Ge Generator Short Circuit Charachteristics

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CA08104001E For more information, visit: www.eaton.com/consultants

September 2011

Contents

Power Distribution Systems1

Sheet 01001

P o w e r D

i s t r i b u t i o

n

S y

s t e m

s

Power Distribution Systems

System Design

Basic Principles. . . . . . . . . . . 1.1-1

Modern Electric PowerTechnologies . . . . . . . . . . . 1.1-1

Goals of System Design . . . 1.1-2

Voltage Classifications; BILs—Basic Impulse Levels . . . . . 1.1-4

Three-Phase TransformerWinding Connections . . . . 1.1-5

Types of Systems—Radial,Loop, Selective, Two-Source,Sparing Transformer, SpotNetwork, Distribution . . . . 1.1-6

Health Care FacilityDesign Considerations . . . 1.1-14

Generator Systems . . . . . . 1.1-17

Generator System Design

Types of Generators. . . . . . . 1.2-1

Generator Systems . . . . . . . 1.2-2

Generator Grounding. . . . . . 1.2-3

Generator Controls. . . . . . . . 1.2-4

Generator Short-CircuitCharacteristics . . . . . . . . . . 1.2-4

Generator Protection . . . . . . 1.2-5

System Analysis

Systems Analysis . . . . . . . . . 1.3-1

Short-Circuit Currents . . . . . 1.3-2

Fault Current WaveformRelationships . . . . . . . . . . . 1.3-3

Fault Current Calculationsand Methods Index . . . . . . 1.3-4

Determine X and R fromTransformer Loss Data . . . 1.3-19

Voltage DropConsiderations . . . . . . . . . . 1.3-20

System Application Considerations

Capacitors andPower Factor

. . . . . . . . . . . 1.4-1

Overcurrent Protectionand Coordination . . . . . . . . 1.4-3

Protection of Conductors. . . 1.4-5

Circuit Breaker CableTemperature Ratings . . . . . 1.4-5

Zone Selective Interlocking . 1.4-5

Ground Fault Protection . . . 1.4-6

Suggested GroundFault Settings. . . . . . . . . . . . . 1.4-6

Grounding/Ground Fault Protection

Grounding—Equipment,System, MV System,LV System . . . . . . . . . . . . . .

1.4-9

Ground Fault Protection. . . .

1.4-11

Lightning and SurgeProtection . . . . . . . . . . . . . .

1.4-14

Grounding Electrodes. . . . . .

1.4-14

MV Equipment SurgeProtection Considerations .

1.4-14

Surge Protection . . . . . . . . . .

1.4-14

Types of SurgeProtection Devices . . . . . . .

1.4-15

Power Quality

Terms, Technical Overview . .

1.4-18

SPD. . . . . . . . . . . . . . . . . . . . .

1.4-19

Harmonics andNonlinear Loads . . . . . . . . .

1.4-21

UPS . . . . . . . . . . . . . . . . . . . .

1.4-25

Other Application Considerations

Secondary Voltage . . . . . . . .

1.4-31

Energy Conservation . . . . . .

1.4-32

Building Control Systems . .

1.4-33

Distributed EnergyResources

. . . . . . . . . . . . . . 1.4-33

Cogeneration. . . . . . . . . . . . .

1.4-33

PV System DesignConsiderations . . . . . . . . . .

1.4-34

Emergency Power. . . . . . . . .

1.4-35

Peak Shaving. . . . . . . . . . . . .

1.4-36

Sound Levels. . . . . . . . . . . . .

1.4-36

Reference Data

IEEE Protective RelayNumbers . . . . . . . . . . . . . . .

1.5-1

Codes and Standards . . . . . .

1.5-6

Motor ProtectiveDevice Data. . . . . . . . . . . . .

1.5-7

Chart of Short-CircuitCurrents for Transformers . .

1.5-9

Transformer Full LoadAmperes . . . . . . . . . . . . . . .

1.5-10

Impedances Data . . . . . . . . .

1.5-11

Transformer Losses,TP-1 Losses. . . . . . . . . . . . .

1.5-12

Power Equipment Losses . . .

1.5-13

NEMA Enclosure Definitions

. .

1.5-13

Cable R, X, Z Data . . . . . . . . .

1.5-14

Conductor Ampacities . . . . .

1.5-16

Conductor TemperatureRatings . . . . . . . . . . . . . . . .

1.5-16

Formulas and Terms. . . . . . .

1.5-19

Seismic Requirements . . . . .

1.5-20

Designing a Distribution System



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System Design

003

Basic Principles

The best distribution system is onethat will, cost-effectively and safely,supply adequate electric service toboth present and future probable

loads—this section is included to aidin selecting, designing and installingsuch a system.

The function of the electric powerdistribution system in a building oran installation site is to receive powerat one or more supply points andto deliver it to the individual lamps,motors and all other electricallyoperated devices. The importanceof the distribution system to thefunction of a building makes it almostimperative that the best system bedesigned and installed.

In order to design the best distribution

system, the system design engineermust have information concerning theloads and a knowledge of the varioustypes of distribution systems that areapplicable. The various categories ofbuildings have many specific designchallenges, but certain basic principlesare common to all. Such principles,if followed, will provide a soundlyexecuted design.

The basic principles or factors requir-ing consideration during design ofthe power distribution system include:

■

Functions of structure, presentand future

■

Life and flexibility of structure

■

Locations of service entrance anddistribution equipment, locationsand characteristics of loads,locations of unit substations

■

Demand and diversity factorsof loads

■

Sources of power; includingnormal, standby and emergency(see Tab 40

)

■

Continuity and quality ofpower available and required(see Tab 33

)

■

Energy efficiency and management

■

Distribution and utilization voltages

■

Bus and/or cable feeders

■

Distribution equipment andmotor control

■

Power and lighting panelboardsand motor control centers

■

Types of lighting systems

■

Installation methods

■

Power monitoring systems

■

Electric utility requirements

Modern Electric PowerTechnologies

Several new factors to consider inmodern power distribution systemsresult from two relatively recent

changes. The first recent change isutility deregulation. The traditionaldependence on the utility for problemanalysis, energy conservation mea-surements and techniques, and asimplified cost structure for electricityhas changed. The second change is lessobvious to the designer yet will havean impact on the types of equipmentand systems being designed. It is thediminishing quantity of qualified build-ing electrical operators, maintenancedepartments and facility engineers.

Modern electric power technologiesmay be of use to the designer and

building owner in addressing thesenew challenges. The advent of micro-processor devices (smart devices)into power distribution equipment hasexpanded facility owners’ options andcapabilities, allowing for automatedcommunication of vital power systeminformation (both energy data andsystem operation information) andelectrical equipment control.

These technologies may be grouped as:

■

Power monitoring and control

■

Building management systemsinterfaces

■

Lighting control

■

Automated energy management

■

Predictive diagnostics

Various sections of this guide coverthe application and selection of suchsystems and components that may beincorporated into the power equip-ment being designed. See Tabs 2, 3, 4,23

and 41

.



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Goals of System Design

When considering the design of anelectrical distribution system fora given customer and facility, theelectrical engineer must consider

alternate design approaches thatbest fit the following overall goals.

1. Safety

: The No. 1 goal is to designa power system that will notpresent any electrical hazard tothe people who use the facility,and/or the utilization equipmentfed from the electrical system.It is also important to design asystem that is inherently safe forthe people who are responsiblefor electrical equipmentmaintenance and upkeep.

The National Electrical Code

®

(NEC

®

), NFPA

®

70 and NFPA 70E,

as well as local electrical codes,provide minimum standards andrequirements in the area of wiringdesign and protection, wiringmethods and materials, as wellas equipment for general use withthe overall goal of providing safeelectrical distribution systemsand equipment.

The NEC also covers minimum

requirements for specialoccupancies including hazardouslocations and special use typefacilities such as health carefacilities, places of assembly,theaters and the like, and theequipment and systems located inthese facilities. Special equipmentand special conditions such asemergency systems, standbysystems and communicationsystems are also covered inthe code.

It is the responsibility of the designengineer to be familiar with theNFPA and NEC code requirementsas well as the customer’s facility,process and operating procedures;to design a system that protectspersonnel from live electricalconductors and uses adequate

circuit protective devices that willselectively isolate overloaded orfaulted circuits or equipment asquickly as possible.

2. Minimum Initial Investment

:The owner’s overall budget forfirst cost purchase and installa-tion of the electrical distributionsystem and electrical utilizationequipment will be a key factor

in determining which of variousalternate system designs are to beselected. When trying to minimizeinitial investment for electricalequipment, consideration shouldbe given to the cost of installation,floor space requirements andpossible extra cooling require-ments as well as the initialpurchase price.

3. Maximum Service Continuity:The degree of service continuityand reliability needed will varydepending on the type and useof the facility as well as the loadsor processes being supplied by

the electrical distribution system.For example, for a smallercommercial office building, apower outage of considerabletime, say several hours, may beacceptable, whereas in a largercommercial building or industrialplant only a few minutes may beacceptable. In other facilities suchas hospitals, many critical loadspermit a maximum of 10 secondsoutage and certain loads, suchas real-time computers, cannottolerate a loss of power for evena few cycles.

Typically, service continuity andreliability can be increased by:

A. Supplying multiple utility powersources or services.

B. Supplying multiple connectionpaths to the loads served.

C. Using short-time rated powercircuit breakers.

D. Providing alternate customer-owned power sources such asgenerators or batteries supplyinguninterruptable power supplies.

E. Selecting the highest quality elec-

trical equipment and conductors.F. Using the best installation methods.

G. Designing appropriate systemalarms, monitoring and diagnostics.

H. Selecting preventative mainte-nance systems or equipment toalarm before an outage occurs.

4. Maximum Flexibility andExpendability: In many industrialmanufacturing plants, electricalutilization loads are periodicallyrelocated or changed requiringchanges in the electrical distribu-

tion system. Consideration ofthe layout and design of theelectrical distribution system toaccommodate these changesmust be considered. For example,providing many smaller trans-formers or loadcenters associatedwith a given area or specificgroups of machinery may lendmore flexibility for future changesthan one large transformer; theuse of plug-in busways to feedselected equipment in lieu ofconduit and wire may facilitatefuture revised equipment layouts.

In addition, consideration must be

given to future building expansion,and/or increased load require-ments due to added utilizationequipment when designing theelectrical distribution system.In many cases considering trans-formers with increased capacityor fan cooling to serve unexpectedloads as well as including spareadditional protective devices and/ or provision for future addition ofthese devices may be desirable.Also to be considered is increasingappropriate circuit capacities orquantities for future growth.

Power monitoring communicationsystems connected to electronicmetering can provide the trendingand historical data necessary forfuture capacity growth.




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5. Maximum Electrical Efficiency(Minimum Operating Costs):Electrical efficiency can generallybe maximized by designingsystems that minimize the lossesin conductors, transformers and

utilization equipment. Propervoltage level selection plays akey factor in this area and willbe discussed later. Selectingequipment, such as transformers,with lower operating losses,generally means higher first costand increased floor space require-ments; thus, there is a balanceto be considered between theowner’s utility energy changefor the losses in the transformeror other equipment versus theowner’s first cost budget andcost of money.

6. Minimum Maintenance Cost:

Usually the simpler the electricalsystem design and the simplerthe electrical equipment, the lessthe associated maintenance costsand operator errors. As electricalsystems and equipment becomemore complicated to providegreater service continuity orflexibility, the maintenance costsand chance for operator errorincreases. The systems should bedesigned with an alternate powercircuit to take electrical equipment(requiring periodic maintenance)out of service without droppingessential loads. Use of drawout

type protective devices such asbreakers and combination starterscan also minimize maintenancecost and out-of-service time.

7. Maximum Power Quality:The power input requirementsof all utilization equipment hasto be considered including theacceptable operating range ofthe equipment and the electrical

distribution system has to bedesigned to meet these needs.For example, what is the requiredinput voltage, current, powerfactor requirement? Consider-ation to whether the loads areaffected by harmonics (multiplesof the basic 60 Hz sine wave) orgenerate harmonics must be takeninto account as well as transientvoltage phenomena.

The above goals are interrelatedand in some ways contradictory.As more redundancy is added tothe electrical system design alongwith the best quality equipment

to maximize service continuity,flexibility and expandability, andpower quality, the more initialinvestment and maintenanceare increased. Thus, the designermust weigh each factor basedon the type of facility, the loadsto be served, the owner’s pastexperience and criteria.

SummaryIt is to be expected that the engineerwill never have complete load infor-mation available when the system isdesigned. The engineer will have toexpand the information made avail-

able to him on the basis of experiencewith similar problems. Of course, itis desirable that the engineer has asmuch definite information as possibleconcerning the function, requirements,and characteristics of the utilizationdevices. The engineer should knowwhether certain loads functionseparately or together as a unit, themagnitude of the demand of the loadsviewed separately and as units, the rated voltage and frequency of the devices,their physical location with respectto each other and with respect to thesource and the probability and possi-bility of the relocation of load devices

and addition of loads in the future.

Coupled with this information, aknowledge of the major types of electricpower distribution systems equips theengineers to arrive at the best systemdesign for the particular building.

It is beyond the scope of this guide topresent a detailed discussion of loadsthat might be found in each of severaltypes of buildings. Assuming that thedesign engineer has assembled thenecessary load data, the followingpages discuss some of the varioustypes of electrical distribution systemsthat can be used. The description of

types of systems, and the diagramsused to explain the types of systemson the following pages omits thelocation of utility revenue meteringequipment for clarity. A discussion ofshort-circuit calculations, coordination,voltage selection, voltage drop, groundfault protection, motor protection andother specific equipment protectionis also presented.



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System Design006

Voltage Classifications

ANSI and IEEE® standards definevarious voltage classifications forsingle-phase and three-phase systems.The terminology used divides voltage

classes into:■ Low voltage

■ Medium voltage

■ High voltage

■ Extra-high voltage

■ Ultra-high voltage

Table 1.1-1 presents the nominal sys-tem voltages for these classifications.

Table 1.1-1. Standard Nominal SystemVoltages and Voltage Ranges(From IEEE Standard 141-1993)

BIL—Basic Impulse Levels

ANSI standards define recommendedand required BIL levels for:

■ Metal-clad switchgear(typically vacuum breakers)

■ Metal-enclosed switchgear (typicallyload interrupters, switches)

■ Liquid immersed transformers

■

Dry-type transformersTable 1.1-2 through Table 1.1-5 containthose values.

Table 1.1-2. Metal-Clad Switchgear Voltageand Insulation Levels (From ANSI/IEEEC37.20.2-1999)

Table 1.1-3. Metal-Enclosed SwitchgearVoltage and Insulation Levels(From ANSI C37.20.3-1987)

Table 1.1-4. Liquid-ImmersedTransformers Voltage and BasicLightning Impulse Insulation Levels (BIL)(From ANSI/IEEE C57.12.00-2000)

BIL values in bold typeface are listed asstandard. Others listed are in common use.

Table 1.1-5. Dry-Type Transformers Voltageand Basic Lightning Impulse InsulationLevels (BIL)—From ANSI/IEEE C57.12.01-1998)

BIL values in bold typeface are listed asstandard. Others listed are in common use.Optional higher levels used where exposureto overvoltage occurs and higher protectionmargins are required.

Lower levels where surge arresterprotective devices can be applied withlower spark-over levels.

Voltage Recommendations byMotor Horsepower

Some factors affecting the selectionof motor operating voltage include:

■ Motor, motor starter and cablefirst cost

■ Motor, motor starter and cableinstallation cost

■ Motor and cable losses

■ Motor availability

■ Voltage drop

■ Qualifications of the buildingoperating staff; and many more

The following table is based in part

on the above factors and experience.Because all the factors affecting theselection are rarely known, it is onlyan approximate guideline.

Table 1.1-6. Selection of Motor HorsepowerRatings as a Function of System Voltage

VoltageClass

Nominal System Voltage

Three-Wire Four-Wire

Lowvoltage

240/120240480600

208Y/120240/120

480Y/277—

Mediumvoltage

2400416048006900

13,20013,80023,00034,50046,00069,000

4160Y/24008320Y/4800

12000Y/693012470Y/720013200Y/762013800Y/7970

20780Y/1200022860Y/1320024940Y/1440034500Y/19920

Highvoltage

115,000138,000161,000230,000

————

Extra-highvoltage

345,000500,000765,000

———

Ultra-highvoltage

1,100,000 —

Rated MaximumVoltage (kV rms)

ImpulseWithstand (kV)

4.76

8.2515.0

60

9595

27.038.0

125150

Rated MaximumVoltage (kV rms)

ImpulseWithstand (kV)

4.768.25

15.0

607595

15.525.838.0

110125150

Applica-tion

NominalSystemVoltage(kV rms)

BIL(kV Crest)

Distribu-tion

1.22.55.0

304560

———

———

———

8.715.025.0

7595

150

——

125

———

———

34.546.0

69.0

200250

350

150 200

250

125—

—

——

—

Power 1.22.55.0

456075

304560

———

———

8.715.025.0

95110150

7595

—

———

———

34.546.069.0

200250350

— 200 250

———

———

115.0138.0161.0

550650750

450550650

350 450 550

———

230.0345.0500.0765.0

900117516752050

825105015501925

750 90014251800

650—1300—

NominalSystemVoltage(kV rms)

BIL (kV Crest)

1.22.55.08.7

————

10203045

20304560

30456095

15.025.034.5

—95

—

60110125

95125150

110150200

Motor Voltage(Volts)

Motorhp Range

SystemVoltage

46023004000

up to 500250 to 2000250 to 3000

48024004160

460013,200

250 to 3000above 2000

480013,800




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System Design007

Table 1.1-7. Three-Phase Transformer Winding Connections

PhasorDiagram

Notes

1. Suitable for both ungrounded and effectively grounded sources.

2. Suitable for a three-wire service or a four-wire service with a mid-tap ground.


2. Suitable for a three-wire service or a four-wire grounded service withXO grounded.

3. With XO grounded, the transformer acts as a ground source for thesecondary system.

4. Fundamental and harmonic frequency zero-sequence currents in the secondarylines supplied by the transformer do not flow in the primary lines. Instead thezero sequence currents circulate in the closed delta primary windings.

5. When supplied from an effectively grounded primary system does not see loadunbalances and ground faults in the secondary system.


2. Suitable for a three-wire service or a four-wire delta service with a mid-tap ground.

3. Grounding the primary neutral of this connection would create a ground sourcefor the primary system. This could subject the transformer to severe overloadingduring a primary system disturbance or load unbalance.

4. Frequently installed with mid-tap ground on one leg when supplyingcombination three-phase and single-phase load where the three-phaseload is much larger than single-phase load.

5. When used in 25 kV and 35 kV three-phase four-wire primary systems,ferroresonance can occur when energizing or de-energizing the transformerusing single-pole switches located at the primary terminals. With smaller kVAtransformers the probability of ferroresonance is higher.


2. Suitable for a three-wire service only, even if XO is grounded.

3. This connection is incapable of furnishing a stabilized neutral and its use mayresult in phase-to-neutral overvoltage (neutral shift) as a result of unbalancedphase-to-neutral load.

4. If a three-phase unit is built on a three-legged core, the neutral point of theprimary windings is practically locked at ground potential.

1. Suitable for four-wire effectively grounded source only.

2. Suitable for a three-wire service or for four-wire grounded service withXO grounded.

3. Three-phase transformers with this connection may experience stray flux tankheating during certain external system unbalances unless the core configuration(four or five legged) used provides a return path for the flux.

4. Fundamental and harmonic frequency zero-sequence currents in the secondarylines supplied by the transformer also flow in the primary lines (and primaryneutral conductor).

5. Ground relay for the primary system may see load unbalances and groundfaults in the secondary system. This must be considered when coordinatingovercurrent protective devices.

6. Three-phase transformers with the neutral points of the high voltage and lowvoltage windings connected together internally and brought out through anHOXO bushing should not be operated with the HOXO bushing ungrounded(floating). To do so can result in very high voltages in the secondary systems.


2. Suitable for a three-wire service or a four-wire service with a mid-tap ground.

3. When using the tap for single-phase circuits, the single-phase load kVA shouldnot exceed 5% of the three-phase kVA rating of the transformer. The three-phaserating of the transformer is also substantially reduced.

H2

H1 H3

X2

X1 X3

DELTA-DELTA Connection

Phasor

Diagram:

Angular Displacement (Degrees): 0

H2

H1 H3

X2

X1

X3

DELTA-WYE Connection

PhasorDiagram:


X0

H2

H1 H3

X2

X1

X3

WYE-DELTA Connection

PhasorDiagram:


H2

H1 H3

WYE-WYE Connection

PhasorDiagram:


X2

X1 X3

X0

H2

H1 H3

GROUNDED WYE-WYE Connection

PhasorDiagram:


X2

X1 X3

X0H0

H2

H1 H3

X2

X1 X3

DELTA-DELTA Connection with Tap

PhasorDiagram:


X4



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Types of Systems

In many cases, power is supplied bythe utility to a building at the utilizationvoltage. In these cases, the distributionof power within the building is achieved

through the use of a simple radialdistribution system.

In cases where the utility service voltageis at some voltage higher than theutilization voltage within the building,the system design engineer has a choiceof a number of types of systems thatmay be used. This discussion coversseveral major types of distributionsystems and practical modificationsof them.

1. Simple radial

2. Loop-primary system—radial secondary system

3. Primary selective system—secondary radial system

4. Two-source primary—secondary selective system

5. Sparing transformer system

6. Simple spot network

7. Medium voltage distributionsystem design

1. Simple Radial System

The conventional simple radial systemreceives power at the utility supplyvoltage at a single substation and stepsthe voltage down to the utilization level.In those cases where the customerreceives his supply from the primarysystem and owns the primary switchand transformer along with the second-ary low voltage switchboard or switch-gear, the equipment may take the formof a separate primary switch, separatetransformer, and separate low voltageswitchgear or switchboard. This equip-ment may be combined in the form ofan outdoor pad-mounted transformerwith internal primary fused switchand secondary main breaker feedingan indoor switchboard.

Another alternative would be a

secondary unit substation wherethe primary fused switch, transformerand secondary switchgear or switch-board are designed and installed asa close-coupled single assembly.

In those cases where the utility ownsthe primary equipment and transformer,the supply to the customer is at theutilization voltage, and the serviceequipment then becomes low voltagemain distribution switchgear ora switchboard.

Low voltage feeder circuits run fromthe switchgear or switchboard assem-blies to panelboards that are locatedcloser to their respective loads asshown in Figure 1.1-1.

Each feeder is connected to the switch-

gear or switchboard bus through acircuit breaker or other overcurrentprotective device. A relatively smallnumber of circuits are used to distributepower to the loads from the switch-gear or switchboard assemblies andpanelboards.

Because the entire load is served froma single source, full advantage can betaken of the diversity among the loads.This makes it possible to minimize theinstalled transformer capacity. However, the voltage regulation and efficiencyof this system may be poor becauseof the low voltage feeders and single

source. The cost of the low voltage-feeder circuits and their associated circuit breakers are high when the feeders arelong and the peak demand is above1000 kVA.

A fault on the secondary low voltagebus or in the source transformer willinterrupt service to all loads. Servicecannot be restored until the necessaryrepairs have been made. A low voltagefeeder circuit fault will interrupt service

to all loads supplied over that feeder.A modern and improved form of theconventional simple radial systemdistributes power at a primary voltage.The voltage is stepped down toutilization level in the several loadareas within the building typicallythrough secondary unit substationtransformers. The transformers areusually connected to their associatedload bus through a circuit breaker, asshown in Figure 1.1-2. Each secondaryunit substation is an assembled unitconsisting of a three-phase, liquid-filled or air-cooled transformer, anintegrally connected primary fused

switch, and low voltage switchgear orswitchboard with circuit breakers orfused switches. Circuits are run tothe loads from these low voltageprotective devices.

Figure 1.1-1. Simple Radial System

Figure 1.1-2. Primary and Secondary Simple Radial System

Primary Fused Switch

Transformer

600V ClassSwitchboard

Distribution

Dry-TypeTransformer

LightingPanelboard

DistributionPanel

MCC DistributionPanel

Secondary UnitSubstation

Primary Main Breaker

Primary Feeder Breakers

PrimaryCables

52

52 52 52 52 52 52




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Because each transformer is locatedwithin a specific load area, it musthave sufficient capacity to carry thepeak load of that area. Consequently,if any diversity exists among the loadarea, this modified primary radial

system requires more transformercapacity than the basic form of thesimple radial system. However,because power is distributed to theload areas at a primary voltage, lossesare reduced, voltage regulation isimproved, feeder circuit costs arereduced substantially, and largelow voltage feeder circuit breakersare eliminated. In many cases theinterrupting duty imposed on theload circuit breakers is reduced.

This modern form of the simple radialsystem will usually be lower in initialinvestment than most other types ofprimary distribution systems for build-

ings in which the peak load is above1000 kVA. A fault on a primary feedercircuit or in one transformer will causean outage to only those secondaryloads served by that feeder or trans-former. In the case of a primary mainbus fault or a utility service outage,service is interrupted to all loads untilthe trouble is eliminated.

