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

2. Learning Objectives Upon completion of the training, the participant will be able to: 1.Identify the 3 basic purposes of protective relays 2.Recognize the importance of batteries in protective relaying. 3.Differentiate between Primary and Backup relaying. 4.Distinguish what determines the zones of protection verses tripping zones.

3. 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.

4. Protective Relay Principles Sensitivity Use inputs from Monitoring devices Current, Voltage, Temperature, Pressure Selectivity Isolate Only the Faulted Area (Zone). Maintain Service to Other Areas (Zones) During and/or after Isolation of the Fault. Speed Minimize Damage from the fault by quick interruption The quicker the fault is removed, the less damage.

5. Protective Relay Principles Cannot prevent faults Proactive Pilot wire relays Pilot wire alarm relays alert when the pilot wires are shorted or open, allowing preventative measures to be taken before a miss-operation occurs. Temperature relays can turn on fans to a Transformer before windings get too hot. Reactive – relays that initiate action after fault occurs They respond after current or voltage gets above their trip level. Trip only what is needed to interrupt the fault current, then restore as much of the system as possible. (when Reclosing relays are used)

6. Protective Relay Principles Designed & utilized to protect against Faults. But could potentially trip due to loading in excess Facility Ratings or System Operating Limits (SOLs). It is incumbent on the System Operator to alleviate these conditions real time and Day ahead planners pre-contingency. 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.

7. G5 G4G2G3 G1 G6 30Ω 10Ω 70Ω 40Ω 20Ω 25Ω Fault Current 25,000 Amps Fault Current 2,000 Amps G5 G4G2G3 G1 G6 30Ω 10Ω 70Ω 40Ω 20Ω 25Ω Black Start Reduced available fault current during blackouts can affect relay operation

8. Network verses Radial Radial One source - fault interrupting devices are in series with lateral feeds to customers. Distribution Circuits are typically radial. Network Dual or Multiple Sources The BES 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

9. Station Battery NERC’s definition of a Protection System includes: Station dc supply associated with protective functions (including batteries, chargers, and non-battery based dc supply) Associated Alarms Loss of AC to Battery Charger Low Battery Voltage Loss of DC

10. 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.

11. 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 (>500kV) circuits Sub-transmission (<100kV) 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

12. 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. A B C D RRRRRRRR Elm Ash Oak

13. Various Zones of Protection Overlapping occurs even when a CB is not present. Transmission bushing has 2 CTs

14. LOR Tripped By Numerous Relays Transformer and Bus differential zones shown. Both zones will still trip the same LOR. LOR (lock-out relay) trips Distribution CBs, Circuit Switcher XT1 and MOAB X1 R R RR R LOR Fault in Bus Zone of Protection Bus Targets and LOR Fault in Transformer Zone of Protection Transformer Targets and LOR Fault in Trans Circuit Zone of Protection (Includes Transformer Surge Arresters ) Line Targets

15. 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

16. 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.

17. Overcurrent Relays Can be Instantaneous (50) or time-delayed (51) Can be non-directional or directional (67). 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 ΦΦΦ G Phase Relays Ground Relay A B C CB Fault

18. 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” AC B INST TOC INST TOC INST TOC X Fault AC B INST TOC INST TOC INST TOC X Y Fault

19. 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 UV Relay Trip Coil Tripping Relay Relay Coil

20. Impedance (Distance) Relays Sub-transmission 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.

21. Impedance (Distance) Relays Zone 1 is instantaneous Typical setting is 80-90% Zone 2 has up to a 40-cycle delay Typical setting is 120-150% Zone 3 has up to a 90-cycle delay Typical setting is 200% Zone 2 150% Zone 3 Zone 1 90% 21 DC AB 50 miles 75 miles FE 25 miles HG

22. Impedance (Distance) Relays Instantaneous clearing only in middle 80% of circuit Zone 2 A 21 B C Zone 1 Zone 2 Zone 1 80% Source Z2Z2 Z1Z1 21 Zone 2 A 21 B C Zone 1 Zone 2 Zone 1 80% Source Z1Z1 Z1Z1 21

23. 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 DABC 21A 21B E

24. Directional Comparison Carrier Blocking 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 Reverse looking Carrier Start element Forward looking tripping element

25. 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 180 o power reversal, (which is indicative of an internal fault), the comparer will initiate trip of the breaker.

