GE Consumer

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Protection Basics

• Presented by
• John S. Levine, P.E.
• Levine Lectronics and Lectric, Inc.
• 770 565-1556
• John_at_L-3.com

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Protection Fundamentals
ByJohn Levine
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Outline

• Introductions
• Tools
• Enervista Launchpad
• On Line Store
• Demo Relays at Levine
• ANSI number
• Training CDs
• Protection Fundamentals

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Objective

• We are here to help make your job easier. This
  is very informal and designed around
  Applications. Please ask question. We are not
  here to preach to you.
• The knowledge base in the room varies greatly.
  If you have a question, there is a good chance
  there are 3 or 4 other people that have the same
  question. Please ask it.

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Tools
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(No Transcript)
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Demo Relays at L-3
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Relays at L-3
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(No Transcript)
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GE Multilin Training CDs
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ANSI Symbols
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Conversion of Electro-Mechanical to Electronic
sheet
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PowerPoint presentations at
http//l-3.com/private/ieee/
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Protection Fundamentals
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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
  the fault or abnormal operating condition
• Speed Usually the faster the better in terms of
  minimizing equipment damage and maintaining
  system integrity
• Simplicity KISS
• Economics Dont break the bank

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Art Science of Protection

• Selection of protective relays requires
  compromises
• Maximum and Reliable protection at minimum
  equipment cost
• High Sensitivity to faults and insensitivity to
  maximum load currents
• High-speed fault clearance with correct
  selectivity
• Selectivity in isolating small faulty area
• Ability to operate correctly under all
  predictable power system conditions

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Art Science of Protection

• Cost of protective relays should be balanced
  against risks involved if protection is not
  sufficient and not enough redundancy.
• Primary objectives is to have faulted zones
  primary protection operate first, but if there
  are protective relays failures, some form of
  backup protection is provided.
• Backup protection is local (if local primary
  protection fails to clear fault) and remote (if
  remote protection fails to operate to clear fault)

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Primary 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 other phases
• Isolators (switches) - to create a visible and
  permanent isolation 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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Primary 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 for charge current (shunt)
• VT and CT - to measure primary current and
  voltage and supply scaled down values to PC,
  metering, SCADA, etc.
• Regulators - voltage, current, VAR, phase angle,
  etc.

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Types of Protection

• Overcurrent
• 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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Instantaneous Overcurrent Protection (IOC)
Definite Time Overcurrent

• Relay closest to fault operates first
• Relays closer to source operate slower
• Time between operating for same current is called
  CTI (Clearing Time Interval)

Distribution Substation
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(TOC) Coordination

• Relay closest to fault operates first
• Relays closer to source operate slower
• Time between operating for same current is called
  CTI

Distribution Substation
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Time Overcurrent Protection (TOC)

• Selection of the curves uses what is termed as a
  time multiplier or time dial to effectively
  shift the curve up or down on the time axis
• Operate region lies above selected curve, while
  no-operate region lies below it
• Inverse curves can approximate fuse curve shapes

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Time Overcurrent Protection(51, 51N, 51G)
Multiples of pick-up
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Classic Directional Overcurrent Scheme for Looped
System Protection
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Types of Protection

• Differential
• current in current out
• Simple
• Very fast
• Very defined clearing area
• Expensive
• Practical distance limitations
• Line differential systems overcome this using
  digital communications

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Differential

• Note CT polarity dots
• This is a through-current representation
• Perfect waveforms, no saturation

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Differential

• Note CT polarity dots
• This is an internal fault representation
• Perfect waveforms, no saturation

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Types of Protection

• Voltage
• Uses voltage to infer fault or abnormal condition
• May employ definite time or inverse time curves
• May also be used for undervoltage load shedding
• Simple
• May be slow
• Selectivity at the cost of speed (coordination
  stacks)
• Inexpensive

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Types of Protection

• Frequency
• Uses frequency of voltage to detect power balance
  condition
• May employ definite time or inverse time curves
• Used for load shedding machinery
  under/overspeed protection
• Simple
• May be slow
• Selectivity at the cost of speed can be expensive

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Types of Protection

• Power
• Uses voltage and current to determine power 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 Protection

• Distance (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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Impedance
X
Z
L

• Relay in Zone 1 operates first
• Time between Zones is called CTI

R
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Impedance POTT Scheme

• POTT will trip only faulted line section
• RO elements are 21 21G or 67N

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Power vs. Protection EngineerViews of the World

• 180 Opposites!

