ge multilin_1craig wester, john levine

*GE Consumer & IndustrialMultilin

Power System Protection Fundamentals Craig Wester, John Levine GE Multilin



OutlineIntroductions Tools Enervista Launchpad On Line Store Demo Relays at ISO / LevineDiscussion of future classes Protection FundamentalsANSI number handout, Training CDs



IntroductionSpeakers:Craig Wester GE Multilin Regional ManagerJohn Levine GE Multilin Account Manager



ObjectiveWe are here to help make your job easier. This is very informal and designed around ISO Applications. Please ask question. We are not here to preach to you.The knowledge base on GE Multilin Relays varies greatly at ISO. 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.



Tools



Demo Relays with EthernetWorking with James McRoy and Dave CurtisSR 489SR 750G30MIF IITraining CDs



Demo Relays at L-3



Future ClassesGE 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 RelayMay MIF II relayJune - 750 RelayJuly - UR relay basic including Enervista EngineerAugust UR F60 and F35 relaysSeptember G30 and G60 including Transformer and Generator in same zoneOctober Communications and securityNovember - Neutral Grounding ResistorsDecember Cts and PTs



Protection Fundamentals



Desirable Protection AttributesReliability: System operate properlySecurity: Dont trip when you shouldntDependability: Trip when you shouldSelectivity: Trip the minimal amount to clear the fault or abnormal operating conditionSpeed: Usually the faster the better in terms of minimizing equipment damage and maintaining system integritySimplicity: KISSEconomics: Dont break the bank



Selection of protective relays requires compromises:Maximum and Reliable protection at minimum equipment costHigh Sensitivity to faults and insensitivity to maximum load currentsHigh-speed fault clearance with correct selectivitySelectivity in isolating small faulty areaAbility 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 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)Art & Science of Protection



Primary Equipment & ComponentsTransformers - to step up or step down voltage level Breakers - to energize equipment and interrupt fault current to isolate faulted equipmentInsulators - to insulate equipment from ground and other phasesIsolators (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 & ComponentsGrounding - to operate and maintain equipment safelyArrester - to protect primary equipment of sudden overvoltage (lightning strike).Switchgear integrated components to switch, protect, meter and control power flowReactors - 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 ProtectionOvercurrent Uses current to determine magnitude of faultSimpleMay employ definite time or inverse time curvesMay be slowSelectivity at the cost of speed (coordination stacks)InexpensiveMay use various polarizing voltages or ground current for directionalityCommunication aided schemes make more selective



Instantaneous Overcurrent Protection (IOC) & Definite Time Overcurrent

Relay closest to fault operates firstRelays closer to source operate slowerTime between operating for same current is called CTI (Clearing Time Interval)Distribution Substation



(TOC) CoordinationRelay closest to fault operates firstRelays closer to source operate slowerTime between operating for same current is called CTIDistribution Substation



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 axisOperate region lies above selected curve, while no-operate region lies below itInverse curves can approximate fuse curve shapesTime Overcurrent Protection (TOC)



Multiples of pick-upTime Overcurrent Protection (51, 51N, 51G)



Classic Directional Overcurrent Scheme for Looped System Protection



Types of ProtectionDifferentialcurrent in = current outSimpleVery fastVery defined clearing areaExpensivePractical distance limitationsLine differential systems overcome this using digital communications



DifferentialNote CT polarity dotsThis is a through-current representationPerfect waveforms, no saturation



DifferentialNote CT polarity dotsThis is an internal fault representationPerfect waveforms, no saturation



Types of ProtectionVoltageUses voltage to infer fault or abnormal conditionMay employ definite time or inverse time curvesMay also be used for undervoltage load sheddingSimpleMay be slowSelectivity at the cost of speed (coordination stacks)Inexpensive



Types of ProtectionFrequencyUses frequency of voltage to detect power balance conditionMay employ definite time or inverse time curvesUsed for load shedding & machinery under/overspeed protectionSimpleMay be slowSelectivity at the cost of speed can be expensive



Types of ProtectionPowerUses voltage and current to determine power flow magnitude and directionTypically definite timeComplexMay be slowAccuracy important for many applications Can be expensive



Types of ProtectionDistance (Impedance)Uses voltage and current to determine impedance of faultSet on impedance [R-X] planeUses definite time Impedance related to distance from relayComplicatedFastSomewhat defined clearing area with reasonable accuracyExpensiveCommunication aided schemes make more selective



ImpedanceRelay in Zone 1 operates firstTime between Zones is called CTIRXZL



Impedance: POTT SchemePOTT will trip only faulted line sectionRO elements are 21; 21G or 67N



Power vs. Protection Engineer:Views of the World180 Opposites!


