Transcript 2014 SERC SOC_ProtectiveRelayRefresher_SOC3_SOC4

2014 System Operator Conference
Protective Relaying Refresher
September 9 & September 23, 2014
Nashville/Franklin, TN
Rick King
Senior Operator/Consultant
Tennessee Valley Authority
1
Emmett Handy
Trans. Control Center Supervisor
Alabama Power Co.
2014 System Operator Conference
Terminal Objective
• At the completion of this training, participants will
be familiar with the purpose and limitations of
typical relay protection system schemes.
•
̶
NERC Standard PRC-001-1, System Protection
Coordination, Requirement 1 is the basis for this
training.
2
Each Transmission Operator, Balancing Authority, and
Generator Operator shall be familiar with the purpose
and limitations of protection schemes applied in its
area.
2014 System Operator Conference
Learning Objectives
At the conclusion of this training session, you should be able to:
• Describe the basic types of relay protection used for power
system elements, including the protection afforded.
• Identify typical relay protection schemes used on typical
electrical generators.
• Explain the types of relay protection used on power system
transmission lines.
• State and discuss typical relay protection applied to power
transformers.
• Identify typical relay protection employed at power
substations and in the switchyard.
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Outline of Topics
• Protective Relaying Overview
• Generator Protection
• Transmission Line Protection
• Transformer Protection
• Substation Protection
• Automatic Underfrequency & Under voltage
Protection
• Review
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Purpose of Protective Relaying Systems
- Protect the bulk electric system
- Remove abnormal conditions as soon as practical
- Minimize the amount of customer service interrupted
- Limit the damage to equipment
- NOT operate under normal conditions
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ANSI/IEEE Standard Device Numbers
21 – Distance Relay: Requires a combination of high current and low voltage to
operate. The various zones of the distance scheme assist with
determining the location of the fault.
50 – Instantaneous Overcurrent: Operates with no time delay when current
rises above a set level.
51 – Time Overcurrent: Operates on a time delay basis depending on the
amount of current above a set level.
67 – Directional Overcurrent: Operates if current is above a set value and
flowing in the designated direction.
79 – Reclosing Relay: Initiates an automatic closing of a circuit breaker
following a trip condition.
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87 – Differential Relay: Senses a difference in currents entering and leaving
power system equipment.
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Relay
“electromagnetic or electronic
device for remote or automatic
control that is actuated by
variation in conditions of an
electric circuit, and that operates
in turn other devices (as
switches) in the same or different
circuits”
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Protective Relaying
► Protective relays used by a power utility are designed
to maintain system stability and minimize system
disturbances by removing abnormal conditions
► When a protective relay senses an abnormal condition
(voltage and/or current) a command is issued to open
an interrupting device
► When the interrupting
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device opens, it removes
the power source from the
circuit, thereby limiting
damage to system
components
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Function of a Protective Relay Scheme
To cause the prompt removal from service of any
element of a power system when:
•
It suffers a fault
OR
•
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It starts to operate in any abnormal manner that
might cause damage or otherwise interfere with
the effective operation of the rest of the system
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Terminology - Faults
► An event occurring on an electric system such as
a short circuit, a broken wire/conductor, or an
intermittent connection
► Types of Faults
 Phase to Ground
 Phase to Phase
 Three Phase
 Transient
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Relay Protection – Basic Types
► Primary Protective Relays


Sense system parameters such as current, voltage, etc.
Initiate actions when setpoint is reached to de-energize the
circuit
► Backup Protective Relays


Senses same parameter as associated primary relay
(Breaker Failure Relays)
Will operate & disconnect more than the faulty element to
de-energize the circuit if the primary relay circuit
malfunctions or the associated breaker/switch fails to
operate.
