Introduction To Protective Relays

Introduction To Protective Relays
This training is applicable to protective relaying and System Monitoring tasks associated with NERC Standards PRC-001 and TOP-006

Learning Objectives Upon completion of the training, the participant will be able to: Recognize the importance of batteries in protective relaying. Identify the 3 basic purposes of protective relays Differentiate between Primary and Backup relaying. Distinguish what determines the zones of protection verses tripping zones. NERC’s definition of a Protection System includes the station batteries and the battery charger. So a complete discussion on Protective Relaying must include the importance of that DC system.

Applicable NERC Standards
PRC-001 System Protection Coordination R1. Each Transmission Operator, Balancing Authority, and Generator Operator shall be familiar with the purpose and limitations of protection system schemes applied in its area. TOP-006 Monitoring System Conditions R3. Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall provide appropriate technical information concerning protective relays to their operating personnel. Why is Protective Relaying being presented on a routine basis? NERC Standards require it. (Standards mandatory since 6/18/2007) On Certification exams, 5 questions on the RC and 5 questions on the TO are in the Protection and Control category. More emphasis on Transmission Operator needing to know relaying concepts. Click 1:PRC-001 and TOP-006 directly apply to Transmission Operator. Click 2: PRC-001 …… Read R1 emphasizing Purpose and Limitations TOP-006 …… Read R3 emphasizing Technical Information PRC-004 is guidance e for mis-operations; and PRC-005 outlines requirements for Relay testing Although Dispatchers/Operators do not analyze misoperations or do relay testing, we are involved in such that we must give permission to cut relays out for this testing.

Station Battery Loss of AC to Battery Charger Low Battery Voltage
NERC’s definition of a Protection System includes: Station dc supply associated with protective functions (including batteries, chargers, and non-battery based dc supply) NERC realizes that the station batteries are an important part of system protection; & has included batteries as part of their definition of a Protection System. The P&C schemes require a dependable source of power in order for them to be functional at all times. The DC system, or station battery, provides this source, and is literally the foundation for all P&C schemes. Since batteries are so critical in the protection system, most stations have the alarms shown. Review each alarm Loss of AC - battery begins to drain due to constant load Low Battery Voltage – At some point the voltage will fall below what is needed to operate equipment. Loss of DC – May have alarms on individual circuits. Associated Alarms Loss of AC to Battery Charger Low Battery Voltage Loss of DC

Battery Chargers Convert an AC source to DC, and maintain adequate charge on the batteries. Do NOT have the capacity to carry the full station DC load. Shown here is just one of numerous types of battery chargers installed. The charger information is usually shown on the station one-line diagram. Regardless of the type, the purpose of a charger is to convert the AC source to DC to maintain adequate charge on the batteries, so we always have a reliable source to operate equipment when needed. They all have means to read the DC Voltage and DC amps. All batteries have a constant drain on them from the DC lights and coils that are continuously energized. The current seen on the battery charger is the constant drain that the batteries are supplying to this constant load. As equipment operates (like a motorized switch or CB), this takes even more energy from the battery that must be replenished. It is important to understand that the Battery Charger cannot supply the full station DC load. It is the Battery that supplies the station DC load. The Charger is simply supplying constant charging current to keep the batteries fully charged.

Protective Relay Principles
Cannot prevent faults Proactive – pilot wire relays; temperature relays Reactive – relays that initiate action after fault occurs Use inputs from Monitoring devices Current, Voltage, Temperature, Pressure Initiates corrective action as needed to remove fault Minimize Damage from the fault by quick interruption The quicker the fault is removed, the less damage. Isolate Only the Faulted Area (Zone). Maintain Service to Other Areas (Zones) During and/or after Isolation of the Fault. BEFORE FIRST CLICK Relays cannot PREVENT faults from occurring. They can’t prevent a lightning strike, or a tree falling on a circuit. Some relays can be considered Proactive. Pilot wire alarm relays alert us when the pilot wires are shorted or open, allowing preventative measures to be taken before a misoperation occurs. Temperature relays can turn on fans to a Transformer before winding get too hot. Protective relays are Reactive. They respond after current or voltage gets above their trip level. Click 1: A protective relay will use inputs from monitoring devices, and at preset levels, take corrective actions to remove the fault from the system. Removing faults from the system is the main goal of protective relays, but they should do so such that: Click 2: Minimize Damage – Desire to interrupt Transf fault before it ruptures. Isolate Only Faulted area – Trip only what is needed to interrupt the fault current, then restore as much of the system as possible, so that only the faulted area remains isolated. This is where Reclosing relays come into play in a protection system.

Protective Relay Principles
Designed & utilized to protect against Faults, not overloads. Settings determined with system normal During System Restoration / Islanding events May not have enough fault current available to reach trip values. Have Switching Personnel monitor ammeters when closing devices. When closing by supervisory control, monitor ammeters on SCADA. Protective Relays on the transmission system, with few exceptions, are set well above equipment ratings. They are set for Fault current, not overloads. Ask who is responsible to protect lines/equipment from overloads. ANSWER: The Dispatcher, by doing what NERC requires of the Transmission Operator in Standard TOP that is to MONITOR the system. Click 1: It is also important to understand that the Relay settings are determined with System normal conditions. When you are restoring a system from a Blackout; or an islanding event, Due to the increase in SHORT CIRCUIT REACTANCE of the weakened system, it is unlikely that available fault current will be as high as when the system is normal. So you could close a CB into a fault, and the CB will not trip. When energizing circuits and equipment in these conditions, it is even more important to remind the switchperson to observe ammeters when closing. He may be able to detect that one phase is much higher than the other two. If using supervisory control, observe the ammeter readings on SCADA.

