Total Protection Basics
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Transcript of Total Protection Basics
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1GE Consumer & Industrial
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Protection Fundamentals
ByCraig Wester, John Levine
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2GE Consumer & Industrial
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Outline Introductions Tools
Enervista Launchpad On Line Store
Demo Relays at ISO / Levine Discussion of future classes Protection Fundamentals ANSI number handout, Training CDs
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3GE Consumer & Industrial
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Introduction Speakers:
Craig Wester GE Multilin Regional Manager John Levine GE Multilin Account Manager
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4GE Consumer & Industrial
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Objective We are here to help make your job easier.
This is very informal and designed aroundISO Applications. Please ask question.We are not here to preach to you.
The knowledge base on GE MultilinRelays varies greatly at ISO. If you have aquestion, there is a good chance there are3 or 4 other people that have the samequestion. Please ask it.
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5GE Consumer & Industrial
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Tools
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6GE Consumer & Industrial
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7GE Consumer & Industrial
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Demo Relays with Ethernet Working with James McRoy and Dave
Curtis SR 489
SR 750 G30 MIF II Training CDs
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9GE Consumer & Industrial
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Demo Relays at L-3
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10GE Consumer & Industrial
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Future Classes GE Multilin Training will be the 2nd Friday of
every month. We will cover: March Basics, Enervista Launchpad, ANSI number
and what they represent, Uploading, downloading,Training CDs, etc. April 489 Relay May MIF II relay
June - 750 Relay July - UR relay basic including Enervista Engineer August UR F60 and F35 relays September G30 and G60 including Transformer and
Generator in same zone October Communications and security November - Neutral Grounding Resistors December Cts and PTs
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11GE Consumer & Industrial
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Protection Fundamentals
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12GE Consumer & Industrial
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Desirable Protection Attributes
Reliability: System operate properly Security: Dont trip when you shouldnt Dependability: Trip when you should
Selectivity: Trip the minimal amount to clear thefault or abnormal operating condition
Speed: Usually the faster the better in terms ofminimizing equipment damage and maintainingsystem integrity
Simplicity: KISS Economics: Dont break the bank
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13GE Consumer & Industrial
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Selection of protective relays requires compromises:
Maximum and Reliable protection at minimumequipment cost
High Sensitivity to faults and insensitivity to maximumload currents
High-speed fault clearance with correct selectivity
Selectivity in isolating small faulty area
Ability to operate correctly under all predictable powersystem conditions
Art & Science of Protection Art & Science of Protection
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Cost of protective relays should be balancedagainst risks involved if protection is notsufficient and not enough redundancy.
Primary objectives is to have faulted zones
primary protection operate first, but if there areprotective relays failures, some form ofbackup protection is provided.
Backup protection is local (if local primaryprotection fails to clear fault) and remote (ifremote protection fails to operate to clear
fault)
Art & Science of Protection Art & Science of Protection
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15GE Consumer & Industrialultl n
Primary Equipment & ComponentsPrimary Equipment & Components Transformers - to step up or step down voltage level Breakers - to energize equipment and interrupt fault current
to isolate faulted equipment
Insulators - to insulate equipment from ground and otherphases
Isolators (switches) - to create a visible and permanentisolation of primary equipment for maintenance purposes
and route power flow over certain buses. Bus - to allow multiple connections (feeders) to the same
source of power (transformer).
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16GE Consumer & Industrialultl n
Primary Equipment & ComponentsPrimary Equipment & Components Grounding - to operate and maintain equipment safely Arrester - to protect primary equipment of sudden
overvoltage (lightning strike). Switchgear integrated components to switch, protect,
meter and control power flow
Reactors - to limit fault current (series) or compensate forcharge current (shunt)
VT and CT - to measure primary current and voltage andsupply scaled down values to P&C, metering, SCADA, etc.
Regulators - voltage, current, VAR, phase angle, etc.
