturbances records support for a suitable software tool shall be included. The uploaded recording shall be of a well-recognized format, preferably the COMTRADE format. 6.1 Event registration 6.2 Fault records The SoE (Sequence of Events information must be accessible locally via the user interface on the relay front panel or remotely via the communication interface of the relay. The information should further be accessible, either locally or remotely, using the web-browser based user interface. To collect sequence-of-events (SoE) information, the relay must incorporate a nonvolatile memory with a capacity of storing at least 1000 event codes with associated time stamps. The non-volatile memory must retain its data also in case the relay temporarily loses its auxiliary supply. The event log should facilitate detailed preand post-fault analyses of feeder faults and disturbances. The relay should have the capacity to store the records of at least 100 fault events. The records must enable the user to analyze the four most recent power system events. Each record must include the current and voltage values (if applicable), the start times of the protection blocks, time stamps, etc. It must be possible to trigger the fault recording by the start signal or the trip signal of a protection block, or by both. The available measurement modes include DFT, RMS and peak-to-peak. In addition, the maximum demand current with time stamp should be separately recorded. By default, the records must be stored in a nonvolatile memory.
13 6.3 Disturbance records 13 (16) The relay must be provided with a disturbance recorder featuring up to 12 analog and 64 binary signal channels. From the analog channels it should be possible to record either the waveform or the trend of the currents and voltage measured. It must be possible to trigger the recording function by an analog channel when the measured value falls below or exceeds the set triggering value. The binary signal channels should be capable of starting a recording on the rising or the falling edge of the binary signal or on both. Binary relay signals such as a protection start or trip signal, or an external relay control signal over a binary input should be capable of triggering a recording. The recorded information must be stored in a non-volatile memory and be uploadable for subsequent fault analysis. 6.4 Time synchronization The relay should support the following time synchronization methods with a timestamping resolution of 1 ms. SNTP (Simple Network Time Protocol) IRIG-B (Inter-Range Instrumentation Group - Time Code Format B) 7 Condition monitoring The condition monitoring functions of the device must constantly monitor the performance and the condition of the circuit breaker. When specified the monitoring should at least cover the spring charging time, SF 6 gas pressure, the travel-time and the inactivity time of the circuit breaker. 7.1 Self supervision The device built-in self-supervision system must continuously monitor the state of the relay hardware and the operation of the relay software. Any fault or malfunction detected must be used for alerting the operator. A permanent device fault must block the protection functions of the relay to prevent incorrect operation.
14 8 Communication interfaces 14 (16) The relay shall be of native IEC design, thus offering optimal connection interface to a substation automation systems based on the standard. The physical communication connection shall be based on an Ethernet bus either with galvanic 100BaseTX (RJ45) interface or optical 100BaseFX (LC) interface. For increasing station bus communication availability and reliability, the relay shall have support for Ethernet redundancy. At minimum, support for RSTP (Rapid Spanning Tree Protocol) redundancy shall be available, but more preferably HSR (High-availability Seamless Redundancy) or PRP (Parallel Redundancy Protocol) shall be supported. Other communication possibilities shall cover Modbus over WAN and Modbus serial. On the front side of the relay there shall be a local communication interface with an RJ45 connector. This connection shall be dedicated for the protection relay local user interface, allowing parameterization, disturbance recorder upload, etc using software tools. 8.1 IEC GOOSE messaging In applications where the IEC protocol is used for horizontal level communication, the relays must be capable of utilizing GOOSE-messages, as described in the IEC standard. The GOOSE-message presentation and mapping shall be carried out in the relay in a user friendly way, exposing the GOOSE incoming and outgoing signals to a very similar manner as the physical binary inputs and outputs. The GOOSE signal performance has to be in accordance with type 1A and fulfill the requirements of class P User authorization The relay shall support user authorization at least on four different levels. The authorization within the different levels shall start from basic viewer only functionality, ending with the highest authorization level having all rights, including password management. There shall be settable separate passwords for each user level. The password shall be different for local and remote access. 9 Setting and configuration software All necessary setting and configuration software, including cables, must be included. The software must be delivered together with the protection relays.
15 15 (16) 10 Environmental conditions The relay must fulfill the environmental conditions listed below. Description Operating temperature range Short-time service temperature range Relative humidity Value ºC (continuous) ºC (<16h) <93%, non-condensing Electromagnetic compatibility tests The EMC immunity test level meets the requirements listed below: Description Value 1 MHz burst disturbance test, class III: According to IEC and IEC , level 3 Electromagnetic compatibility tests Fast transient disturbance tests: All ports According to IEC and IEC , class A 4 kv Mechanical tests Description Value Vibration tests (sinusoidal) According to IEC , class 2 Shock and bump test According to IEC , class 2 11 Quality assurance and standards The provider of the device must have a quality system in place, which aims at securing a high quality of the manufactured device. The product has to comply with RoHS directive 2002/95/EC.
TRACTION NETWORK MONITORING AND PROTECTION SYSTEM SMTN-3 CITY ELECTRIC TRANSPORT RAILWAYS METRO INDUSTRY 2 TRACTION NETWORK MONITORING AND PROTECTION SYSTEM Traction network monitoring and protection system,
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Generator Differential Relay Electrical Apparatus MD3G Rotating Machine Differential Relay 150-3 The MD3G Rotating Machine Differential Relay is a member of Cooper Power Systems Edison line of microprocessor
VECTOR NETWORK ANALYZER PLANAR TR1300/1 DATA SHEET Frequency range: 300 khz to 1.3 GHz Measured parameters: S11, S21 Dynamic range of transmission measurement magnitude: 130 db Measurement time per point:
HELLENIC ELECTRICITY DISTRIBUTION NETWORK OPERATOR S.A. NOTICE OF CALL FOR TENDERS No ND-xxx PROJECT: Pilot Telemetering and Management System for the Electric Power Supply Demand by Residential and Small
96-01101 / rev. 2e / 2-2-12 Uninterruptible Power Supply EXCEPTIONAL SUPPORT & PROTECTION Uninterruptible Power Supply with Energy Saver design that is optimized to address the needs of A/V systems Features