G4 G2 G3 G5 30Ω 70Ω 10Ω 25Ω Fault Current 25,000 Amps G6 30Ω 40Ω G1
20Ω Reduced available fault current during blackouts can affect relay operation G5 G4 G2 G3 G1 G6 30Ω 10Ω 70Ω 40Ω 20Ω 25Ω Black Start With system near normal, generators over the entire interconnection are a source for fault current. Click 1: Therefore, when a fault occurs, there is a large amount of fault current available (shown here to be 25,000 amps); and the relays are set for this normal or near normal condition. The fault detector may be set for 5000 amps. Click 2: When we have a blackout, and we are building cranking paths to other generating stations, we don’t have all those sources. In the lower diagram, we show the Gen 1 as the Black Start unit. Click 3: If you close into a fault while trying to get coping power to Units 2 and 3, Generator 1 is the only source you have, and there may be only 2000 amps of fault current. The fault detectors may be set much higher than the 2000 amps, and the circuit may not trip. During restoration, continue to follow the practice of having the switchperson to observe the ammeters when closing the CB (or observe via SCADA). If two phases are reading very low, while the third phase is very high, there is possibly of a fault on the circuit. Fault Current 2,000 Amps

Network verses Radial Radial Network
One source - fault interrupting devices are in series with lateral feeds to customers. Distribution Circuits are typically radial. Network Dual or Multiple Sources The Transmission system is largely a Transmission Network. Relay coordination becomes more complicated and more expensive. Magnitude of current and Time Delay Direction of current Communication channels C O O R D I N A T I O N is much more complicated with network circuits and circuits at higher voltages. Review bullets listed

Primary verses Backup Relays
Primary relays are normally expected to operate first and trip breakers when faults occur within the zone they protect. Instantaneous on Transmission and EHV circuits Subtransmission may or may not be instantaneous Depending on relaying used and location of fault Backup relays operate to clear around a CB that fails to interrupt a fault within a specific time period. Local Backup (7 – 15 cycles) Breaker Failure or Transfer Trip relays at the local station Remote Backup (20 – 30 cycles) Time Delay or Zone 2 relays at remote stations Primary relays are the ones that should operate to clear the fault in the zone of protection they are set for. Click 1: Should the primary relays fail, (which happens sometimes), then the BACKUP relays will clear the fault. BACKUP relays can be REMOTE or LOCAL. LOCAL means that the trip for the backup devices is initiated at the station where the primary relaying failed to cleared the fault. So LOCAL backup relaying includes Breaker Failure relays where we can trip other CBs at the LOCAL station, and Transfer Trip relaying where we can send the trip signal to a remote station. Remote BACKUP relaying is simply allowing the coordination of the Directional relays to trip CBs at the remote terminal. This is much slower than LOCAL backup. A major drawback to BACKUP relays is that you are removing a larger portion of the system than is necessary to clear the fault. So the Primary and Backup relays must be coordinated so the Backup relays operate ONLY when necessary.

Zones of Protection Defined by Current Transformers (CTs) that sense current flow into the zone. Each zone will have unique targets All primary equipment is included in at least one zone of protection. Overlapping ensures no equipment is left unprotected. Very important principle for dispatchers/operators to understand Zones of protection are defined by the CTs that will “see” the fault current going into the protected zone. Each zone will have its own target (s). Being able to analyze which zone the fault was in, and comparing that with the targets that were reported, is the means that a Dispatcher uses to determine whether a mis-operation has occurred. If you have a bus to lock out, but only line targets, something didn’t operate correctly. All primary equipment is included in at least one zone of protection, which makes it necessary to overlap the zones, which can easily be seen when a CB is involved. Click 1: The zone of protection for the Elm-Oak Circuit uses the CTs on the bus side of CB C and CB D. Therefore both CBs are included in that zone. Click 2: The zone of protection for the bus at Elm uses the CTs on the line side of CBs B and C. CBs B & C are therefore included in the bus zone. Because the two zones overlap, a fault inside CB C is included in two zones of protection: 1 – The Elm-Oak circuit -and- 2 – The bus at Elm A B C D R Elm Ash Oak

Various Zones of Protection
Overlapping occurs even when a CB is not present. Transmission bushing has 2 CTs Zones boundaries are where you would expect to see a bushing. Diagram shows various Zones of Protection. Point out various zones Internal diff at Station B, and overall diff at Station C. Circuit with tap station, point out where ground sw will be. Bus Diffs at Station A and Station C All the zones are defined at places where you would expect to see a bushing At CBs High and low sides of Transformers The zones overlap even where there is no CB. To see how this is possible, we can look at the Transformer bushing of the 138/12kV Transf. Click 1: Notice that there are two CTs at the base of the bushing, each with a set of leads connected to a junction terminal. Click 2: The CT at the top is used to sense current going through the CB or the Transformer winding. Click 3: The CT at the bottom is used to sense current going back up through the bushing toward the bus.