► Auxiliary Relays

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Operates in response to primary/backup relays to assist
another relay or device in performing a function
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Inputs to Protective Relays (Primary)
► Current Transformer – CT


12
Consists of many fine wires wrapped around a
conductor that induces a current in the secondary
directly proportional to the magnitude of amps in the
primary
Resulting current flow, based on the theory of induced
voltage, will be in the opposite direction to the primary
current flow
Output of CT
can be used
for Relaying
or Metering
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Inputs to Protective Relays (Primary)
► Potential (Voltage)
Transformer – PT or VT


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Small transformers deriving a
directly proportional ratio of
the primary to the secondary
voltage
Lower voltage to a more
practical level to be used in
metering, relaying, and
synchronization on the
system
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Relay Protection – Basic Types
Auxiliary Relay (86 - Lockout, 94 – Tripping or Trip Free)
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
An electrically operated relay used as a function switch to disable
or enable the operations of protection and control schemes
–
Primary or Backup Relays actuate Auxiliary Relays

Supplement the actions of other relays
–
Timers
–
Tripping
–
Reclosing
–
Lockout relays
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Generator Protection Scheme
Primary Fault
Protection
 87 Differential
 59GN Neutral OV
Primary Non-Fault
Protection
 40 Loss of Field
 32 Reverse Power
 24 Volts/Hertz
(59/81)
Backup Protection
 21GB Gen Backup
 46 Neg. Sequence
 51 Overcurrent
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 Differential relays are
used to protect
generators,
transformers, & buses
 Operates for phase-tophase and phase-toground faults
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Relay Protection – Differential Relays
► For external faults no
current will flow through
the operate coil 1
► Given a fault anywhere
between the two CTs,
the conditions shown will
exist 2
► If the current flows to the
fault from both directions
as shown, the sum of the
CT secondary currents
will flow through the
differential relay
16
Operate Coil
1
External
Fault
2
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Generator Protection Scheme
Primary Fault
Protection
 87 Differential
 59GN Neutral OV
Primary Non-Fault
Protection
 40 Loss of Field
 32 Reverse Power
 24 Volts/Hertz
(59/81)
Backup Protection
 21GB Gen Backup
 46 Neg. Sequence
 51 Overcurrent
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 Operates for close-in phase
to ground faults
 Typical generator
construction has step-down
transformer on wye
connected ground for
generator
 59GN monitors this voltage
and will operate when fault
current produces secondary
voltage above relay setpoint
 Secondary circuit normally
contains resistors to limit
fault current before relay
operates
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Generator Protection Scheme
Primary Fault
Protection
 87 Differential
 59GN Neutral OV
Primary Non-Fault
Protection
 40 Loss of Field
 32 Reverse Power
 24 Volts/Hertz
(59/81)
Backup Protection
 21GB Gen Backup
 46 Neg. Sequence
 51 Overcurrent
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 Operates when
generator field current is
abnormally low or has
failed (loss of excitation)
 On loss of field
generator becomes
induction vs.
synchronous generator
 Protects generator from
high stator currents that
can occur during under
excited conditions
 High stator currents can
result in overheating &
damage to stator
windings & insulation
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Generator Protection Scheme
Primary Fault
Protection
 87 Differential
 59GN Neutral OV
Primary Non-Fault
Protection
 40 Loss of Field
 32 Reverse Power
 24 Volts/Hertz
(59/81)
Backup Protection
 21GB Gen Backup
 46 Neg. Sequence
 51 Overcurrent
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 Uses phase to phase
voltage & line current
 Operates on
predetermined value of
power flow in a given
direction (reverse
power) that results
from motoring of a
generator upon loss of
its prime mover
 Typically used to
protect steam driven
generating units
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Generator Protection Scheme
Primary Fault
Protection
 87 Differential
 59GN Neutral OV
Primary Non-Fault
Protection
 40 Loss of Field
 32 Reverse Power
 24 Volts/Hertz
(59/81)
Backup Protection
 21GB Gen Backup
 46 Neg. Sequence
 51 Overcurrent
20
 Operates when ratio of
volts per hertz exceeds
setpoint
 Protects generators &
step-up transformers from
damage due to excessive
magnetic flux resulting
from overvoltage
 Excessive magnetic flux,
if sustained, can cause
serious overheating &
may result in damage to
transformer and/or
generator core
2014 System Operator Conference
Generator Protection Scheme
Primary Fault
Protection
 87 Differential
 59GN Neutral OV
Primary Non-Fault
Protection
 40 Loss of Field
 32 Reverse Power
 24 Volts/Hertz
(59/81)
Backup Protection
 21GB Gen Backup
 46 Neg. Sequence
 51 Overcurrent
21
 Directional impedance
type relay set to look
back into generator
 Can detect phase to
ground & phase to
phase faults in
generator or
associated busswork
 Backs up primary fault
protection relays
2014 System Operator Conference
Generator Protection Scheme
Primary Fault
Protection
 87 Differential
 59GN Neutral OV
Primary Non-Fault
Protection
 40 Loss of Field
 32 Reverse Power
 24 Volts/Hertz
(59/81)
Backup Protection
 21GB Gen Backup
 46 Neg. Sequence
 51 Overcurrent
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 Also called Phase-Balance
Current Relay
 Functions when polyphase
currents are unbalanced or
contain negative phase
sequence components
 These currents in the
generator stator will result
in rotor overheating and will
damage generator if
continued operation in
unbalance condition is
allowed
2014 System Operator Conference
Generator Protection Scheme
Primary Fault
Protection
 87 Differential
 59GN Neutral OV
Primary Non-Fault
Protection
 40 Loss of Field
 32 Reverse Power
 24 Volts/Hertz
(59/81)
Backup Protection
 21GB Gen Backup
 46 Neg. Sequence
 51 Overcurrent
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 Time delayed nondirectional overcurrent
 Protects stator windings
from overheating due to
overcurrent conditions
 Has high current setpoint to
accommodate normal load
currents
 Some generators use a
voltage input for voltage
restraint. If voltage value
drops the current setpoint
will also drop to a lower
setting.