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Types of ProtectionOvercurrent Uses current to determine magnitude of fault
Simple May employ definite time or inverse time curves May be slow
Selectivity at the cost of speed (coordination stacks) Inexpensive May use various polarizing voltages or ground current
for directionality Communication aided schemes make more selective
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18GE Consumer & Industrialultl n
Instantaneous Overcurrent Protection (IOC) &Definite Time Overcurrent
t
I
CTI
50+2
50+2
CTI Relay closest to fault operatesfirst
Relays closer to sourceoperate slower
Time between operating forsame current is called CTI(Clearing Time Interval)
DistributionSubstation
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(TOC) Coordination
t
I
CTI
Relay closest to fault operatesfirst
Relays closer to source
operate slower Time between operating for
same current is called CTI
DistributionSubstation
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Selection of the curvesuses what is termed as a
time multiplier ortime dial to effectivelyshift the curve up ordown on the time axis
Operate region liesabove selected curve,while no-operate region
lies below it Inverse curves can
approximate fuse curveshapes
Time Overcurrent Protection (TOC)
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Multiples of pick-up
Time Overcurrent Protection(51, 51N, 51G)
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Classic Directional Overcurrent
Scheme for Looped SystemProtection
1 5
2 4
3
A
B
E
D
C
c
e
d
a
b
L L
L L
Bus X Bus Y
E D C B A
a b c d et
I
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Types of ProtectionDifferential
current in = current out Simple Very fast Very defined clearing area Expensive Practical distance limitations
Line differential systems overcome this usingdigital communications
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Types of ProtectionVoltage Uses voltage to infer fault or abnormal
condition May employ definite time or inverse time
curves
May also be used for undervoltage loadshedding Simple
May be slow Selectivity at the cost of speed (coordinationstacks)
Inexpensive
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Types of ProtectionFrequency Uses frequency of voltage to detect power
balance condition May employ definite time or inverse time
curves
Used for load shedding & machineryunder/overspeed protection Simple
May be slow Selectivity at the cost of speed can be expensive
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Types of ProtectionPower
Uses voltage and current to determinepower flow magnitude and direction Typically definite time
Complex May be slow Accuracy important for many applications
Can be expensive
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Types of ProtectionDistance (Impedance)
Uses voltage and current to determine impedance of
fault Set on impedance [R-X] plane Uses definite time Impedance related to distance from relay Complicated Fast Somewhat defined clearing area with reasonable
accuracy Expensive Communication aided schemes make more selective
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30GE Consumer & Industrialultl n
Impedance Relay in Zone 1 operates f irst Time between Zones is called
CTI
Source
A B
21 21
T1
T2Z A
ZB
R
X ZL
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31GE Consumer & Industrialultl n
Impedance: POTT Scheme
POTT will trip only faulted line section RO elements are 21; 21G or 67N
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32GE Consumer & Industrialultl n
Power vs. Protection Engineer:Views of the World
180 Opposites!
MVA = KV 2
Z( R
c )
Rv
+Q
+P
-Q
-P
M o r e P o w e
r
M o r e P o w e
r
SS
SS
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Generation-typically at 4-20kV
Transmission-typically at 230-765kV
Subtransmission-typically at 69-161kV
Receives power from transmission system andtransforms into subtransmission level
Receives power from subtransmission systemand transforms into primary feeder voltage
Distribution network-typically 2.4-69kV
Low voltage (service)-typically 120-600V
TypicalBulk
PowerSystem
TypicalBulk
PowerSystem
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1. Generator or Generator-Transformer Units
2. Transformers3. Buses
4. Lines (transmission and distribution)
5. Utilization equipment (motors, static loads, etc.)6. Capacitor or reactor (when separately protected)
Unit Generator-Tx zoneBus zone
Line zone
Bus zone
Transformer zoneTransformer zone
Bus zone
Generator
~
XFMR Bus Line Bus XFMR Bus Motor
Motor zone
Protection ZonesProtection Zones
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1. Overlap is accomplished by the locations of CTs, the key source forprotective relays.
2. In some cases a fault might involve a CT or a circuit breaker itself, whichmeans i t can not be cleared until adjacent breakers (local or remote) areopened.
Zone A Zone B
Relay Zone A
Relay Zone B
CTs are located at both sides of CB-fault between CTs is cleared from both remotesides
Zone A Zone B
Relay Zone A
Relay Zone B
CTs are located at one side of CB-fault between CTs is sensed by both relays,remote righ t side operate only.