LOR Tripped By Numerous Relays
Transformer and Bus differential zones shown. Both zones will still trip the same LOR. LOR trips Distribution CBs, Swr XT1 and MOAB X1 R LOR R Fault in Bus Zone of Protection Bus Targets and LOR R Fault in Transformer Zone of Protection Transformer Targets and LOR Normally more than one relay can trip a Lockout relay. Therefore, when a Lockout Relay target is reported, it is important to also obtain the target of the relay that tripped the Lockout Relay, so you will know which zone to look for the trouble. In addition to the transformer zone and the bus zone shown, on a typical distibution station, there are time and instantaneous high side overcurrents, and low side ground overcurrents that will trip the Lockout Relay. Regardless of what tripped the Lockout relay, the Lockout relay will trip the same devices; i.e. the distribution CBs, the Switcher XT1 and the motorized switch X1. Click 1: For a fault within the Bus zone of protection, there should be bus targets and the LOR Click 2: For a fault within the Transformer zone of protection, there should be transformer targets and the LOR Click 3: For a fault within the Transmission circuit zone of protection, there should line targets. Nothing at the station will trip. Transmission circuit zone of protection includes the surge arresters. Fault in Trans Circuit Zone of Protection (Includes Transformer Surge Arresters ) Line Targets R R

Potential Sources for Relays
Some relays require a voltage/potential input in addition to the current input, to monitor the zone determined by the associated CTs. Do NOT define the zone of protection Should be attached close to equipment they protect Sources of Relay Potential Potential Transformer (PT) – Most accurate Coupling Capacitor Potential Device (CCPD) Coupling Capacitor Voltage Transformer (CCVT) Resistive Potential Device Many relays use potential instead of, or in addition to, current to function properly. The most accurate of the types of potential sources we use is the Potential Transformer. With this accuracy comes cost, and therefore other devices are used where high accuracy is not needed. We will look at each of these types. Resistive pot. Devices are generally used in neutrals of Capacitors; and we will look at this later. Although the PTs don’t define the zone of protection, their location should be as close as possible to the equipment they protect. If protecting a 138kV circuit, the potential should be from the 138kV bus potential device, not from a 12kV bus potential device. Module 409 has information on PTs and CTs. WHAT QUESTIONS DO YOU HAVE

Fundamentals of Relay Protection Potential for Relaying (cont.)
Coupling Capacitor Potential Device. (CCPD) Coupling Capacitor Voltage Transformer (CCVT) Uses a series capacitor voltage divider principle. Typically used for relay potential 138 kV and above. CCVT is more accurate and has more capacity. CCVTs and CCPDs operate on the same principle of capacitive voltage divider. The CCVTs are more accurate and have more capacity. CCVTs can have Relay Accuracy (0.6%) or Metering Accuracy (0.15 – 0.30%) Higher accuracy equates to higher cost. Therefore, unless a CCVT is needed for inter- or intra-change, CCVTs are purchased with Relay Accuracy.

Fundamentals of Relay Protection Potential for Relaying (cont.)
Cascading of Capacitor cans All cans intact, each group has same impedance and voltage divides equally. If one can fails in a group, the impedance of that group increases. That group then has more of the voltage. More stress on cans in the group. As other cans fail, more voltage (and more stress) is on cans in the group, and cascading can occur. RELAY Another use of a potential device in in the neutral of capacitor banks to prevent cascading failure of the capacitor cans. Capacitors are made up with groups of smaller capacitors. Groups are in series with each other. As long as all capacitors are intact, each group has the same impedance and the voltage drop on each group is the same. In addition, as long as all cans are intact, there is no imbalance to cause current in the neutral. The more cans fail, the greater the neutral current. According to Ohms Law, when you have current through a resistance, you have voltage. The greater the current the greater the voltage. This voltage can be monitored to detect when there is enough of an imbalance to cause cascading failure of the capacitor bank, and used to trip the LOR of the capacitor bank. Click 1: Each time a can fails, the impedance of that group (or parallel branch) increases. That group then has more of the voltage (and more stress) which soon will lead to other cans failing. Click 2: If another can fails, the impedance of that group (or parallel branch) increases again, putting even more stress on that group. If left unchecked, cascading will likely occur. So these relays are set so that a small unbalance (such as one or two cans in a phase failing), will cause enough voltage to produce an alarm. Then if the unbalance increases to the next level, (indicating even more cans have failed), then the capacitor is tripped off line to prevent cascading failure of the cans. RPD

Overcurrent Relays Can be Instantaneous (50) or time-delayed (51)
Can be non-directional or directional. Non-directional used on radial circuits Directional used on Network circuits Ground Relay Sees only imbalance current. Usually set lower than phase relay Ground target only on some faults Phase relays Phase relays must be set above load current. Use Undervoltage scheme where load approaches available fault current Φ G Phase Relays Ground Relay A B C CB Fault Overcurrent relays operate after their setting has been reached, either instantaneously or after a time-delay. The Inst and Time relays can be in one relay, or in separate relays. The can be Directional or non-directional.

