Protection Fundamentals Levine Lectronics and Lectric by ixieshaofang


									     Protection Basics
          Presented by
       John S. Levine, P.E.
Levine Lectronics and Lectric, Inc.
          770 565-1556
Protection Fundamentals

       John Levine
•   Introductions
•   Tools
    – Enervista Launchpad
    – On – Line Store
    – Demo Relays at Levine
•   ANSI number
•   Training CD’s
•   Protection Fundamentals
• 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
Demo Relays at L-3
Relays at L-3
GE Multilin Training CD’s
ANSI Symbols
Conversion of Electro-Mechanical
        to Electronic sheet
PowerPoint presentations at:
Protection Fundamentals
Desirable Protection Attributes
• Reliability: System operate properly
  – Security: Don’t trip when you shouldn’t
  – 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: Don’t break the bank
       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
     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 zone’s
  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)
  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

• 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).
  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 P&C, metering, SCADA, etc.

• Regulators - voltage, current, VAR, phase angle, etc.
         Types of Protection
• 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
Instantaneous Overcurrent Protection (IOC) &
                  Definite Time Overcurrent
                      • Relay closest to fault operates
                      • Relays closer to source
                        operate slower
                      • Time between operating for
                        same current is called CTI
                        (Clearing Time Interval)

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

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
Time Overcurrent Protection
      (51, 51N, 51G)

          Multiples of pick-up
Classic Directional Overcurrent
   Scheme for Looped System
      Types of Protection
  – current in = current out
  – Simple
  – Very fast
  – Very defined clearing area
  – Expensive
  – Practical distance limitations
     • Line differential systems overcome this using
       digital communications

• Note CT polarity
• This is a through
• Perfect
  waveforms, no

• Note CT
  polarity dots
• This is an
  internal fault
• Perfect
  waveforms, no
        Types of Protection
• Uses voltage to infer fault or abnormal
• May employ definite time or inverse time
• May also be used for undervoltage load
  – Simple
  – May be slow
  – Selectivity at the cost of speed (coordination
  – Inexpensive
       Types of Protection
• Uses frequency of voltage to detect power
  balance condition
• May employ definite time or inverse time
• Used for load shedding & machinery
  under/overspeed protection
  – Simple
  – May be slow
  – Selectivity at the cost of speed can be expensive
      Types of Protection
• 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
        Types of Protection
Distance (Impedance)
– Uses voltage and current to determine impedance of
– Set on impedance [R-X] plane
– Uses definite time
– Impedance related to distance from relay
– Complicated
– Fast
– Somewhat defined clearing area with reasonable
– Expensive
– Communication aided schemes make more selective
     X            ZL
                                    • Relay in Zone 1 operates first
                                    • Time between Zones is called

T2                                                     ZB


                  21                          21

                       A                           B
               Impedance: POTT Scheme

– POTT will trip only faulted line section
– RO elements are 21; 21G or 67N
Power vs. Protection Engineer:
    Views of the World

        180 Opposites!
Generation-typically at 4-20kV
Transmission-typically at 230-765kV   System
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
                                        GE Consumer & Industrial
                         Protection Zones
    •       Generator or Generator-Transformer Units
    •       Transformers
    •       Buses
    •       Lines (transmission and distribution)
    •       Utilization equipment (motors, static loads, etc.)
    •       Capacitor or reactor (when separately protected)
                                  Bus zone               Bus zone                      Bus zone
Unit Generator-Tx zone                       Line zone
                                                                    Transformer zone              Motor zone
               Transformer zone

Generator       XFMR               Bus       Line         Bus             XFMR          Bus             Motor
                                     Zone Overlap
•   Overlap is accomplished by the locations of CTs, the key source for
    protective relays.
•   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

                            Relay Zone A                                     Relay Zone A

    Zone A   Relay Zone B                  Zone B    Zone A   Relay Zone B                  Zone B

CTs are located at both sides of CB-                CTs are located at one side of CB-
fault between CTs is cleared from both remote       fault between CTs is sensed by both relays,
sides                                               remote right side operate only.
Electrical – Mechanical
Parameter Comparisons

                          GE Consumer & Industrial
Electrical – Mechanical
Parameter Comparisons
Effects of Capacitive & Inductive Loads
              on Current
Motor Model and Starting Curves
    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.