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Transmission Line Protection Scheme
Primary Fault Protection
 21 Directional
Impedance

67 Directional
Overcurrent
Backup Protection
 50BF Breaker Failure
Other Relays
 79 Reclosing
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Transmission Line Protection Scheme
Primary Fault Protection
 21 Directional
Impedance

67 Directional
Overcurrent
Backup Protection
 50BF Breaker Failure
Other Relays
 79 Reclosing
E
Z
I
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Formula
relay calculates
 Used on transmission lines to measure impedance or
distance to a fault & operate if the fault is within their zone
of protection
 Primary protection against phase to phase fault conditions
 Relay divides voltage input by current input to calculate
“Z” or effective impedance for line
 If fault occurs outside the relays zone of protection, the
impedance doesn’t change much from the perspective of
relay’s location
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Zone Distance Relaying
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Line Protection: Distance – Zone 1
The relays at breaker 1 are set with a Zone 1 reach of
80-85% of the protected line. Since all faults in this zone
are within the protected line, no intentional time delay is
introduced. Zone 1 tripping occurs instantaneously.
5
3
1
4
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Z1
ZONE 1 = 85% OF PROTECTED LINE
Instantaneous
2
6
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Line Protection: Distance – Zone 1
Instantaneous
coverage area of
both Z1 relays =
the center 70%
of the protected
line.
3
1
2
ZONE 1 = 85% OF PROTECTED LINE
4
Z1
Instantaneous
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5
ZONE 1 = 85% OF PROTECTED LINE
Z1
Instantaneous
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Line Protection: Distance – Zone 2
The second zone reach of the relays at breaker 1 are set for a minimum of 120% of the
protected line. The second zone extends beyond the end of the protected line. This is to
insure that the relays will operate for all faults in the section of line between point B and
breaker 2. Tripping in Zone 2 is normally delayed for about 30 cycles, but will vary
depending upon the application. This time delay is for coordination purposes to give the
relays on breakers 5 and 6 time to trip for a fault on their protected line.
3
ZONE 2 = 120% OF PROTECTED LINE
B
1
End of Zone 1 Protection
2
Zone 2 Protection
4
Z2
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30 cycle delay = ½ second
5
Delayed pickup zone
for
Z2 of breaker 1
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Line Protection: Distance – Zone 2
Delayed pickup zone for
Z2 of breaker 2
30 cycle delay = ½ second
ZONE 2 = 120% OF PROTECTED LINE
Z2
3
1
2
6
4
Z2
ZONE 2 = 120% OF PROTECTED LINE
Delayed pickup zone for
Z2 of breaker 1
30
5
30 cycle delay = ½ second
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Line Protection: Distance – Zone 3
The primary function of the Zone 3 unit is backup protection in the event of
the failure of breakers 5 or 6 or their associated relays. Zone 3 is set for
100% of the protected line plus 120% of the longest line out of the next
bus. Due to line loads, length of lines, etc., it is not always possible to set
the Zone 3 unit this far out. Zone 3 tripping time is set from 60 cycles and
up, depending upon the application.