Undervoltage/OverCurrent Scheme
A special scheme in which the over-current relays can’t operate unless low voltage indicates a fault. The Voltage Relay keeps the over-current relay coils shorted for normal voltage Removes the short to place the over-current relay coils in service when voltage is depressed due to fault conditions. Cheaper than adding Electro-Mechanical impedance relay Trip Coil Tripping Relay Relay Coil UV Relay Some long circuits, the available fault current is limited by impedance, & load current can approach the available fault current. Since overcurrent relays can’t be set above the available fault current, an undervoltage scheme was added. We don’t want these circuit tripping on load only. An Undervoltage/Over-current scheme was designed in these cases to prevent tripping when no fault is present. Click 1: With normal load, the source bus voltage will remain relatively close to normal. Threfore the voltage relay will keep the over-current relay bypassed or shorted when voltage is ABOVE a preset level. Click 2: However, under fault conditions, the bus voltage drops considerably. The undervoltage relay drops out. This removes the short on the relay coil. The secondary CT current now flows through the relay coil, which picks up the Trip contact which energizes the CB trip coil. So in this scheme, the current must be above the pickup of the relay, and voltage must be below the preset limit before trip occurs; saving the expense of installing impedance relays. This scheme was cheaper than adding an impedance relay in the E-M world.

Instantaneous Clearing of Fault Only in Middle 80%
Fault between Breaker “A” and point “X” INST target at Breaker “A” and Time target at “B” Fault between points “A” & “B” Fault X A C B INST TOC Fault A C B INST TOC X Y Looking at the Instantaneous zones from both terminals of a circuit that uses Overcurrent relays for protection, you can see that only when the fault is in the middle 80 percent will the fault be cleared from the system instantaneously. In the upper diagram, even though CB A will open instantaneously, the system is still feeding the fault until CB “B” opens after a time delay. In the lower diagram, both CBs will trip instantaneously WHAT QUESTIONS DO YOU HAVE ON OVERCURRENT RELAYS?

Differential Relaying
Operate when the power into a protected zone does NOT equal the power out of the protected zone. Basically - CTs algebraically add for paths into and out-of the zone to cancel at the relay operate coil. The differential relay is preset to operate instantaneously when the difference that is seen by the relay exceeds its trip setting. Bus Zones (87B) Transformer Zones (87T) Generator Zones (87G) Diff relays are based on the concept that you should be able to account for all the power that is going into a zone; i.e. the power going into the zone EQUALS the power leaving the zone, after you account for normal losses and inaccuracies. If not, there is a fault inside that zone. Electrically, the secondary currents of the CTs that monitor the zone will flow through the CTs only, and will sum to zero at the Operate coil when current in equals current out. When current in does not equal current out, current will flow through the Operate coil. When the current flowing through the Operate coil exceeds the trip setting, then the relay trips instantaneously. There are several zones that the Differential relay can be applied to. Three of the more common applications are with Buses, Transformers and Generators.

Differential Relaying – External Fault
Current into the Zone equals the current leaving the Zone Secondary current sums to zero at the operate coil Fault 1200A 1200A BUS 600/5 600/5 A B 10A 10A Here we show an EXTERNAL fault. Even though there is a large amount of current flowing, the current in the differential zone equals the current leaving the zone, therefore the Differential Relay does not call for a trip. There is not current flowing through the operate coil. 0A 87B

Differential Relaying – Internal Fault
Current into the zone does not equal the current leaving the zone Secondary current combines and goes through the operate coil of the relay Fault 1200A BUS 1200A 600/5 600/5 A B 10A 10A However, for and INTERNAL fault, the secondary currents add and go through the operate coil. The Diff relay will close its tripping contact instantaneously and trip the Lockout Relay. This same analogy can be applied to transformer differential relays. However, since the voltage transformation causes an opposite transformation of current, the CTs on each side of the transformer would have be be different ratios. 20A 87B

Differential Relays Trip Lockout Relays
The 87T trips the lockout relay which in turn trips the associated breakers. 87T A B 138 kV 69 kV 1200/5 600/5 600A 1200A 5A 10A Fault 86T/ 87XT Shown here is a transformer differential, and you can see the CT ratios are different to match the secondary currents. The Differential Relay trips the Lockout Relay which trips the devices necessary to clear the fault.

Lockout Relays When reset, burning light monitors the trip coil
Older LORs, the light was wired separately from the relay When tripped, the light will go off, and a target flag will show The second light will burn when a relay is sending trip to the Lockout Relay Older LORs do not have the Standing Trip light Standing Trip Trip Ckt OK Tripped Position Reset Position The Trip Circuit OK light on the Left is built into the relay, functions same as the external light on the older relays. Click 1: This light will go out when the relay trips. Light on the right indicates a relay is still sending a trip signal to the LOR. Normally the trip signal is removed soon after trip of the CBs. Click 2: But should something hold trip on the LOR, the light on the right will burn. If the switch-person reports this light burning, do not ask for the LOR to be reset. Have relay personnel check where the trip signal is coming from.