Reducing the number of transformersper primary feeder by adding moreprimary feeder circuits will improvethe flexibility and service continuityof this system; the ultimate being onesecondary unit substation per primary

feeder circuit. This of course increasesthe investment in the system butminimizes the extent of an outageresulting from a transformer orprimary feeder fault.

Primary connections from one secondary unit substation to the next secondaryunit substation can be made with“double” lugs on the unit substationprimary switch as shown, or withseparable connectors made inmanholes or other locations.

Depending on the load kVA connectedto each primary circuit and if no groundfault protection is desired for either the

primary feeder conductors and trans-formers connected to that feeder orthe main bus, the primary main and/orfeeder breakers may be changed toprimary fused switches. This will sig-nificantly reduce the first cost, but alsodecrease the level of conductor andequipment protection. Thus, shoulda fault or overload condition occur,downtime increases significantly andhigher costs associated with increaseddamage levels and the need for fusereplacement is typically encountered.

In addition, if only one primary fuse ona circuit opens, the secondary loads arethen single phased, causing damage tolow voltage motors.

Another approach to reducing costsis to eliminate the primary feeder

breakers completely, and use a singleprimary main breaker or fused switchfor protection of a single primaryfeeder circuit with all secondary unitsubstations supplied from this circuit.Although this system results in lessinitial equipment cost, system reliabilityis reduced drastically because a singlefault in any part of the primary conductor would cause an outage to all loadswithin the facility.

2. Loop Primary System—Radial Secondary System

This system consists of one or more

“PRIMARY LOOPS” with two or moretransformers connected on the loop.This system is typically most effectivewhen two services are available fromthe utility as shown in Figure 1.1-3. Eachprimary loop is operated such that oneof the loop sectionalizing switches iskept open to prevent parallel operationof the sources. When secondary unitsubstations are used, each trans-former has its own duplex (2-load

break switches with load side busconnection) sectionalizing switchesand primary load break fused switchas shown in Figure 1.1-4.

When pad-mounted compartmental-ized transformers are used, they are

furnished with loop-feed oil-immersedgang-operated load break sectionalizingswitches and drawout current limitingfuses in dry wells as shown in Figure1.1-5. By operating the appropriatesectionalizing switches, it is possibleto disconnect any section of the loopconductors from the rest of the system.In addition, by opening the transformerprimary switch (or removing the loadbreak drawout fuses in the pad-mounted transformer) it is possible to disconnectany transformer from the loop.

A key interlocking scheme is normallyrecommended to prevent closing all

sectionalizing devices in the loop. Eachprimary loop sectionalizing switch andthe feeder breakers to the loop areinterlocked such that to be closed theyrequire a key (which is held captiveuntil the switch or breaker is opened)and one less key than the number ofkey interlock cylinders is furnished.An extra key is provided to defeat theinterlock under qualified supervision.

Figure 1.1-3. Loop Primary—Radial Secondary System

NC NCNO

Loop A

Loop B

TieBreaker Loop Feeder Breaker

Primary Main Breaker 2

Secondary Unit Substations Consisting of:Duplex Primary Switches/Fused Primary Switches/ Transformer and Secondary Main Feeder Breakers

NO NC NC NCNC NC

NC

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Fault Sensors

Primary Main Breaker 1



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Figure 1.1-4. Secondary Unit SubstationLoop Switching

Figure 1.1-5. Pad-Mounted TransformerLoop Switching

In addition, the two primary mainbreakers, which are normally closed,and primary tie breaker, which isnormally open, are either mechanicallyor electrically interlocked to preventparalleling the incoming source lines.For slightly added cost, an automaticthrow-over scheme can be addedbetween the two main breakers andtie breaker. During the more commonevent of a utility outage, the automatictransfer scheme provides significantlyreduced power outage time.

The system in Figure 1.1-3 has highercosts than in Figure 1.1-2, but offersincreased reliability and quick restora-tion of service when 1) a utility outageoccurs, 2) a primary feeder conductorfault occurs, or 3) a transformer faultor overload occurs.

Should a utility outage occur on one ofthe incoming lines, the associated pri-mary main breaker is opened and thetie breaker closed either manually orthrough an automatic transfer scheme.

LoopFeeder

LoopFeeder

Load BreakLoop Switches

FusedDisconnectSwitch

Loop

Feeder

Loop

Feeder

Load BreakLoop Switches

Load BreakDrawout Fuses

When a primary feeder conductor faultoccurs, the associated loop feederbreaker opens and interrupts serviceto all loads up to the normally openprimary loop load break switch(typically half of the loads). Once it is

determined which section of primarycable has been faulted, the loop sec-tionalizing switches on each side ofthe faulted conductor can be opened,the loop sectionalizing switch that hadbeen previously left open then closedand service restored to all secondaryunit substations while the faultedconductor is replaced. If the faultshould occur in a conductor directlyon the load side of one of the loopfeeder breakers, the loop feederbreaker is kept open after tripping andthe next load side loop sectionalizingswitch manually opened so that thefaulted conductor can be sectionalizedand replaced.

Note: Under this condition, all secondaryunit substations are supplied through theother loop feeder circuit breaker, and thusall conductors around the loop should besized to carry the entire load connected tothe loop. Increasing the number of primaryloops (two loops shown in Figure 1.1-6)will reduce the extent of the outage from aconductor fault, but will also increase thesystem investment.

When a transformer fault or overloadoccurs, the transformer primary fusesopen, and the transformer primaryswitch manually opened, disconnectingthe transformer from the loop, and

leaving all other secondary unitsubstation loads unaffected.

Figure 1.1-6. Single Primary Feeder—Loop System

A basic primary loop system thatuses a single primary feeder breakerconnected directly to two loop feederswitches which in turn then feed theloop is shown in Figure 1.1-6. In thisbasic system, the loop may be normallyoperated with one of the loop section-alizing switches open as described

above or with all loop sectionalizingswitches closed. If a fault occurs in thebasic primary loop system, the singleloop feeder breaker trips, and secondaryloads are lost until the faulted conductoris found and eliminated from the loopby opening the appropriate loopsectionalizing switches and thenreclosing the breaker.

3. Primary Selective System—Secondary Radial SystemThe primary selective—secondaryradial system, as shown in Figure 1.1-7,differs from those previously described

in that it employs at least two primaryfeeder circuits in each load area. It is

Figure 1.1-7. Basic Primary Selective—Radial Secondary System

Loop A Loop A

In cases where only one primary lineis available, the use of a single primarybreaker provides the loop connectionsto the loads as shown here.

52

Primary Metal-Clad

Switchgear Lineup

Bus A Bus B

Feeder A1 Feeder B1

Primary Feeder Breaker

Feeder B2

Feeder A2

Primary Main Breaker

To OtherSubstations

Typical Secondary UnitSubstation Duplex PrimarySwitch/FusesTransformer/600V ClassSecondary Switchgear

52 52

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52 52

NO

NC

NO

NC

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designed so that when one primarycircuit is out of service, the remainingfeeder or feeders have sufficientcapacity to carry the total load. Halfof the transformers are normallyconnected to each of the two feeders.

When a fault occurs on one of theprimary feeders, only half of theload in the building is dropped.

Duplex fused switches as shown inFigure 1.1-7 and detailed in Figure 1.1-8 are the normal choice for this type ofsystem. Each duplex fused switchconsists of two (2) load break three-pole switches each in their ownseparate structure, connected togetherby bus bars on the load side. Typically,the load break switch closest to thetransformer includes a fuse assemblywith fuses. Mechanical and/or keyinterlocking is furnished such thatboth switches cannot be closed at

the same time (to prevent paralleloperation) and interlocking suchthat access to either switch or fuseassembly cannot be obtained unlessboth switches are opened.

Figure 1.1-8. Duplex Fused Switch inTwo Structures

As an alternate to the duplex switcharrangement, a non-load break selectorswitch mechanically interlocked with aload break fused switch can be used asshown in Figure 1.1-9. The non-loadbreak selector switch is physicallylocated in the rear of the load breakfused switch, thus only requiring onestructure and a lower cost and floorspace savings over the duplexarrangement. The non-load breakswitch is mechanically interlocked toprevent its operation unless the loadbreak switch is opened. The maindisadvantage of the selector switch isthat conductors from both circuits areterminated in the same structure.

Figure 1.1-9. Fused Selector Switch inOne Structure

This means limited cable space espe-cially if double lugs are furnished for

each line as shown in Figure 1.1-7 andshould a faulted primary conductorhave to be changed, both lines wouldhave to be de-energized for safechanging of the faulted conductors.

In Figure 1.1-7 when a primary feederfault occurs, the associated feederbreaker opens and the transformersnormally supplied from the faultedfeeder are out of service. Then manu-ally, each primary switch connected tothe faulted line must be opened andthen the alternate line primary switchcan be closed connecting the trans-former to the live feeder, thus restoring

service to all loads. Note that each of theprimary circuit conductors for FeederA1 and B1 must be sized to handle thesum of the loads normally connectedto both A1 and B1. Similar sizing ofFeeders A2 and B2, etc., is required.

If a fault occurs in one transformer,the associated primary fuses blowand interrupt the service to justthe load served by that transformer.Service cannot be restored to theloads normally served by the faultedtransformer until the transformeris repaired or replaced.

Cost of the primary selective—

secondary radial system is greaterthan that of the simple primary radialsystem of Figure 1.1-1 because of theadditional primary main breakers, tiebreaker, two-sources, increased number of feeder breakers, the use of primary-duplex or selector switches, and thegreater amount of primary feedercable required. The benefits from thereduction in the amount of load lostwhen a primary feeder is faulted, plusthe quick restoration of service to all

or most of the loads, may more thanoffset the greater cost. Having twosources allows for either manual orautomatic transfer of the two primarymain breakers and tie breaker shouldone of the sources become unavailable.

The primary selective-secondary radialsystem, however, may be less costly ormore costly than a primary loop—secondary radial system of Figure 1.1-3 depending on the physical locationof the transformers while offeringcomparable downtime and reliability.The cost of conductors for the twotypes of systems may vary greatlydepending on the location of thetransformers and loads within thefacility and greatly override primaryswitching equipment cost differencesbetween the two systems.

4. Two-Source Primary—

Secondary Selective SystemThis system uses the same principleof duplicate sources from the powersupply point using two primary mainbreakers and a primary tie breaker.The two primary main breakers andprimary tie breaker being eithermanually or electrically interlockedto prevent closing all three at the sametime and paralleling the sources. Uponloss of voltage on one source, a manualor automatic transfer to the alternatesource line may be used to restorepower to all primary loads.

Each transformer secondary isarranged in a typical double-endedunit substation arrangement as shownin Figure 1.1-10. The two secondarymain breakers and secondary tiebreaker of each unit substation areagain either mechanically or electricallyinterlocked to prevent parallel operation. Upon loss of secondary source voltageon one side, manual or automatictransfer may be used to transfer theloads to the other side, thus restoringpower to all secondary loads.

This arrangement permits quickrestoration of service to all loads whena primary feeder or transformer fault

occurs by opening the associatedsecondary main and closing thesecondary tie breaker. If the loss ofsecondary voltage has occurredbecause of a primary feeder faultwith the associated primary feederbreaker opening, then all secondaryloads normally served by the faultedfeeder would have to be transferredto the opposite primary feeder. Thismeans each primary feeder conductormust be sized to carry the load on bothsides of all the secondary buses it is

PrimaryFeeders

Load BreakSwitches

Fuses

PrimaryFeeders

Non-Load BreakSelector Switches

Fuses

Load BreakDisconnect

Inter-

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serving under secondary emergencytransfer. If the loss of voltage was dueto a failure of one of the transformers inthe double-ended unit substation, thenthe associated primary fuses wouldopen taking only the failed transformerout of service, and then only thesecondary loads normally served bythe faulted transformer would haveto be transferred to the oppositetransformer. In either of the above

emergency conditions, the in-servicetransformer of a double-ended unitsubstation would have to have thecapability of serving the loads onboth sides of the tie breaker. For thisreason, transformers used in thisapplication have equal kVA ratingon each side of the double-endedunit substation and the normaloperating maximum load on eachtransformer is typically about 2/3 basenameplate kVA rating. Typically these

Figure 1.1-10. Two-Source Primary—Secondary Selective System

Figure 1.1-11. Sparing Transformer System

Primary Main Breakers

Primary Feeder Breakers

To Other SubstationsTo Other Substations

Secondary Main BreakerTie BreakerPrimary Fused Switch Transformer

TypicalDouble-EndedUnitSubstation

52 52

52

52 52 52 52

KK K

K K

K K

Sparing Transformer

Typical Secondary Busway Loop

Typical Single-Ended Substation

transformers are furnished withfan-cooling and/or lower than normaltemperature rise such that underemergency conditions they can carryon a continuous basis the maximumload on both sides of the secondary tiebreaker. Because of this spare trans-former capacity, the voltage regulationprovided by the double-ended unitsubstation system under normalconditions is better than that of thesystems previously discussed.

The double-ended unit substationarrangement can be used in conjunctionwith any of the previous systemsdiscussed, which involve two primarysources. Although not recommended,if allowed by the utility, momentaryre-transfer of loads to the restoredsource may be made closed transition(anti-parallel interlock schemes wouldhave to be defeated) for either the

primary or secondary systems. Underthis condition, all equipment interrupt-ing and momentary ratings should besuitable for the fault current availablefrom both sources.

For double-ended unit substationsequipped with ground fault systemsspecial consideration to transformerneutral grounding and equipmentoperation should be made—see“Grounding” and “Ground FaultProtection” in Section 1.4. Wheretwo single-ended unit substations areconnected together by external tieconductors, it is recommended that

a tie breaker be furnished at each endof the tie conductors.

5. Sparing Transformer SystemThe sparing transformer system concept came into use as an alternative to thecapital cost intensive double-endedsecondary unit substation distributionsystem (see Two-Source Primary—Secondary Selective System). It essen-tially replaces double-ended substationswith single-ended substations and oneor more “sparing” transformer substa-tions all interconnected on a commonsecondary bus (see Figure 1.1-11).

Generally no more than three to fivesingle-ended substations are on asparing loop.

The essence of this design philosophyis that conservatively designed andloaded transformers are highly reliableelectrical devices and rarely fail. There-fore, this design provides a single com-mon backup transformer for a group oftransformers in lieu of a backup trans-former for each and every transformer.This system design still maintains ahigh degree of continuity of service.




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Referring to Figure 1.1-11, it is appar-ent that the sparing concept backs upprimary switch and primary cable fail-ure as well. Restoration of lost or failedutility power is accomplished similarlyto primary selective scheme previouslydiscussed. It is therefore important touse an automatic throwover systemin a two source lineup of primaryswitchgear to restore utility poweras discussed in the “Two-SourcePrimary” scheme—see Figure 1.1-10.

A major advantage of the sparingtransformer system is the typicallylower total base kVA of transformation.In a double-ended substation design,each transformer must be rated tocarry the sum of the loads of two bussesand usually requires the addition ofcooling fans to accomplish this rating.In the “sparing” concept, each trans-former carries only its own load, which

is typically not a fan-cooled rating. Major space savings is also a benefit of thissystem in addition to first cost savings.

The sparing transformer systemoperates as follows:

■ All main breakers, includingthe sparing main breaker, arenormally closed; the tie breakersare normally open

■ Once a transformer (or primarycable or primary switch/fuse) fails,the associated secondary mainbreaker is opened. The associatedtie breaker is then closed, whichrestores power to the single-ended

substation bus■ Schemes that require the main to

be opened before the tie is closed(“open transition”), and that allowany tie to be closed before thesubstation main is opened, (“closedtransition”) are possible

With a closed transition scheme, it iscommon to add a timer function thatopens the tie breaker unless eithermain breaker is opened within a timeinterval. This closed transition allowspower to be transferred to the sparingtransformer without interruption, suchas for routine maintenance, and then

back to the substation. This closedtransition transfer has an advantage insome facilities; however, appropriateinterrupting capacities and bus bracingmust be specified suitable for themomentary parallel operation.

In facilities without qualified electricalpower operators, an open transitionwith key interlocking is often aprudent design.

Note: Each pair of “main breaker/tie breaker”key cylinders should be uniquely keyed to

prevent any paralleled source operations.

Careful sizing of these transformersas well as careful specification of thetransformers is required for reliability.Low temperature rise specified withcontinuous overload capacity orupgraded types of transformersshould be considered.

One disadvantage to this system isthe external secondary tie system,see Figure 1.1-11. As shown, all single-ended substations are tied together onthe secondary with a tie busway orcable system. Location of substationsis therefore limited because of voltagedrop and cost considerations.

Routing of busway, if used, must becarefully layed out. It should also benoted, that a tie busway or cable faultwill essentially prevent the use of thesparing transformer until it is repaired.Commonly, the single-ended substa-tions and the sparing transformermust be clustered. This can also bean advantage, as more kVA can besupported from a more compactspace layout.

6. Simple Spot Network Systems

The AC secondary network system

is the system that has been used formany years to distribute electric powerin the high-density, downtown areasof cities, usually in the form of utilitygrids. Modifications of this type ofsystem make it applicable to serveloads within buildings.

The major advantage of the secondarynetwork system is continuity ofservice. No single fault anywhereon the primary system will interruptservice to any of the system’s loads.Most faults will be cleared withoutinterrupting service to any load.

Another outstanding advantage thatthe network system offers is its flexi-bility to meet changing and growingload conditions at minimum cost andminimum interruption in service toother loads on the network. In additionto flexibility and service reliability, thesecondary network system providesexceptionally uniform and goodvoltage regulation, and its highefficiency materially reduces thecosts of system losses.

Three major differences between thenetwork system and the simple radialsystem account for the outstanding

advantages of the network. First,a network protector is connected inthe secondary leads of each networktransformer in place of, or in additionto, the secondary main breaker, asshown in Figure 1.1-12. Also, thesecondaries of each transformer ina given location (spot) are connectedtogether by a switchgear or ring busfrom which the loads are served overshort radial feeder circuits. Finally, theprimary supply has sufficient capacityto carry the entire building load with-out overloading when any one primaryfeeder is out of service.

A network protector is a speciallydesigned heavy-duty air power breaker,spring close with electrical motor-charged mechanism, with a network relay tocontrol the status of the protector(tripped or closed). The network relayis usually a solid-state microprocessor-based component integrated

Figure 1.1-12. Three-Source Spot Network

CustomerLoads

CustomerLoads

CustomerLoads

NC NC

TieTie

Typical Feeder

To OtherNetworks

DrawoutLow VoltageSwitchgear

Fuses

Primary Circuit

Network Transformer

Network Protector

Optional Main, 50/51Relaying and/orNetwork Disconnect

LV Feeder



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into the protector enclosure thatfunctions to automatically close theprotector only when the voltageconditions are such that its associatedtransformer will supply power to thesecondary network loads, and to auto-

matically open the protector whenpower flows from the secondary to thenetwork transformer. The purpose ofthe network protector is to protect theintegrity of the network bus voltageand the loads served from it againsttransformer and primary feeder faultsby quickly disconnecting the defectivefeeder-transformer pair from thenetwork when backfeed occurs.

The simple spot network systemresembles the secondary-selectiveradial system in that each load areais supplied over two or more primaryfeeders through two or more trans-formers. In network systems, the

transformers are connected throughnetwork protectors to a commonbus, as shown in Figure 1.1-12, fromwhich loads are served. Because thetransformers are connected in parallel,a primary feeder or transformer faultdoes not cause any service interrup-tion to the loads. The paralleledtransformers supplying each loadbus will normally carry equal loadcurrents, whereas equal loading ofthe two separate transformers supply-ing a substation in the secondary-selective radial system is difficult toobtain. The interrupting duty imposedon the outgoing feeder breakers in the

network will be greater with the spotnetwork system.

The optimum size and number ofprimary feeders can be used in thespot network system because theloss of any primary feeder and itsassociated transformers does notresult in the loss of any load evenfor an instant. In spite of the sparecapacity usually supplied in networksystems, savings in primary switch-gear and secondary switchgear costsoften result when compared to a radialsystem design with similar sparecapacity. This occurs in many radial

systems because more and smallerfeeders are often used in order tominimize the extent of any outagewhen a primary fault event occurs.

In spot networks, when a fault occurson a primary feeder or in a transformer,the fault is isolated from the systemthrough the automatic tripping of theprimary feeder circuit breaker and allof the network protectors associated

with that feeder circuit. This operationdoes not interrupt service to any loads.After the necessary repairs have beenmade, the system can be restored tonormal operating conditions by closingthe primary feeder breaker. All network

protectors associated with that feederwill close automatically.

The chief purpose of the network busnormally closed ties is to provide forthe sharing of loads and a balancingof load currents for each primary ser-vice and transformer regardless ofthe condition of the primary services.

Also, the ties provide a means forisolating and sectionalizing groundfault events within the switchgearnetwork bus, thereby saving a portionof the loads from service interruptions,yet isolating the faulted portion forcorrective action.

The use of spot network systemsprovides users with several importantadvantages. First, they save trans-former capacity. Spot networks permitequal loading of transformers underall conditions. Also, networks yieldlower system losses and greatlyimprove voltage conditions. Thevoltage regulation on a networksystem is such that both lights andpower can be fed from the sameload bus. Much larger motors canbe started across-the-line than on asimple radial system. This can result insimplified motor control and permitsthe use of relatively large low voltage

motors with their less expensivecontrol. Finally, network systemsprovide a greater degree of flexibilityin adding future loads; they can beconnected to the closest spotnetwork bus.

Spot network systems are economicalfor buildings that have heavy concen-trations of loads covering small areas,with considerable distance betweenareas, and light loads within thedistances separating the concentratedloads. They are commonly used inhospitals, high rise office buildings,and institutional buildings where a

high degree of service reliability isrequired from the utility sources.Spot network systems are especiallyeconomical where three or moreprimary feeders are available.Principally, this is due to supplyingeach load bus through three ormore transformers and the reductionin spare cable and transformercapacity required.

They are also economical whencompared to two transformer double-ended substations with normallyopened tie breakers.

Emergency power should be connectedto network loads downstream from

the network, or upstream at primaryvoltage, not at the network bus itself.

7. Medium Voltage DistributionSystem Design

A. Single Bus, Figure 1.1-13

The sources (utility and/or generator(s))are connected to a single bus. All feeders are connected to the same bus.

Figure 1.1-13. Single BusThis configuration is the simplestsystem; however, outage of the utilityresults in total outage.

Normally the generator does not haveadequate capacity for the entire load.A properly relayed system equippedwith load shedding, automatic voltage/ frequency control may be able tomaintain partial system operation.

Any future addition of breaker sectionsto the bus will require a shutdown ofthe bus, because there is no tie breaker.

B. Single Bus with Two Sources from the

Utility, Figure 1.1-14Same as the single bus, except thattwo utility sources are available.This system is operated normally withthe main breaker to one source open.Upon loss of the normal service, thetransfer to the standby normallyopen (NO) breaker can be automaticor manual. Automatic transfer ispreferred for rapid service restorationespecially in unattended stations.

52

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Main Bus

G

One of Several Feeders

52

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Figure 1.1-14. Single Bus with Two-Sources

Retransfer to the “Normal” can beclosed transition subject to the approvalof the utility. Closed transition momen-tarily (5–10 cycles) parallels bothutility sources. Caution: when bothsources are paralleled, the fault currentavailable on the load side of the maindevice is the sum of the available faultcurrent from each source plus the motorfault contribution. It is recommendedthat the short-circuit ratings of thebus, feeder breakers and all load sideequipment are rated for the increasedavailable fault current. If the utilityrequires open transfer, the disconnec-tion of motors from the bus must beensured by means of suitable time delayon reclosing as well as supervisionof the bus voltage and its phase withrespect to the incoming source voltage.

This busing scheme does not precludethe use of cogeneration, but requiresthe use of sophisticated automatic syn-chronizing and synchronism checkingcontrols, in addition to the previouslymentioned load shedding, automaticfrequency and voltage controls.

This configuration is more expensivethan the scheme shown in Figure 1.1-13,but service restoration is quicker. Again,a utility outage results in total outage tothe load until transfer occurs. Extensionof the bus or adding breakers requiresa shutdown of the bus.

If paralleling sources, reverse current,

reverse power and other appropriaterelaying protection should be addedas requested by the utility.

C. Multiple Sources with Tie Breaker,Figure 1.1-15 and Figure 1.1-16

This configuration is similar to configu-ration B. It differs significantly in thatboth utility sources normally carry theloads and also by the incorporationof a normally open tie breaker. Theoutage to the system load for a utilityoutage is limited to half of the system.

Utility #2Utility #1

Normal Standby

NC NO

Loads

52 52

Again, the closing of the tie breaker canbe manual or automatic. The statementsmade for the retransfer of scheme Bapply to this scheme also.

Figure 1.1-15. Two-Source Utility withTie Breaker

If looped or primary selective distribu-tion system for the loads is used, thebuses can be extended without a shut-down by closing the tie breaker andtransferring the loads to the other bus.

This configuration is more expensivethan B. The system is not limited to twobuses only. Another advantage is thatthe design may incorporate momentaryparalleling of buses on retransfer afterthe failed line has been restored to pre-

vent another outage. See the Caution for Figures 1.1-14, 1.1-15 and 1.1-16.

In Figure 1.1-16, closing of the tiebreaker following the opening of amain breaker can be manual or auto-matic. However, because a bus canbe fed through two tie breakers, thecontrol scheme should be designedto make the selection.