Zone OverlapZone Overlap
l i l h i l
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Electrical Mechanical
Parameter Comparisons
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El i l M h i l
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Electrical Mechanical
Parameter Comparisons
ff f C i i & d i d
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Effects of Capacitive & Inductive Loads
on Current
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Motor Model and Starting Curves
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1. One-line diagram of the system or area involved
2. Impedances and connections of power equipment, systemfrequency, voltage level and phase sequence
3. Existing schemes
4. Operating procedures and practices affecting protection
5. Importance of protection required and maximum allowedclearance times
6. System fault studies
7. Maximum load and system swing limits
8. CTs and VTs locations, connections and ratios
9. Future expansion expectance
10. Any special considerations for application.
What Info is Required to Apply ProtectionWhat Info is Required to Apply Protection
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C37.2:Device
Numbers
Partial listing
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One Line Diagram Non-dimensioned diagram showing how
pieces of electrical equipment areconnected
Simplification of actual system Equipment is shown as boxes, circles and
other simple graphic symbols
Symbols should follow ANSI or IECconventions
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1-Line Symbols [1]
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1-Line Symbols [2]
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1-Line Symbols [3]
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1-Line Symbols [4]
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1-Line [1]
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1-Line [2]
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3-Line
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Diagram Comparison
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C37.2: Standard Reference Position 1) These may be speed, voltage, current ,
load, or similar adjusting devicescomprising rheostats, springs, levers, orother components for the purpose.
2) These electr ically operated devices areof the nonlatched-in type, whose contactposition is dependent only upon thedegree of energization of the operating,restraining, or holding coil or coils thatmay or may not be suitable forcont inuous energization . The de-energized posi tion of the device is that
with all coils de-energized 3) The energizing influences for thesedevices are considered to be,respectively, rising temperature, risinglevel, incr easing flow, rising speed,increasing vibration, and increasingpressure.
4.5.3) In the case of latched-in or hand-reset relays, which operate fromprotective devices to perform theshutdown of a piece of equipment andhold it out of service, the contacts shouldpreferably be shown in the normal,nonlockout position
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CB Trip Circuit (Simplified)
Showing Contacts NOT in
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Showing Contacts NOT inStandard Reference Condition
Some people show the contact
state changed like this
Showing Contacts NOT in
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Showing Contacts NOT inStandard Reference Condition
Better practice, do not change the
contact style, but rather usemarks like these to indicate non-standard reference position
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Lock Out Relay
86b
PR
86b
Shown in RESET position
86TC 86a
CB Coil Circuit Monitoring:
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56GE Consumer & Industrial
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CB Coil Circuit Monitoring:
T with CB Closed; C with CB Opened
Coil Monitor Input
Trip/Close Contact
+
T/CCoil
-
52/aor
52/b
Breaker
Relay
52/a for trip circuit52/b for close circuit
CB Coil Circuit Monitoring:
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CB Coil Circuit Monitoring:
Both T&C Regardless of CB state
Breaker
Relay
Breaker
Relay
Current Transformers
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Current transformers are used to step primary system currentsto values usable by relays, meters, SCADA, transducers, etc.
CT ratios are expressed as primary to secondary; 2000:5, 1200:5,600:5, 300:5
A 2000:5 CT has a CTR of 400
Standard IEEE CT Relay
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IEEE relay class is defined in terms of the voltage a CTcan deliver at 20 times the nominal current ratingwithout exceeding a 10% composite ratio error.
For example, a relay class of C100 on a 1200:5 CT means thatthe CT can develop 100 volts at 24,000 primary amps(1200*20) without exceeding a 10% ratio error. Maximumburden = 1 ohm.