Generation-typically at 4-20kVTransmission-typically at 230-765kVSubtransmission-typically at 69-161kVReceives power from transmission system and transforms into subtransmission levelReceives power from subtransmission system and transforms into primary feeder voltageDistribution network-typically 2.4-69kVLow voltage (service)-typically 120-600VTypicalBulkPower System*GE Consumer & IndustrialMultilin


Generator or Generator-Transformer UnitsTransformersBusesLines (transmission and distribution)Utilization equipment (motors, static loads, etc.)Capacitor or reactor (when separately protected)Protection Zones



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 opened.Zone Overlap


Electrical Mechanical Parameter Comparisons*GE Consumer & IndustrialMultilin

Electrical Mechanical Parameter Comparisons

Effects of Capacitive & Inductive Loads on Current


Motor Model and Starting Curves



One-line diagram of the system or area involvedImpedances and connections of power equipment, system frequency, voltage level and phase sequenceExisting schemes Operating procedures and practices affecting protectionImportance of protection required and maximum allowed clearance timesSystem fault studiesMaximum load and system swing limitsCTs and VTs locations, connections and ratiosFuture expansion expectanceAny special considerations for application. What Info is Required to Apply Protection


C37.2: Device NumbersPartial listing*GE Consumer & IndustrialMultilin


One Line DiagramNon-dimensioned diagram showing how pieces of electrical equipment are connectedSimplification of actual systemEquipment is shown as boxes, circles and other simple graphic symbolsSymbols should follow ANSI or IEC conventions



1-Line Symbols [1]



1-Line Symbols [2]



1-Line Symbols [3]



1-Line Symbols [4]



1-Line [1]


1-Line [2]


3-Line



Diagram Comparison



C37.2: Standard Reference Position1) 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



CB Trip Circuit (Simplified)



Showing Contacts NOT in Standard Reference ConditionSome people show the contact state changed like this



Showing Contacts NOT in Standard Reference ConditionBetter 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 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, 300:5A 2000:5 CT has a CTR of 400Current Transformers



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)

Standard IEEE CT Relay Accuracy



Excitation Curve



Standard IEEE CT Burdens (5 Amp) (Per IEEE Std. C57.13-1993)



Current into the Dot, Out of the DotCurrent out of the dot, in to the dot



Voltage (potential) transformers are used to isolate and step down and accurately reproduce the scaled voltage for the protective device or relayVT ratios are typically expressed as primary to secondary; 14400:120, 7200:120A 4160:120 VT has a VTR of 34.66

Voltage Transformers



Typical CT/VT CircuitsCourtesy of Blackburn, Protective Relay: Principles and Applications



CT/VT Circuit vs. Casing GroundCase ground made at IT locationSecondary circuit ground made at first point of useCaseSecondary Circuit



Equipment GroundingPrevents shock exposure of personnelProvides current carrying capability for the ground-fault currentGrounding includes design and construction of substation ground mat and CT and VT safety grounding



System GroundingLimits overvoltagesLimits difference in electric potential through local area conducting objectsSeveral methodsUngroundedReactance Coil Grounded High Z GroundedLow Z GroundedSolidly Grounded



System Grounding



Grounding Differences.Why?Solidly GroundedMuch ground current (damage)No neutral voltage shiftLine-ground insulationLimits step potential issuesFaulted area will clearInexpensive relaying



Grounding Differences.Why?Somewhat GroundedManage ground current (manage damage)Some neutral voltage shiftFaulted area will clearMore expensive than solid, less expensive then ungrounded



Grounding Differences.Why?UngroundedVery little ground current (less damage)Big neutral voltage shiftMust insulate line-to-line voltageMay run system while trying to find ground faultRelay more difficult/costly to detect and locate ground faultsIf you get a second ground fault on adjacent phase, watch out!



System Grounding Influences Ground Fault Detection MethodsLow/No Z



System Grounding Influences Ground Fault Detection MethodsMed/High Z



Basic Current Connections:How System is Grounded Determines How Ground Fault is DetectedMedium/High Resistance GroundLow/No Resistance Ground



Substation TypesSingle Supply Multiple SupplyMobile Substations for emergenciesTypes are defined by number of transformers, buses, breakers to provide adequate service for application



Industrial Substation Arrangements(Typical)



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 circuitsUtility Substation ArrangementsRing 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.(Typical)



Double Bus: Upper Main and Transfer, bottom Double Main busUtility Substation ArrangementsMain-Reserved and Transfer Bus: Allows maintenance of any bus and any breaker(Typical)



Switchgear DefinedAssemblies containing electrical switching, protection, metering and management devicesUsed in three-phase, high-power industrial, commercial and utility applicationsCovers a variety of actual uses, including motor control, distribution panels and outdoor switchyardsThe 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