The third tie breaker allows any busto be fed from any utility source.

Summary

The medium voltage system configura-tions shown are based on using metal-

clad drawout switchgear. The servicecontinuity required from electricalsystems makes the use of single-sourcesystems impractical.

In the design of a modern mediumvoltage system, the engineer should:

1. Design a system as simple aspossible.

2. Limit an outage to as small aportion of the system as possible.

3. Provide means for expanding thesystem without major shutdowns.

4. Relay the system so that only the

faulted part is removed fromservice, and damage to it is mini-mized consistent with selectivity.

5. Specify and apply all equipmentwithin its published ratings andnational standards pertaining tothe equipment and its installation.

Figure 1.1-16. Triple-Ended Arrangement

Utility #1

NC

Bus #1 Bus #2

Load Load

Utility #2

NC

NO

52 52

52

52 52

Caution for Figures 1.1-14, 1.1-15 and 1.1-16: If continuous paralleling ofsources is planned, reverse current,

reverse power and other appropriaterelaying protection should be added.When both sources are paralleled forany amount of time, the fault currentavailable on the load side of the maindevice is the sum of the availablefault current from each source plusthe motor fault contribution. It isrequired that bus bracing, feederbreakers and all load side equipmentis rated for the increased availablefault current.

NO

NC

Bus #1 Bus #2

Utility #1 Utility #2

NC

NO NO

Utility #3

Bus #3

NC

Tie Busway

52 52 52

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52 NOTypical Feeder52 5252



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Health Care Facilities

Health care facilities are defined byNFPA (National Fire Protection Agency)as “Buildings or portions of buildingsin which medical, dental, psychiatric,

nursing, obstetrical, or surgical careare provided.” Due to the criticalnature of the care being provided atthese facilities and their increasingdependence on electrical equipmentfor preservation of life, health carefacilities have special requirements forthe design of their electrical distribu-tion systems. These requirements aretypically much more stringent thancommercial or industrial facilities.The following section summarizessome of the unique requirementsof health care facility design.

There are several agencies and organi-zations that develop requirements

for health care electrical distributionsystem design. The following is alisting of some of the specific NFPA(National Fire Protection Agency)standards that affect health carefacility design and implementation:

■ NFPA 37-2010—Standard forStationary Combustion Enginesand Gas Turbines

■ NFPA 70-2011—NationalElectrical Code

■ NFPA 99-2005—Health Care Facilities

■ NFPA 101-2009—Life Safety Code

■ NFPA 110-2010—Standard for Emer-gency and Standby Power Systems

■ NFPA 111-2010—Standard onStored Electrical Energy Emergencyand Standby Power Systems

These NFPA guidelines represent themost industry recognized standardrequirements for health care electricaldesign. However, the electrical designengineer should consult with theauthorities having jurisdiction overthe local region for specific electricaldistribution requirements.

Health Care Electrical SystemRequirements

Health care electrical systems usuallyconsist of two parts:

1. Non-essential or normal

electrical system.

2. Essential electrical system.

All electrical power in a health carefacility is important, though someloads are not critical to the safe opera-tion of the facility. These “non-essential”or “normal” loads include things suchas general lighting, general lab equip-ment, non-critical service equipment,patient care areas, etc. These loads arenot required to be fed from an alternatesource of power.

The electrical system requirements forthe essential electrical system (EES)vary according to the type of healthcare facility. Health care facilities arecategorized by NFPA 99 as Type 1,Type 2 or Type 3 facilities. Some

example health care facilities, classifiedby type, are summarized in thefollowing Table 1.1-8.

Table 1.1-8. Health Care Facilities

If electrical life support or critical care areasare present, then facility is classified as Type 1.

Type 1 Essential ElectricalSystems (EES)

Type 1 essential electrical systems(EES) have the most stringent require-ments for providing continuity ofelectrical service and will, therefore,be the focus of this section. Type 1EES requirements meet or exceedthe requirements for Type 2 andType 3 facilities.

Figure 1.1-17. Typical Large Hospital Electrical System—Type 1 Facility

Description Definition EES Type

HospitalsNursing homesLimited care

facilities

NFPA 99 Chap. 13NFPA 99 Chap. 17

NFPA 99 Chap. 18

Type 1Type 2

Type 2

Ambulatorysurgicalfacilities

Other healthcare facilities

NFPA 99 Chap. 14

NFPA 99 Chap. 14

Type 3

Type 3

Normal Source Normal Source

G

Non-Essential Loads Non-Essential Loads

Essential Electrical System

Manual Transfer Switch

Normal Source Emergency Power Supply

Life SafetyBranch

CriticalBranch

Emergency System

EquipmentSystemDelayed Automatic Transfer Switch

Automatic (Non-Delaying)Transfer Switch




1.1September 2011


Sheet 01

System Design017

Sources: Type 1 systems are requiredto have a minimum of two independentsources of electrical power—a normalsource that generally supplies theentire facility and one or more alter-nate sources that supply power when

the normal source is interrupted. Thealternate source(s) must be an on-sitegenerator driven by a prime moverunless a generator(s) exists as thenormal power source. In the casewhere a generator(s) is used as thenormal source, it is permissible for thealternate source to be a utility feed.Alternate source generators must beclassified as Type 10, Class X, Level 1gensets per NFPA 110 Tables 4.1(a)and 4.2(b) that are capable of providingpower to the load in a maximum of10 seconds. Typically, the alternatesources of power are supplied to theloads through a series of automaticand/or manual transfer switches (see Tab 25). The transfer switches canbe non-delayed automatic, delayedautomatic or manual transfer dependingon the requirements of the specificbranch of the EES that they are feeding.It is permissible to feed multiplebranches or systems of the EES froma single automatic transfer switchprovided that the maximum demandon the EES does not exceed 150 kVA.This configuration is typically seenin smaller health care facilities thatmust meet Type 1 EES requirements(see Figure 1.1-18).

Figure 1.1-18. Small Hospital ElectricalSystem—Single EES Transfer Switch

Table 1.1-9. Type 1 EES Applicable Codes

Systems and Branches of Service: TheType 1 EES consists of two separatepower systems capable of supplyingpower considered essential for lifesafety and effective facility operationduring an interruption of the normalpower source. They are the emergencysystem and the equipment system.

1. Emergency system—consists ofcircuits essential to life safety and

critical patient care.

The emergency system is an electricalsub-system that must be fed from anautomatic transfer switch or series ofautomatic transfer switches. Thisemergency system consists of twomandatory branches that provide powerto systems and functions essential tolife safety and critical patient care.

A. Life safety branch—suppliespower for lighting, receptaclesand equipment to perform thefollowing functions:

1. Illumination of means of egress.

2. Exit signs and exit direction signs.3. Alarms and alerting systems.

4. Emergency communicationssystems.

5. Task illumination, batterychargers for battery poweredlighting, and select receptaclesat the generator.

6. Elevator lighting control, com-munication and signal systems.

7. Automatic doors used for egress.

These are the only functionspermitted to be on the life safetybranch. Life safety branch equip-

ment and wiring must be entirelyindependent of all other loadsand branches of service. Thisincludes separation of raceways,boxes or cabinets. Power must besupplied to the life safety branchfrom a non-delayed automatic transfer switch.

B. Critical branch—supplies powerfor task illumination, fixed equip-ment, selected receptacles andselected power circuits for areasrelated to patient care. Thepurpose of the critical branch

is to provide power to a limitednumber of receptacles and loca-tions to reduce load and minimizethe chances of fault conditions.The transfer switch(es) feeding thecritical branch must be automatictype. They are permitted to haveappropriate time delays that willfollow the restoration of the lifesafety branch, but should havepower restored within 10 secondsof normal source power loss.The critical branch provides powerto circuits serving the followingareas and functions:

1. Critical care areas.

2. Isolated power systems inspecial environments.

3. Task illumination and selectedreceptacles in the followingpatient care areas: infantnurseries, medication prepareas, pharmacy, selectedacute nursing areas, psychiatricbed areas, ward treatmentrooms, nurses’ stations.

4. Specialized patient care taskillumination, where needed.

5. Nurse call systems.

6. Blood, bone and tissue banks.

7. Telephone equipment roomsand closets.

8. Task illumination, selectedreceptacles and selected powercircuits for the following: generalcare beds (at least one duplexreceptacle), angiographic labs,cardiac catheterization labs,coronary care units, hemodialysis rooms, selected emergencyroom treatment areas, humanphysiology labs, intensive careunits, selected postoperativerecovery rooms.

9. Additional circuits and single-phase fraction motors as neededfor effective facility operation.

Normal Source

G

Non-EssentialLoads

AlternateSource

Entire Essential

Electric System(150 kVA or Less)

Description Standard Section

DesignSources

Uses

EmergencyPower SupplyClassification

NFPA 99NFPA 99

NFPA 99

NFPA 110

4.4.1.1.14.4.1.1.4 thru4.4.4.1.1.7.24.4.1.1.8 (1-3)

4

Distribution NFPA 99NEC

4.4.2517.30



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Table 1.1-10. Type 1—Emergency SystemApplicable Codes

2. Equipment system—consists ofmajor electrical equipment necessaryfor patient care and Type 1 operation.

The equipment system is a subsystemof the EES that consists of large electrical equipment loads needed for patientcare and basic hospital operation.Loads on the equipment system thatare essential to generator operation are

required to be fed by a non-delayed automatic transfer switch.

The following equipment must bearranged for delayed automatic transfer to the emergency power supply:

1. Central suction systems for medicaland surgical functions.

2. Sump pumps and other equipmentrequired for the safe operation ofa major apparatus.

3. Compressed air systems formedical and surgical functions.

4. Smoke control and stairpressurization systems.

5. Kitchen hood supply and exhaustsystems, if required to operateduring a fire.

The following equipment must bearranged for delayed automatic or manual transfer to the emergencypower supply:

1. Select heating equipment.

2. Select elevators.

3. Supply, return and exhaustventilating systems for surgical,obstetrical, intensive care,coronary care, nurseries andemergency treatment areas.

4. Supply, return and exhaustventilating systems for airborneinfectious/isolation rooms, labs andmedical areas where hazardousmaterials are used.

5. Hyperbaric facilities.

6. Hypobaric facilities.

7. Autoclaving equipment.

8. Controls for equipment listed above.

9. Other selected equipment inkitchens, laundries, radiologyrooms and central refrigerationas selected.

Table 1.1-11. Type 1—Equipment SystemApplicable Codes

Any loads served by the generator thatare not approved as outlined above as

part of the essential electrical systemmust be connected through a separatetransfer switch. These transfer switchesmust be configured such that the loadswill not cause the generator to overload

and must be shed in the event thegenerator enters an overload condition.

Ground fault protection—per NFPA 70NEC Article 230.95, ground faultprotection is required on any feeder orservice disconnect 1000A or larger on

systems with line to ground voltagesof 150V or greater and phase-to-phasevoltages of 600V or less. For health carefacilities (of any type), a second level ofground fault protection is required tobe on the next level of feeder down-stream. This second level of groundfault is only required for feeders thatserve patient care areas and equipmentintended to support life. 100% selectivecoordination of the two levels of groundfault protection must be achieved with aminimum six-cycle separation betweenthe upstream and downstream device.

New in the 2011 NEC, ground fault

protection is now allowed betweenthe generator(s) and the EES transferswitch(es). However, NEC 517.17(B)prohibits the installation of ground faultprotection on the load side of a transferswitch feeding EES circuits (see Figure1.1-19—additional level of ground fault).Careful consideration should be used inapplying ground fault protection on theessential electrical system to preventa ground fault that causes a trip of thenormal source to also cause a trip onthe emergency source. Such an eventcould result in complete power loss ofboth normal and emergency powersources and could not be recovered

until the source of the ground faultwas located and isolated from thesystem. To prevent this condition,NEC 700.26 removes the ground faultprotection requirement for the

Figure 1.1-19. Additional Level of Ground Fault Protection Ground fault protection is required for service disconnects 1000A and larger or systems with less than 600V phase-to-phase and greater than 150V to

ground per NEC 230.95.


General NFPA 99NEC

4.4.2.2.2517.31

Life safety

branch

NFPA 99

NEC

4.4.2.2.2.2

517.32

Critical branch NFPA 99NEC

4.4.2.2.2.3517.33

Wiring NFPA 99NEC

4.4.2.2.4517.30(C)


General NFPA 99NEC

4.4.2.2.3517.34

Equipment NFPA 99NEC

4.4.2.2.3 (3-5)517.34(A)-(B)

Normal Source ormal Source(s)

G

480/277V➀

ServiceEntrance

1000Aor Larger

GFServiceEntrance

1000Aor Larger

GF

480/277V

GFGFGF GFGFGFGFGFGF GFGF

ServiceEntrance

1000Aor Larger

GF

480/277V

GF

Non-Essential Loads Non-Essential Loads

Essential Electrical System

Additional Levelof Ground FaultProtection

Ground Faultis Permitted

and EES TransferSwitches.(NEC 517.17(B))

Additional Level of Ground Fault isnotTransfer Switches. (NEC 517.17a(2))

= Ground Fault Protection Required

Generator Breakers areSupplied with

Ground Fault AlarmOnly. (NEC 700.26)




1.1September 2011


Sheet 01

System Design019

emergency system source. Typically,the emergency system generator(s)are equipped with ground fault alarmsthat do not automatically disconnectpower during a ground fault.

Table 1.1-12. Ground Fault Protection

Applicable Codes

Wet procedure locations—A wetprocedure location in a health carefacility is any patient care area thatis normally subject to wet conditionswhile patients are present. Typical wetprocedure locations can include oper-

ating rooms, anesthetizing locations,dialysis locations, etc. (Patient beds,toilets and sinks are not consideredwet locations.) These wet procedurelocations require special protectionto guard against electric shock. Theground fault current in these areasmust be limited to not exceed 6 mA.

In areas where the interruption of poweris permissible, ground fault circuitinterrupters (GFCI) can be employed.GFCIs will interrupt a circuit whenground fault current exceeds 5 mA(±1 mA).

In areas where the interruption of

power cannot be tolerated, protectionfrom ground fault currents is accom-plished through the use of an isolatedpower system. Isolated power systemsprovide power to an area that is iso-lated from ground (or ungrounded).This type of system limits the amountof current that flows to ground inthe event of a single line-to-groundfault and maintains circuit continuity.Electronic line isolation monitors (LIM)are used to monitor and display leakagecurrents to ground. When leakagecurrent thresholds are exceeded, visibleand/or audible alarms are initiated toalert occupants of a possible hazardous

condition. This alarm occurs withoutinterrupting power to allow for thesafe conclusion of critical procedures.

Table 1.1-13. Wet Procedure LocationApplicable Codes

Maintenance and Testing

Regular maintenance and testing ofthe electrical distribution system ina health care facility is necessary toensure proper operation in an emer-gency and, in some cases, to maintain

government accreditation. Any healthcare facility receiving Medicare orMedicaid reimbursement from thegovernment must be accredited by theJoint Commission on Accreditation ofHealth Care Organizations (JCAHO).JCAHO has established a group ofstandards called the Environment ofCare, which must be met for healthcare facility accreditation. Included inthese standards is the regular testingof the emergency (alternate) powersystem(s). Diesel-powered EPS instal-lations must be tested monthly inaccordance with NFPA 110 Standard for Emergency and Standby Power

Systems . Generators must be testedfor a minimum of 30 minutes underthe criteria defined in NFPA 110.

One method to automate the task ofmonthly generator tests is through theuse of Power Xpert® communications.With the Power Xpert integrated meter-ing, monitoring and control system, afacility maintenance director can ini-tiate a generator test, control/monitorloads, meter/monitor generator testpoints and create a JCAHO compliantreport automatically from a central PC.The report contains all metered values,test results, date/time information, etc.necessary to satisfy JCAHO require-

ments. This automated generator testing procedure reduces the labor, trainingand inaccuracies that occur duringmanual emergency power system tests.(See Power Monitoring Tab 2.)

Table 1.1-14. Maintenance and TestingApplicable Codes

Routine maintenance should be per-formed on circuit breakers, transferswitches, switchgear, generator equip-ment, etc. by trained professionalsto ensure the most reliable electricalsystem possible. See Tab 41 forEaton’s Electrical Services & Systems(EESS), which provides engineers,

trained in development and executionof annual preventative maintenanceprocedures of health care facilityelectrical distribution systems.

Paralleling Emergency Generators

Without Utility Paralleling

In many health care facilities (andother large facilities with criticalloads), the demand for standbyemergency power is large enoughto require multiple generator sets topower all of the required essentialelectrical system (EES) loads. In manycases, it becomes more flexible andeasier to operate the required multiplegenerators from a single location usinggenerator paralleling switchgear.Figure 1.1-20 on Page 1.1-18 showsan example of a typical one-line for aparalleling switchgear lineup feeding

the EES.A typical abbreviated sequence ofoperation for a multiple emergencygenerator and ATS system follows.Note that other modes of operationsuch as generator demand priority andautomated testing modes are availablebut are not included below. (ReferenceTab 41 for complete detailedsequences of operation.)

1. Entering emergency mode

a. Upon loss of normal source,automatic transfer switchessend generator control systema run request.

b. All available generators arestarted. The first generator upto voltage and frequency isclosed to the bus.

c. Unsheddable loads and loadshed Priority 1 loads are pow-ered in less than 10 seconds.

d. The remaining generators aresynchronized and paralleledto the bus as they come up tovoltage and frequency.

e. As additional generators areparalleled to the emergencybus, load shed priority levels

are added, powering theirassociated loads.

f. The system is now inemergency mode.

2. Exit from emergency mode

a. Automatic transfer switchessense the utility source iswithin acceptable operationaltolerances for a time durationset at the automatic transferswitch.


ServicesFeeders

NECNEC

230.95215.10

Additional level NECNFPA 99

517.174.3.2.5

Alternate source NECNEC

700.26701.26


General NFPA 99NEC

4.3.2.2.9517.20

Isolated powersystems

NFPA 99NEC

4.3.2.6517.160


Grounding NFPA 99 4.3.3.1

Emergency powersystem

NFPA 99JCAHO

4.4.4.1.1EC.2.14(d)

Generator NFPA 110 8.4

Transfer switches NFPA 110 8.3.5, 8.4.6

Breakers NFPA 99

NFPA 110

4.4.4.1.2

8.4.7



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System Design020

b. As each automatic transferswitch transfers back to utilitypower, it removes its runrequest from the generatorplant.

c. When the last automatic trans-

fer switch has retransferred tothe utility and all run requestshave been removed from thegenerator plant, all generatorcircuit breakers are opened.

d. The generators are allowedto run for their programmedcool-down period.

e. The system is now back inautomatic/standby mode.

With Utility Paralleling

Today, many utilities are offering theircustomers excellent financial incen-tives to use their on-site generationcapacity to remove load from the utilitygrid. These incentives are sometimes

referred to as limited interruptiblerates (LIP). Under these incentives,utilities will greatly reduce or eliminatekWhr or kW demand charges to theircustomers with on-site generationcapabilities. In exchange, during timesof peak loading of the utility grid, theutility can ask their LIP rate customersto drop load from the grid by usingtheir on-site generation capabilities.

Health care facilities are ideally suitedto take advantage of these programsbecause they already have significanton-site generation capabilities due tothe code requirements described.

Many health care facilities are takingadvantage of these utility incentivesby adding generator capacity overand above the NFPA requirements.Figure 1.1-21 on Page 1.1-19 showsan example one-line of a health care

facility with complete generatorbackup and utility interconnect.

NFPA 110 requirements state that thenormal and emergency sources mustbe separated by a fire-rated wall.

The intent of this requirement is so thata fire in one location cannot take outboth sources of power. To meet thisrequirement, the paralleling switchgearmust be split into separate sectionswith a tie bus through a fire-rated wall.For more information on generatorparalleling switchgear, see Tab 40.

Figure 1.1-20. Typical One-Line for a Paralleling Switchgear Lineup Feeding the Essential Electrical System (EES)

UtilityMetering

Utility

Transformer

Service Main

Normal Bus

OptionalElectricallyOperatedStoredEnergyBreakers

Non-EssentialLoads

EP1 EP2 EPX

FxF2F1EFxEF2EF1

Generators X = Number of Units

TypicalGeneratorBreaker

Emergency Bus

EquipmentATS # 1

Life SafetyATS # 2

CriticalATS # X

TypicalPanelboards

GxG2G1

Optional ElectricallyOperated StoredEnergy Breakers

Load Shed/LoadAdd ATS Units

Optional ClosedTransitionParalleling ofGenerators andUtility




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Sheet 01

System Design021

Figure 1.1-21. Typical One-Line Health Care Facility with Complete Generator Backup and Utility Interconnect

Utility

Transformer

UtilityMetering

Generators X = Number of Units

TypicalGeneratorBreaker

GxG2G1

Emergency Bus

Electrically OperatedStored EnergyBreakers

EFxEF2EF1

Service Main

Normal Bus

OptionalElectricallyOperatedStoredEnergyBreakers

FxF2F1

Non-EssentialLoads

EquipmentATS # 1

Life SafetyATS # 2

CriticalATS # X

Load Shed/ Load AddATS Units

TypicalPanelboards

EP1 EP2 EPX

UtilityProtectiveRelay

TIE Optional TIE

Fire-Rated Wallor Separation Barrier

Field InstalledCable or Busway

ClosedTransitionParalleling ofGenerators andUtility, PlusSoft Loading/ Unloading



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Generator System Design023

Generators andGenerator Systems

Typical Diesel Genset—Caterpillar

Introduction

The selection and applicationof generators into the electricaldistribution system will depend onthe particular application. There aremany factors to consider, includingcode requirements, environmentalconstraints, fuel sources, controlcomplexity, utility requirements andload requirements. The health carerequirements for legally requiredemergency standby generationsystems are described starting onPage 1.1-14. Systems described inthis section are applicable to healthcare requirements, as well as otherfacilities that may require a highdegree of reliability. The electricalsupply for data centers, financialinstitutions, telecommunications,government and public utilitiesalso require high reliability. Threatsof disaster or terror attacks haveprompted many facilities to requirecomplete self-sufficiency forcontinuous operation.

2011 NEC Changes Related toGenerator Systems

Article 250.30—Grounding SeparatelyDerived AC Systems—has beencompletely rewritten for clarity andfor usability. Most notably, the termequipment bonding jumper waschanged to supply-side bondingjumper (see 250.30(A)(2)). This wasnecessary to ensure proper identifica-tion and installation of bondingconductors within or on the supply

side of service equipment andbetween the source of a separatelyderived system and the first discon-necting means. The other require-ments for grounded systems wererenumbered to accommodate the250.30(A)(2) change. 250.30(B)(3)—Ungrounded Systems—has beenadded, and this language requires

a supply-side bonding jumper tobe installed from the source of aseparately derived system to the firstdisconnecting means in accordancewith 250.30(A)(2). Another newrequirement, 250.30(C)—Outdoor

Source—has been added, and requiresa grounding electrode connection atthe source location when the separatelyderived system is located outsideof the building or the structurebeing supplied.

Article 445.19—Generators SupplyingMultiple Loads—has been revisedto require that the generator haveovercurrent protection per 240.15(A)when using individual enclosurestapped from a single feeder.

Article 517.17(B)—Feeder GFP (HealthCare Facilities)—now allows, but doesnot require, multiple levels of GFPE

upstream of the transfer switch whenthe choice is made to provide GFPEon the alternate power source(i.e., generator).

Article 701.6(D)—Signals (LegallyRequired Standby Systems)—nowrequires ground fault indication forlegally required standby systems ofmore than 150V to ground and OCPDsrated 1000A or more.

Types of Engines

Many generator sets are relativelysmall in size, typically ranging fromseveral kilowatts to several mega-

watts. These units are often requiredto come online and operate quickly.They need to have the capacity torun for an extended period of time.The internal combustion engine isan excellent choice as the primemover for the majority of theseapplications. Turbines may also beused. Diesel-fueled engines are themost common, but other fuels usedinclude natural gas, digester gas,landfill gas, propane, biodiesel,crude oil, steam and others.

Some campuses and industrialfacilities use and produce steamfor heating and other processes.

These facilities may find it economi-cally feasible to produce electricity asa byproduct of the steam production.These installations would typically beclassified as a cogeneration facilityproducing a fairly constant poweroutput and operating in parallel withthe electric utility system.

Types of GeneratorsGenerators can be either synchronousor asynchronous. Asynchronousgenerators are also referred to asinduction generators. The constructionis essentially the same as an induction

motor. It has a squirrel-cage rotor andwound stator. An induction generatoris a motor driven above its designedsynchronous speed thus generatingpower. It will operate as a motor if itis running below synchronous speed.The induction generator does not havean exciter and must operate in parallelwith the utility or another source. Theinduction generator requires VARs froman external source for it to generatepower. The induction generatoroperates at a slip frequency so itsoutput frequency is automaticallylocked in with the utility's frequency.

An induction generator is a popularchoice for use when designingcogeneration systems, where it willoperate in parallel with the utility.This type of generator offers certainadvantages over a synchronousgenerator. For example, voltage andfrequency are controlled by the utility;thus voltage and frequency regulatorsare not required. In addition, thegenerator construction offers highreliability and little maintenance.Also, a minimum of protective relaysand controls are required. Its majordisadvantages are that it requiresVARs from the system and it normally

cannot operate as a standby/ emergency generator.