26. 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

27. Phase Comparison Internal Fault The over-current fault detector relays see fault current. Comparers see a 180 o difference in phase angles. Trip occurs for Breakers 1 & 2

28. 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

29. 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 TT R Z1

30. 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

31. Permissive Under-reach Transfer Trip For a fault close to CB 2 Permissive Transfer Trip will set up instantaneous tripping of CB 1 Z1 Z2 TTR

32. 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.

33. Permissive Over-reach Transfer Trip 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

34. Differential Relaying Operate when the current into a protected zone does NOT equal the current 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)

35. Differential Relaying – External Fault Current into the Zone equals the current leaving the Zone Secondary current sums to zero at the operate coil 10A 87B AB 600/5 1200A 0A BUS Fault

36. 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 10A 87B AB 600/5 1200A 20A BUS Fault

37. Differential Relays Trip Lockout Relays The 87T trips the lockout relay which in turn trips the associated breakers. 87T AB 138 kV69 kV 1200/5600/5 600A1200A 5A 10A Fault 5A 86T/ 87XT

38. Summary NERC Standards require Operators to have knowledge of relay systems Importance of DC system in Protection systems Principles of relay protections Can’t prevent faults Three main purposes SENSITIVITY - Detection of the fault in the correct zone SELECTIVITY - For permanent faults, isolate only the faulted zone. SPEED - Quick interruption of faults to minimize damage During blackout restoration, relay protection is compromised

39. 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 Impedance (Distance) Relays Zones 1, 2 and 3 Differential relays

40. FRCC System Protection Outage Coordination Procedure Section 6.2 Unplanned Protection System Outages or Failures

41. Under No Circumstances shall a BES Facility remain in-service without any Protection Systems in-service!

42. Unplanned Protection System Outages or Failures System protection personnel (TO or GO) shall immediately notify their TOP or GOP of any unplanned protection system outages or failures.

43. Unplanned Protection System Outages or Failures Each GOP shall immediately notify its TOP and BA of the unplanned Protection System outage or failure. Each TOP shall immediately notify the RCSO and affected TOPs and BAs. Notification shall include:  The Facility protected by the affected Protection System.  The type of protection out-of-service (i.e. step-distance, direct transfer trip, carrier blocking, etc.)  The type of protection remaining in-service.  Any relay communication systems out-of-service.

44. Unplanned Protection System Outages or Failures Within 30 minutes of being notified of a Protection System outage or failure, the TOP or GOP shall remove the facility monitored by the failed Protection System from service unless one of these conditions are met: The Protection System Outage is not on the Primary Protection A redundant protection system remains in service A system study has been performed that simulates a fault on the facility with the protection system outage or failure and the study determines that there will be no cascading outages or wide area load loss Removing the monitored facility will result in thermal overloads, an under-voltage condition, or cascading outages.  These issues must be resolved as soon as possible so that the facility monitored by the failed Protection System can be removed from service.

45. Unplanned Protection System Outages or Failures If the facility meets one of those criteria and it is determined the Facility must remain in-service during the outage: The TOP or GOP shall perform the Condition Assessment and BES Risk Assessment and report the results to the RCSO If the results of the BES Risk Assessment shows there is an impact to BES reliability, the facility must be removed from service unless: Removing the monitored facility will result in dropping customer load. Or removing the monitored facility will result in a real-time thermal overload or under-voltage condition that cannot be mitigated through other means. The RCSO shall also perform a power flow and contingency analysis study to determine the impact and develop a plan

46. Unplanned Protection System Outages or Failures Even if the monitored facility is removed from service, the following steps should still be taken: The TOP or GOP should perform a BES Risk Assessment per the expected outage duration (this provides the RCSO and the TOP valuable information in the event the facility must be returned to service for a system emergency) Note: The facility can be returned to service only if one of the following conditions are met:  BES Risk Assessment determines no reliability concerns with RSCO and other affected TOPs concurrence  Restoring monitored Facility is the only mitigation that resolves a real- time under-voltage or SOL, IROL, or Facility Rating exceedance.

47. Summary Under No Circumstances shall a Facility remain in-service without any Protection Systems in-service. System protection personnel (TO or GO) shall immediately notify their TOP or GOP of any unplanned protection system outage Each GOP shall immediately notify its TOP and BA of any unplanned protection system outage Each TOP should immediately notify the RCSO and other affected BAs and TOPs A Condition Assessment and BES Risk Assessment must be performed based on the expected outage duration per the procedure

48. Questions?