3
ZONE 3 = 100% OF PROTECTED LINE PLUS 120% OF LONGEST LINE OUT OF NEXT BUS
1
2
6
4
Z3
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5
Delayed pickup zone
for Z2 of breaker 1
60 cycle delay = 1 second
2014 System Operator Conference
Line Protection: Distance – Zone 3
Delayed pickup zone
for
Z3 of breaker 2
60 cycle delay = 1 second
ZONE 3 = 100% OF PROTECTED LINE PLUS 120% OF LONGEST LINE OUT OF NEXT BUS
Z3
3
1
5
2
6
4
ZONE 3 = 100% OF PROTECTED LINE PLUS 120% OF LONGEST LINE OUT OF NEXT BUS
Z3
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60 cycle delay = 1 second
Delayed pickup zone
for
Z3 of breaker 1
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Line Protection – Zone 1 Fault
60 cycle delay = 1 second
30 cycle delay = ½ second
Instantaneous
ZONE 3 = 100% OF PROTECTED LINE PLUS 120% OF LONGEST LINE OUT OF NEXT BUS
ZONE 2 = 120% OF
PROTECTED LINE
ZONE 1 = 85% OF PROTECTED LINE
3
1
Z1 Z2
Z3
5
2
ZONE 1 = 85% OF PROTECTED LINE
4
Z2
Z1
Z3
Instantaneous
30 cycle delay = ½ second
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60 cycle delay = 1 second
ZONE 2 = 120% OF
PROTECTED LINE
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ZONE 3 = 100% OF PROTECTED LINE PLUS 120% OF LONGEST LINE OUT OF NEXT BUS
For a fault at this location both Z1 relays at breaker 1 and
breaker 2 should see the fault and operate instantaneously. Z2
and Z3 relays also see the fault, however, they are delayed in
operation in order to give Z1 time to operate.
2014 System Operator Conference
Line Protection – Zone 1 Fault
60 cycle delay = 1 second
30 cycle delay = ½ second
Instantaneous
ZONE 3 = 100% OF PROTECTED LINE PLUS 120% OF LONGEST LINE OUT OF NEXT BUS
ZONE 2 = 120% OF
PROTECTED LINE
ZONE 1 = 85% OF PROTECTED LINE
3
1
Z1 Z2
Z3
5
2
ZONE 1 = 85% OF PROTECTED LINE
4
Z2
Z1
Z3
Instantaneous
30 cycle delay = ½ second
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60 cycle delay = 1 second
ZONE 2 = 120% OF
PROTECTED LINE
6
ZONE 3 = 100% OF PROTECTED LINE PLUS 120% OF LONGEST LINE OUT OF NEXT BUS
For a fault at this location Z1 relay at breaker 1 and Z2
relay at breaker 2 should see the fault. Z1 at breaker 1
should operate instantaneously to clear the close-in fault
and Z2 at breaker 2 should operate 30 cycles later
completing the isolation from the far end. Z2 and Z3
relays also see the fault, however, they are delayed in
operation in order to give Z1 time to operate.
2014 System Operator Conference
Line Protection – Zone 1 Fault
60 cycle delay = 1 second
30 cycle delay = ½ second
Instantaneous
ZONE 3 = 100% OF PROTECTED LINE PLUS 120% OF LONGEST LINE OUT OF NEXT BUS
ZONE 2 = 120% OF
PROTECTED LINE
ZONE 1 = 85% OF PROTECTED LINE
3
1
Z1 Z2
Z3
5
2
ZONE 1 = 85% OF PROTECTED LINE
4
Z2
Z1
Z3
Instantaneous
30 cycle delay = ½ second
60 cycle delay = 1 second
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ZONE 2 = 120% OF
PROTECTED LINE
6
ZONE 3 = 100% OF PROTECTED LINE PLUS 120% OF LONGEST LINE OUT OF NEXT BUS
For a fault at this location Z2 relay at breaker 1 and Z1
relay at breaker 2 should see the fault. Z1 at breaker 2
should operate instantaneously to clear the close-in fault
and Z2 at breaker 1 should operate 30 cycles later
completing the isolation from the far end. Z2 and Z3
relays also see the fault, however, they are delayed in
operation in order to give Z1 time to operate.
2014 System Operator Conference
Transmission Line Protection Scheme
Primary Fault Protection
 21 Directional
Impedance
 67 Directional
Overcurrent
Backup Protection
 Used on transmission lines primarily to detect ground faults
 50BF Breaker Failure
 Operates when current exceeds a predetermined value & the
fault current is in the proper direction
Other Relays
 Directional element uses a current polarizing and/or potential
 79 Reclosing
polarizing input that provides directional reference
 Can contain instantaneous & timed elements
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Directional Overcurrent Relays
• Directional Overcurrent relays have additional elements included
to determine the direction of current flow through protected
equipment. To accomplish directional sensing, the relay checks
the relationship between input current and a “polarizing” quantity.
The polarizing quantity is simply a reference from which the relay
can determine power flow direction.
• The polarizing quantity can be voltage or a current.
• Voltage = Voltage polarizing
• Current = Current polarizing
Current inputs
M
M Current inputs
Directional
O.C.
