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:
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.
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.
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.
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)
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.
G4
G2
G3
G5
30Ω
70Ω
10Ω
25Ω
G6
30Ω
40Ω
Fault Current
25,000 Amps
G1
20Ω
Reduced available fault current during blackouts can affect relay operation
G4
G2
G3
G5
30Ω
70Ω
10Ω
25Ω
G6
30Ω
40Ω
20Ω
Fault Current
2,000 Amps
G1 Black
Start
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
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
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.
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
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
Ash
R
C
B
R
R
R
R
Elm
D
R
R
Oak
R
Various Zones of Protection
• Overlapping occurs even when a CB
is not present.
• Transmission bushing has 2 CTs
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,
R
Circuit Switcher XT1 and MOAB X1
LOR
R
R
Fault in Bus Zone of Protection
Bus Targets and LOR
R
R
Fault in Transformer Zone of Protection
Transformer Targets and LOR
Fault in Trans Circuit Zone of Protection
(Includes Transformer Surge Arresters )
Line Targets
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
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.
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
A
• Phase relays
CB
B
• Ground Relay
• Sees only imbalance current.
• Usually set lower than phase relay
• Ground target only on some faults
Fault
C
Φ
Φ
G
Φ
Phase Relays
Ground Relay
• Phase relays must be set above load current.
• Use Undervoltage scheme where load approaches available fault current
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
X
TOC
INST
A
C
B
INST
INST
TOC
TOC
• Fault between points “A” & “B”
X
Fault
TOC
INST
A
C
B
INST
INST
TOC
TOC
Y
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
UV Relay
Relay
Coil
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.
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 3
Zone 2 150%
Zone 1 90%
C
A
75 miles
B
E
21
50 miles
D
F
25 miles
G
H
Impedance (Distance) Relays
• Instantaneous clearing only in middle 80% of circuit
Zone 2
Zone 1
80%
Source
B
A
21 Z1
21
Z2
C
Source
Zone 1
Zone 2
Zone 2
Zone 1
80%
Source
A
21 Z1
Zone 2
21
Z1
Zone 1
B
C
Source
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
Z-3 Instantaneous
E
A
21A
blocking signal to prevent
CB A from tripping for a
fault on circuit C - D.
21B
B
C
Z-3 Instantaneous
D
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.
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
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
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
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
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
Permissive Under-reach Transfer Trip
• For a fault close to CB 2
• Permissive Transfer Trip will set up instantaneous tripping of CB 1
Z2
TTR
Z1
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.
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
Distance Relay
Over-Reach Zone of CB 1
•Over-Reach Zone of CB 2
Distance
Relay
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)
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
A
600/5
B
10A
10A
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
20A 87B
Differential Relays Trip Lockout Relays
• The 87T trips the lockout relay which in turn trips the
associated breakers.
138 kV
600A
69 kV
1200A
Fault
600/5
1200/5
A
B
86T/
87XT 5A
5A
10A
5A
87T
5A
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
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
FRCC System Protection Outage Procedure
• Procedure for Unplanned FRCC Protection System
Outages or Failures
Unplanned Protection System Outages or Failures
• System protection personnel (TO or GO) shall inform their TOP or GOP
of any unplanned protection system outages or failures when one of the
following conditions is met:
• The outage or failure of any Protection System associated with a BES
component.
• Any protection system outage or failure that could impact BES reliability.
• Any protection system outages resulting in increased clearing time on BES
facilities for any faults.
• A fault within the zone of protection that causes multiple BES elements to
trip.
• The potential for BES elements to “Over-Trip”.
Unplanned Protection System Outages or Failures
• Any outage or failure will require a condition assessment of the remaining
protection that would be relied on to clear a potential fault.
• A verification that the remaining protection is in service.
• Under No Circumstances shall a Facility remain in service
without any Protection Systems in service.
Unplanned Protection System Outages or Failures
• Every GOP shall notify their host TOP upon being
informed of an unplanned Protection System outage or
failure.
• Every TOP shall notify the FRCC RC upon being
informed of an unplanned Protection System outage or
failure unless a redundant Protection System remains in
service.
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:
• 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 undervoltage 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.
Unplanned Protection System Outages or Failures
If the facility must remain in service while the unplanned Protection System outage or failure
is being addressed:
• the TOP or GOP should perform the condition assessment as soon as practical, placing
an emphasis on the physical check of the remaining protection.
• If the Protection System outage or failure could last for more than 72 hours and the facility
is in service, the TOP or GOP must perform the BES Risk Assessment prior to the
Protection System outage or failure exceeding 72 hours.
• If the results of the BES Risk Assessment show 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 undervoltage condition
that cannot be mitigated through other means.
Unplanned Protection System Outages or Failures
• If the monitored facility is removed from service,
• The TOP or GOP should perform a BES Risk Assessment. This will provide the FRCC RC and the
TOP valuable information in the event the facility must be returned to service for a system
emergency.
• The facility can be returned to service (with the Protection System outage or failure) for any of
the following conditions if all potentially affected reliability entities concur and any alternate
remediation is complete:
• A BES Risk Assessment determines that the Protection System outage or failure causes no
reliability concerns.
• An alternate remediation has been implemented to alleviate the reliability concern
discovered in the BES Risk Assessment.
• Restoring the monitored element is the only mitigation that resolves a real-time thermal
overload or under-voltage condition.
Unplanned Protection System Outages or Failures
• Summary
• System protection personnel (TO or GO) shall inform their TOP or
GOP of any unplanned protection system outages.
• Any protection system outage or failure will require a condition
assessment.
• If the Protection System outage or failure could last for more than
72 hours and the facility is in service, the TOP or GOP must perform
the BES Risk Assessment.
• Under No Circumstances shall a Facility remain in service without
any Protection Systems in service.
Questions?
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
Forward looking
tripping element
Reverse looking
Carrier Start
element