Lockout Relays Never hold lockout relay in reset position; or try to reset if standing trip light is on Coil Contact Latch Trip Contacts The LOR is a dumb relay, meaning that it does not know when to trip. Some other relay must tell it to trip. Therefore when you have an LOR relay reported to you, you should also get the number of the relay device that tripped the LOR. But once another relay tells it to trip, the multiple tripping contacts clean house. There are NO and NC contacts that change status when the relay is tripped. There are 5 trip contacts in the relay. (the 5 NO contacts in the front) The relay is held in the RESET position by a latch. When the relay coil is energized, it raises the latch allowing the armature to rotate. This closes the NO trip contacts and opens the NC contacts. One of the NC contacts which opens removes the voltage from the trip coil. The voltage applied to the trip coil is about double the rating of the coil. A lower voltage coil is used so that the coil will trip even if the battery voltage has reduced to half-voltage. During relay tests, one test is applying half voltage to trip the relay. Click 1: With the coil being designed for intermittent use, if a Lockout relay is manually held in the reset position with another relay holding trip, it will fairly quickly burn up the trip coil. Sometimes there are so many devices that need tripping that more than 5 contacts are needed. WHAT QUESTIONS DO YOU HAVE on LORs Coil Trip Contacts

Impedance (Distance) Relays
Subtransmission circuits have high impedances Instantaneous overcurrent relays can be set for proper coordination. Impedances of circuits operated at 138kV and above are much lower Coordination with overcurrent relays is more difficult Impedance (Distance) relays use the secondary current and secondary voltage during a fault to calculate the impedance to the fault. Since the impedance per mile of the circuit is known, the impedance to the fault can be used to estimate the distance to the fault. If impedance to the fault is within the Zone 1 setting, an instantaneous trip occurs. Circuit impedances at the subtransmission levels reduced the available fault current to a level that coordination is possible using overcurrent relays. Due to the low impedances of transmission circuits, the available fault current between the buses are so close that coordination for faults is nearly impossible using overcurrent relays. Typical % Impedance per mile 345kV 0.06 46kV 138kV 0.4 34.5kV 6.0 69kV 1.6 23kV 13.0

Zone 1 is instantaneous Typical setting is 80-90% Zone 2 has up to a 40-cycle delay Typical setting is % Zone 3 has up to a 90-cycle delay Typical setting is 200% Zone 3 21 D C A B 50 miles 75 miles F E 25 miles H G Zone 2 150% Zone 1 90% Impedance relays are set in percentage of the total impedance of the circuit. Zone 1 is instantaneous, and is typically set 80-90%. They don’t set above 90% to ensure that the instantaneous setting does not reach beyond the end of the circuit. CLICK 1 Zone 2 reaches up to 150%, but it has a delay of up to 30 cycles before trip occurs. This delay gives time for the instantaneous relays of adjacent circuits to clear faults. Zone 2 may be NORMAL if an impedance relay is the primary protection for a circuit, such as would be the case on subtransmission circuits. If the fault is in the 10% of the circuit closer to CB “B”, then CB “A” would have a Zone 2 target, and that would be normal. CLICK 2 Because Zone 3 reaches up to 200% and has a time delay of up to 60 cycles, a Zone 3 target means you’ve had a fault not cleared by primary relaying somewhere. Zone 3 targets should be reported to P&C for investigation. Zones 2 & 3 are also REMOTE BACKUPs for faults on the adjacent circuits

Instantaneous clearing only in middle 80% of circuit Zone 2 A 21 B C Zone 1 80% Source Z2 Z1 Zone 2 Although the impedance relay is an improvement over the overcurrent relay, the shortcoming of not providing instantaneous tripping for 100% of the circuit still exists. In the top diagram, even though CB “A” opens instantaneously, the system is still feeding the fault because the trip of CB “B” is delayed by up to 30 cycles. In the bottom diagram, since the fault is in Zone 1 of both CBs, the fault is cleared instantaneously from the system. It is desirable to have instantaneous protection on 100% of the circuit when operated at 138kV or above. WHAT QUESTIONS DO YOU HAVE about Impedance relays Zone 1 Z1 21 Source 80% Source A B C 21 Z1 Zone 1 Zone 2

Directional Comparison Carrier Blocking
Impedance relays (Z1, Z2, Z3) remain in service, and function as Backup Relays The Directional Comparison Carrier Blocking scheme uses a Zone-3 impedance relay with no time delay Communication channel used only to transmit a blocking signal for external faults Relays of CB B will send blocking signal to prevent CB A from tripping for a fault on circuit C - D. Z-3 Instantaneous D A B C 21A 21B E Discuss bullets and diagram on slide Keep in mind the diagram depicts only the carrier blocking relays. The Z1-Z2-Z3 impedance relays are still present and will serve as backup relays.

When fault current is detected A blocking signal is transmitted ONLY for external faults No signal is transmitted for internal faults Trip occurs when a fault is detected and no blocking signal is received. Wave Traps Forward looking tripping element Discuss bullets and diagram on slide Reverse looking Carrier Start element

Multiple circuits (Fault on G-H) Carrier Relays for CBs _________________see fault into the circuit; and therefore will not transmit Carrier Relays for CBs _______________ see fault into the bus; and therefore will transmit CBs G and H trip because their respective relays see fault current into the circuit and no blocking signal was received. A, D, E, G, H B, C, F A B D C F E H G Discuss points on the slide. Answers to first blank will appear before the second red bullet appears. Answers to second blank will appear before the Third red bullet appears. Answers to both blanks will be covered up on next click after the third red bullet. WHAT QUESTIONS DO YOU HAVE ON DIRECTIONAL COMPARISON CARRIER BLOCKING

Phase Comparison Phase comparison systems use only current for fault location (i.e. internal or external) Very desirable on lines with variable impedance, such as a line with switched series capacitor or series reactor compensation. Upon fault detection, the comparer logic relay compares the current at each terminal. If the phase angle and magnitude are within a preset comparison window, no tripping will occur. If the angle reverses at either end (signifying a 180o power reversal, (which is indicative of an internal fault), the comparer will initiate trip of the breaker. Discuss points on the slide.