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Directional
O.C.
Polarizing
Input
V= Voltage
I = Current
Polarizing
Input
V= Voltage
I = Current
2014 System Operator Conference
Directional Overcurrent Relays
• Directional Overcurrent Relays may be used to protect
transmission lines between substations, where power can flow in
either direction. Directional overcurrent relays are “more sensitive”
than non-directional relays.
• Directional relays are used to confine relay operations to one
particular line section. The relay will only trip for faults in the line it
is responsible for.
Current inputs
Normal Current Flow
M
Directional
O.C.
Polarizing
Input
V= Voltage
I = Current
38
M Current inputs
Fault Current Flow
Extremely High
Current
Directional
O.C.
Polarizing
Input
V= Voltage
I = Current
2014 System Operator Conference
Line Protection: Overcurrent – Directional
Due to the sensitivity of the directional elements in these relays, they can/will
pick up for normal load if power flow is in the same direction for which the
relay is connected to operate.
Therefore, at terminals where normal load flow can keep the directional
element picked up, the overcurrent unit must be set high enough to insure
that they won't operate for maximum load current flow in the tripping
direction.
Change Tap Settings or ALT SET APPLIED to
prevent “overcurrent” element from picking up and
tripping when abnormal line configurations occur.
Overcurrent element
not picked up = current is not
beyond trip set point for
protected line
TRIP
39
Directional element
picked up = current is flowing
“into” the protected line
2014 System Operator Conference
Transmission Line Protection Scheme
Primary Fault Protection
 21 Directional
Impedance
 67 Directional
Overcurrent
 Provides system backup protection in the event of a circuit
breaker failing to open on a trip signal
Backup Protection
 50BF Breaker Failure
 Accomplished by applying a trip signal from the primary
relays to the breaker failure relay, if breaker still passing
current after 15-17 cycle time delay then 50BF will send
trip signal to other breakers on same bus and other paired
breaker
Other Relays
 50BF
79 Reclosing
 Relay initiation is stopped by either absence of trip signal
from primary relays or by current flow through breaker
dropping below a preset level
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Relay Protection – Breaker Failure Relays
X
41
Breaker failure initiates tripping to the backup breakers within a
preset time delay of 15 to 17 cycles after the original trip signal
initiated
2014 System Operator Conference
Transmission Line Protection Scheme
Primary Fault Protection
 21 Directional
Impedance
 67 Directional
Overcurrent
 Controls the automatic reclosing and locking out of an AC circuit
Backup Protection
 50BF Breaker Failureinterrupter (PCB)
 Reclosing occurs after protective relay operation on a transmission line
Other Relays
 79 Reclosing
 Reclose capability controlled by Transmission Operators
 Types of reclosing used:
– High speed (~20 cycles)
– Fast speed (~45 cycles)
– Standard speed (varies based on configuration)
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 If reclosing is unsuccessful, reclose relay locks out breaker
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Transformer Protection Scheme
Primary Fault Protection
 87 Differential
 63 Sudden Pressure
Backup Protection
 51N Neutral Overcurrent
 51 Phase Overcurrent
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2014 System Operator Conference
Transformer Protection Scheme
Primary Fault Protection
 87 Differential
 Relay
63 Sudden
Pressure
will operate
for
phase to phase or phase
to ground fault within
Backup
Protection
monitored
area
 Monitors
51N Neutral
Overcurrent
for imbalance
or
 current
51 Phase
flow Overcurrent
through CTs
bounding monitoring area
 Transformer differential
relays may contain a
harmonic restraint unit
Would the 87 relay actuate
for a fault at location 1?
44
What about location 2?