• Partial listing

          GE Consumer & Industrial
         One Line Diagram
• Non-dimensioned diagram showing how
  pieces of electrical equipment are
• Simplification of actual system
• Equipment is shown as boxes, circles and
  other simple graphic symbols
• Symbols should follow ANSI or IEC
1-Line Symbols [1]
1-Line Symbols [2]
1-Line Symbols [3]
1-Line Symbols [4]
1-Line [1]
1-Line [2]
Diagram Comparison
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
                   •   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
CB Trip Circuit (Simplified)
  Showing Contacts NOT in
Standard Reference Condition

                Some people show the contact
                state changed like this
  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
Lock Out Relay
         CB Coil Circuit Monitoring:
T with CB Closed; C with CB Opened
      CB Coil Circuit Monitoring:
Both T&C Regardless of CB state
               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; 2000:5, 1200:5,
    600:5, 300:5
•   A 2000:5 CT has a “CTR” of 400
      Standard IEEE CT Relay
• 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 1200:5 CT means that
     the CT can develop 100 volts at 24,000 primary amps
     (1200*20) 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)
Excitation Curve
Standard IEEE CT Burdens (5 Amp)
              (Per IEEE Std. C57.13-1993)
Current into the Dot, Out of the Dot
Current out of the dot, in to the dot
               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;
    14400:120, 7200:120
•   A 4160:120 VT has a “VTR” of 34.66


                    Typical CT/VT Circuits

Courtesy of Blackburn, Protective Relay: Principles and Applications
   CT/VT Circuit vs. Casing Ground

                           Secondary Circuit

• Case ground made at IT location
• Secondary circuit ground made at first point of
     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
             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
•   Ungrounded: There is no intentional
    ground applied to the system-
    however it’s grounded through
    natural capacitance. Found in 2.4-
    15kV systems.

2. Reactance Grounded: Total system
   capacitance is cancelled by equal
   inductance. This decreases the
   current at the fault and limits voltage
   across the arc at the fault to decrease
    X0 <= 10 * X1
           System Grounding
3. High Resistance Grounded: Limits
   ground fault current to 10A-20A.
   Used to limit transient overvoltages
   due to arcing ground faults.
   R0 <= X0C/3, X0C is capacitive zero
     sequence reactance

4. Low Resistance Grounded: To limit
   current to 25-400A
   R0 >= 2X0
            System Grounding

5. Solidly Grounded: There is a
   connection of transformer or
   generator neutral directly to station
   Effectively Grounded: R0 <= X1, X0
      <= 3X1, where R is the system
      fault resistance
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
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
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
  • If you get a second ground fault on adjacent phase,
    watch out!
 System Grounding Influences
Ground Fault Detection Methods

                  Low/No Z
 System Grounding Influences
Ground Fault Detection Methods

                  Med/High Z
  Basic Current Connections:
       How System is Grounded
Determines How Ground Fault is Detected

     Medium/High           Low/No
      Resistance          Resistance
       Ground              Ground
         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
Industrial Substation Arrangements
Industrial Substation Arrangements
     Utility Substation Arrangements

Single Bus, 1 Tx, Dual supply   Single Bus, 2 Tx, Dual   2-sections Bus with HS Tie-Breaker,
                                Supply                            2 Tx, Dual Supply
       Utility Substation Arrangements


     Bus 2

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

 Main bus

 Aux. bus

 Bus 1

 Bus 2

Double Bus: Upper Main and           Main-Reserved and Transfer
Transfer, bottom Double Main bus     Bus: Allows maintenance of any
                                     bus and any breaker
         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
• 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"
Switchgear Examples
            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
         Switchgear Basics [1]
• All Switchgear has a metal
• Metalclad construction
  requires 11 gauge steel
  between sections and main
• 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.
      Switchgear Basics [2]
• Devices such as circuit breakers or fused switches
  provide protection against short circuits and ground
• 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.
          Switchgear Basics [3]
• Power to switchgear is
  connected via Cables or Bus
• 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
Air Magnetic Breakers
SF6 and Vacuum Breakers
     A Good Day in System
– CTs and VTs bring electrical info to relays
– Relays sense current and voltage and declare
– Relays send signals through control circuits to
  circuit breakers
– Circuit breaker(s) correctly trip