Phase Comparison External Fault
The over-current fault detector relays see fault current but neither comparer sees a difference in phase angle. No trip occurs for Breakers 1 or 2 Discuss points on the slide.

Phase Comparison Internal Fault
The over-current fault detector relays see fault current. Comparers see a 180o difference in phase angles. Trip occurs for Breakers 1 & 2 Discuss points on the slide. WHAT QUESTIONS DO YOU HAVE ON PHASE COMPARISON

Transfer Trip Schemes Direct Transfer Trip (DTT)
Also used for Breaker failure to trip remote breakers, lines terminated by transformers, and with shunt reactors. Direct Under-reach Transfer Trip (DUTT) Permissive Under-Reach Transfer Trip (PUTT) Permissive Over-Reach Transfer Trip (POTT) Most common TT scheme used for line protection Guard signal is transmitted constantly to check integrity of the Transfer Trip Channel. When a trip signal is needed, the signal is shifted from the Guard frequency to the Trip frequency. Used as backup to the two redundant primary relays on EHV We will look at the Transfer trip schemes used for line protection. Discuss the bullets. Primary 1 is the GE package Primary 2 is the SEL package

Direct Under-Reach Transfer Trip
When under-reaching Zone 1 element detects a fault: Trips local CB instantaneously, and Sends Direct Transfer Trip signal to trip remote CBs Upon receipt of Direct Transfer Trip signal, CBs trip instantaneously with no other condition necessary Transfer trip signal important when fault is beyond Z1 For fault shown on diagram, relays at CB 1 do not see a Zone 1 fault, and therefore will not trip CB 1 instantaneously. CLICK 1: When fault is beyond reach of Zone 1, as shown in the diagram, the transfer trip signal becomes very important for instantaneous clearing of the fault. As shown in the diagram, the relays of CB 1 don’t see a Zone 1 fault, and would trip by a time delay if it were not for the transfer trip signal from the opposite terminal. Relays at CB 2 see a zone 1 fault, which trips CB 2 instantaneously, and also send the Direct Transfer trip signal to trip CB 1 instantaneously. WHAT QUESTIONS DO YOU HAVE ON DIRECT TRANSFER TRIP Z1 TTR

Permissive Under-reach Transfer Trip
When under-reaching Zone 1 element detects a fault: Trips local CBs instantaneously, and Sends permissive Transfer Trip signal to relays at remote terminal. If relays at remote terminal see only a Zone 2 fault: The permissive signal will bypass the time delay and allow the CBs at the remote terminal to trip instantaneously. For faults in the middle 80% CBs at both terminals will trip instantaneously by Zone 1 Will also receive TT signal For faults beyond Zone 1 reach of one terminal Permissive Transfer Trip signal becomes very important The PERMISSIVE UNDER-REACH transfer trip scheme has both a Zone 1 instantaneous element and a time-delay Zone 2 element. Discuss the points listed.

For a fault close to CB 2 Permissive Transfer Trip will set up instantaneous tripping of CB 1 Z2 TTR Z1 In this example, there is a fault near CB 2 which is beyond the Zone 1 reach of the relays for CB 1. CLICK 1: Therefore the under-reaching Zone 2 element will trip by a time delay if it doesn’t receive the permissive Transfer Trip signal from the opposite terminal. CLICK 2: The relays at CB 2 see a Zone 1 fault and will trip the CB instantaneously and send the permissive Transfer Trip signal over to the relays at CB 1. CLICK 3: The Transfer Trip signal will bypass the time delay of the Zone 2 relays, allowing CB 1 to trip instantaneously. CLICK 4: Targets will be TTR and Z2 at CB 1; and Z1 at CB 2

Permissive Over-reach Transfer Trip
More common as line protection scheme than other TT schemes. If the overreaching Distance Relay sees a fault, a permissive TT signal is sent to the other end. To trip instantaneously: The overreaching Distance Relay must see a fault, and Receive a permissive transfer trip signal from the opposite terminal. The permission OVER-REACH Transfer Trip Scheme is the more common of the TT schemes used for line protection. Review the bullets.