2
1
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Transformer Protection Scheme
Primary Fault Protection
 87 Differential
 63 Sudden Pressure
 Detects internal faults for
Backup
power Protection
transformers &
(tap Overcurrent
changers)
 regulators
51N Neutral
a fast rise in
 Responds
51 PhasetoOvercurrent
internal pressure produced
by an internal fault
 Capable of detecting faults
below sensitivity level of
differential relays
 Typically mounted on the side
or top of the transformer
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2014 System Operator Conference
Transformer Protection Scheme
Primary Fault Protection
 87 Differential
 63 Sudden Pressure
Backup Protection
 51N Neutral Overcurrent
delay overcurrent
that monitors neutral
 Time
51 Phase
Overcurrent
of transformer winding
 Can have a definite or inverse time
characteristic that functions when ac input
current exceeds a predetermined value
 Senses ground faults on that side (typically
secondary) of transformer and initiates
protective action
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2014 System Operator Conference
Transformer Protection Scheme
Primary Fault Protection
 87 Differential
 63 Sudden Pressure
Backup Protection
 51N Neutral Overcurrent
 51 Phase Overcurrent
 Non-directional, operates when current in operating
element exceeds relay’s minimum trip setting
 Relay must be set higher than anticipated load current,
yet operate to provide adequate protection for faults
 Relay can contain an instantaneous (50) and/or timed
(51) element
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Relay Protection – Residual Ground Relay (64)
► Normal balanced load
conditions, no current
in the ground relay
► Only when one phase
becomes faulted will
there be appreciable
current flow in this
portion of the circuit
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Substation (Bus) Protection Scheme
Primary Fault Protection
 87 Bus Differential
 87FD Feeder Differential
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Bus Differential Protection
Breakers may / may not be
configured to trip,
depending on downstream
sources.
BUS DIFFERENTIAL= Operates for faults
detected on the bus. Separate protection is
provided for the transformer bank.
3
Protected Zone
Trip
1
Trip
4
Trip Output
Trip
Current Input
Current Input
Current Input
50
Differential Relay
2014 System Operator Conference
Bus Protection – Back Up
Most buses are in Zone 2 of the line relays at the remote terminals. If the
primary bus protection does not clear a fault, the fault will be cleared in
Zone 2 time of the remote terminals. This would be 30 to 45 cycles. As a
result of this, all lines connected to the station plus any tapped load
would be lost. Remote bus protection should only be considered as
backup protection.
3
ZONE 2 = 120% OF PROTECTED LINE
B
1
End of Zone 1 Protection
4
Z2
I’ve got your back!
Bus Back-up that is.
51
30 cycle delay = ½ second
5
2
Zone 2 Protection
Bus Zone
Delayed pickup zone
for
Z2 of breaker 1
6
2014 System Operator Conference
Combined Transformer-Bus Protection
In many substations, there will not be a circuit breaker between the transformer bank
and the low voltage bus. The CT's in all the load circuits may be paralleled and the
transformer's differential zone of protection may be extended to include the bus.
Protected Zone
3
Trip
1
Trip
2
Trip Output
Trip
Current Input
Current Input
Current Input
52
Differential Relay
2014 System Operator Conference
Combined Transformer-Bus Protection
Breakers may / may not be configured to
trip, depending on downstream sources.
3
BUS/BANK DIFFERENTIAL = Operates for faults
detected on the bus or the transformer bank. Additional
troubleshooting will be necessary to determine the
nature of the fault. (i.e. bus fault, transformer fault,
lightning arrestor, etc.)
Protected Zone
Trip
1
Trip
2
Trip Output
Trip
Current Input
Current Input
Current Input
53
Differential Relay
2014 System Operator Conference
Automatic Underfrequency Load Shed
Relay Protection
► UFLS programs provide an automatic means of reducing
load due to a load/generation imbalance
► NERC requirements:


Must be capable of shedding at least 33% of the peak hour load in a
minimum of three steps
Operate over the frequency range of 59.5 Hz to 58.4 Hz, using at
least three steps, the first of which should be no lower than 59.3 Hz
► Locations for UFLS are typically equally distributed across
the entities Transmission System
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2014 System Operator Conference
Relay Protection – Undervoltage Relays
► Operates when its input voltage is
less than a predetermined value
 Can be set to operate with a time
delay or instantaneously
► Utilized across system for protection
and actuation of equipment
 Initiate undervoltage load shed
 Auto operate cap banks
 Auto control and alarming of
auxiliary equipment
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2014 System Operator Conference
Summary of Main Points
• Basic types of relay protection: primary, backup, auxiliary
• Backup removes more elements, but protects for primary failure
• Auxiliary relays assist other relays in performing a function
• Generator protection types include: differential, loss of field, reverse
power, volts/Hz
• Typical transmission line protection includes: impedance-type,
directional overcurrent, step-distance relaying, breaker failure
backup, and reclosing
• Power transformer protection types: differential, sudden pressure,
phase and neutral overcurrent backup
• Substation/switchyard protection schemes include: bus differential,
automatic under-frequency load shedding (UFLS) and automatic
under-voltage load shedding (UVLS)
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2014 System Operator Conference
Now, Talk to Me
Rick King
[email protected]
(423) 751-7728 (W)
(423) 605-7997 (M)
57
Emmett Handy
[email protected]
(205) 769-742 (W)
(205) 288-1453