100 V = 20 * 5 * (1ohm)200 V = 20 * 5 * (2 ohms)400 V = 20 * 5 * (4 ohms)800 V = 20 * 5 * (8 ohms)
Standard IEEE CT Relay Accuracy
Excitation Curve
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Excitation Curve
Standard IEEE CT Burdens (5 Amp)
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Application BurdenDesignation
Impedance(Ohms)
VA @5 amps
PowerFactor
Metering B0.1 0.1 2.5 0.9B0.2 0.2 5 0.9B0.5 0.5 12.5 0.9B0.9 0.9 22.5 0.9B1.8 1.8 45 0.9
Relaying B1 1 25 0.5B2 2 50 0.5
B4 4 100 0.5B8 8 200 0.5
Standard IEEE CT Burdens (5 Amp)(Per IEEE Std. C57.13-1993)
Current into the Dot, Out of the DotC f h d i h d
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62GE Consumer & Industrial
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Current out of the dot, in to the dotForward Power
IP
IS
IR
Relayor Meter
Forward Power
IP
IS
IR
Relayor Meter
Voltage Transformers
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VP
VSRelay
Voltage (potential) transformers are used to isolate and stepdown and accurately reproduce the scaled voltage for theprotective device or relay
VT ratios are typically expressed as pr imary to secondary;14400:120, 7200:120
A 4160:120 VT has a VTR of 34.66
Typical CT/VT Circuits
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Typical CT/VT Circuits
Courtesy of Blackburn, Protective Relay: Principles and Applications
CT/VT Circuit vs. Casing Ground
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g
Case ground made at IT location Secondary circuit ground made at first point of
use
Case
Secondary Circuit
Equipment Grounding
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Equipment Grounding
Prevents shock exposure of personnel
Provides current carrying capability for theground-fault current Grounding includes design and construction of
substation ground mat and CT and VT safetygrounding
System Grounding
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System Grounding
Limits overvoltages Limits difference in electric potential through local
area conducting objects Several methods
Ungrounded Reactance Coil Grounded High Z Grounded Low Z Grounded Solidly Grounded
System Grounding
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1. Ungrounded: There is no intentionalground applied to the system-however its grounded throughnatural capacitance. Found in 2.4-15kV systems.
2. Reactance Grounded: Total systemcapacitance is cancelled by equalinductance. This decreases the
current at the fault and limits voltageacross the arc at the fault to decreasedamage.
X0
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3. High Resistance Grounded: Limitsground fault current to 10A-20A.
Used to limit transient overvoltagesdue to arcing ground faults.
R0 = 2X 0
System Grounding
System Grounding
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5. Solidly Grounded: There is aconnection of transformer orgenerator neutral directly to stationground.Effectively Grounded: R 0
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Grounding Differences.Why?
Solidly Grounded Much ground current (damage) No neutral voltage shift
Line-ground insulation
Limits step potential issues Faulted area will clear Inexpensive relaying
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Grounding Differences.Why?
Somewhat Grounded Manage ground current (manage damage) Some neutral voltage shift Faulted area will clear More expensive than solid, less expensive then
ungrounded
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Grounding Differences.Why?
Ungrounded Very little ground current (less damage) Big neutral voltage shift
Must insulate line-to-line voltage
May run system while trying to find ground fault Relay more difficult/costly to detect and locate ground
faults
If you get a second ground fault on adjacent phase,watch out!
System Grounding Influences
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Ground Fault Detection MethodsSource
50
51
50N
51N
50
51
50N
51N
50
51
50N
51N
Low/No Z
System Grounding Influences
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Ground Fault Detection MethodsSource
50
51
50G
51G
50
51
50G
51G
50
51
50G
51G
Med/High Z
Basic Current Connections:
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How System is GroundedDetermines How Ground Fault is Detected
Medium/HighResistance
Ground
Low/NoResistance
Ground
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Substation TypesSubstation Types Single Supply
Multiple Supply
Mobile Substations for emergencies
Types are defined by number of
transformers, buses, breakers to provide
adequate service for application
Industrial Substation Arrangements(Typical)
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(Typical)
Industrial Substation Arrangements(Typical)
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( yp )
Utility Substation ArrangementsUtility Substation Arrangements(Typical)
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Single Bus, 1 Tx, Dual supply Single Bus, 2 Tx, DualSupply
2-sections Bus with HS Tie-Breaker,2 Tx, Dual Supply
(Typical)
Utility Substation ArrangementsUtility Substation Arrangements(Typical)
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Breaker-and-a-half allows reduction ofequipment cost by using 3 breakers foreach 2 circuits. For load transfer andoperation is simple, but relaying iscomplex as middle breaker is responsibleto both circuits
Bus1
Bus 2
Ring bus advantage that onebreaker per circuit. Also eachoutgoing circuit (Tx) has 2 sourcesof supply. Any breaker can be takenfrom service without disruptingothers.