For a fault at any point on the circuit Fault is seen by over-reaching element at both terminals Both terminals receive the permissive signal Both terminals trip instantaneously Over-Reach Zone of CB 1 Over-Reach Zone of CB 2 Distance Relay Review the first bullet. CLICK 1: First red bullet appears, along with the dashed arrows toward transmitters. Review the bullet CLICK 2: The second red bullet appears, along with the Transfer Trip arrows toward the receivers. CLICK 3: Third red bullet appears, along with the solid arrows from the receivers to the CBs. WHAT QUESTIONS DO YOU HAVE ON TRANFER TRIP SCHEMES Distance Relay

Subtransmission circuits have high impedances Instantaneous overcurrent relays can be set for proper coordination. Impedances of circuits operated at 138kV and above are much lower Coordination with overcurrent relays is more difficult Impedance (Distance) relays use the secondary current and secondary voltage during a fault to calculate the impedance to the fault. Since the impedance per mile of the circuit is known, the impedance to the fault can be used to estimate the distance to the fault. If impedance to the fault is within the Zone 1 setting, an instantaneous trip occurs. Circuit impedances at the subtransmission levels reduced the available fault current to a level that coordination is possible using overcurrent relays. Due to the low impedances of transmission circuits, the available fault current between the buses are so close that coordination for faults is nearly impossible using overcurrent relays. Typical % Impedance per mile 345kV 0.06 46kV 138kV 0.4 34.5kV 6.0 69kV 1.6 23kV 13.0

Zone 1 is instantaneous Typical setting is 80-90% Zone 2 has up to a 40-cycle delay Typical setting is % Zone 3 has up to a 90-cycle delay Typical setting is 200% Zone 3 21 D C A B 50 miles 75 miles F E 25 miles H G Zone 2 150% Zone 1 90% Impedance relays are set in percentage of the total impedance of the circuit. Zone 1 is instantaneous, and is typically set 80-90%. They don’t set above 90% to ensure that the instantaneous setting does not reach beyond the end of the circuit. CLICK 1 Zone 2 reaches up to 150%, but it has a delay of up to 30 cycles before trip occurs. This delay gives time for the instantaneous relays of adjacent circuits to clear faults. Zone 2 may be NORMAL if an impedance relay is the primary protection for a circuit, such as would be the case on subtransmission circuits. If the fault is in the 10% of the circuit closer to CB “B”, then CB “A” would have a Zone 2 target, and that would be normal. CLICK 2 Because Zone 3 reaches up to 200% and has a time delay of up to 60 cycles, a Zone 3 target means you’ve had a fault not cleared by primary relaying somewhere. Zone 3 targets should be reported to P&C for investigation. Zones 2 & 3 are also REMOTE BACKUPs for faults on the adjacent circuits

Instantaneous clearing only in middle 80% of circuit Zone 2 A 21 B C Zone 1 80% Source Z2 Z1 Zone 2 Although the impedance relay is an improvement over the overcurrent relay, the shortcoming of not providing instantaneous tripping for 100% of the circuit still exists. In the top diagram, even though CB “A” opens instantaneously, the system is still feeding the fault because the trip of CB “B” is delayed by up to 30 cycles. In the bottom diagram, since the fault is in Zone 1 of both CBs, the fault is cleared instantaneously from the system. It is desirable to have instantaneous protection on 100% of the circuit when operated at 138kV or above. WHAT QUESTIONS DO YOU HAVE about Impedance relays Zone 1 Z1 21 Source 80% Source A B C 21 Z1 Zone 1 Zone 2

Impedance relays (Z1, Z2, Z3) remain in service, and function as Backup Relays The Directional Comparison Carrier Blocking scheme uses a Zone-3 impedance relay with no time delay Communication channel used only to transmit a blocking signal for external faults Relays of CB B will send blocking signal to prevent CB A from tripping for a fault on circuit C - D. Z-3 Instantaneous D A B C 21A 21B E Discuss bullets and diagram on slide Keep in mind the diagram depicts only the carrier blocking relays. The Z1-Z2-Z3 impedance relays are still present and will serve as backup relays.

When fault current is detected A blocking signal is transmitted ONLY for external faults No signal is transmitted for internal faults Trip occurs when a fault is detected and no blocking signal is received. Wave Traps Forward looking tripping element Discuss bullets and diagram on slide Reverse looking Carrier Start element

Multiple circuits (Fault on G-H) Carrier Relays for CBs _________________see fault into the circuit; and therefore will not transmit Carrier Relays for CBs _______________ see fault into the bus; and therefore will transmit CBs G and H trip because their respective relays see fault current into the circuit and no blocking signal was received. A, D, E, G, H B, C, F A B D C F E H G Discuss points on the slide. Answers to first blank will appear before the second red bullet appears. Answers to second blank will appear before the Third red bullet appears. Answers to both blanks will be covered up on next click after the third red bullet. WHAT QUESTIONS DO YOU HAVE ON DIRECTIONAL COMPARISON CARRIER BLOCKING

Phase Comparison Phase comparison systems use only current for fault location (i.e. internal or external) Very desirable on lines with variable impedance, such as a line with switched series capacitor or series reactor compensation. Upon fault detection, the comparer logic relay compares the current at each terminal. If the phase angle and magnitude are within a preset comparison window, no tripping will occur. If the angle reverses at either end (signifying a 180o power reversal, (which is indicative of an internal fault), the comparer will initiate trip of the breaker. Discuss points on the slide.

Phase Comparison External Fault
The over-current fault detector relays see fault current but neither comparer sees a difference in phase angle. No trip occurs for Breakers 1 or 2 Discuss points on the slide.