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TypicalBulkPower System
Generation-typically at 4-20kV
Transmission-typically at 230-765kV
Receives power from transmission system and
transforms into subtransmission level
Subtransmission-typically at 69-161kV
Receives power from subtransmission system and
transforms into primary feeder voltage
Distribution network-typically 2.4-69kV
Low voltage (service)-typically 120-600V
36 GE Consumer Industrial Multilin
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Protection Zones

1. Generator or Generator-Transformer Units
2. Transformers
3. Buses
4. Lines (transmission and distribution)
5. Utilization equipment (motors, static loads,
   etc.)
6. Capacitor or reactor (when separately protected)

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Zone Overlap

1. Overlap is accomplished by the locations of CTs,
   the key source for protective relays.
2. In some cases a fault might involve a CT or a
   circuit breaker itself, which means it can not be
   cleared until adjacent breakers (local or remote)
   are opened.

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Electrical Mechanical Parameter Comparisons
39 GE Consumer Industrial Multilin
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Electrical Mechanical Parameter Comparisons
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Effects of Capacitive Inductive Loads on
Current
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Motor Model and Starting Curves
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What Info is Required to Apply Protection

• One-line diagram of the system or area involved
• Impedances and connections of power equipment,
  system frequency, voltage level and phase
  sequence
• Existing schemes
• Operating procedures and practices affecting
  protection
• Importance of protection required and maximum
  allowed clearance times
• System fault studies
• Maximum load and system swing limits
• CTs and VTs locations, connections and ratios
• Future expansion expectance
• Any special considerations for application.

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C37.2 Device Numbers

• Partial listing

44 GE Consumer Industrial Multilin
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One Line Diagram

• Non-dimensioned diagram showing how pieces of
  electrical equipment are connected
• Simplification of actual system
• Equipment is shown as boxes, circles and other
  simple graphic symbols
• Symbols should follow ANSI or IEC conventions

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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 devices comprising rheostats,
  springs, levers, or other components for the
  purpose.
• 2) These electrically operated devices are of the
  nonlatched-in type, whose contact position is
  dependent only upon the degree of energization of
  the operating, restraining, or holding coil or
  coils that may or may not be suitable for
  continuous energization. The de-energized
  position of the device is that with all coils
  de-energized
• 3) The energizing influences for these devices
  are considered to be, respectively, rising
  temperature, rising level, increasing flow,
  rising speed, increasing vibration, and
  increasing pressure.
• 4.5.3) In the case of latched-in or hand-reset
  relays, which operate from protective devices to
  perform the shutdown of a piece of equipment and
  hold it out of service, the contacts should
  preferably be shown in the normal, nonlockout
  position

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CB Trip Circuit (Simplified)
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Showing Contacts NOT in Standard Reference
Condition
Some people show the contact state changed like
this
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Showing Contacts NOT in Standard Reference
Condition
Better practice, do not change the contact style,
but rather use marks like these to indicate
non-standard reference position
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Lock Out Relay
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CB Coil Circuit MonitoringT with CB Closed C
with CB Opened
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CB Coil Circuit MonitoringBoth TC Regardless
of CB state
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Current Transformers

• Current transformers are used to step primary
  system currents to values usable by relays,
  meters, SCADA, transducers, etc.
• CT ratios are expressed as primary to secondary
  20005, 12005, 6005, 3005
• A 20005 CT has a CTR of 400

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Standard IEEE CT Relay Accuracy

• IEEE relay class is defined in terms of the
  voltage a CT can deliver at 20 times the nominal
  current rating without exceeding a 10 composite
  ratio error.
• For example, a relay class of C100 on a 12005
  CT means that the CT can develop 100 volts at
  24,000 primary amps (120020) without exceeding a
  10 ratio error. Maximum burden 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)

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Excitation Curve
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Standard IEEE CT Burdens (5 Amp) (Per IEEE Std.
C57.13-1993)
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Current into the Dot, Out of the DotCurrent out
of the dot, in to the dot
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Voltage Transformers

• Voltage (potential) transformers are used to
  isolate and step down and accurately reproduce
  the scaled voltage for the protective device or
  relay
• VT ratios are typically expressed as primary to
  secondary 14400120, 7200120
• A 4160120 VT has a VTR of 34.66

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Typical CT/VT Circuits
Courtesy of Blackburn, Protective Relay
Principles and Applications
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CT/VT Circuit vs. Casing Ground
Case
Secondary Circuit

• Case ground made at IT location
• Secondary circuit ground made at first point of
  use

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Equipment Grounding

• Prevents shock exposure of personnel
• Provides current carrying capability for the
  ground-fault current
• Grounding includes design and construction of
  substation ground mat and CT and VT safety
  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

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System Grounding
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System Grounding
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System Grounding
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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!