Switchgear: MetalClad vs. Metal-EnclosedMetal-clad switchgear (C37.20.2)Breakers or switches must be draw-out designBreakers must be electrically operated, with anti-pump featureAll bus must be insulatedCompletely enclosed on all side and top with grounded metalBreaker, bus and cable compartments isolated by metal barriers, with no intentional openingsAutomatic shutters over primary breaker stabs.Metal-enclosed switchgearBus not insulatedBreakers or switches not required to be draw-outNo compartment barriering required



Switchgear Basics [1]All Switchgear has a metal enclosureMetalclad construction requires 11 gauge steel between sections and main compartmentsPrevents 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 useMetalclad 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 faultsInterrupting 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 equipmentRoutine 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 DuctThe main internal bus carries power between elements within the switchgearPower within the switchgear moves from compartment to compartment on horizontal bus, and within compartments on vertical busInstrument Transformers (CTs & PTs) are used to step down current and voltage from the primary circuits or use in lower-energy monitoring and control circuitry.



Air Magnetic Breakers



SF6 and Vacuum Breakers



A Good Day in System ProtectionCTs and VTs bring electrical info to relaysRelays sense current and voltage and declare faultRelays send signals through control circuits to circuit breakersCircuit breaker(s) correctly tripWhat Could Go Wrong Here????



A Bad Day in System ProtectionCTs or VTs are shorted, opened, or their wiring isRelays do not declare fault due to setting errors, faulty relay, CT saturationControl wires cut or batteries dead so no signal is sent from relay to circuit breakerCircuit breakers do not have power, burnt trip coil or otherwise fail to tripProtection 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 reactanceduring a fault



Useful Conversions



Per Unit SystemEstablish two base quantities:

Standard practice is to defineBase power 3 phaseBase voltage line to lineOther quantities derived with basic power equations



Per Unit Basics



Short Circuit CalculationsPer Unit SystemPer Unit Value = Actual Quantity Base QuantityVpu = Vactual Vbase Ipu = Iactual Ibase Zpu = Zactual Zbase



Short Circuit CalculationsPer Unit System



Short Circuit CalculationsPer Unit System Base ConversionZpu = Zactual Zbase Zbase = kV 2base MVAbase Zpu1 = MVAbase1 kV 2base1X ZactualZpu2 = MVAbase2 kV 2base2 X Zactual Zpu2 =Zpu1 x kV 2base1 x MVAbase2 kV 2base2 MVAbase1



Information for Short Circuit, Load Flow and Voltage StudiesTo perform the above studies, information is needed on the electrical apparatus and sources to the system under consideration



Utility InformationkVMVA short circuitVoltage and voltage variationHarmonic and flicker requirements



Generator InformationRated kVRate MVA, MWXs; synchronous reactanceXd; transient reactanceXd; subtransient reactance



Motor DrivekVRated HP or KWTypeSync or InductionSubtransient or locked rotor currentIs it regenerativeHarmonic spectrum



Transformers

Rated primary and secondary kVRated MVA (OA, FA, FOA)Winding connections (Wye, Delta)Impedance and MVA base of impedanceReactorsRated kVOhms



Cables and Transmission Lines

For rough calculations, some can be neglectedLength of conductorImpedance at given lengthSize of conductorSpacing of overhead conductorsRated voltageType of conduitNumber 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 & IndustrialMultilin


A Study of a Fault.


Fault Interruption and Arcing*GE Consumer & IndustrialMultilin


Arc Flash Hazard



Arc Flash Mitigation:Problem DescriptionAn 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 clothingThe 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 HazardArc flash energy may be expressed in I2t terms, so you can decrease the I or decrease the t to lessen the energyProtective relays can help lessen the t by optimizing sensitivity and decreasing clearing timeProtective Relay TechniquesOther means can lessen the I by limiting fault currentNon-Protective Relay Techniques



Non-Protective Relaying Methods of Reducing Arc Flash HazardSystem design modifications increase power transformer impedanceAddition of phase reactorsFaster operating breakersSplitting of busesCurrent 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



Protective Relaying Methods of Reducing Arc Flash HazardBus 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 relaysTemporary 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 coordinationEmploy UV light detectors with current disturbance detectors for selective gear tripping



Fuses vs. Relayed Breakers


Arc Flash Hazards*GE Consumer & IndustrialMultilin

Arc Pressure Wave*GE Consumer & IndustrialMultilin

Arc Flash Warning Example [1]*GE Consumer & IndustrialMultilin


Copy of this presentation are at:

www.L-3.com\private\Levine



Protection FundamentalsQUESTIONS?


****************************************************O1 trip handle, pr1 and pr2 electromechnincal with phase and ground, s1 seal in ts1 is the seal in coil******Current Turns Ratio (CTR)******************************************Figure 2.4 Variation of current with time during a fault*Fig. 2.5 Variation of generator reactance with time during a fault*********************************

ge multilin_1craig wester, john levine

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