Synchronous generators, however,are the most common. Their output isdetermined by their field and governorcontrols. Varying the current in theDC field windings controls the voltageoutput. The frequency is controlledby the speed of rotation. The torqueapplied to the generator shaft bythe driving engine controls the poweroutput. In this manner, the synchro-nous generator offers precise controlover the power it can generate. Incogeneration applications, it can beused to improve the power factor of

the system.



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Generator Systems

Emergency Standby Generator System

There are primarily three types ofgenerator systems. The first andsimplest type is a single generator

that operates independently fromthe electric utility power grid.This is typically referred to as anemergency standby generatorsystem. Figure 1.2-1 shows a singlestandby generator, utility sourceand a transfer switch. In this case, theload is either supplied from the utilityor the generator. The generator andthe utility are never continuouslyconnected together. This simple radialsystem has few requirements forprotection and control. It also has theleast impact on the complete electricpower distribution system. It shouldbe noted that this type of generator

system improves overall electricalreliability but does not provide theredundancy that some facilitiesrequire if the generator fails tostart or is out for maintenance.

Figure 1.2-1. Emergency StandbyGenerator System

Multiple Isolated Standby Generators

The second type of generator systemis a multiple isolated set of standbygenerators. Figure 1.2-2 showsmultiple generators connected toa paralleling bus feeding multiple

transfer switches. The utility is thenormal source for the transfer switches.The generators and the utility are nevercontinuously connected together in thisscheme. Multiple generators may berequired to meet the load requirements(N system). Generators may be appliedin an N+1 or a 2N system for improvedsystem reliability.

Figure 1.2-2. Multiple Isolated Set ofStandby Generators

In an N system, where N is the numberof generators required to carry theload; if a generator fails or is out formaintenance, then the load may bedropped. This is unacceptable for mostcritical 24/7 operations. In an N + 1

system, N is the number of generatorsneeded to carry the load and 1 isan extra generator for redundancy.If one generator fails to start or is outfor maintenance, it will not affect theload. In a 2N system, there is complete100% redundancy in the standbygeneration system such that the failureof one complete set of generatorswill not affect the load.

Multiple generator systems have amore complex control and protectionrequirement as the units have to besynchronized and paralleled together.The generators are required to sharethe load proportionally without swings

or prolonged hunting in voltage orfrequency for load sharing. They mayalso require multiple levels of loadshedding and/or load restorationschemes to match generation capacity.

Multiple Generators Operating inParallel with Utility System

The third type of system is either onewith a single or multiple generatorsthat operate in parallel with the utilitysystem. Figure 1.2-3 shows twogenerators and a utility source feedinga switchgear lineup feeding multipleloads. This system typically requiresgenerator capacity sufficient to carrythe entire load or sophisticated loadshedding schemes. This system willrequire a complete and complexprotection and control scheme. Theelectric utility may have very stringentand costly protection requirementsfor the system. IEEE standard 1547describes the interconnection require-ments for paralleling to the utility.

Figure 1.2-3. Multiple Generators Operatingin Parallel with Utility System

Utility

ATS

Load

G1

Utility

ATS-1

Load 1

ATS-2

Load 2

G1 G2

Switchgear

Utility

Switchgear

Load 1 Load 2 Load 3

G1 G2




1September 2011


Sheet 01


Generator FundamentalsA generator consists of two primarycomponents, a prime mover and analternator. The prime mover is theenergy source used to turn the rotorof the alternator. It is typically a

diesel combustion engine for mostemergency or standby systems.In cogeneration applications, theprime mover may come from a steamdriven turbine or other source. Ondiesel units, a governor and voltageregulator are used to control the speedand power output.

The alternator is typically a synchro-nous machine driven by the primemover. A voltage regulator controls itsvoltage output by adjusting the field.The output of a single generator ormultiple paralleled generator sets iscontrolled by these two inputs. Thealternator is designed to operate at aspecified speed for the required outputfrequency, typically 60 or 50 Hz. Thevoltage regulator and engine governoralong with other systems define thegenerator’s response to dynamicload changes and motor startingcharacteristics.

Generators are rated in power andvoltage output. Most generators aredesigned to operate at a 0.8 powerfactor. For example, a 2000 kWgenerator at 277/480V would have akVA rating of 2500 kVA (2000 kW/ 08 pf)and a continuous current ratingof 3007A

Typical synchronous generatorsfor industrial and commercialpower systems range in size from100–3000 kVA and from 208V–13,800V.Other ratings are available and thesediscussions are applicable to thoseratings as well.

Generators must be considered in theshort-circuit and coordination studyas they may greatly impact the ratingof the electrical distribution system.This is especially common on largeinstallations with multiple generatorsand systems that parallel with theutility source. Short-circuit current

contribution from a generatortypically ranges from 8 to 12 timesfull load amperes.

2500 kVA 480V 3 ⁄ ( )˙̇ ˙.

The application of generators requiresspecial protection requirements.The size, voltage class, importanceand dollar investment will influencethe protection scheme associated withthe generator(s). Mode of operationwill influence the utility company’sinterface protection requirements.Paralleling with the electric utility isthe most complicated of the utilityinter-tie requirements. IEEE ANSI 1547provides recommended practices.

Generator Grounding and Bonding(Ref. NEC 2011, Article 250.30(A)(1)and (2))

Generator grounding methods needto be considered and may affect thedistribution equipment and ratings.Generators may be connected in deltaor wye, but wye is the most typicalconnection. A wye-connected generatorcan be solidly grounded, low impedancegrounded, high impedance groundedor ungrounded. Section 1.4 discussesgeneral grounding schemes, benefitsof each and protection considerations.

A solidly grounded generator may havea lower zero sequence impedance thanits positive sequence impedance. In thiscase, the equipment will need to be rated for the larger available ground faultcurrent. The generator’s neutral maybe connected to the system-neutral; ifit is, the generator is not a separatelyderived system and a three-pole transferswitch is used. If the generator’s neutralis bonded to ground separate from thesystem-neutral, it is a separately

derived system and a four-pole transferswitch is required or ground fault relayscould misoperate and unbalancedneutral current may be carried onground conductors.

An IEEE working group has studied the

practice of low resistance groundingof medium voltage generators withinthe general industry. This “workinggroup” found that, for internal generatorground faults, the vast majority of thedamage is done after the generatorbreaker is tripped offline, and the fieldand turbine are tripped. This is due tothe stored energy in the generator fluxthat takes several seconds to dissipateafter the generator is tripped offline.It is during this time that the lowresistance ground allows significantamounts of fault current to flow intothe ground fault. Because the large faultcurrents can damage the generator’swinding, application of an alternateprotection method is desirable duringthis time period. One of the solutionsset forth by this “working group” isa hybrid high resistance grounding(HHRG) scheme as shown inFigure 1.2-4. In the HHRG scheme,the low resistance ground (LRG)is quickly tripped offline when thegenerator protection senses theground fault. The LRG is clearedat the same time that the generatorbreaker clears, leaving the highresistance ground portion connectedto control the transient overvoltagesduring the coast-down phase of thegenerator, thereby all but eliminating

generator damage.

Figure 1.2-4. Hybrid High Resistance Grounding Scheme

Gen 59G

51G

87GN

86

PhaseRelays

HRG

LRGR

R



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Generator ControlsThe engine generator set has controlsto maintain the output frequency(speed) and voltage. These controlsconsist of a governor and voltageregulator. As loads change on the

system, the frequency and voltagewill change. The speed control willthen adjust the governor to correctfor the load (kW) change. Thevoltage regulator will change thefield current to adjust the voltageto the desired voltage value. Theseare the basic controls found on allsynchronous generators.

Multiple generator systems requiremore sophisticated controls.Generators are paralleled in a multi-generator system and they must sharethe load. These systems often havea load shed scheme, which adds to

the complexity.Multiple generator schemes need amaster controller to prevent units frombeing connected out-of-phase. Thesequence of operation is to send astart signal to all generators simulta-neously. The first unit up to frequencyand voltage will be permitted to closeits respective breaker and energize theparalleling bus. Breakers for the othergenerators are held open, not permit-ted to close, until certain conditionsare met. Once the paralleling bus isenergized, the remaining generatorsmust be synchronized to it beforethe generators can be paralleled.

Synchronization compares the voltagephasor’s angle and magnitude. Bothgenerators must be operating at thesame frequency and phase-matchedwithin typically 5 to 10 degrees witheach other. The voltage magnitudetypically must be within 20 to 24%.

A synch-scope is typically suppliedon paralleling gear. The synch-scopedisplays the relative relationshipbetween voltage phasors on thegenerator to be paralleled and thebus. If the generator is running slower

than the bus (less than 60 Hz) then theneedle on the scope will spin in thecounterclockwise direction. If it isrunning faster, then it will rotate inthe clockwise direction. The greaterthe frequency difference, the fasteris the rotation. It is important that thegenerators are in phase before theyare paralleled. Severe damage willoccur if generators are paralleledout-of-phase.

Generator Short-CircuitCharacteristics

If a short circuit is applied directly to

the output terminals of a synchronousgenerator, it will produce an extremelyhigh current initially, gradually decaying to a steady-state value. This changeis represented by a varying reactiveimpedance. Three specific reactancesare used for short-circuit fault currents.They are:

■ Subtransient reactance Xd”, whichis used to determine the faultcurrent during the first 1 to 5 cycles

■ Transient reactance Xd’, which isused to determine the fault currentduring the next 5 to 200 cycles

■ Synchronous reactance Xd”, which

is used to determine the steady-state fault current

The subtransient reactance Xd” willrange from a minimum of approxi-mately 9% for a two-pole, wound-rotormachine to approximately 32% for alow-speed, salient-pole, hydro-generator. The initial symmetrical fault current can

be as much as 12 times full load current.Depending on the generator type,the zero sequence impedance may beless than the subtransient reactanceand the ground fault current substan-tially higher than the three-phaseshort-circuit current. For example, a2500 kVA, 480/277V, four-pole, 2/3 pitchstandby generator has a 0.1411 perunit subtransient reactance Xd” anda 0.033 per unit zero sequence Xo reactance. The ground current isapproximately a third larger than thethree-phase fault current. The groundfault current can be reduced to thethree-phase level by simply adding a

small reactance between the generatorneutral and ground while still beingconsidered solidly grounded.

The electric power system analysismust be performed based on the worst-case operating conditions. Typicallythis is when all sources are paralleled.If the system can operate with boththe utility supply and generators inparallel, then the equipment must berated for the combined fault currentplus motor contribution. If the generatorand utility will not be paralleled, thenboth cases will need to be looked atindependently and the worst case used

for selecting the equipment ratings.




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Generator ProtectionGenerator protection will vary anddepend on the size of the generator,type of system and importance of thegenerator. Generator sizes are definedas: small—1000 kVA maximum up

to 600V (500 kVA maximum whenabove 600V); medium over 1000 kVAto 12,500 kVA maximum regardlessof voltage; large—from 12,500–50,000 kVA. The simplest is a singlegenerator system used to feed emer-gency and/or standby loads. In thiscase, the generator is the only sourceavailable when it is operating andit must keep operating until thenormal source returns.

Figure 1.2-5 Part (A) shows minimumrecommended protection for a singlegenerator used as an emergency orstandby system. Phase and ground

time overcurrent protection (Device51 and 51G) will provide protection forexternal faults. For medium voltagegenerators, a voltage controlled timeovercurrent relay (Device 51V) isrecommended for the phase protec-tion as it can be set more sensitivethan standard overcurrent relays andis less likely to false operate on normaloverloads. This scheme may notprovide adequate protection forinternal generator faults when noother power source exists. Localgenerator controllers may offeradditional protection for voltageand frequency conditions outside

the generator’s capabilities.Figure 1.2-5 Part (B) shows therecommended protection for multiple,isolated, medium voltage, smallgenerators. Additional protectionmay be desired and could includegenerator differential, reverse power,and loss of field protection. Differentialprotection (Device 87) can be accom-plished with either a self-balancingset of CTs as in Figure 1.2-6 or witha percentage differential scheme asin Figure 1.2-7 on Page 1.2-6. Thepercentage differential schemeoffers the advantage of reducing thepossibility for false tripping due to

CT saturation. The self-balancingscheme offers the advantages ofincreased sensitivity, needing threecurrent transformers in lieu of six,and the elimination of currenttransformer external wiring fromthe generator location to the generatorswitchgear location.

Figure 1.2-5. Typical Protective Relaying Scheme for Small Generators

Figure 1.2-6. Self-Balancing Generator

Differential Relay Scheme

51G

1

PreferredLocation

51

51G

1

1

Gen

51

1

AlternateLocation

1 1

51V 32 40

1

3

87

Gen

Generator Protection ANSI/IEEEStd 242-1986

(A) (B)(A) Single Isolated Generator on Low Voltage System

(B) Multiple Isolated Generator on Medium Voltage System

87-1

87-3

87-2

50/5A

50/5A

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R

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Reverse power protection (Device 32)is used to prevent the generatorfrom being motored. Motoring coulddamage (with other hazards) the primemover. A steam turbine could overheatand fail. A diesel or gas engine could

either catch fire or explode. A steamturbine can typically withstandapproximately 3% reverse powerwhere a diesel engine can withstandup to 25% reverse power.

Loss of field protection (Device 40) isneeded when generators are operatingin parallel with one another or thepower grid. When a synchronousgenerator loses its field, it will continueto generate power as an inductiongenerator obtaining its excitation fromthe other machines on the system.During this condition, the rotor willquickly overheat due to the slipfrequency currents induced in it. Loss

of excitation in one machine couldjeopardize the operation of the othermachines beyond their capability andthe entire system.

Figure 1.2-7. Generator Percentage Differential Relay (Phase Scheme)and Ground Differential Scheme Using a Directional Relay

87

01 R1

02 R2

03 R3

R1

R2

R3

PC

OC

87G

GroundingResistor

51G

To Main Bus

52

Gen

OC = Operating coilPC = Permissive coil




1September 2011


Sheet 01


Typical protection for larger generatorsis shown in Figure 1.2-8. It addsphase unbalance and field groundfault protection. Phase unbalance(Device 46) or negative sequenceovercurrent protection prevents the

generator’s rotor from overheatingdamage. Unbalanced loads, faultconditions or open phasing willproduce a negative sequence currentto flow. The unbalanced currentsinduce double system frequencycurrents in the rotor, which quicklycauses rotor overheating. Seriousdamage will occur to the generator ifthe unbalance is allowed to persist.

Other protection functions such asunder/overvoltage (Device 27/59)could be applied to any size generator.The voltage regulator typically main-tains the output voltage within itsdesired output range. This protection

can provide backup protection in casethe voltage regulator fails. Under/overfrequency protection (Device 81U/81O)could be used for backup protectionfor the speed control. Sync checkrelays (Device 25) are typically appliedas a breaker permissive close functionwhere generators are paralleled.

Many modern protective relays aremicroprocessor-based and provide afull complement of generator protection functions in a single package. The costper protection function has beendrastically reduced such that it isfeasible to provide more complete

protection even to smaller generators.IEEE ANSI 1547 provides recom-mended practices for utility inter-tieprotection. If the system has closed-transition or paralleling capability,additional protection may be requiredby the utility. Typically, no additionalprotection is required if the generatoris paralleled to the utility for a maximumof 100 msec or less. Systems thatoffer soft transfer, peak shaving orco-generation will require additionalutility inter-tie protection. The protectioncould include directional overcurrentand power relays and even transfertrip schemes. Please consult your local

utility for specific requirements.

Figure 1.2-8. Typical Protective Relaying Scheme for Large Generator

3

87B

3

87

1

87G

1

49

Gen

1

64

E

60

46324051V

3

Voltage Regulator andMetering Circuits

51G

81U/O

27/59

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Generator Set Sizingand Ratings

Many factors must be consideredwhen determining the proper size orelectrical rating of an electrical power

generator set. The engine or primemover is sized to provide the actualor real power in kW, as well as speed(frequency) control through the useof an engine governor. The generatoris sized to supply the kVA needed atstartup and during normal runningoperation and it also provides voltagecontrol using a brushless exciter andvoltage regulator. Together the engineand generator provide the energynecessary to supply electrical loadsin many different applicationsencountered in today’s society.

The generator set must be able to

supply the starting and runningelectrical load. It must be able topick up and start all motor loads andlow power factor loads, and recoverwithout excessive voltage dip orextended recovery time. Nonlinearloads like variable frequency drives,uninterruptible power supply (UPS)systems and switching power suppliesalso require attention because the SCRswitching causes voltage and currentwaveform distortion and harmonics.The harmonics generate additionalheat in the generator windings, andthe generator may need to be upsizedto accommodate this. The type of

fuel (diesel, natural gas, propane, etc.)used is important as it is a factor indetermining generator set transientresponse. It is also necessary todetermine the load factor or averagepower consumption of the generatorset. This is typically defined as the load(kW) x time (hrs. while under thatparticular load) / total running time.When this load factor or averagepower is taken into considerationwith peak demand requirementsand the other operating parametersmentioned above, the overall electricalrating of the genset can be deter-mined. Other items to consider includethe unique installation, ambient, andsite requirements of the project. Thesewill help to determine the physicalconfiguration of the overall system.

Typical rating definitions for dieselgensets are: standby, prime plus 10,continuous and load management(paralleled with or isolated fromutility). Any diesel genset can haveseveral electrical ratings dependingon the number of hours of operationper year and the ratio of electricalload/genset rating when in operation.The same diesel genset can have astandby rating of 2000 kW at 0.8 powerfactor (pf) and a continuous rating of1825 kW at 0.8 pf. The lower continu-ous rating is due to the additionalhours of operation and higher loadthat the continuous genset mustcarry. These additional requirementsput more stress on the engine andgenerator and therefore the ratingis decreased to maintain longevityof the equipment.

Different generator set manufacturers

use basically the same diesel gensetelectrical rating definitions and theseare based on international dieselfuel stop power standards fromorganizations like ISO, DIN and others.A standby diesel genset rating istypically defined as supplying varyingelectrical loads for the duration of apower outage with the load normallyconnected to utility, genset operating<100 hours per year and no overloadcapability. A prime plus 10 rating istypically defined as supplying varyingelectrical loads for the duration of apower outage with the load normallyconnected to utility, genset operating

≤500 hours per year and overloadcapability of 10% above its rating for1 hour out of 12. A continuous ratingis typically defined as supplyingunvarying electrical loads (i.e., baseloaded) for an unlimited time. The loadmanagement ratings apply to gensetsin parallel operation with the utilityor isolated/islanded from utility andthese ratings vary in usability from<200 hours per year to unlimitedusage. Refer to generator set manufac-turers for further definitions on loadmanagement ratings, load factor oraverage power consumption, peakdemand and how these ratings are

typically applied. Even though there issome standardization of these ratingsacross the manufacturers, there alsoexists some uniqueness with regard tohow each manufacturer applies theirgenerator sets.

Electrical rating definitions for naturalgas powered gensets are typicallydefined as standby or continuous withdefinitions similar to those mentionedabove for diesels. Natural gas gensetsrecover more slowly than dieselgensets when subjected to blockloads. Diesel engines have a muchmore direct path from the engine gov-ernor and fuel delivery system to thecombustion chamber and this resultsin a very responsive engine-generator.A natural gas engine is challengedwith air-fuel flow dynamics and amuch more indirect path from theengine governor (throttle actuator)and fuel delivery system (naturalgas pressure regulator, fuel valve andactuator, carburetor mixer, aftercooler,intake manifold) to the combustionchamber and this results in aless responsive engine-generator.Diesel gensets recover about twiceas fast as natural gas gensets.

For the actual calculations involvedfor sizing a genset, there are readilyaccessible computer software programs that are available on the genset manu-facturer’s Internet sites or from themanufacturer’s dealers or distributors.These programs are used to quicklyand accurately size generator sets fortheir application. The programs takeinto consideration the many differentparameters discussed above, includingthe size and type of the electrical loads(resistive, inductive, SCR, etc.), reducedvoltage soft starting devices (RVSS),

motor types, voltage, fuel type, siteconditions, ambient conditions andother variables. The software willoptimize the starting sequences of themotors for the least amount of voltagedip and determine the starting kVAneeded from the genset. It also providestransient response data, includingvoltage dip magnitude and recoveryduration. If the transient response isunacceptable, then design changes canbe considered, including oversizingthe generator to handle the additionalkVAR load, adding RVSS devices toreduce the inrush current, improvingsystem power factor and other methods.

The computer software programs arequite flexible in that they allow changesto the many different variables andparameters to achieve an optimumdesign. The software allows, forexample, minimizing voltage dipsor using paralleled gensets vs. asingle genset.




1September 2011


Sheet 01


Genset Sizing GuidelinesSome conservative rules of thumbfor genset sizing include:

1. Oversize genset 20–25%for reserve capacity and for

motor starting.2. Oversize gensets for unbalanced

loading or low power factorrunning loads.

3. Use 1/2 hp per kW for motor loads.

4. For variable frequency drives,oversize the genset by atleast 40%.

5. For UPS systems, oversize thegenset by 40% for 6 pulse and15% for 6 pulse with input filtersor 12 pulse.

6. Always start the largest motor

first when stepping loads.For basic sizing of a generator system,the following example could be used:

Step 1: Calculate Running Amperes

■ Motor loads:

❑ 200 hp motor. . . . . . . . . . . . . 156A

❑ 100 hp motor. . . . . . . . . . . . . . 78A

❑ 60 hp motor. . . . . . . . . . . . . . . 48A

■ Lighting load . . . . . . . . . . . . . . . . 68A

■ Miscellaneous loads . . . . . . . . . . 95A

■ Running amperes . . . . . . . . . . . 445A

Step 2: Calculating Starting Amperes

Using 1.25 Multiplier■ Motor loads:

❑ . . . . . . . . . . . . . . . . . . . . . . . . 195A

❑ . . . . . . . . . . . . . . . . . . . . . . . . . 98A

❑ . . . . . . . . . . . . . . . . . . . . . . . . . 60A

■ Lighting load . . . . . . . . . . . . . . . . 68A

■ Miscellaneous loads . . . . . . . . . . 95A

■ Starting amperes . . . . . . . . . . . 516A

Step 3: Selecting kVA of Generator

■ Running kVA =(445A x 480V x 1.732)/ 1000 = 370 kVA

■ Starting kVA =(516A x 480V x 1.732)/ 1000 = 428 kVA

Solution

Generator must have a minimumstarting capability of 428 kVA and minimum running capability of 370 kVA.

Also, please see section “FactorsGoverning Voltage Drop” onPage 1.3-21 for further discussionon generator loading and reducedvoltage starting techniques for motors.

Generator Set Installationand Site Considerations

There are many different installationparameters and site conditionsthat must be considered to have a

successful generator set installation.The following is a partial list of areasto consider when conducting thisdesign. Some of these installationparameters include:

■ Foundation type (crushed rock,concrete, dirt, wood, separateconcrete inertia pad, etc.)

■ Foundation to genset vibrationdampening (spring type, corkand rubber, etc.)

■ Noise attenuation (radiator fanmechanical noise, exhaust noise,air intake noise)

■ Combustion and cooling air

requirements■ Exhaust backpressure requirements

■ Emissions permitting

■ Delivery and rigging requirements

■ Genset derating due to highaltitudes or excessive ambienttemperatures

■ Hazardous waste considerationsfor fuel, antifreeze, engine oil

■ Meeting local building andelectrical codes

■ Genset exposure (coastalconditions, dust, chemicals, etc.)

■ Properly sized starting systems(compressed air, batteriesand charger)

■ Allowing adequate space forinstallation of the genset and formaintenance (i.e., air filter removal,oil changing, general gensetinspection, etc…)

■ Flex connections on all systems thatare attached to the genset and arigid structure (fuel piping, founda-tion vibration isolators, exhaust, airintake, control wiring, power cables,radiator flanges/duct work, etc.)

■ Diesel fuel day tank systems

(pumps, return piping)■ Fuel storage tank (double walled,

fire codes) and other parameters

Please see the generator set manufac-turer’s application and installationguidelines for proper applicationand operation of their equipment.

Figure 1.2-9. Typical Genset Installation

Note: Courtesy of Caterpillar, Inc.



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System Analysis033

Systems Analysis

A major consideration in thedesign of a distribution system is toensure that it provides the requiredquality of service to the various

loads. This includes serving eachload under normal conditions and,under abnormal conditions, providingthe desired protection to serviceand system apparatus so thatinterruptions of service are minimizedconsistent with good economic andmechanical design.

Under normal conditions, the impor-tant technical factors include voltageprofile, losses, load flow, effects ofmotor starting, service continuity andreliability. The prime considerationsunder faulted conditions are apparatusprotection, fault isolation and servicecontinuity. During the system prelimi-

nary planning stage, before selectionof the distribution apparatus, severaldistribution systems should be analyzedand evaluated, including both economicand technical factors. During this stage,if system size or complexity warrant,it may be appropriate to provide athorough review of each system underboth normal and abnormal conditions.