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System Grounding Influences Ground Fault
Detection Methods
Low/No Z
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System Grounding Influences Ground Fault
Detection Methods
Med/High Z
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Basic Current ConnectionsHow System is Grounded
Determines How Ground Fault is Detected
Medium/High Resistance Ground
Low/No Resistance Ground
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Substation Types

• Single Supply
• Multiple Supply
• Mobile Substations for emergencies
• Types are defined by number of transformers,
  buses, breakers to provide adequate service for
  application

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Industrial Substation Arrangements
(Typical)
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Industrial Substation Arrangements
(Typical)
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Utility Substation Arrangements
(Typical)
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Utility Substation Arrangements
(Typical)
Breaker-and-a-half allows reduction of equipment
cost by using 3 breakers for each 2 circuits. For
load transfer and operation is simple, but
relaying is complex as middle breaker is
responsible to both circuits
Ring bus advantage that one breaker per circuit.
Also each outgoing circuit (Tx) has 2 sources of
supply. Any breaker can be taken from service
without disrupting others.
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Utility Substation Arrangements
(Typical)
Main-Reserved and Transfer Bus Allows
maintenance of any bus and any breaker
Double Bus Upper Main and Transfer, bottom
Double Main bus
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Switchgear Defined

• 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 outdoor
  switchyards
• The term "switchgear" is plural, even when
  referring to a single switchgear assembly (never
  say, "switchgears")
• May be a described in terms of use
• "the generator switchgear"
• "the stamping line switchgear"

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Switchgear Examples
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Switchgear MetalClad vs. Metal-Enclosed

• 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 by
  metal 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

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Switchgear Basics 1

• All Switchgear has a metal enclosure
• Metalclad construction requires 11 gauge steel
  between sections and main compartments
• Prevents contact with live circuits and
  propagation of ionized gases in the unlikely
  event of an internal fault.
• Enclosures are also rated as weather-tight for
  outdoor use
• Metalclad gear will include shutters to ensure
  that powered buses are covered at all times, even
  when a circuit breaker is removed.

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Switchgear Basics 2

• Devices such as circuit breakers or fused
  switches provide protection against short
  circuits and ground faults
• Interrupting devices (other than fuses) are
  non-automatic. They require control signals
  instructing them to open or close.
• Monitoring and control circuitry work together
  with the switching and interrupting devices to
  turn circuits on and off, and guard circuits from
  degradation or fluctuations in power supply that
  could affect or damage equipment
• Routine metering functions include operating
  amperes and voltage, watts, kilowatt hours,
  frequency, power factor.

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Switchgear Basics 3

• Power to switchgear is connected via Cables or
  Bus Duct
• The main internal bus carries power between
  elements within the switchgear
• Power within the switchgear moves from
  compartment to compartment on horizontal bus, and
  within compartments on vertical bus
• Instrument Transformers (CTs PTs) are used to
  step down current and voltage from the primary
  circuits or use in lower-energy monitoring and
  control circuitry.

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Air Magnetic Breakers
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SF6 and Vacuum Breakers
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A Good Day in System 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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A Bad Day in System Protection

• CTs or VTs are shorted, opened, or their wiring
  is
• Relays do not declare fault due to setting
  errors, faulty relay, CT saturation
• Control wires cut or batteries dead so no signal
  is sent from relay to circuit breaker
• Circuit breakers do not have power, burnt trip
  coil or otherwise fail to trip

Protection Systems Typically are Designed for N-1
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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

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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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Short Circuit CalculationsFault Types Line to
Line
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Short Circuit CalculationsFault Types Three
Phase
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AC DC Current Components of Fault Current
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Variation of current with time during a fault
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Variation of generator reactanceduring a fault
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Useful Conversions
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Per Unit System