Phase Comparison Internal Fault
The over-current fault detector relays see fault current. Comparers see a 180o difference in phase angles. Trip occurs for Breakers 1 & 2 Discuss points on the slide. WHAT QUESTIONS DO YOU HAVE ON PHASE COMPARISON

Transfer Trip Schemes Direct Transfer Trip (DTT)
Also used for Breaker failure to trip remote breakers, lines terminated by transformers, and with shunt reactors. Direct Under-reach Transfer Trip (DUTT) Permissive Under-Reach Transfer Trip (PUTT) Permissive Over-Reach Transfer Trip (POTT) Most common TT scheme used for line protection Guard signal is transmitted constantly to check integrity of the Transfer Trip Channel. When a trip signal is needed, the signal is shifted from the Guard frequency to the Trip frequency. Used as backup to the two redundant primary relays on EHV We will look at the Transfer trip schemes used for line protection. Discuss the bullets. Primary 1 is the GE package Primary 2 is the SEL package

Direct Under-Reach Transfer Trip
When under-reaching Zone 1 element detects a fault: Trips local CB instantaneously, and Sends Direct Transfer Trip signal to trip remote CBs Upon receipt of Direct Transfer Trip signal, CBs trip instantaneously with no other condition necessary Transfer trip signal important when fault is beyond Z1 For fault shown on diagram, relays at CB 1 do not see a Zone 1 fault, and therefore will not trip CB 1 instantaneously. CLICK 1: When fault is beyond reach of Zone 1, as shown in the diagram, the transfer trip signal becomes very important for instantaneous clearing of the fault. As shown in the diagram, the relays of CB 1 don’t see a Zone 1 fault, and would trip by a time delay if it were not for the transfer trip signal from the opposite terminal. Relays at CB 2 see a zone 1 fault, which trips CB 2 instantaneously, and also send the Direct Transfer trip signal to trip CB 1 instantaneously. WHAT QUESTIONS DO YOU HAVE ON DIRECT TRANSFER TRIP Z1 TTR

When under-reaching Zone 1 element detects a fault: Trips local CBs instantaneously, and Sends permissive Transfer Trip signal to relays at remote terminal. If relays at remote terminal see only a Zone 2 fault: The permissive signal will bypass the time delay and allow the CBs at the remote terminal to trip instantaneously. For faults in the middle 80% CBs at both terminals will trip instantaneously by Zone 1 Will also receive TT signal For faults beyond Zone 1 reach of one terminal Permissive Transfer Trip signal becomes very important The PERMISSIVE UNDER-REACH transfer trip scheme has both a Zone 1 instantaneous element and a time-delay Zone 2 element. Discuss the points listed.

For a fault close to CB 2 Permissive Transfer Trip will set up instantaneous tripping of CB 1 Z2 TTR Z1 In this example, there is a fault near CB 2 which is beyond the Zone 1 reach of the relays for CB 1. CLICK 1: Therefore the under-reaching Zone 2 element will trip by a time delay if it doesn’t receive the permissive Transfer Trip signal from the opposite terminal. CLICK 2: The relays at CB 2 see a Zone 1 fault and will trip the CB instantaneously and send the permissive Transfer Trip signal over to the relays at CB 1. CLICK 3: The Transfer Trip signal will bypass the time delay of the Zone 2 relays, allowing CB 1 to trip instantaneously. CLICK 4: Targets will be TTR and Z2 at CB 1; and Z1 at CB 2

More common as line protection scheme than other TT schemes. If the overreaching Distance Relay sees a fault, a permissive TT signal is sent to the other end. To trip instantaneously: The overreaching Distance Relay must see a fault, and Receive a permissive transfer trip signal from the opposite terminal. The permission OVER-REACH Transfer Trip Scheme is the more common of the TT schemes used for line protection. Review the bullets.

For a fault at any point on the circuit Fault is seen by over-reaching element at both terminals Both terminals receive the permissive signal Both terminals trip instantaneously Over-Reach Zone of CB 1 Over-Reach Zone of CB 2 Distance Relay Review the first bullet. CLICK 1: First red bullet appears, along with the dashed arrows toward transmitters. Review the bullet CLICK 2: The second red bullet appears, along with the Transfer Trip arrows toward the receivers. CLICK 3: Third red bullet appears, along with the solid arrows from the receivers to the CBs. WHAT QUESTIONS DO YOU HAVE ON TRANFER TRIP SCHEMES Distance Relay

Zone Designation Comparison
GE and SEL both use Zone 2 to designate the Pilot tripping zone (60-cycle delay) Traditionally this zone was designated Zone 3 Function Traditional GE SEL Inst trip zone Zone 1 Z1 Z1P 30~ delay zone Zone 2 Z3 Z4P 60~ delay & Pilot zone Zone 3 Z2 Z2P Pilot Block (Reverse looking) No Target Z4 Z3P Discuss bullets and table data

SEL 421 Targets Targets can be labelled as each region desires

Summary Standards require Operators to have knowledge of relay systems
Importance of DC system in Protection systems Digital relays emulate control and reclose switch positions Principles of relay protections Can’t prevent faults Three main purposes Quick interruption of faults For permanent faults, isolate only the faulted zone Use reclosing relays to restore as much of the system as possible after a fault Transmission relays set for fault current During blackout restoration, relay protection is compromised Summary

Summary Primary and Backup relays Zones of Protection
Targets indicate in which zone the fault was Zones overlap at a CB Potential sources for relays Overcurrent relays Differential relays Lockout Relays Impedance (Distance) Relays Zones 1, 2 and 3 Summary

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Introduction To Protective Relays

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