The principal types of computerprograms used to provide systemstudies include:

■ Short circuit—identify three-phaseand line-to-ground fault currentsand system impedances

■ Arc flash—calculates arc flashenergy levels, which leads to theselection of personal protectiveequipment (PPE)

■ Circuit breaker duty—identifyasymmetrical fault current basedon X/R ratio

■ Protective device coordination—determine characteristics and set-tings of medium voltage protectiverelays and fuses, and entire lowvoltage circuit breaker and fusecoordination

■ Load flow—simulate normalload conditions of system

voltages, power factor, lineand transformer loadings

■ Motor starting—identify systemvoltages, motor terminal voltage,motor accelerating torque, andmotor accelerating time whenstarting large motors

Short-circuit calculations definemomentary and steady-state faultcurrents for LV and MV breaker andfuse duty and bus bracings at anyselected location in the system, and alsodetermine the effect on the system

after removal of utility power due tobreaker operation or scheduled poweroutages. Computer software programscan identify the fault current at anybus, in every line or source connectedto the faulted bus, or to it and everyadjacent bus, or to it and every busthat is one and two buses away, orcurrents in every line or source in thesystem. The results of these calculationspermit optimizing service to the loadswhile properly applying distributionapparatus within their intended limits.

The following additional studiesshould be considered dependingupon the type and complexity of the

distribution system, the type of facilityand the type of loads to be connectedto the system:

■ Harmonic analysis

■ Transient stability

■ Insulation coordination

■ Grounding study

■ Switching transient

Eaton’s Electrical Services & Systemsdivision can provide the studiesenumerated above.



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System Analysis034

Short-Circuit Currents—General

The amount of current available in ashort-circuit fault is determined by thecapacity of the system voltage sources

and the impedances of the system,including the fault. Voltage sourcesinclude the power supply (utility oron-site generation) plus all rotatingmachines connected to the system atthe time of the fault. A fault may beeither an arcing or bolted fault. In anarcing fault, part of the circuit voltage isconsumed across the fault and the totalfault current is somewhat smaller thanfor a bolted fault, so the latter is theworst condition, and therefore is thevalue sought in the fault calculations.

Basically, the short-circuit current isdetermined by applying Ohm’s Law

to an equivalent circuit consisting ofa constant voltage source and a time-varying impedance. A time-varyingimpedance is used in order to accountfor the changes in the effective voltagesof the rotating machines during thefault. In an AC system, the resultingshort-circuit current starts out higherin magnitude than the final steady-state value and asymmetrical (dueto the DC offset) about the X-axis.The current then decays toward alower symmetrical steady-state value.The time-varying characteristic of theimpedance accounts for the symmetri-cal decay in current. The ratio of the

reactive and resistive components (X/Rratio) accounts for the DC decay, see Figure 1.3-1. The fault current consistsof an exponentially decreasing direct-current component superimposedupon a decaying alternating-current.The rate of decay of both the DC andAC components depends upon theratio of reactance to resistance (X/R)of the circuit. The greater this ratio,the longer the current remains higherthan the steady-state value that itwould eventually reach.

The total fault current is not symmetricalwith respect to the time-axis becauseof the direct-current component,

hence it is called asymmetrical current.The DC component depends on thepoint on the voltage wave at whichthe fault is initiated.

See Table 1.3-2 for multiplying factorsthat relate the rms asymmetrical valueof total current to the rms symmetricalvalue, and the peak asymmetricalvalue of total current to the rmssymmetrical value.

The AC component is not constantif rotating machines are connectedto the system because the impedanceof this apparatus is not constant. Therapid variation of motor and generatorimpedance is due to these factors:

Subtransient reactance (x "d), deter-mines fault current during the firstcycle, and after about 6 cycles thisvalue increases to the transient reac-tance. It is used for the calculationof the momentary interrupting and/ormomentary withstand duties ofequipment and/or system.

Transient reactance (x 'd), which deter-mines fault current after about 6 cyclesand this value in 1/2 to 2 secondsincreases to the value of the synchro-nous reactance. It is used in the settingof the phase OC relays of generatorsand medium voltage circuit breakers.

Synchronous reactance (xd), whichdetermines fault current after steady-state condition is reached. It has noeffect as far as short-circuit calculationsare concerned, but is useful in thedetermination of relay settings.

Transformer impedance, in percent, isdefined as that percent of rated primaryvoltage that must be applied to thetransformer to produce rated currentflowing in the secondary, with second-ary shorted through zero resistance.Therefore, assuming the primaryvoltage can be sustained (generallyreferred to as an infinite or unlimited

supply), the maximum current a trans-former can deliver to a fault condition isthe quantity of (100 divided by percentimpedance) times the transformer

rated secondary current. Limiting thepower source fault capacity will therebyreduce the maximum fault current fromthe transformer.

The electric network that determinesthe short-circuit current consists of an

AC driving voltage equal to the pre-faultsystem voltage and an impedancecorresponding to that observed whenlooking back into the system from thefault location. In medium and highvoltage work, it is generally satisfactoryto regard reactance as the entireimpedance; resistance may beneglected. However, this is normallypermissible only if the X/R ratio of themedium voltage system is equal to ormore than 25. In low voltage (1000Vand below) calculations, it is usuallyworthwhile to attempt greater accuracyby including resistance with reactancein dealing with impedance. It is for this

reason, plus ease of manipulating thevarious impedances of cables andbuses and transformers of the lowvoltage circuits, that computer studiesare recommended before final selectionof apparatus and system arrangements.

When evaluating the adequacyof short-circuit ratings of mediumvoltage circuit breakers and fuses,both the rms symmetrical value andasymmetrical value of the short-circuitcurrent should be determined.

For low voltage circuit breakers andfuses, the rms symmetrical valueshould be determined along with

either: the X/R ratio of the faultat the device or the asymmetricalshort- circuit current.

Figure 1.3-1. Structure of an Asymmetrical Current Wave

3.0

2.5

2.0

1.5

1.0

0.5

0

0.5

–1.0

–1.5

–2.0

Total Current—A Wholly OffsetAsymmetrical Alternating Wave

rms Value of Total Current

Alternating Component -Symmetrical Wave

rms Value ofAlternating Component

Direct Component—The Axisof Symmetrical Wave Time in Cycles of

a 60 Hz Wave

1 2 3 4

S c a l e o f C u r e n

t V a l u e s




1September 2011


Sheet 01

System Analysis035

Fault Current Waveform Relationships

The following Figure 1.3-2 describesthe relationship between faultcurrent peak values, rms symmetricalvalues and rms asymmetrical values

depending on the calculated X/R ratio.The table is based on the followinggeneral formulas:

1.

2.

Where:

I = Symmetrical rms current

Ip = Peak current

e = 2.718

ω = 2 π f

f = Frequency in Hz

t = Time in seconds

Based on a 60 Hz system and t = 1/2 cycle(ANSI/IEEE C37.13.1990/10.1.4)

Peak multiplication factor =

rms multiplication factor =

Example for X/R =15

Figure 1.3-2. Relation of X/R Ratio to Multiplication Factor

Ip I 2 1 e

ωt–

X R ⁄ ------------

+

=

Irms asym I 1 2e

2ωt–

X R ⁄ ---------------

+=

IpI----- 2 1 e

2π60–

120----------------

X R ⁄ ----------------

+

2 1 e

π–

X R ⁄ ----------

+ = =

Irms asym

I------------------------------ 1 2e

2–( ) 2π60( )120

-------------------------------

X R ⁄ -------------------------------

+ 1 2e

2π–

X R ⁄ ------------

+= =

Peak mf 2 1 e

π–

15-------

+

2.5612= =

rms mf 1 2e

2π–

15----------

+ 1.5217= =

2.8

2.7

2.6

2.5

2.4

2.3

2.2

2.1

2.0

1.9

1.8

1.7

1.6

1.5

1.41.51 2 2.5 3 4 5 6 7 8 9 10 15 20 25 30 40 50 60 70 80 90 100

1.8

1.7

1.6

1.5

1.4

1.3

1.2

1.1

P E A K

M U L T I P L I C A T I O N

F A C T O

R

R M S M

U L T I P L

I C A T I O

N F A

C T O R

CIRCUIT X/R RATIO (TAN PHASE)

Based Upon: rms Asym = DC2 + rms Sym2

with DC ValueTaken at Current Peak

R M S M U L T I P

L I C A T I O N F A C T O R =

R M S M A X I M U M A

S Y

M M E T R I C A L

R M S S Y M M E T

R I C A L

P E A K M U L T I P L I C A T I O N F A C T O R =

P E A K M A X I M U M A

S Y M M E T R I C A L

R M S S Y M M E

T R I C A L



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System Analysis036

Fault Current Calculations

The calculation of asymmetricalcurrents is a laborious procedure sincethe degree of asymmetry is not thesame on all three phases. It is common

practice for medium voltage systems,to calculate the rms symmetrical faultcurrent, with the assumption beingmade that the DC component hasdecayed to zero, and then applya multiplying factor to obtain the firsthalf-cycle rms asymmetrical current,which is called the “momentarycurrent.” For medium voltage systems(defined by IEEE as greater than 1000Vup to 69,000V) the multiplying factoris established by NEMA® and ANSI

standards depending upon theoperating speed of the breaker. Forlow voltage systems, short-circuitstudy software usually calculates the

symmetrical fault current and thefaulted system X/R ratio using ANSIguidelines. If the X/R ratio is within thestandard, and the breaker interruptingcurrent is under the symmetrical faultvalue, the breaker is properly rated.If the X/R ratio is higher than ANSI

standards, the study applies a multi-plying factor to the symmetricalcalculated value (based on theX/R value of the system fault) andcompares that value to the breakersymmetrical value to assess if it isproperly rated. In the past, especiallyusing manual calculations, a multiply-ing factor of 1.17 (based on the useof an X/R ratio of 6.6 representinga source short-circuit power factorof 15%) was used to calculate theasymmetrical current. These valuestake into account that medium voltagebreakers are rated on maximumasymmetry and low voltage breakersare rated average asymmetry.

To determine the motor contributionduring the first half-cycle fault current,when individual motor horsepowerload is known, the subtransientreactances found in the IEEE Red Bookshould be used in the calculations.When the system motor load isunknown, the following assumptions

generally are made:

Induction motors—use 4.0 timesmotor full load current (impedancevalue of 25%).

Note: For motors fed through adjustablefrequency drives or solid-state soft starters,there is no contribution to fault current, unless1) they have an internal run contactor or2) they have a bypass contactor.

Synchronous motors—use 5.0 timesmotor full load current (impedancevalue of 20%).

When the motor load is not known,the following assumptions generallyare made:

208Y/120V Systems

■ Assume 50% lighting and 50%motor load

or

■ Assume motor feedback contribu-tion of twice full load current oftransformer

or

240/480/600V Three-Phase, Three-Wire orFour-Wire Systems

■ Assume 100% motor load

or

■ Assume motors 25% synchronousand 75% induction

or

■ Assume motor feedback contribu-tion of four times full load currentof transformer

480Y/277V Systems in Commercial Buildings

■ Assume 50% induction motor load

or

■ Assume motor feedback contribu-tion of two times full load currentof transformer or source

Medium Voltage MotorsIf known, use actual values otherwiseuse the values indicated for the sametype of motor.

Calculation Methods

The following pages describe variousmethods of calculating short-circuitcurrents for both medium and lowvoltage systems. A summary ofthe types of methods and types ofcalculations is as follows:

■ Medium voltageswitchgear—exactmethod . . . . . . . . . . . . . .Page 1.3-5

■ Medium voltageswitchgear—quickcheck table . . . . . . . . . . . Page 1.3-7

■ Medium voltageswitchgearExample 1—verifyratings of breakers. . . . .Page 1.3-8

■ Medium voltageswitchgearExample 2—verifyratings of breakerswith rotatingloads . . . . . . . . . . . . . . . .Page 1.3-9

■ Medium voltageswitchgear Example 3—verify ratings ofbreakers withgenerators . . . . . . . . . . . Page 1.3-10

■ Medium voltagefuses—exact method. . . Page 1.3-11

■ Power breakers—

asymmetryderating factors . . . . . . . Page 1.3-11

■ Molded-casebreakers—asymmetryderating factors . . . . . . . Page 1.3-12

■ Short-circuitcalculations—short cut methodfor a system . . . . . . . . . . Page 1.3-13

■ Short-circuitcalculations—shortcut method forend of cable . . . . . . . . . . Page 1.3-15

■ Short-circuitcalculations—

short cut methodfor end of cablechart method . . . . . . . . . Page 1.3-16

■ Short-circuit currents—chart of transformers300–3750 kVA . . . . . . . . . Page 1.5-9




1September 2011


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System Analysis037

Fault Current Calculationsfor Specific Equipment—Exact Method

The purpose of the fault current calcu-

lations is to determine the fault currentat the location of a circuit breaker, fuseor other fault interrupting device inorder to select a device adequate for thecalculated fault current or to check thethermal and momentary ratings of non-interrupting devices. When the devicesto be used are ANSI-rated devices, thefault current must be calculated and thedevice selected as per ANSI standards.

The calculation of available fault currentand system X/R rating is also used toverify adequate bus bar bracing andmomentary withstand ratings ofdevices such as contactors.

Medium Voltage VCP-WMetal-Clad Switchgear

The applicable ANSI Standards, C37is the latest applicable edition. Thefollowing is a review of the meaningof the ratings. (See Tab 5, Section 5.4.)

The Rated Maximum Voltage

This designates the upper limit ofdesign and operation of a circuitbreaker. For example, a circuit breakerwith a 4.76 kV rated maximum voltagecannot be used in a 4.8 kV system.

K-Rated Voltage Factor

The rated voltage divided by this factor

determines the system kV a breaker canbe applied up to the short-circuit kVArating calculated by the formula

Note: Interrupting capabilities of some oftoday’s vacuum breakers may have K = 1,whereby the interrupting current is constantacross its entire operating range.

Rated Short-Circuit Current

This is the symmetrical rms value ofcurrent that the breaker can interruptat rated maximum voltage. It shouldbe noted that the product x 4.76 x29,000 = 239,092 kVA is less than the

nominal 250,000 kVA listed. This rating(29,000A) is also the base quantitythat all the “related” capabilities arereferred to.

Maximum Symmetrical InterruptingCapability

This is expressed in rms symmetricalamperes or kiloamperes and is K x Irated; 29,000 x 1.24 = 35,960 roundedto 36 kA.

This is the rms symmetrical currentthat the breaker can interrupt down to

3 Rated SC Current× Rated Max. Voltage×

3

a voltage = maximum rated voltagedivided by K (for example, 4.76/1.24 =3.85). If this breaker is applied in asystem rated at 2.4 kV, the calculatedfault current must be less than 36 kA.

For example, consider the following case:

Assume a 12.47 kV system with 20,000Asymmetrical available. In order todetermine if an Eaton Type 150 VCP-W500 vacuum breaker is suitable for thisapplication, check the following:

From Table 5.4-1B in Tab 5, Section 5.4 under column “Rated MaximumVoltage” V = 15 kV, under column“Rated short-circuit Current” I = 18 kA,“Rated Voltage Range Factor” K = 1.3.

Test 1 for V/Vo x I or 15 kV/12.47 kV x18 kA = 21.65; also check K x I (whichis shown in the column headed“Maximum Symmetrical InterruptingCapability”) or 1.3 x 18 kA = 23.4 kA.Because both of these numbers aregreater than the available system fault

current of 20,000A, the breaker isacceptable (assumes the breaker’smomentary and fault close rating isalso acceptable).

Note: If the system available fault currentwere 22,000A symmetrical, this breaker

could not be used even though the“Maximum Symmetrical InterruptingCapability” is greater than 22,000 becauseTest 1 calculation is not satisfied.

For approximate calculations, Table 1.3-1 provides typical values of % reactance(X) and X/R values for various rotatingequipment and transformers. For sim-plification purposes, the transformerimpedance (Z) has been assumed to beprimarily reactance (X). In addition, theresistance (R) for these simplified cal-culations has been ignored. For detailedcalculations, the values from the IEEERed Book Standard 141, for rotatingmachines, and ANSI C57 and/or C37

for transformers should be used.

Table 1.3-1. Reactance X

Table 1.3-2. Typical System X/R Ratio Range (for Estimating Purposes)

SystemComponent

Reactance X Used for Typical Values and Rangeon Component BaseShort-Circuit

DutyClose and Latch(Momentary) % Reactance X/R Ratio

Two-pole turbo generatorFour-pole turbo generator

XX

XX

9 (7–14)15 (12–17)

80 (40–120)80 (40–120)

Hydro generator with damper wedgesand synchronous condensers

X X 20 (13–32) 30 (10–60)

Hydro generator without damper windings 0.75X 0.75X 16 (16–50) 30 (10–60)

All synchronous motors 1.5X 1.0X 20 (13–35) 30 (10–60)

Induction motors above 1000 hp, 1800 rpmand above 250 hp, 3600 rpm

1.5X 1.0X 17 (15–25) 30 (15–40)

All other induction motors 50 hp and above 3.0X 1.2X 17 (15–25) 15 (2–40)Induction motors below 50 hp andall single-phase motors

Neglect Neglect — —

Distribution system from remotetransformers

X X As specifiedor calculated

15 (5–15)

Current limiting reactors X X As specifiedor calculated

80 (40–120)

Transformers

OA to 10 MVA, 69 kV X X 8.0 18 (7–24)

OA to 10 MVA, above 69 kV X X 8.0 to 10.5Depends onprimarywindings BILrating

18 (7–24)

FOA 12–30 MVA X X 20 (7–30)

FOA 40–100 MVA X X 38 (32–44)

Type of Circuit X/R Range

Remote generation through other types of circuits such as transformers rated 10 MVAor smaller for each three-phase bank, transmission lines, distribution feeders, etc.

15 or less

Remote generation connected through transformer rated 10 MVA to 100 MVAfor each three-phase bank, where the transformers provide 90% or moreof the total equivalent impedance to the fault point

15–40

Remote generation connected through transformers rated 100 MVA or largerfor each three-phase bank where the transformers provide 90% or moreof the total equivalent impedance to the fault point

30–50

Synchronous machines connected through transformers rated 25–100 MVAfor each three-phase bank

30–50

Synchronous machines connected through transformers rated 100 MVA and larger 40–60

Synchronous machines connected directly to the bus or through reactors 40–120



.3-6


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System Analysis038

The Close and Latch Capability

This is also a related quantityexpressed in rms asymmetricalamperes by 1.6 x maximumsymmetrical interrupting capability.For example, 1.6 x 36 = 57.6 or 58 kA,

or 1.6 K x rated short-circuit current.Another way of expressing the closeand latch rating is in terms of the peakcurrent, which is the instantaneousvalue of the current at the crest. ANSIStandard C37.09 indicates that theratio of the peak to rms asymmetricalvalue for any asymmetry of 100% to20% (percent asymmetry is defined asthe ratio of DC component of the faultin per unit to ) varies not more than±2% from a ratio of 1.69. Therefore,the close and latch current expressedin terms of the peak amperes is = 1.6 x1.69 x K x rated short-circuit current.

In the calculation of faults for the pur-poses of breaker selection, the rotatingmachine impedances specified in ANSIStandard C37.010 Article 5.4.1 shouldbe used. The value of the impedancesand their X/R ratios should be obtainedfrom the equipment manufacturer. Atinitial short-circuit studies, data frommanufacturers is not available. Typicalvalues of impedances and their X/Rratios are given in Table 1.3-1.

Figure 1.3-3. Three-phase Fault MultiplyingFactors that Include Effects of AC andDC Decrement

The ANSI Standard C37.010 allows theuse of the X values only in determin-ing the E/X value of a fault current. TheR values are used to determine the X/Rratio, in order to apply the propermultiplying factor, to account for the

total fault clearing time, asymmetry,and decrement of the fault current.

The steps in the calculation of faultcurrents and breaker selection aredescribed hereinafter:

Step 1: Collect the X and R data of thecircuit elements. Convert to a commonkVA and voltage base. If the reactancesand resistances are given either inohms or per unit on a different voltageor kVA base, all should be changedto the same kVA and voltage base.This caution does not apply wherethe base voltages are the same asthe transformation ratio.

Step 2: Construct the sequencenetworks and connect properly forthe type of fault under consideration.Use the X values required by ANSIStandard C37.010 for the “interrupting”duty value of the short-circuit current.

Figure 1.3-4. Line-to-Ground Fault MultiplyingFactors that Include Effects of AC andDC Decrement

Step 3: Reduce the reactance networkto an equivalent reactance. Call thisreactance XI.

Step 4: Set up the same network forresistance values.

Step 5: Reduce the resistance networkto an equivalent resistance. Call thisresistance RI. The above calculationsof XI and RI may be calculated byseveral computer programs.

Step 6: Calculate the E/XI value, whereE is the prefault value of the voltage atthe point of fault nominally assumed1.0 pu.

Step 7: Determine X/R = aspreviously calculated.

Step 8: Go to the proper curve forthe type of fault under consideration(three-phase, phase-to-phase, phase-

to-ground), type of breaker at the loca-tion (2, 3, 5 or 8 cycles), and contactparting time to determine the multi-plier to the calculated E/XI.

See Figures 1.3-3, 1.3-4 and 1.3-5 for5-cycle breaker multiplying factors.Use Figure 1.3-5 if the short circuit isfed predominantly from generatorsremoved from the fault by two or more

Figure 1.3-5. Three-phase and Line-to-GroundFault Multiplying Factors that Include Effectsof DC Decrement Only

2

6

5

4

C

O N T A C T

P A R T I N G

T I M E

3

5-CYCLEBREAKER

1.0 1.1 1.2 1.3 1.4

Multiplying Factors for E / X Amperes

R a t i o X / R

130

120

110

100

90

80

70

60

50

40

30

20

10

7 8

5-CYCLEBREAKER

1.0 1.1 1.2 1.3 1.4


3 4 5

R a t i o X / R

130

120

110

100

90

80

70

60

50

40

30

20

10

XI

RI

------

4

5-CYCLEBREAKER

1.0 1.1 1.2 1.3 1.4


6

8 1 0 1

2

C O N T A C T

P A R T I N

G T I M E

3

R a t i o X / R

130

120

110

100

90

80

70

60

50

40

30

20

10




1September 2011


Sheet 01

System Analysis039

transformations or the per unit reac-tance external to the generation is 1.5times or more than the subtransientreactance of the generation on a com-mon base. Also use Figure 1.3-5 wherethe fault is supplied by a utility only.

Step 9: Interrupting duty short-circuitcurrent = E/XI x MFx = E/X2.

Step 10: Construct the sequence(positive, negative and zero) networksproperly connected for the type offault under consideration. Use theX values required by ANSI StandardC37.010 for the “Close and Latch”duty value of the short-circuit current.

Step 11: Reduce the network to anequivalent reactance. Call the reac-tance X. Calculate E/X x 1.6 if thebreaker close and latch capability isgiven in rms amperes or E/X x 2.7 ifthe breaker close and latch capabilityis given in peak or crest amperes.

Step 12: Select a breaker whose:

a. Maximum voltage rating exceedsthe operating voltage of the system:

b.

See Table 6.0-1, Tab 6.

Where:I = Rated short-circuit current

Vmax = Rated maximum voltageof the breaker

VD = Actual system voltage

KI = Maximum symmetricalinterrupting capacity

c. E/X x 1.6 ≤ rms closing andlatching capability of the breaker

and/or

E/X x 2.7 ≤ Crest closing andlatching capability of the breaker.

EX2

------- IVmax

Vo

-------------- KI≤×≤

The ANSI standards do not require theinclusion of resistances in the calcula-tion of the required interrupting andclose and latch capabilities. Thus thecalculated values are conservative.However, when the capabilities of

existing switchgears are investigated,the resistances should be included.

For single line-to-ground faults, thesymmetrical interrupting capabilityis 1.15 x the symmetrical interruptingcapability at any operating voltage,but not to exceed the maximumsymmetrical capability of the breaker.

Section 5 of ANSI C37 providesfurther guidance for medium voltagebreaker application.

Reclosing Duty

ANSI Standard C37.010 indicates thereduction factors to use when circuit

breakers are used as reclosers. EatonVCP-W breakers are listed at 100%rating factor for reclosing.

Application Quick Check Table

For application of circuit breakers in aradial system supplied from a singlesource transformer. Short-circuit dutywas determined using E/X amperes

and 1.0 multiplying factor for X/R ratioof 15 or less and 1.25 multiplyingfactor for X/R ratios in the range of15 to 40.

Application Above 3,300 ft (1,000m)

The rated one-minute power frequencywithstand voltage, the impulse with-stand voltage, the continuous currentrating, and the maximum voltage ratingmust be multiplied by the appropriatecorrection factors below to obtainmodified ratings that must equal orexceed the application requirements.

Note: Intermediate values may be obtainedby interpolation.

Table 1.3-3. Altitude Derating

Table 1.3-4. Application Quick Check Table

Transformer impedance 6.5% or more, all other transformer impedances are 5.5% or more.