(Typical)
Utility Substation ArrangementsUtility Substation Arrangements(Typical)
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Double Bus: Upper Main andTransfer, bottom Double Main bus
Main bus
Aux. bus
Bus 1
Bus 2 T i e
b r e a
k e r
Main
Reserve
Transfer
Main-Reserved and TransferBus: A llows maintenance of anybus and any breaker
(Typical)
Switchgear Defined
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Assemblies containing electrical switching,protection, metering and management devices
Used in three-phase, high-power industrial,
commercial and utility applications Covers a variety of actual uses, including motor
control, distribution panels and outdoorswitchyards
The term "switchgear" is plural, even whenreferring to a single switchgear assembly (neversay, "switchgears")
May be a described in terms of use: "the generator switchgear" "the stamping line switchgear"
Switchgear Examples
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Switchgear:MetalClad vs. Metal-Enclosed
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Metal-clad switchgear (C37.20.2) Breakers or switches must be draw-out design Breakers must be electrically operated, with anti-
pump feature All bus must be insulated Completely enclosed on all side and top with
grounded metal
Breaker, bus and cable compartments isolated bymetal barriers, with no intentional openings Automatic shutters over primary breaker stabs.
Metal-enclosed switchgear Bus not insulated Breakers or switches not required to be draw-out No compartment barriering required
Switchgear Basics [1]
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All Switchgear has a metalenclosure
Metalclad constructionrequires 11 gauge steel
between sections and maincompartments Prevents contact with live
circuits and propagation ofionized gases in the unlikelyevent of an internal fault.
Enclosures are also rated asweather-tight for outdoor use
Metalclad gear will includeshutters to ensure thatpowered buses are covered atall times, even when a circuitbreaker is removed.
Switchgear Basics [2]
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Devices such as circuit breakers or fused switchesprovide protection against short circuits and groundfaults
Interrupting devices (other than fuses) are non-automatic. They require control signals instructingthem to open or close.
Monitoring and control circuitry work together withthe switching and interrupting devices to turncircuits on and off, and guard circuits fromdegradation or fluctuations in power supply thatcould affect or damage equipment
Routine metering functions include operatingamperes and voltage, watts, kilowatt hours,frequency, power factor.
Switchgear Basics [3]
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Power to switchgear isconnected via Cables or BusDuct
The main internal bus carriespower between elements withinthe switchgear
Power within the switchgearmoves from compartment to
compartment on horizontal bus,and within compartments onvertical bus
Instrument Transformers (CTs& PTs) are used to step downcurrent and voltage from theprimary circuits or use in lower-energy monitoring and controlcircuitry.
Air Magnetic Breakers
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A Good Day in System
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Protection CTs and VTs bring electrical info to relays Relays sense current and voltage and declare
fault Relays send signals through control circuits to
circuit breakers Circuit breaker(s) correctly trip
What Could Go Wrong Here????