  What Could Go Wrong Here????
          A Bad Day in System
– 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
Protection Performance Statistics

 •   Correct and desired: 92.2%
 •   Correct but undesired: 5.3%
 •   Incorrect: 2.1%
 •   Fail to trip: 0.4%
Contribution to Faults
Fault Types (Shunt)
       Short Circuit Calculation
Fault Types – Single Phase to Ground
Short Circuit Calculations
Fault Types – Line to Line
 Short Circuit Calculations
Fault Types – Three Phase
AC & DC Current Components
      of Fault Current
Variation of current with time
        during a fault
Variation of generator reactance
          during a fault
Useful Conversions
        Per Unit System
Establish two base quantities:

Ø   Standard practice is to define
     – Base power – 3 phase
     – Base voltage – line to line
Ø   Other quantities derived with basic power
Per Unit Basics
 Short Circuit Calculations
     Per Unit System

Per Unit Value =   Actual Quantity
                    Base Quantity

     Vpu = Vactual
      Ipu = Iactual
     Zpu = Zactual
Short Circuit Calculations
    Per Unit System
     Short Circuit Calculations
Per Unit System – Base Conversion

Zpu = Zactual                    Zbase = kV            2
      Zbase                                       MVAbase

Zpu1 = MVAbase1                       Zpu2 = MVAbase2
                        X   Zactual               kV   2
       kV   2
                base1                                      base2   Zactual
     ] Zpu2 =Zpu1 x kV                base1 x   MVAbase2
                              kV        base2     MVAbase1
    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
            Utility Information

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

•   Rated kV
•   Rate MVA, MW
•   Xs; synchronous reactance
•   X’d; transient reactance
•   X’’d; subtransient reactance
         Motor                 Drive
• kV                     • Is it regenerative
• Rated HP or KW         • Harmonic spectrum
• Type
  – Sync or Induction
• Subtransient or
  locked rotor current
•   Rated primary and secondary kV
•   Rated MVA (OA, FA, FOA)
•   Winding connections (Wye, Delta)
•   Impedance and MVA base of impedance

• Rated kV
• Ohms
    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
ANSI 1-Line
IEC 1-Line
Short Circuit Study [1]
Short Circuit Study [2]
Short Circuit Study [3]

                          GE Consumer & Industrial
A Study of a Fault…….
Fault Interruption and Arcing

                          GE Consumer & Industrial
Arc Flash Hazard
                                 Arc Flash Mitigation:
                                 Problem 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
   • 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.
                          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
  • “Non-Protective Relay Techniques”
      Non-Protective Relaying Methods
         of Reducing Arc Flash Hazard
– System design                   – Electronic current limiters (these
  modifications increase            devices sense overcurrent and
                                    interrupt very high currents with
  power transformer                 replaceable conductor links
  impedance                         (explosive charge)
   • Addition of phase reactors   – Arc-resistant switchgear (this
   • Faster operating breakers      really doesn't reduce arc flash
   • Splitting of buses             energy; it deflects the energy
                                    away from personnel)
– Current limiting fuses
                                  – Optical arc flash protection via
  (provides partial protection      fiber sensors
  only for a limited current      – Optical arc flash protection via
  range)                            lens sensors
                 Protective Relaying Methods
                of Reducing Arc Flash Hazard
– Bus differential protection (this   – FlexCurve for improved
  reduces the arc flash energy by       coordination opportunities
  reducing the clearing time          – Employ 51VC/VR on feeders
– Zone interlock schemes where          fed from small generation to
  bus relay selectively is allowed      improve sensitivity and
  to trip or block depending on         coordination
  location of faults as identified    – Employ UV light detectors with
  from feeder relays                    current disturbance detectors
– Temporary setting changes to          for selective gear tripping
  reduce clearing time during
    • Sacrifices coordination
Fuses vs. Relayed Breakers
Arc Flash Hazards

                    GE Consumer & Industrial
Arc Pressure Wave

                    GE Consumer & Industrial
Arc Flash Warning Example [1]

                         GE Consumer & Industrial
Arc Flash Warning Example [2]

                         GE Consumer & Industrial
Arc Flash Warning Example [3]

                         GE Consumer & Industrial
Copy of this presentation are at:\private\IEEE
Protection Fundamentals


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