Altitude inFeet (Meters)

Correction Factor

Current Voltage

3300 (1006) (and below)5000 (1524)

10,000 (3048)

1.000.990.96

1.000.950.80

SourceTransformerMVA Rating

Operating VoltagekV

Motor Load 2.4 4.16 6.6 12 13.8

100% 0%

1

1.52

1.5

22.5

50 VCP-W 25012 kA 50 VCP-W 250

10.1 kA150 VCP-W 50023 kA

150 VCP-W 50022.5 kA

150 VCP-W 50019.6 kA2.5

333.75

3.755

57.5

50 VCP-W 25036 kA 50 VCP-W 250

33.2 kA7.510

1010

50 VCP-W 35049 kA

10 12

12 15 50 VCP-W 35046.9 kA

75 VCP-W 50041.3 kA

15 20

20 20 Breaker Type andsymmetrical interrupting capacityat the operating voltage

150 VCP-W 75035 kA

150 VCP-W 75030.4 kA25

30

50 150 VCP-W 100046.3 kA

150 VCP-W 100040.2 kA



.3-8


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System Analysis040

Application on Symmetrical Current Rating Basis

Example 1—Fault Calculations

Given a circuit breaker interrupting and momentary rating in the table below,verify the adequacy of the ratings for a system without motor loads, as shown.

Table 1.3-5. Short-Circuit Duty

Note: Interrupting capabilities I1 and I2 at operating voltage must not exceed maximumsymmetrical interrupting capability Kl.

Check capabilities I1, I2 and I3 on the following utility system where there is nomotor contribution to short circuit.

Figure 1.3-6. Example 1—One-Line Diagram

From transformer losses per unit or percentR is calculated

31,000 Watts Full Load– 6,800 Watts No Load

24,200 Watts Load Losses

On 13.8 kV System, 3.75 MVA Base

Transformer Standard 5.5% Impedance

has a ±7.5% Manufacturing Tolerance

5.50 Standard Impedance–0.41 (–7.5% Tolerance)

Transformer Z =5.09%

X = 5.05%

X R X/R

13.8 kV System 0.99% 0.066% 15Transformer 5.05% 0.65% 8System Total 6.04% 0.716% 9or 0.0604 pu 0.00716 pu

TypeBreaker

V Max. Three-Phase Symmetrical Interrupting Capability Close and Latch orMomentaryat V Max. Max. KI at 4.16 kV Oper. Voltage

50VCP–W250 4.76 kV 29 kA 36 kA(29) = 33.2 kA I1

58 kA I3

LG symmetrical interrupting capability

— 36 kA 1.15 (33.2) = 38.2 kA I2

4.764.16-----------

13.8 kV

75 MVvailable

13.8 kV

750 kV

4.16 kV

50VPC-W25

= 15X

R

Z 3.75 MVA375 MVA

--------------------------------- 0.01 pu or 1%= =

Z2

X2

R2

R2 X

2

R2

-------- 1+

=+=

RZ

X2

R2

-------- 1+

-----------------------1

266----------------

115.03------------------ 0.066%= = = =

X XR----- R( ) 15 (0.066) .99%= = =

R 24.2 kW

3750 kVA-------------------------------- 0.0065 pu or 0.65%= =

Transformer X Z2

R2

– (5.09)2

(0.65)2

– 25.91 0.42– 25.48= = =

For Three-Phase Fault

where X is ohms per phase and E isthe highest typical line-to-neutraloperating voltage or

where X is per unit reactance

IB is base current

would use 1.0 multiplying factor forshort-circuit duty, therefore, short-circuit duty is 8.6 kA sym. for three-phase fault I1 and momentary duty is8.6 x 1.6 = 13.7 kA I3.

For Line-to-Ground Fault

For this system, X0 is the zero sequencereactance of the transformer, whichis equal to the transformer positivesequence reactance and X1 is the posi-tive sequence reactance of the system.

Therefore,

Using 1.0 multiplying factor (seeTable 1.3-6), short-circuit duty = 9.1 kASym. LG (I2)

Answer

With this application, shortcuts couldhave been taken for a quicker check ofthe application. If we assume unlimitedshort circuit available at 13.8 kV andthat Trans. Z = X

X/R ratio 15 or less multiplying factoris 1.0 for short-circuit duty.

The short-circuit duty is then 9.5 kASym. (I1, I2) and momentary duty is9.5 x 1.6 kA = 15.2 kA (I3).

The 50VCP-W250 breaker capabilitiesexceed the duty requirements andmay be applied.

I3-PhaseEX-----=

I3-Phase

IBX-----=

Base current IB3.75 MVA

3 4.16 kV( )−−−−−−−−−−−−−−−−−−−− 0.52kA= =

3-Phase

I1X-----

0.520.0604---------------------- 8.6 kA Sym.= = =

System XR−− 9 (is less than 15)=

ILG3E

2X1 X0+

---------------------------

3IB2X1 X0+

---------------------------==

ILG3(0.52)

2(0.0604) 0.0505+−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−− 9.1 kA Sym.= =

Then I3-Phase

IBX-----

0.520.055------------------ 9.5 kA Sym.= = =




1September 2011


Sheet 01

System Analysis041


Given the system shown with motorloads, calculate the fault currentsand determine proper circuit breakerselection.

All calculations on per unit basis.7.5 MVA base

3000 hp Synchronous Motor

X = 0.20 (0.628) = 0.638 pu at 7.5 MVA Base0.197

2500 hp Ind. Motor

X = 0.25 (0.628) = 0.908 pu at 7.5 MVA Base0.173

Table 1.3-6. Multiplying Factor for E/XAmperes (ANSI C37.010, 1979, Figures 1.1-8,1.1-9 and 1.1-10)

Where system X/R ratio is 15 or less, themultiplying factor is 1.0.

X R X/R

13.8 kV System

Transformer

0.015

0.055

0.001

0.0055

15

10

Total Source Transformer 0.070 pu 0.0065 pu 11

SystemX/R

Type VCP-W VacuumCircuit BreakerRated Interrupting Time, 5-Cycle

Type of Fault

Ratio Three-Phase

LG Three-Phaseand LG

Source of Short Circuit

Local Remote

115

202530

1.001.001.001.001.04

1.001.001.021.061.10

1.001.001.051.101.13

3640455055

1.061.081.121.131.14

1.141.161.191.221.25

1.171.221.251.271.30

606570

7580

1.161.171.19

1.201.21

1.261.281.29

1.301.31

1.321.331.35

1.361.37

859095

100

—1.22—1.23

—1.32—1.33

1.381.391.401.41

100120130

1.241.241.24

1.341.351.35

1.421.431.43

Base Current IB7.5 MVA

3 6.9 kV------------------------------- 0.628 kA= =

X = 0.628 (6.9) = 0.01521 (13.8)

I3-PhEX-----

IBX----- where X on per unit base= =


System = 0.062 (235) = 14.5 is a Multiplying Factor of 1.0 from Table 1.3-6

Table 1.3-7. Short-Circuit Duty = 10.1 kA

Answer

Source ofShort-Circuit Current

InterruptingE/X Amperes

MomentaryE/X Amperes

XR

X (1)R (X)

1R

I3 Source Transformer 0.6280.070

= 8.9710.6280.070

= 8.971 11 110.070

= 157

I1 3000 hp Syn. Motor 0.628(1.5) 0.638

= 0.6560.6280.638

= 0.984 2525

0.638= 39

I1 2500 hp Syn. Motor 0.628(1.5) 0.908

= 0.4610.6280.908

= 0.691 35 350.908

= 39

I3F = 10.088or 10.1 kA

10.647 Total 1/R = 235x 1.6

17.0 kA Momentary Duty

Z = 5.53% = 10

13.8 kV

7500 kVA

6.9 kV

13.8 kV System

3

21 kA Sym. Available = 15X

R

X = 5.5%

R = 0.55%

X

R

X

R= 25

X

R= 35

3000 hp1.0 PF

Syn.

2500 hp

Ind.

2197A FLX'' = 20%d

173A FLX'' = 25%d

1

Total X IBI3F

--------0.62810.1

------------------ 0.062= = =

BreakerType

VMax.

Three-Phase Symmetrical Interrupting Capability Close and Latchor Momentaryat V Max. Max. KI at 6.9 kV Oper. Voltage

75VCP-W500 8.25 kV 33 kA 41 kA 8.256.9

(33) = 39.5 kA 66 kA

150VCP-W500 15 kV 18 kA 23 kA 15 (18)6.9

(39.1) = 23 kA

(But not to exceed KI)

37 kA

XR-----

Either breaker could be properlyapplied, but price will make the type150VCP-W500 the more economicalselection.



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System Analysis042


Check breaker application or generator bus for the system of generators shown.

Each generator is 7.5 MVA, 4.16 kV 1040A full load, IB = 1.04 kA

Sub transient reactance Xd” = 11% or, X = 0.11 pu

Since generator neutral grounding reactors are used to limit the I LG to I3-phase orbelow, we need only check the I3 short-circuit duty.

System of 30 is a Multiplying Factor of 1.04 from Table 1.3-6.

Short-circuit duty is 28.4 (1.04) = 29.5 kA Symmetrical

Gen XR----- ratio is 30

Three-Phase Symmetrical Interrupting Capability

Breaker Type V Max. at V Max. Max. KI at 4.16 kV Oper. Voltage

50VCP-W250 4.76 kV 29 kA 36 kA 4.764.16

(29) = 33.2 kA

1XS

−−−− 1X−− 1

X−− 1

X−− 3

X−− and

1RS

−−−− 1R−− 1

R−− 1

R−− 3

R−−=+ +==+ +=

or XSX3----- and RS

R3---- Therefore, System

XS

RS

--------XR----- Gen X

R----- 30= = = = =

IBPhaseIBX-----

IBX-----

IBX-----

31B

X-----------

3(1.04)0.11

----------------------- 28.4 kA Symmetrical E/X amperes= =+ + +=

XR-----

Answer


The 50VCP-W250 breaker could beapplied.

G1 G2 G3

4.16 kV




1.3September 2011


Sheet 01

System Analysis043

Medium Voltage Fuses—Fault Calculations

There are two basic types of mediumvoltage fuses. The following definitionsare taken from ANSI Standard C37.40.

Expulsion Fuse (Unit)

A vented fuse (unit) in which theexpulsion effect of the gases producedby internal arcing, either alone or aidedby other mechanisms, results in currentinterruption.

Current-Limiting Fuse (Unit)

A fuse unit that, when its current-responsive element is melted by acurrent within the fuse’s specifiedcurrent-limiting range, abruptlyintroduces a high resistance toreduce current magnitude andduration, resulting in subsequent

current interruption.There are two classes of fuses;power and distribution. They aredistinguished from each other bythe current ratings and minimummelting type characteristics.

The current-limiting ability of acurrent-limiting fuse is specified byits threshold ratio, peak let-throughcurrent and I2t characteristics.

Interrupting Ratings of Fuses

Modern fuses are rated in amperesrms symmetrical. They also have alisted asymmetrical rms rating that

is 1.6 x the symmetrical rating.

Refer to ANSI/IEEE C37.48 for fuseinterrupting duty guidelines.

Calculation of the Fuse RequiredInterrupting Rating:

Step 1—Convert the fault fromthe utility to percent or per unit ona convenient voltage and kVA base.

Step 2—Collect the X and R data of allthe other circuit elements and convertto a percent or per unit on a conve-nient kVA and voltage base same asthat used in Step 1. Use the substran-sient X and R for all generators and

motors.

Step 3—Construct the sequencenetworks using reactances and connectproperly for the type of fault underconsideration and reduce to a singleequivalent reactance.

Step 4—Construct the sequencenetworks using resistances andconnect properly for the type offault under consideration and reduceto a single equivalent resistance.

Step 5—Calculate the E/XI value,

where E is the prefault value of thevoltage at the point of fault normallyassumed 1.0 in pu. For three-phasefaults E/XI is the fault current to beused in determining the required inter-rupting capability of the fuse.

Note: It is not necessary to calculate asingle phase-to-phase fault current. Thiscurrent is very nearly /2 x three-phasefault. The line-to-ground fault may exceedthe three-phase fault for fuses located ingenerating stations with solidly groundedneutral generators, or in delta-wye trans-formers with the wye solidly grounded,where the sum of the positive and negativesequence impedances on the high voltage

side (delta) is smaller than the impedance ofthe transformer.

For single line-to-ground fault:

Step 6—Select a fuse whosepublished interrupting ratingexceeds the calculated fault current.

Figure 1.3-2 should be used whereolder fuses asymmetrically rated areinvolved.

The voltage rating of power fuses usedon three-phase systems should equalor exceed the maximum line-to-linevoltage rating of the system. Currentlimiting fuses for three-phase systemsshould be so applied that the fusevoltage rating is equal to or less than1.41 x nominal system voltage.

Low Voltage Power CircuitBreakers—Fault Calculations

The steps for calculating the fault cur-rent for the selection of a low voltagepower circuit breaker are the same asthose used for medium voltage circuitbreakers except that where the con-nected loads to the low voltage bus

includes induction and synchronousmotor loads. The assumption is madethat in 208Y/120V systems the contri-bution from motors is two times the fullload current of step-down transformer.This corresponds to an assumed 50%motor aggregate impedance on a kVAbase equal to the transformer kVArating or 50% motor load. For 480V,480Y/277V and 600V systems, theassumption is made that the contribution from the motors is four times the fullload current of the step-down trans-former, which corresponds to an assumed 25% aggregate motor impedance on akVA base equal to the transformer kVArating or 100% motor load.

In low voltage systems that containgenerators, the subtransient reactanceshould be used.

If the X/R to the point of fault is greaterthan 6.6, a derating multiplying factor(MF) must be applied. The X/R ratio iscalculated in the same manner as thatfor medium voltage circuit breakers.

Calculated symmetrical amperes xMF ≤ breaker interrupting rating.

The multiplying factor MF can becalculated by the formula:

If the X/R of system feeding thebreaker is not known, use X/R = 15.

For fused breakers by the formula:

If the X/R of the system feeding thebreaker is not known, use X/R = 20.

Refer to Table 1.3-8 for the standardranges of X/R and power factors used intesting and rating low voltage breakers.Refer to Table 1.3-9 for the circuitbreaker interrupting rating multiplyingfactors to be used when the calculatedX/R ratio or power factor at the pointthe breaker is to be applied in thepower distribution system falls outsideof the Table 1.3-8 X/R or power factorsused in testing and rating the circuitbreakers. MF is always greater than 1.0.

3

XI XI(+) XI(–) XI(0)+ +=

IfEXI

------ 3×=

MF2 1 2.718

π( ) X/R( ) ⁄ –+[ ]2.29

−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−=

MF1 2 2.718( ) 2π( ) X/R( ) ⁄ –×+

1.25−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−=



.3-12


September 2011


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Sheet 01

System Analysis044

Molded-Case Breakers andInsulated Case CircuitBreakers—Fault Calculations

The method of fault calculation is the

same as that for low voltage powercircuit breakers. Again, the calculatedfault current x MF ≤ breaker interruptingcapacity. Because molded case breakersare tested at lower X/R ratios, the MFsare different than those for low voltagepower circuit breakers.

X1 ⁄ R1 = test X/R value

X2 ⁄ R2 = X/R at point where breaker

is applied

MF1 2.718

πX2

R2

−−− ⁄ –

+

1 2.718π

X1

R1

−−− ⁄ –

+

----------------------------------------------------=

Low Voltage Circuit BreakerInterrupting Derating Factors

Refer to Table 1.3-8 for the standardranges of X/R and power factors usedin testing and rating low voltage

breakers. Refer to Table 1.3-9 forthe circuit breaker interrupting ratingde-rating factors to be used when thecalculated X/R ratio or power factorat the point the breaker is to be appliedin the power distribution system fallsoutside of the Table 1.3-8 X/R or powerfactors used in testing and rating thecircuit breakers.

Normally the short-circuit power factoror X/R ratio of a distribution systemneed not be considered in applyinglow voltage circuit breakers. This isbecause the ratings established inthe applicable standard are based

on power factor values that amplycover most applications.

Established standard values includethe following:

Table 1.3-8. Standard Test Power Factors

For distribution systems where thecalculated short-circuit current X/Rratio differs from the standard valuesgiven in the above table, circuit breakerinterrupting rating derating factors fromTable 1.3-9 table should be applied.

Table 1.3-9. Circuit Breaker Interrupting Rating Derating Factors

Note: These are derating factors applied to the breaker and are the inverse of MF.

InterruptingRating in kA

Power FactorTest Range

X/R TestRange

Molded Case Circuit Breaker

10 or LessOver 10 to 20Over 20

0.45–0.500.25–0.0300.15–0.20

1.98–1.733.87–3.186.6–4.9

Low Voltage Power Circuit Breaker

All 0.15 Maximum 6.6 Minimum

% P.F. X/R Interrupting Rating

Molded Case or Insulated Case Power Circuit Breaker

/ = 10 kA>10 kA

/ = 20 kA >20 kA Unfused Fused

503025

1.733.183.87

1.0000.8470.805

1.0001.0000.950

1.0001.0001.000

1.0001.0001.000

1.0001.0001.000

201512

4.906.598.27

0.7620.7180.691

0.8990.8470.815

1.0000.9420.907

1.0001.0000.962

1.0000.9390.898

108.57

9.9511.7214.25

0.6730.6590.645

0.7940.7780.761

0.8830.8650.847

0.9370.9180.899

0.8700.8490.827

5 19.97 0.627 0.740 0.823 0.874 0.797

< <




1.3September 2011


Sheet 01

System Analysis045

Short-Circuit Calculations—Shortcut Method

Determination of Short-Circuit CurrentNote 1: Transformer impedance generally relates to self-ventilated rating (e.g., with OA/FA/FOA transformer use OA base).

Note 2: kV refers to line-to-line voltage in kilovolts.

Note 3: Z refers to line-to-neutral impedance of system to fault where R + jX = Z.

Note 4: When totaling the components of system Z, arithmetic combining of impedances as “ohms Z”. “per unit Z”. etc., is considered ashortcut or approximate method; proper combining of impedances (e.g., source, cables transformers, conductors, etc.). should useindividual R and X components. This Total Z = Total R + j Total X (see IEEE “Red Book” Standard No. 141).

(a) Per unit = pu impedance kVA base

(b) Percent = % impedance kVA base

(a) Per unit impedance = pu

(b) % impedance = %

(c) Ohms impedance =

(a) —if utility fault capacity given in kVA

Per-unit impedance = pu

(b) —if utility fault capacity given in rms symmetrical short circuit amperes

Per-unit impedance = pu

(a) —motor kVA — (kV) (I) where I = motor nameplate full-load amperes

(b) —if 1.0 power factor synchronous motor kVA = (0.8) (hp)

(c) —if 0.8 power factor synchronous motor kVA = (1.0) (hp)

(d) —if induction motor kVA = (1.0) (hp)

(a) Base current = I Base = or

(b) Per unit

(c) rms Symmetrical current = ISC = (pu ISC) (IBase Amperes)

(d) rms Symmetrical current = Amperes = or

(e) = or

(g) =

(a) Symmetrical short-circuit kVA =

(b) =

(a) —from three-phase transformer—approx. 86% of three-phase current

(b) —three single-phase transformers (e.g., 75 kVA, Z = 2%) calculate same as one three-phaseunit (i.e., 3 x 75 kVA = 225 kVA, Z = 2%).

(c) —from single-phase transformer—see Page 1.3-15.

(a) —synchronous motor—5 times motor full load current (impedance 20%)

(b) —induction motor—4 times motor full-load current (impedance 25%)

(c) —motor loads not individually identified, use contribution from group of motors as follows:—on 208Y/120V systems—2.0 times transformer full-load current—on 240-480-600V three-phase, three-wire systems—4.0 times transformer full-load current—on 480Y/277V three-phase, four-wire systems—In commercial buildings, 2.0 times transformers full-load current (50% motor load)—In industrial plants, 4.0 times transformer full-load current (100% motor load)

2kVA base 2

kVA base 1−−−−−−−−−−−−−−− (pu impedance on kVA base 1)×=

2kVA base 2

kVA base 1−−−−−−−−−−−−−−− (% impedance on kVA base 1)×=

Z percent impedance

100−−−−−−−−−−−−−−−−−−−−−−−−−−−

(ohms impedance)

kV( )2−−−−−−−−−−−−−−−−−−−−−−−−−−(kVA base)

1000( )−−−−−−−−−−−−−−−= =

Z(ohms impedance)

kV( )2−−−−−−−−−−−−−−−−−−−−−−−−−−(kVA base)

10( )−−−−−−−−−−−−−−−=

(% impedance) kV( )2 (10)

kVA base−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−

Z kVA base in studypower-source kVA fault capacity-------------------------------------------------------------------------------------------=

Z kVA base in study

(short-circuit current) 3( )(kV of source)----------------------------------------------------------------------------------------------------------------=

3( )

Three-phase kVA

3( ) kV( )

−−−−−−−−−−−−−−−−−−−−−−−− Single-phase kVA

kV line-to-neutral−−−−−−−−−−−−−−−−−−−−−−−−−

ISC

1.0

puZ−−−−−=

Three-phase KVA base

puZ( ) 3( ) kV( )----------------------------------------------------------------

Single-phase kVA basepuZ( ) kV( )

-----------------------------------------------------------------

(Three-phase kVA base) (100)

(%Z) 3( ) kV( )-----------------------------------------------------------------------------------

Single-phase kVA base (100)(%Z) kV( )

--------------------------------------------------------------------------------

(kV) (1000)

3 (ohms Z)-----------------------------------

kVA basepuZ( )

--------------------------(kVA base) (100)

%Z----------------------------------------------

kV( )2 1000( )ohms Z

----------------------------------= =

3(line-to-neutral kV)2 1000( )(ohms Z)

-----------------------------------------------------------------------------

1. Select convenient kVA base for system tobe studied.

2. Change per unit, or percent, impedance fromone kVA base to another:

3. Change ohms, or percent or per unit, etc.:

4. Change power-source impedance to per unitor percent impedance on kVA base as selectedfor this study:

5. Change motor rating to kVA:

6. Determine symmetrical short-circuit current:

7. Determine symmetrical short-circuit kVA:

8. Determine line-to-line short-circuit current:

9. Determine motor contribution (or feedback) assource of fault current: See IEEE

Standard No. 141



.3-14


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System Analysis046

Example Number 1

How to Calculate Short-Circuit Currents at Ends of Conductors

Figure 1.3-9. Example Number 1

Utility Source 500 MVA

1000 kV A5.75%480V

Switchboard Fault

100 ft (30m)3–350 kcmil Cablein Steel Conduit

Mixed Load—Motors and LightingEach Feeder—100 ft (30m) of 3–350 kcmilCable in Steel Conduit Feeding Lighting and250 kVA of Motors

Cable Fault

Utility

Transformer

Major Contribution

Cables

Switchboard Fault

Cables

Cable Fault

A B C

0.002 pu

Switchboard Fault

0.027 pu

Cable Fault

A B C 0.0575 pu

1.00 pu

0.027 pu

1.00 pu

0.027 pu

1.00 pu

0.027 pu

0.342 pu

0.027 pu

0.0507 pu

0.027 pu

E 0.0777 pu

Combining Series Impedances: ZTOTAL = Z1 + Z2 + ... +Zn

Combining Parallel Impedances:ZTOTAL

1 =Z1

1 +Z2

1 + ...Zn

1

0.0595 pu

EquationStep (See) Calculation1 – Select 1000 kVA as most convenient base, since all data except utility source is on

secondary of 1000 kVA transformer.

2 4(a) Utility per unit impedance

3 3(a) Transformer per unit impedance =

4 4(a) and Motor contribution per unit impedance =9(c)

5 3(a) Cable impedance in ohms (see above) = 0.00619 ohms

Cable impedance per unit =

6 6(d) Total impedance to switchboard fault = 0.0507 pu (see diagram above)

Symmetrical short circuit current at switchboard fault =

7 6(d) Total impedance to cable fault = 0.0777 pu (see diagram above)

Symmetrical short circuit current at cable fault =

Zpu

kVA baseutility fault kVA-------------------------------------------

1000500.000---------------------

0.002 pu= ===

Zpu

%Z100----------

5.75100-----------

0.0575 pu= = =

Zpu

kVA base4 x motor kVA----------------------------------------

10004 x 250--------------------

1.00 pu= ==

Zpu

(ohms)(kVA base)

(kV)2(1000)

--------------------------------------------------

(0.00619)(1000)

(0.480)2(1000)

-------------------------------------------0.027pu= = =

3-phase kVA base

Zpu

( ) 3( ) kV( )−−−−−−−−−−−−−−−−−−−−−−−−−

1000

0.0507( ) 3( ) 0.480( )−−−−−−−−−−−−−−−−−−−−−−−−−−−− 23,720 amperes rms= =

3-phase kVA base

Zpu

( ) 3( ) kV( )−−−−−−−−−−−−−−−−−−−−−−−−−

1000

0.0777( ) 3( ) 0.480( )−−−−−−−−−−−−−−−−−−−−−−−−−−−− 15 480 amperes rms,= =

A. System Diagram B. Impedance Diagram (Using “Short Cut” Method for Combining Impedancesand Sources).

C. Conductor impedance from Table 1.5-16,Page 1.5-14. Conductors: 3–350 kcmil copper,single conductors Circuit length: 100 ft (30m),in steel (magnetic) conduit ImpedanceZ = 0.00619 ohms/100 ft (30m).ZTOT = 0.00619 ohms (100 circuit feet)

D. Fault current calculations (combining imped-

ances arithmetically, using approximate“Short Cut” method—see Note 4,Page 1.3-13)




1.3September 2011


Sheet 01

System Analysis047

Example Number 2

Fault Calculation—Secondary Side of Single-Phase Transformer

Figure 1.3-10. Example Number 2

Method 1: Shortcut Methods—End of Cable

This method uses the approximationof adding Zs instead of the accuratemethod of Rs and Xs.