• Establish two base quantities
• Standard practice is to define
• Base power 3 phase
• Base voltage line to line
• Other quantities derived with basic power
  equations

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Per Unit Basics
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Short Circuit CalculationsPer Unit System
Per Unit Value Actual Quantity Base
Quantity
Vpu Vactual Vbase
Ipu Iactual Ibase
Zpu Zactual Zbase
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Short Circuit CalculationsPer Unit System
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Short Circuit CalculationsPer Unit System Base
Conversion
Zpu Zactual Zbase
Zbase kV 2base MVAbase
Zpu2 MVAbase2 kV 2base2
Zpu1 MVAbase1 kV 2base1
X Zactual
X Zactual
? Zpu2 Zpu1 x kV 2base1 x MVAbase2
kV 2base2 MVAbase1
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Information for Short Circuit, Load Flow and
Voltage Studies

• To perform the above studies, information is
  needed on the electrical apparatus and sources to
  the system under consideration

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(No Transcript)
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Utility Information

• kV
• MVA short circuit
• Voltage and voltage variation
• Harmonic and flicker requirements

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Generator Information

• Rated kV
• Rate MVA, MW
• Xs synchronous reactance
• Xd transient reactance
• Xd subtransient reactance

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Motor Drive

• kV
• Rated HP or KW
• Type
• Sync or Induction
• Subtransient or locked rotor current

• Is it regenerative
• Harmonic spectrum

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Transformers

• Rated primary and secondary kV
• Rated MVA (OA, FA, FOA)
• Winding connections (Wye, Delta)
• Impedance and MVA base of impedance

Reactors

• Rated kV
• Ohms

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Cables and Transmission Lines

• 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

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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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Short Circuit Study 3
122 GE Consumer Industrial Multilin
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A Study of a Fault.
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Fault Interruption and Arcing
124 GE Consumer Industrial Multilin
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Arc Flash Hazard
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Arc Flash MitigationProblem Description

• An electric arc flash can occur if a conductive
  object gets too close to a high-amp current
  source or by equipment failure (ex., while
  opening or closing disconnects, racking out)
• 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 exposure and 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.

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Methods to Reduce Arc Flash Hazard

• Arc flash energy may be expressed in I2t terms,
  so you can decrease the I or decrease the t to
  lessen the energy
• Protective relays can help lessen the t by
  optimizing sensitivity and decreasing clearing
  time
• Protective Relay Techniques
• Other means can lessen the I by limiting fault
  current
• Non-Protective Relay Techniques

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Non-Protective Relaying Methods of Reducing Arc
Flash Hazard

• System design modifications increase power
  transformer impedance
• Addition of phase reactors
• Faster operating breakers
• Splitting of buses
• Current limiting fuses (provides partial
  protection only for a limited current range)

• Electronic current limiters (these devices sense
  overcurrent and interrupt very high currents
  with replaceable conductor links (explosive
  charge)
• Arc-resistant switchgear (this really doesn't
  reduce arc flash energy it deflects the energy
  away from personnel)
• Optical arc flash protection via fiber sensors
• Optical arc flash protection via lens sensors

129
Protective Relaying Methods of Reducing Arc
Flash Hazard

• Bus differential protection (this reduces the arc
  flash energy by reducing the clearing time
• Zone interlock schemes where bus relay
  selectively is allowed to trip or block depending
  on location of faults as identified from feeder
  relays
• Temporary setting changes to reduce clearing time
  during maintenance
• Sacrifices coordination

• FlexCurve for improved coordination opportunities
  
• Employ 51VC/VR on feeders fed from small
  generation to improve sensitivity and
  coordination
• Employ UV light detectors with current
  disturbance detectors for selective gear tripping

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Fuses vs. Relayed Breakers
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Arc Flash Hazards
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Arc Pressure Wave
132 GE Consumer Industrial Multilin
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Arc Flash Warning Example 1
133 GE Consumer Industrial Multilin
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Arc Flash Warning Example 2
134 GE Consumer Industrial Multilin
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Arc Flash Warning Example 3
135 GE Consumer Industrial Multilin
136

• Copy of this presentation are at
• www.L-3.com\private\IEEE

137
Protection Fundamentals

• QUESTIONS?