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P i P f S i i
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Protection Performance Statistics
Correct and desired: 92.2% Correct but undesired: 5.3%
Incorrect: 2.1% Fail to trip: 0.4%
Contribution to Faults
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Fault Types (Shunt)
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Short Circuit CalculationFault Types Single Phase to Ground
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X
X
Z
Z
Z
G
BC
A
Fault Types Single Phase to Ground
Short Circ it Calc lations
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X
X
Z
Z
Z
G
BC
A
Short Circuit CalculationsFault Types Line to Line
Short Circuit CalculationsF l T Th Ph
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Fault Types Three Phase
Z
Z
Z
G
BC
AX
X
X
AC & DC Current Components
of Fault Current
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of Fault Current
Variation of current with timeduring a fault
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during a fault
Variation of generator reactanceduring a fault
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during a fault
Useful Conversions
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Per Unit System
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Per Unit System
Establish two base quantities:
Standard practice is to define
Base power 3 phase Base voltage line to lineOther quantities derived with basic powerequations
Per Unit Basics
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Short Circuit Calculations
Per Unit System
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Per Unit SystemPer Unit Value = Actual Quantity
Base Quantity Vpu = V actual
Vbase
Ipu = I actualIbase
Zpu = Z actualZbase
Short Circuit CalculationsPer Unit System
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Per Unit System
3 x kV L-L base I base =
x 1000MVA base
Z base =kV2L-L base MVA base
Short Circuit Calculations
Per Unit System Base Conversion
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Per Unit System Base Conversion
Zpu = Z actualZbase Zbase =
kV 2baseMVA base
Zpu1 = MVA base1kV 2base1X Zactual Zpu2 =
MVA base2kV 2base2
X Zactual
Zpu2
= Zpu1 x
kV 2base1 x
MVA base2kV 2base2 MVA base1
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Utility Information
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kV
MVA short circuit Voltage and voltage variation
Harmonic and flicker requirements
Generator Information
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Rated kV
Rate MVA, MW Xs; synchronous reactance
Xd; transient reactance Xd; subtransient reactance
Motor Drive
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kV Rated HP or KW Type
Sync or Induction
Subtransient orlocked rotor current
Is it regenerative Harmonic spectrum
Transformers Rated primary and secondary kV
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Rated MVA (OA, FA, FOA)
Winding connections (Wye, Delta) Impedance and MVA base of impedance
Reactors Rated kV
Ohms
Cables and Transmission Lines
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For rough calculations, some can be neglected Length of conductor Impedance at given length Size of conductor Spacing of overhead conductors Rated voltage Type of conduit Number of conductors or number per phase
ANSI 1-Line
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IEC 1-Line
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Short Circuit Study [1]
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Short Circuit Study [2]
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A Study of a Fault.
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Fault Interruption and Arcing
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Arc Flash Hazard
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Arc Flash Mitigation:Problem Description
An electric arc flash can occur if a conductive object gets
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An electric arc flash can occur if a conductive object getstoo close to a high-amp current source or by equipment
failure (ex., while opening or closing disconnects, rackingout) The arc can heat the air to temperatures as high as 35,000 F, and
vaporize metal in equipment
The arc flash can cause severe skin burns by direct heat exposureand by igniting clothing The heating of the air and vaporization of metal creates a pressure
wave (arc blast) that can damage hearing and cause memory loss(from concussion) and other injuries.
Flying metal parts are also a hazard.
Methods to Reduce
Arc Flash Hazard Arc flash energy may be expressed in I2t terms
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Arc flash energy may be expressed in I t terms,so you can decrease the I or decrease the t tolessen the energy
Protective relays can help lessen the t byoptimizing sensitivity and decreasing clearing time Protective Relay Techniques
Other means can lessen the I by limiting faultcurrent Non-Protective Relay Techniques
Non-Protective Relaying Methods
of Reducing Arc Flash Hazard System design Electronic current limiters (thesed i t d
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modifications increasepower transformerimpedance Addition of phase reactors Faster operating breakers
Splitting of buses Current limiting fuses
(provides partial protectiononly for a limited current
range)
devices sense overcurrent andinterrupt very high currents with
replaceable conductor links(explosive charge) Arc-resistant switchgear (this
really doesn't reduce arc flashenergy; it deflects the energyaway from personnel)
Optical arc flash protection viafiber sensors
Optical arc flash protection vialens sensors
Protective Relaying Methodsof Reducing Arc Flash Hazard
Bus differential protection (thisreduces the arc flash energy by
FlexCurve for improvedcoordination opportunities
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reduces the arc flash energy byreducing the clearing time
Zone interlock schemes wherebus relay selectively is allowedto trip or block depending onlocation of faults as identifiedfrom feeder relays
Temporary setting changes toreduce clearing time duringmaintenance
Sacrifices coordination
coordination opportunities Employ 51VC/VR on feeders
fed from small generation toimprove sensitivity andcoordination
Employ UV light detectors with
current disturbance detectorsfor selective gear tripping
Fuses vs. Relayed Breakers
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Arc Flash Hazards
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Arc Pressure Wave
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Arc Flash Warning Example [1]
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Arc Flash Warning Example [2]
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Arc Flash Warning Example [3]
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Copy of this presentation are at:
www L-3 com\private\Levine
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www.L 3.com\private\Levine
Protection Fundamentals
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QUESTIONS?