For Example: For a 480/277V systemwith 30,000A symmetrical availableat the line side of a conductor run of100 ft (30m) of 2–500 kcmil per phaseand neutral, the approximate fault current

at the load side end of the conductorscan be calculated as follows.

277V/30,000A = 0.00923 ohms (sourceimpedance)

Conductor ohms for 500 kcmil conductor from reference data in this section inmagnetic conduit is 0.00551 ohms per100 ft (30m). For 100 ft (30m) and twoconductors per phase we have:

0.00551/2 = 0.00273 ohms (conductorimpedance)

Add source and conductor impedance or 0.00923 + 0.00273 = 0.01196 total ohms

Next, 277V/0.01196 ohms = 23,160Arms at load side of conductors

Figure 1.3-11. Short-Circuit Diagram

RSyst = 0.00054

RCond = 0.00677

RTfmr = 0.0164

RTotal = 0.02371

F1

RSyst = 0.00356

RCond = 0.00332

RTfmr = 0.0227

RTotal = 0.02958

F1

RSyst = 0.00054

RCond = 0.00677

RTfmr = 0.0246

RTotal = 0.03191

F2

XSyst = 0.00356

XCond = 0.00332

XTfmr = 0.0272

XTotal = 0.03408

F2

240VF1

120VF2

Half-winding of Transformer

Full-winding of Transformer

{Multiply % R by 1.5Multiply % X by 1.2 }

75 kVA Single-Phase 480-120/240V; Z = 2.8%, R = 1.64%, X = 2.27%

100 Ft. Two #2/0 Copper Conductors, Magnetic Conduit{R = 0.0104 OhmsX = 0.0051 Ohms

480V Three-Phase Switchboard Bus at 50,000A Symmetrical, X/R = 6.6

{

R = 0.1498 Z

X = 0.9887 Z

ZCond = (From Page 1.3-13Formula 3(a) )

ohms kVA Base×kV( )2

1000×−−−−−−−−−−−−−−−−−−−−−−−−−

A. System Diagram Deriving Transformer R and X:

X = 6.6 R

Z =

R = R = 0.1498Z

X = 6.6R X = 0.9887Z

X

R−− 6.6=

X2

R2

+ 6.6R( )2R

2+ 43.56R

2R

2+ 44.56R

26.6753R= = = =

Z

6.6753−−−−−−−−−

B. Impedance Diagram—Fault F1

D. Impedance and Fault Current Calculations—75 kVA Base

Note: To account for the outgoing and return paths of single-phase circuits (conductors,systems, etc.) use twice the three-phase values of R and X.

RSyst = 2 (0.1498 x Z) = 0.00054 pu

XSyst = 2 (0.9887 x Z) = 0.00356 pu

RCond = 2 = 0.00677 pu

XCond = 2 = 0.00332 pu

RTfmr = = 0.0164 pu

XTfmr = = 0.0277 pu

RTfmr = 1.5 = 0.0246 pu

XTfmr = 1.2 = 0.0272 pu

Z = = 0.03791 pu

Z = = 0.04669 pu

0.0104 75×0.48

21000×

−−−−−−−−−−−−−−−−−

0.0051 75×

0.48( )2

1000×

−−−−−−−−−−−−−−−−−−−−

1.64

100−−−−−

2.27

100−−−−−

1.64

100−−−−−( )

2.27

100−−−−−( )

0.02371( )20.02958( )2

+

0.03191( )20.03408( )2

+

ZSyst = (From Page 1.3-13Formula 4(b) )

75

3 0.480× 50,000×−−−−−−−−−−−−−−−−−−−−−−−−−−−− 0.0018

pu=

Full-winding of Transformer (75 kVA Base)

Half-winding of Transformer (75 kVA Base)

Impedance to Fault F1—Full Winding

Impedance to Fault F2—Half Winding

Short circuit current F1 = 75 ÷ (0.03791 x 0.240 kV) = 8,243A Symmetrical

Short circuit current F2 = 75 ÷ (0.04669 x 0.120 kV) = 13,386A Symmetrical

C. Impedance Diagram—Fault F2

Reference: IEEE Standard No. 141

X 30,000A available

100 ft (30m)2–500 kcmil per phase

X If = 23,160A



.3-16


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System Analysis048

Method 2: Chart Approximate MethodThe chart method is based on the following:

Motor Contribution

For system voltages of 120/208V, it is reasonable to assumethat the connected load consists of 50% motor load, and that

the motors will contribute four times their full load currentinto a fault. For system voltages of 240 and 480V, it is rea-sonable to assume that the connected load consists of 100%motor load, and that the motors will contribute four timestheir full load current into a fault. These motor contributionshave been factored into each curve as if all motors wereconnected to the transformer terminals.

Feeder Conductors

The conductor sizes most commonly used for feedersfrom molded case circuit breakers are shown. For conductorsizes not shown, the following table has been included forconversion to equivalent arrangements. In some cases itmay be necessary to interpolate for unusual feeder ratings.Table 1.3-10 is based on using copper conductor.

Table 1.3-10. Conductor Conversion (Based on Using Copper Conductor)

Short-Circuit Current Readout

The readout obtained from the charts is the rms symmetricalamperes available at the given distance from the trans-former. The circuit breaker should have an interruptingcapacity at least as large as this value.

How to Use the Short-Circuit ChartsStep One

Obtain the following data:

1. System voltage

2. Transformer kVA rating (from transformer nameplate)

3. Transformer impedance (from transformer nameplate)

4. Primary source fault energy available in kVA(from electric utility or distribution system engineers)

Step Two

Select the applicable chart from the following pages. Thecharts are grouped by secondary system voltage, which islisted with each transformer. Within each group, the chartfor the lowest kVA transformer is shown first, followed in

ascending order to the highest rated transformer.

Step Three

Select the family of curves that is closest to the “availablesource kVA.” The black line family of curves is for a source of500,000 kVA. The lower value line (in red) family of curves isfor a source of 50,000 kVA. You may interpolate betweencurves if necessary, but for values above 100,000 kVA it isappropriate to use the 500,000 kVA curves.

Step Four

Select the specific curve for the conductor size being used. Ifyour conductor size is something other than the sizes shownon the chart, refer to the conductor conversion Table 1.3-10.

Step Five

Enter the chart along the bottom horizontal scale with thedistance (in feet) from the transformer to the fault point.Draw a vertical line up the chart to the point where it inter-sects the selected curve. Then draw a horizontal line to theleft from this point to the scale along the left side of the chart.

Step Six

The value obtained from the left-hand vertical scale is the faultcurrent (in thousands of amperes) available at the fault point.

For a more exact determination, see the formula method.It should be noted that even the most exact methods forcalculating fault energy use some approximations and someassumptions. Therefore, it is appropriate to select a methodwhich is sufficiently accurate for the purpose, but not moreburdensome than is justified. The charts that follow makeuse of simplifications that are reasonable under most cir-cumstances and will almost certainly yield answers that areon the safe side. This may, in some cases, lead to applicationof circuit breakers having interrupting ratings higher thannecessary, but should eliminate the possibility of applyingunits which will not be safe for the possible fault duty.

Figure 1.3-12. 225 kVA Transformer/4.5% Impedance/208V


If Your Conductor is: Use Equivalent Arrangement

3–No. 4/0 cables4–No. 2/0 cables

2–500 kcmil2–500 kcmil

3–2000 kcmil cables5–400 kcmil cables6–300 kcmil cables

4–750 kcmil4–750 kcmil4–750 kcmil

800A busway1000A busway1600A busway

2–500 kcmil2–500 kcmil4–750 kcmil

1 2 1 2 1 2

2.5

.

7.

1 .

12.5

Distance in Feet from T

2 kcmiWGWG

10 20 50 100 200 500 1000 2000 5000

10

1

20

2

30

a u l t C u r r e n t i n T h o u s

a n d s o f A m p e r e s ( S y m . )


kcmil

#4 A F 50,00




1.3September 2011


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System Analysis049







2 10 20 50 100 200 00 1000 2000 5000

10

1

2

2

30

F a u l t C u r r e n t i n T h o u s a n d s o f A m

p e r e s ( S y m . )


F

2

1 2 1 2 1 2

1

2

30

4

50

F a u l t C u r r e n t i n T h o u s a n d s o f A m p e r e s ( S y m . )


B

kcmil

WG

A

F 50,000

2 10 20 50 100 200 00 1000 2000 5000

10

20

40

60

F a u l t C u r r e n t i n

T h o u s a n d s o f A m p e r e s ( S y m . )


WG

kcmilkcmil

50,00

0 2 10 20 0 100 200 500 1000 2000 5000

20

40

1

120


WG

WG50,00

1 2 1 2 1 20

2

4

60

100

12


B

F

WG

A

F 50,000

0 2 5 10 20 0 100 200 500 1000 2000 5000

4

8

1

12




4

50,00



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System Analysis050






0 5 10 20 0 100 200 500 1000 2000 000

5

10

1

20

2

0

F a u l t C u r r e n t i n T h o u s a n d s o f A m

p e r e s ( S y m . )


50,00

/ WG

0 5 10 20 0 100 200 500 1000 2000 000

10

1

20

2

0

F a u l t C u r r e n t i n T h o u s a n d s o f A m p e r e s ( S y m . )


B

50,00

4 kcmi

#4 A

750

0 10 20 0 100 200 500 1000 2000 000

5

10

1

20

2

0




B

50,00

4 – 750 kcmil

WG

10 20 50 100 200 500 1000 2000

10

20

40

0

a u l t C u r r e n t i n T h o u s a n d s o f A m

p e r e s ( S y m . )


F

50,00

4 750 k cmil

kcmi

#4 AWG

10 20 50 100 200 500 1000 2000

1

20

40

0

a u l t C u r r e n t i n T h o u s a n d s o f A m p e r e s ( S y m . )


F

50,00

kcmi

G




1.3September 2011


Sheet 01

System Analysis051

Determining X and R Valuesfrom Transformer Loss Data

Method 1:

Given a 500 kVA, 5.5% Z transformerwith 9000W total loss; 1700W no-loadloss; 7300W load loss and primaryvoltage of 480V.

%R = 0.0067 ohms

Method 2:

Using same values above.

How to Estimate Short-CircuitCurrents at TransformerSecondaries:

Method 1:

To obtain three-phase rms symmetricalshort-circuit current available attransformer secondary terminals,use the formula:

where %Z is the transformer impedancein percent, from Tables 1.5-6 through1.5-10, Page 1.5-11.

This is the maximum three-phase sym-metrical bolted-fault current, assumingsustained primary voltage during fault,i.e., an infinite or unlimited primarypower source (zero source impedance).

Because the power source mustalways have some impedance, thisis a conservative value; actual faultcurrent will be somewhat less.

Note: This will not include motor short-circuit contribution.

Method 2:

Refer to Page 1.5-9 in the Referencesection, and use appropriate row ofdata based on transformer kVA andprimary short-circuit current available.This will yield more accurate results

and allow for including motor short-circuit contribution.

3 500

3 0.480×−−−−−−−−−−−−−−−−−

2

× R 7300W=×

%R0.0067 500×

10 0.482×

−−−−−−−−−−−−−−−−−−−−− 1.46%==

%X 5.52

1.462

– 5.30%==

%RI R Losses2

10 kVA×−−−−−−−−−−−−−−−−−=

730010 500×−−−−−−−−−−−−− 1.46=

%X 5.52

1.462

– 5.30%==

ISC IFLC100%Z------------×=



.3-20


September 2011


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Sheet 01

System Analysis052

Voltage Drop ConsiderationsThe first consideration for voltagedrop is that under the steady-stateconditions of normal load, the voltageat the utilization equipment must beadequate. Fine-print notes in the NEC

recommend sizing feeders and branchcircuits so that the maximum voltagedrop in either does not exceed 3%,with the total voltage drop for feedersand branch circuits not to exceed 5%,for efficiency of operation. (Fine printnotes in the NEC are not mandatory.)

In addition to steady-state conditions,voltage drop under transient condi-tions, with sudden high-current, short-time loads, must be considered. Themost common loads of this type aremotor inrush currents during starting.These loads cause a voltage dip onthe system as a result of the voltage

drop in conductors, transformers andgenerators under the high current.This voltage dip can have numerousadverse effects on equipment in thesystem, and equipment and conduc-tors must be designed and sized tominimize these problems. In manycases, reduced-voltage starting ofmotors to reduce inrush currentwill be necessary.

Recommended Limits ofVoltage Variation

General Illumination: Flicker inincandescent lighting from voltagedip can be severe; lumen output dropsabout three times as much as thevoltage dips. That is, a 10% drop involtage will result in a 30% drop inlight output. While the lumen outputdrop in fluorescent lamps is roughlyproportional to voltage drop, if thevoltage dips about 25%, the lamp willgo out momentarily and then restrike.For high-intensity discharge (HID)lamps such as mercury vapor, high-pressure sodium or metal halide, if thelamp goes out because of an excessivevoltage dip, it will not restrike until ithas cooled. This will require severalminutes. These lighting flicker effectscan be annoying, and in the case of

HID lamps, sometimes serious. Inareas where close work is being done,such as drafting rooms, precisionassembly plants, and the like, evena slight variation, if repeated, can bevery annoying, and reduce efficiency.Voltage variation in such areas shouldbe held to 2 or 3% under motor-startingor other transient conditions.

Computer Equipment: With theproliferation of data-processing andcomputer- or microprocessor-controlled manufacturing, the sensitivity ofcomputers to voltage has become animportant consideration. Severe dips of

short duration can cause a computerto “crash”—shut down completely,and other voltage transients causedby starting and stopping motors cancause data-processing errors. Whilevoltage drops must be held to a mini-mum, in many cases computers willrequire special power-conditioningequipment to operate properly.

Industrial Plants: Where large motorsexist, and unit substation transformersare relatively limited in size, voltagedips of as much as 20% may be per-missible in some cases, if they do notoccur too frequently. Lighting is oftensupplied from separate transformers,

and is minimally affected by voltagedips in the power systems. However, itis usually best to limit dips to between5 and 10% at most. One critical consid-eration is that a large voltage dip cancause a dropout (opening) of magneticmotor contactors and control relays.The actual dropout voltage varies con-siderably among starters of differentmanufacturers. The only standard thatexists is that of NEMA, which statesthat a starter must not drop out at 85%of its nominal coil voltage, allowingonly a 15% dip. While most starterswill tolerate considerably more volt-age dip before dropping out, limiting

dip to 15% is the only way to ensurecontinuity of operation in all cases.

X-Ray Equipment: Medical x-ray andsimilar diagnostic equipment, such asCAT-scanners, are extremely sensitiveto low voltage. They present a small,steady load to the system until theinstant the x-ray tube is “fired.” Thispresents a brief but extremely highinstantaneous momentary load. Insome modern x-ray equipment, thefiring is repeated rapidly to createmultiple images. The voltage regula-tion must be maintained within themanufacturer’s limits, usually 2 to 3%,

under these momentary loads, toensure proper x-ray exposure.

Motor StartingMotor inrush on starting must be limitedto minimize voltage dips. Table 1.3-11 on the next page will help select theproper type of motor starter for variousmotors, and to select generators of

adequate size to limit voltage dip.See Tab 29 for additional data onreduced voltage motor starting.

Utility Systems

Where the power is supplied by autility network, the motor inrush canbe assumed to be small comparedto the system capacity, and voltageat the source can be assumed tobe constant during motor starting.Voltage dip resulting from motorstarting can be calculated on the basisof the voltage drop in the conductorsbetween the power source andthe motor resulting from the inrush

current. Where the utility system islimited, the utility will often specify themaximum permissible inrush currentor the maximum hp motor they willpermit to be started across-the-line.

Transformer Considerations

If the power source is a transformer,and the inrush kVA or current of themotor being started is small comparedto the full-rated kVA or current of thetransformer, the transformer voltagedip will be small and may be ignored.As the motor inrush becomes a signifi-cant percentage of the transformerfull-load rating, an estimate of the

transformer voltage drop must beadded to the conductor voltage dropto obtain the total voltage drop to themotor. Accurate voltage drop calcula-tion would be complex and dependupon transformer and conductorresistance, reactance and impedance,as well as motor inrush current andpower factor. However, an approxima-tion can be made on the basis of thelow power-factor motor inrush current(30–40%) and impedance of the trans-former.

The allowable motor inrush current isdetermined by the total permissiblevoltage drop in transformer andconductors.

For example, if a 480V transformerhas an impedance of 5%, and the

motor inrush current is 25% of thetransformer full-load current (FLC),then the worst case voltage drop willbe 0.25 x 5%, or 1.25%.




1.3September 2011


Sheet 01

System Analysis053

Table 1.3-11. Factors Governing Voltage Drop

Consult NEMA MG-1 sections 1 and 12 for the exact definition of the design letter. In each case, a solid-state reduced voltage starter can be adjusted and controlled to provide the required inrush current and torque characteristics.

Where accuracy is important, request the code letter of the the motor and starting and breakdown torques from the motor vendor. Using 80% taps.

Engine Generator Systems

With an engine generator as thesource of power, the type of starterthat will limit the inrush depends onthe characteristics of the generator.Although automatic voltage regulatorsare usually used with all AC engine-generators, the initial dip in voltage iscaused by the inherent regulation ofthe generator and occurs too rapidlyfor the voltage regulator to respond.It will occur whether or not a regulatoris installed. Consequently, the percent

of initial voltage drop depends on theratio of the starting kVA taken by themotor to the generator capacity, theinherent regulation of the generator,the power-factor of the load thrownon the generator, and the percentageload carried by the generator.

A standard 80% power-factor engine-type generator (which would beused where power is to be suppliedto motor loads) has an inherentregulation of approximately 40%from no-load to full-load. This meansthat a 50% variation in load wouldcause approximately 20% variationin voltage (50% x 40% = 20%).

Assume that a 100 kVA, 80% PFengine-type generator is supplyingthe power and that the voltage dropshould not exceed 10%. Can a 7-1/2 hp,220V, 1750 rpm, three-phase, squirrel-cage motor be started withoutexceeding this voltage drop?

Starting ratio =

From the nameplate data on the motor,the full-load amperes of a 7-1/2 hp.220V, 1750 rpm, three-phase, squirrel-cage motor is 19.0A. Therefore:

Starting current (%F.L.) =

From Table 1.3-11, a NEMA design C orNEMA design D motor with an autotrans-former starter gives approximately thisstarting ratio. It could also be obtained

from a properly set solid-state adjust-able reduced voltage starter.

The choice will depend upon thetorque requirements of the load sincethe use of an autotransformer starterreduces the starting torque in directproportion to the reduction in startingcurrent. In other words, a NEMAdesign C motor with an autotrans-former would have a starting torqueof approximately full-load (see Table1.3-11) whereas the NEMA design Dmotor under the same conditionswould have a starting torque ofapproximately 1-1/2 times full-load.

Note: If a resistance starter were used forthe same motor terminal voltage, the start-ing torque would be the same as thatobtained with autotransformer type, but thestarting current would be higher, as shown.

Shortcut Method

Column 7 in Table 1.3-11 has beenworked out to simplify checking.The figures were obtained by usingthe formula above and assuming1 kVA generator capacity and 1%voltage drop.

Example:

Assuming a project having a1000 kVA generator, where thevoltage variation must not exceed10%. Can a 75 hp, 1750 rpm, 220V,three-phase, squirrel-cage motor bestarted without objectionable lampflicker (or 10% voltage drop)?

From tables in the circuit protectivedevices reference section, the full-loadamperes of this size and type of motoris 158A. To convert to same basis ascolumn 7, 158A must be divided by

the generator capacity and % voltagedrop, or:

158 = 0.0158A per kVA1000 x 10 per 1% voltage drop

Checking against the table, 0.0158 fallswithin the 0.0170–0.0146 range. Thisindicates that a general-purpose motorwith autotransformer starting canbe used.

Note: Designers may obtain calculatedinformation from engine generatormanufacturers.

The calculation results in conservative

results. The engineer should provideto the engine-generator vendor thestarting kVA of all motors connected tothe generator and their starting sequence. The engineer should also specify themaximum allowable drop. The engineershould request that the engine-generator vendor consider the proper generatorsize when closed-transition autotrans-former reduced voltage starters, andsoft-start solid-state starter are used;so the most economical method ofinstallation is obtained.

Type ofMotor

StartingTorque

StartingCurrent

HowStarted

StartingCurrent% Full-Load

Starting Torque per Unit ofFull Load Torque

Full-Load Amperesper kVA GeneratorCapacity for Each1% Voltage Drop

Motor Rpm

1750 1150 850

Design A Normal Normal Across-the-lineresistanceautotransformer

600–700480–560➁375–450➁

1.50.960.96

1.350.870.87

1.250.800.80

0.0109–.009360.0136–.01170.0170–.0146

Design B Normal Low Across-the-lineresistanceautotransformer

500–600400–480➁320–400➁

1.50.960.96

1.350.870.87

1.250.800.80

0.0131–.01090.0164–.013650.0205–.0170

Design C High Low Across-the-lineresistanceautotransformer

500–600400–480➁320–400➁

———

0.2 to 2.51.28 to 1.61.28 to 1.6

———

0.0131–.01090.0164–.013650.0205–.0170

Wound Rotor High Low Secondary controller 100% currentfor 100%torque

———

———

———

——0.0655

Synchronous (for compressors)Synchronous (for centrifugal pumps)

LowLow

——

Across-the-lineAcross-the-lineAutotransformer

300450–550288–350

40% Starting, 40% Pull-In60% Starting, 110% Pull-In38% Starting, 110% Pull-In

0.02180.0145–.01180.0228–.0197

Percent voltage drop gen. kVA× 1000×F.L. amperes volts× 3× reg. of gen.×−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−

10 100× 1000×19.0 220× 3× 0.40×−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−− 3.45 or 345%.=



.3-22


September 2011


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Sheet 01

System Analysis054

Voltage Drop Formulas

Approximate Method

Voltage Drop

where abbreviations are same as below “Exact Method.”

Exact Methods

Voltage drop

Exact Method 1—If sending end voltage and load PFare known.

where:

EVD = Voltage drop, line-to-neutral, volts

ES = Source voltage, line-to-neutral, volts

I = Line (Load) current, amperes

R = Circuit (branch, feeder) resistance, ohms

X = Circuit (branch, feeder) reactance, ohms

cosθ = Power factor of load, decimal

sinθ = Reactive factor of load, decimal

If the receiving end voltage, load current and power factor(PF) are known.

ER is the receiving end voltage.

Exact Method 2—If receiving or sending mVA and its powerfactor are known at a known sending or receiving voltage.

or

where:

ER = Receiving line-line voltage in kV

ES = Sending line-line voltage in kV

MVAR = Receiving three-phase mVA

MVAS = Sending three-phase mVA

Z = Impedance between and receiving ends

γ = The angle of impedance Z

θR = Receiving end PF

θS = Sending end PF, positive when lagging

EVD IR cosθ IX sinθ+=

EVD ES IR cosθ IX sinθ ES2

IX cosθ IR sinθ–( )–

2–+ +=

EVD ERcosθ IR+( )2

ERsinθ IX+( )2

ER–+=

ES2

ER2 ZMVAR( )

2

ER2

---------------------------------- 2ZMVARcos γ θR–( )+ +=

ER2

ES2 ZMVAR( )2

ES2

---------------------------------- 2ZMVAScos γ θS–( )–+=




1.3September 2011


Sheet 01

System Analysis055

Voltage Drop

Voltage Drop TablesNote: Busway voltage drop tables areshown in Tab 24 of this catalog.

Tables for calculating voltage drop forcopper and aluminum conductors, ineither magnetic (steel) or nonmagnetic(aluminum or non-metallic) conduit,appear on Page 1.3-24. These tablesgive voltage drop per ampere per100 ft (30m) of circuit length. Thecircuit length is from the beginningpoint to the end point of the circuitregardless of the number of conductors.

Tables are based on the followingconditions:

1. Three or four single conductors ina conduit, random lay. For three-conductor cable, actual voltage

drop will be approximately thesame for small conductor sizesand high power factors. Actualvoltage drop will be from 10 to15% lower for larger conductorsizes and lower power factors.

2. Voltage drops are phase-to-phase,for three-phase, three-wire orthree-phase, four-wire 60 Hzcircuits. For other circuits, multiplyvoltage drop given in the tables bythe following correction factors:

Three-phase, four-wire,phase-to-neutral x 0.577

Single-phase, two-wire x 1.155

Single-phase, three-wire,phase-to-phase x 1.155

Single-phase, three-wire,phase-to-neutral x 0.577

3. Voltage drops are for a conductortemperature of 75°C. They may beused for conductor temperaturesbetween 60°C and 90°C withreasonable accuracy (within ±5%).However, correction factors inTable 1.3-12 can be applied ifdesired. The values in the table arein percent of total voltage drop .

For conductor temperature of 60°C–SUBTRACT the percentage fromTable 1.3-12.

For conductor temperature of 90°C–ADD the percentage from Table 1.3-12.

Table 1.3-12. Temperature Correction Factorsfor Voltage Drop

Calculations

To calculate voltage drop:

1. Multiply current in amperes bythe length of the circuit in feet toget ampere-feet. Circuit length isthe distance from the point oforigin to the load end of the circuit.

2. Divide by 100.

3. Multiply by proper voltage drop

value in tables. Result is voltagedrop.

Example:

A 460V, 100 hp motor, running at 80%PF, draws 124A full-load current. It isfed by three 2/0 copper conductors insteel conduit. The feeder length is150 ft (46m). What is the voltage dropin the feeder? What is the percentagevoltage drop?

1. 124A x 150 ft (46m) = 18,600A-ft

2. Divided by 100 = 186

3. Table: 2/0 copper, magnetic conduit,80% PF = 0.0187

186 x 0.0187 = 3.48V drop3.48 x 100 = 0.76% drop460

4. Conclusion: 0.76% voltage dropis very acceptable. (See NEC 2005Article 215, which suggests that avoltage drop of 3% or less on afeeder is acceptable.)

To select minimum conductor size:

1. Determine maximum desiredvoltage drop, in volts.

2. Divide voltage drop by(amperes x circuit feet).

3. Multiply by 100.

4. Find nearest lower voltage dropvalue in tables, in correct columnfor type of conductor, conduit andpower factor. Read conductor sizefor that value.

5. Where this results in an oversizedcable, verify cable lug sizes formolded case breakers and fusibleswitches. Where lug size availableis exceeded, go to next higherrating.

Example:

A three-phase, four-wire lighting

feeder on a 208V circuit is 250 ft(76.2m) long. The load is 175A at90% PF. It is desired to use aluminumconductors in aluminum conduit. Whatsize conductor is required to limit thevoltage drop to 2% phase-to-phase?

1.

2.

3.

4. In table, under aluminum conduc-tors, nonmagnetic conduit, 90%

PF, the nearest lower value is0.0091. Conductor required is500 kcmil. (Size 4/0 THW wouldhave adequate ampacity, but thevoltage drop would be excessive.)

ConductorSize

Percent Correction

Power Factors %

100 90 80 70 60

No. 14 to No. 4No. 2 to 3/04/0 to 500 kcmil600 to 1000 kcmil

5.05.05.05.0

4.74.23.12.6

4.73.72.62.1

4.63.52.31.5

4.63.21.91.3

VD 2100−−−−−− 208 4.16V=×=

4.16175 250×−−−−−−−−−−−−−−− 0.0000951=

0.0000951 100 0.00951=×



.3-24


September 2011


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System Analysis056

Table 1.3-13. Voltage Drop—Volts per Ampere per 100 Feet (30 m); Three-Phase, Phase-to-Phase

Conductor SizeAWGor kcmil

Magnetic Conduit (Steel) Nonmagnetic Conduit (Aluminum or Nonmetallic)

Load Power Factor, % Load Power Factor, %

60 70 80 90 100 60 70 80 90 100

Copper Conductors

1412108

0.33900.21700.13900.0905

0.39100.24900.15900.1030

0.44300.28100.17900.1150

0.49400.31300.19800.1260

0.54100.34100.21500.1350

0.33700.21500.13700.0888

0.39000.24800.15800.1010

0.44100.28000.17800.1140

0.49300.31200.19700.1250

0.54100.34100.21500.1350

6421

0.05950.03990.02750.0233

0.06700.04430.03000.0251

0.07420.04850.03230.0267

0.08090.05220.03420.0279

0.08500.05340.03360.0267

0.05790.03840.02600.0218

0.06560.04300.02870.0238

0.07300.04730.03120.0256

0.08000.05130.03330.0270

0.08490.05330.03350.0266

1/02/03/04/0

0.01980.01710.01480.0130

0.02110.01800.01540.0134

0.02220.01870.01580.0136

0.02290.01900.01580.0133

0.02130.01700.01360.0109

0.01830.01560.01340.0116

0.01980.01670.01410.0121

0.02110.01760.01470.0124

0.02200.01810.01490.0124

0.02110.01690.01340.0107

250300350500

0.01220.01110.01040.0100

0.01240.01120.01040.0091

0.01240.01110.01020.0087

0.01200.01060.00960.0080

0.00940.00800.00690.0053

0.01070.00970.00900.0078

0.01110.00990.00910.0077

0.01120.00990.00910.0075

0.01100.00960.00870.0070

0.00910.00770.00660.0049

600750

1000

0.00880.0084

0.0080

0.00860.0081

0.0077

0.00820.0077

0.0072

0.00740.0069

0.0063

0.00460.0040

0.0035

0.00740.0069

0.0064

0.00720.0067

0.0062

0.00700.0064

0.0058

0.00640.0058

0.0052

0.00420.0035

0.0029Aluminum Conductors

12108

0.32960.21330.1305

0.38110.24290.1552

0.43490.27410.1758

0.48480.31800.1951

0.53300.33630.2106

0.33120.20900.1286

0.38020.24100.1534

0.43280.27400.1745

0.48480.30520.1933

0.53310.33630.2115

6421

0.08980.05950.04030.0332

0.10180.06600.04430.0357

0.11420.07470.04830.0396

0.12540.08090.05230.0423

0.13490.08620.05350.0428

0.08870.05830.03890.0318

0.10110.06540.04350.0349

0.11270.07190.04730.0391

0.12490.08000.05140.0411

0.13610.08490.05440.0428

1/02/03/04/0

0.02860.02340.02090.0172

0.03050.02460.02200.0174

0.03340.02750.02310.0179

0.03500.02840.02410.0177

0.03410.02740.02170.0170

0.02630.02270.01600.0152

0.02870.02440.01710.0159

0.03220.02640.02180.0171

0.03370.02740.02330.0179

0.03390.02730.02220.0172

250300350500

0.01580.01370.01300.0112

0.01630.01390.01330.0111

0.01620.01430.01280.0114

0.01590.01440.01310.0099

0.01450.01220.01000.0076

0.01380.01260.01220.0093

0.01440.01280.01230.0094

0.01470.01330.01190.0094

0.01550.01320.01200.0091

0.01380.01250.01010.0072

600750

1000

0.01010.00950.0085

0.01060.00940.0082

0.00970.00900.0078

0.00900.00840.0071

0.00630.00560.0043

0.00840.00810.0069

0.00850.00800.0068

0.00850.00780.0065

0.00810.00720.0058

0.00600.00510.0038




1September 2011


Sheet 01


Capacitors057

Capacitors and Power Factor

Capacitor General ApplicationConsiderations

Additional application information

is available in Tab 35 regardingcapacitors and harmonic filtersas follows:

■ Capacitor selection

■ Where to install capacitors in a plantdistribution system

■ Locating capacitors on reducedvoltage and multi-speed starters

■ Harmonic considerations

■ Eliminating harmonic problems

■ National Electrical Coderequirements

Medium Voltage

Capacitor SwitchingCapacitance switching constitutessevere operating duty for a circuitbreaker. At the time the breaker opensat near current zero, the capacitor isfully charged. After interruption, whenthe alternating voltage on the sourceside of the breaker reaches its oppositemaximum, the voltage that appearsacross the contacts of the open breakeris at least twice the normal peak line-to-neutral voltage of the circuit. If abreakdown occurs across the opencontact, the arc is re-established. Dueto the circuit constants on the supplyside of the breaker, the voltage across

the open contact can reach three timesthe normal line-to-neutral voltage.After it is interrupted and withsubsequent alternation of the supplyside voltage, the voltage across theopen contact is even higher.

ANSI Standard C37.06 (indoor oillesscircuit breakers) indicates the preferredratings of Eaton’s Type VCP-W vacuumbreaker. For capacitor switching,careful attention should be paid tothe notes accompanying the table.

The definition of the terms are in ANSIStandard C37.04 Article 5.13 (for thelatest edition). The application guideANSI/IEEE Standard C37.012 coversthe method of calculation of thequantities covered by C37.06 Standard.

Note that the definitions in C37.04make the switching of two capacitorsbanks in close proximity to the switch-gear bus a back-to-back mode ofswitching. This classification requiresa definite purpose circuit breaker(breakers specifically designed forcapacitance switching).

We recommend that such application

be referred to Eaton.A breaker specified for capacitorswitching should include as applicable:

1. Rated maximum voltage.

2. Rated frequency.

3. Rated open wire line chargingswitching current.

4. Rated isolated cable charging andshunt capacitor switching current.

5. Rated back-to-back cablecharging and back-to-backcapacitor switching current.

6. Rated transient overvoltage factor.

7. Rated transient inrush current andits frequency.

8. Rated interrupting time.

9. Rated capacitive currentswitching life.

10. Grounding of system andcapacitor bank.

Load break interrupter switches are permitted by ANSI/IEEE StandardC37.30 to switch capacitance, but theymust have tested ratings for the purpose. Refer to Eaton Type MVS ratings.

Low Voltage Capacitor SwitchingCircuit breakers and switches for usewith a capacitor must have a currentrating in excess of rated capacitorcurrent to provide for overcurrent fromovervoltages at fundamental frequency

and harmonic currents. The followingpercent of the capacitor-rated currentshould be used as a general guideline:

Fused and unfused switches. . . . 165%

Molded case breaker orequivalent . . . . . . . . . . . . . . . . . 150%

DSII power circuit breakers. . . . . 135%

Magnum DS powercircuit breaker . . . . . . . . . . . . . . 135%

Contactors:

Open type . . . . . . . . . . . . . . . . . . . 135%

Enclosed type . . . . . . . . . . . . . . . . 150%

The NEC, Section 460.8(C), requiresthe disconnecting means to be rated notless than 135% of the rated capacitorcurrent (for 600V and below).

See Tab 35 for switching deviceampere ratings. They are based onpercentage of capacitor-rated currentas indicated (above). The interruptingrating of the switch must be selectedto match the system fault currentavailable at the point of capacitorapplication. Whenever a capacitorbank is purchased with less than theultimate kVAR capacity of the rackor enclosure, the switch rating shouldbe selected based on the ultimatekVAR capacity—not the initialinstalled capacity.

Refer to Tab 35 for recommendedselection of capacitor switchingdevices; recommended maximumcapacitor ratings for various motortypes and voltages; and for requiredmultipliers to determine capacitorkVARs required for power factorcorrection.



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Capacitors058

Motor Power FactorCorrection

See Tab 35 containing suggestedmaximum capacitor ratings forinduction motors switched with the

capacitor. The data is general in natureand representative of general purposeinduction motors of standard design.The preferable means to select capacitorratings is based on the “maximumrecommended kVAR” informationavailable from the motor manufacturer.If this is not possible or feasible, thetables can be used.

An important point to rememberis that if the capacitor used with themotor is too large, self-excitationmay cause a motor-damaging over-voltage when the motor and capacitorcombination is disconnected from the

line. In addition, high transient torquescapable of damaging the motor shaftor coupling can occur if the motor isreconnected to the line while rotatingand still generating a voltage ofself-excitation.

Definitions

kVAR—rating of the capacitor inreactive kilovolt-amperes. This valueis approximately equal to the motorno-load magnetizing kilovars.

% AR—percent reduction in linecurrent due to the capacitor. Acapacitor located on the motor sideof the overload relay reduces linecurrent through the relay. Therefore, adifferent overload relay and/or setting

may be necessary. The reduction inline current may be determined bymeasuring line current with andwithout the capacitor or by calculationas follows:

If a capacitor is used with a lower kVARrating than listed in tables, the % ARcan be calculated as follows:

The tables can also be used for othermotor ratings as follows:

A. For standard 60 Hz motorsoperating at 50 Hz:

kVAR = 1.7–1.4 of kVAR listed% AR= 1.8–1.35 of % AR listed

B. For standard 50 Hz motorsoperating at 50 Hz:

kVAR = 1.4–1.1 of kVAR listed% AR= 1.4–1.05 of % AR listed

C. For standard 60 Hz wound-rotormotors:

kVAR = 1.1 of kVAR listed% AR= 1.05 of % AR listed

Note: For A, B, C, the larger multipliers

apply for motors of higher speeds; i.e.,3600 rpm = 1.7 mult., 1800 rpm = 1.65mult., etc.

To derate a capacitor used on a systemvoltage lower than the capacitorvoltage rating, such as a 240Vcapacitor used on a 208V system,use the following formula:

For the kVAC required to correct thepower factor from a given value ofCOS φ1 to COS φ2, the formula is:

kVAC = kW (tan phase1–tan phase2)

Capacitors cause a voltage rise.At light load periods the capacitivevoltage rise can raise the voltage atthe location of the capacitors to anunacceptable level. This voltage risecan be calculated approximately bythe formula:

MVAR is the capacitor rating and MVASC is the system short-circuit capacity.

With the introduction of variable speeddrives and other harmonic currentgenerating loads, the capacitorimpedance value determined mustnot be resonant with the inductivereactances of the system.

% AR 100 100(Original PF)

(Improved PF)−−−−−−−−−−−−−−−−−−−−−−−−×–=

% AR Listed % ARActual kVAR

kVAR in Table−−−−−−−−−−−−−−−−−−−−−−−−×=

Actual kVAR =

Nameplate kVAR Applied Voltage( )2

Nameplate Voltage( )2

----------------------------------------------------------------------×

% VRMVAr

MVASC

−−−−−−−−−−−−=




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Protection and Coordination059

Overcurrent Protectionand Coordination

Overcurrents in a power distributionsystem can occur as a result of bothnormal (motor starting, transformer

inrush, etc.) and abnormal (overloads,ground fault, line-to-line fault, etc.)conditions. In either case, the funda-mental purposes of current-sensingprotective devices are to detect theabnormal overcurrent and with propercoordination, to operate selectivelyto protect equipment, propertyand personnel while minimizing theoutage of the remainder of the system.With the increase in electric powerconsumption over the past fewdecades, dependence on the contin-ued supply of this power has alsoincreased so that the direct costsof power outages have risen signifi-

cantly. Power outages can createdangerous and unsafe conditions asa result of failure of lighting, elevators,ventilation, fire pumps, securitysystems, communications systems,and the like. In addition, economic lossfrom outages can be extremely highas a result of computer downtime,or, especially in industrial processplants, interruption of production.

Protective equipment must be adjustedand maintained in order to functionproperly when an overcurrent occurs,but coordination begins during powersystem design with the knowledgeable

analysis and selection and applicationof each overcurrent protective devicein the series circuit from the powersource(s) to each load apparatus. Theobjective of coordination is to localizethe overcurrent disturbance so that theprotective device closest to the faulton the power-source side has the firstchance to operate; but each precedingprotective device upstream toward thepower source should be capable, withinits designed settings of current andtime, to provide backup and de-energizethe circuit if the fault persists. Sensitivityof coordination is the degree to whichthe protective devices can minimizethe damage to the faulted equipment.

To study and accomplish coordinationrequires (a) a one-line diagram, theroadmap of the power distributionsystem, showing all protective devicesand the major or important distributionand utilization apparatus, (b) identifi-cation of desired degrees of powercontinuity or criticality of loadsthroughout system, (c) definitionof operating-current characteristics(normal, peak, starting) of eachutilization circuit, (d) equipment

damage or withstand characteristics,(e) calculation of maximum short-circuit currents (and ground faultcurrents if ground fault protection isincluded) available at each protectivedevice location, (f) understanding of

operating characteristics and availableadjustments of each protective device,(g) any special overcurrent protectionrequirements including utility limita-tions. Refer to Figure 1.4-1.

To ensure complete coordination, thetime-trip characteristics of all devicesin series should be plotted on a singlesheet of standard log-log paper.Devices of different-voltage systemscan be plotted on the same sheet byconverting their current scales, usingthe voltage ratios, to the same voltage-basis. Such a coordination plot isshown in Figure 1.4-1. In this manner,primary fuses and circuit breaker

relays on the primary side of a

substation transformer can be coordi-nated with the low voltage breakers.Transformer damage points, based onANSI standards, and low voltage cableheating limits can be plotted on thisset of curves to ensure that apparatus

limitations are not exceeded.Ground-fault curves may also beincluded in the coordination studyif ground-fault protection is provided,but care must be used in interpretingtheir meaning.

Standard definitions have beenestablished for overcurrent protectivedevices covering ratings, operationand application systems.

M—Motor (100 hp). Dashed line showsinitial inrush current, starting currentduring 9-sec. acceleration, and drop to124A normal running current, all wellbelow CBA trip curve.

Figure 1.4-1. Time-Current Characteristic Curves for Typical Power Distribution SystemProtective Devices Coordination Analysis

1000

109

7

6

.9

4

5

.5

.3

.2

10090

30

20

500

300

200

1 0 , 0

0 0

8 0 0 0

6 0 0 0

9 0 0 0

7 0 0 0

5 0 0 0

4 0 0 0

3 0 0 0

2 0 0 0

1 0 0 0

8 0 0

6 0 0

9 0 0

7 0 0

5 0 0

4 0 0

3 0 0

2 0 0

1 0 0

8 060 9 0

7 050403020109875 6431 2.9.8.7.5 . 6

600

900800700

400

40

8

50

80

60

70

3

1

2

.8

.7

.6

.4

.1.09.08.07

.06

.05

.04

.03

.02

.01

1 0 , 0

0 0

8 0 0 0

6 0 0 0

9 0 0 0

7 0 0 0

5 0 0 0

4 0 0 0

3 0 0 0

2 0 0 0

1 0 0 0

8 0 0

6 0 0

9 0 0

7 0 0

5 0 0

4 0 0

3 0 0

2 0 0

1 0 0

8 060 9 0

7 050403020109875 6431 2.9.8.7.5 .6

1000

109

7

6

.9

4

5

.5

.3

.2

10090

30

20

500

300

200

600

900800700

400

40

8

50

80

60

70

3

1

2

.8

.7

.6

.4

.1

.09

.08

.07

.06

.05

.04

.03

.02

.01

T I ME I N

S E C ON D S

SCALE X 100 = CURRENT IN AMPERES AT 480V

SCALE X 100 = CURRENT IN AMPERES AT 480V

T I M E I N S E C O N D S

250 MVA4.16 kV

250A

1000kVA

5.75%4,160V∆480/277V

19,600A

1,600A

24,400A

600A

D

C

B

A

M

20,000A

175A

100 hp –124A FLC

X = Available fault currentincluding motorcontribution.

D

ANSI Three-PhaseThru Fault

Protection Curve(More Than 10 inLifetime)

C

B

A

CB

A

B

C

TransformerInrush

GroundFault Trip

M a x .

4 8 0 V F a u l t

M a x .

T h r e e - P h a s e

4 . 1

6 k V F a u l t

M



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A—CB (175A) coordinates selectivelywith motor M on starting and runningand with all upstream devices, exceptthat CB B will trip first on low levelground faults.

B—CB (600A) coordinates selectively

with all upstream and downstreamdevices, except will trip before A onlimited ground faults, since A has noground fault trips.

C—Main CB (1600A) coordinatesselectively with all downstreamdevices and with primary fuse D,for all faults on load side of CB.

D—Primary fuse (250A, 4160V) coordi-nates selectively with all secondaryprotective devices. Curve converted to480V basis. Clears transformer inrushpoint (12 x FLC for 0.1 sec.), indicatingthat fuse will not blow on inrush.Fuse is underneath right-half of ANSIthree-phase withstand curve, indicatingfuse will protect transformer for high-magnitude faults up to ANSI rating.

Delta-wye secondary side shortcircuit is not reflected to the primaryby the relation

for L-L and L-G faults. For line-to-linefault, the secondary (low voltage) sidefault current is 0.866 x I three-phasefault current.

However, the primary (high voltage)side fault is the same as if the secondaryfault was a three-phase fault. Thereforein coordination studies, the knee of theshort-time pickup setting on the sec-ondary breaker should be multiplied by

before it is compared to the minimummelting time of the upstream primaryfuse curve. In the example shown, theknee is at 4000A 30 sec., and the 30-sec.trip time should be compared to theMMT (minimum melt time) of the fusecurve at 4000 x 1.1547 = 4619A. In this

case, there is adequate clearance tothe fuse curve.

In the example shown, the ANSIthree-phase through fault protectioncurve must be multiplied by 0.577and replotted in order to determinethe protection given by the primaryfor a single line to ground fault inthe secondary.

Maximum 480V three-phase faultindicated on the horizontal current axis.

Maximum 4160V three-phase faultindicated, converted to 480V basis.

The ANSI protection curves arespecified in ANSI C57.109 for liquid-filled transformers and C57.12.59 fordry-type transformers.

Illustrative examples such as shownhere start the coordination study fromthe lowest rated device proceedingupstream. In practice, the setting orrating of the utility’s protective devicesets the upper limit. Even in caseswhere the customer owns the mediumvoltage or higher distribution system,the setting or rating of the lowest setprotective device at the source deter-

mines the settings of the downstreamdevices and the coordination.

Therefore the coordination studyshould start at the present settingor rating of the upstream device andwork toward the lowest rated device. Ifthis procedure results in unacceptablesettings, the setting or rating of theupstream device should be reviewed.Where the utility is the sole source,they should be consulted. Where theowner has its own medium or highervoltage distribution, the settings orratings of all upstream devices shouldbe checked.

If perfect coordination is not feasible,then lack of coordination should belimited to the smallest part of the system.

Application data is available for allprotective equipment to permitsystems to be designed for adequateovercurrent protection and coordina-tion. For circuit breakers of all types,time-current curves permit selection ofinstantaneous and inverse-time trips.For more complex circuit breakers,with solid-state trip units, trip curvesinclude long- and short-time delays,as well as ground-fault tripping, with awide range of settings and features to

provide selectivity and coordination.For current-limiting circuit breakers,fuses, and circuit breakers withintegral fuses, not only are time-current characteristic curves available,but also data on current-limitingperformance and protection fordownstream devices.

In a fully rated system, all circuitbreakers must have an interruptingcapacity adequate for the maximum

available fault current at their point ofapplication. All breakers are equippedwith long-time-delay (and possiblyshort delay) and instantaneous over-current trip devices. A main breakermay have short time-delay tripping to

allow a feeder breaker to isolate thefault while power is maintained to allthe remaining feeders.

A selective or fully coordinated systempermits maximum service continuity.The tripping characteristics of eachovercurrent device in the system mustbe selected and set so that the breakernearest the fault opens to isolate thefaulted circuit, while all other breakersremain closed, continuing power tothe entire unfaulted part of the system.

The National Electrical Code contains specific requirements fordesigning certain circuits with selective

coordination. Article 100 definesselective coordination: Coordination(Selective), the following definition:“Localization of an overcurrent condi-tion to restrict outages to the circuit orequipment affected, accomplished bythe choice of overcurrent protectivedevices and their ratings or settings.”

NEC 2011 NFPA 70: National Electrical CodeInternational Electrical Code Series.

Article 620.62 (elevators, dumbwaiters,escalators, moving walks, wheelchairlifts, and stairway chair lifts) requires“Where more than one driving machinedisconnecting means is supplied by a

single feeder, the overcurrent protectivedevices in each disconnecting meansshall be selectively coordinated withany other supply side overcurrentprotective device.” A similar require-ment under Article 700.27 is as follows;“Emergency system(s) overcurrentdevices shall be selectively coordinatedwith all supply side overcurrentprotective devices.” Article 701.27states that “Legally required standbysystem(s) overcurrent devices shall beselectively coordinated with all supplyside overcurrent devices.”

Exception: Selective coordinationshall not be required between two

overcurrent devices located in series if no loads are connected in parallel with the downstream device.

In addition, for health care facilities,Article 517.26, Application of OtherArticles requires that “The essentialelectrical system shall meet therequirements of Article 700, exceptas amended by Article 517.”

IPVS

VP

−−−− IS×=

10.866−−−−−−−−− or 1.1547

I480V

I4160V

4160

480−−−−−−−− ×=




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All breakers must have an interruptingcapacity not less than the maximumavailable short-circuit current at theirpoint of application. A selectivesystem is a fully rated system withtripping devices chosen and adjusted

to provide the desired selectivity.The tripping characteristics of eachovercurrent device should not overlap,but should maintain a minimum timeinterval for devices in series (to allowfor normal operating tolerances) at allcurrent values. Generally, a maximumof four low voltage circuit breakers canbe operated selectively in series, withthe feeder or branch breaker down-stream furthest from the source.

Specify true rms sensing devices inorder to avoid false trips due to rapidcurrents or spikes. Specify trippingelements with I2t or I4t feature forimproved coordination with other

devices having I2t or I4t (such asOPTIM™ trip units) characteristicsand fuses.

In general for systems such as shownin the example:

1. The settings or ratings of theprimary side fuse and main breakermust not exceed the settingsallowed by NEC Article 450.

2. At 12 x IFL the minimum meltingtime characteristic of the fuseshould be higher than 0.1 second.

3. The primary fuse should be to theleft of the transformer damagecurve as much as possible. Thecorrection factor for a single line-to-ground factor must be appliedto the damage curve.

4. The setting of the short-time delayelement must be checked againstthe fuse MMT after it is correctedfor line-to-line faults.

5. The maximum fault current mustbe indicated at the load side ofeach protective device.

6. The setting of a feeder protectivedevice must comply with Article240 and Article 430 of the NEC.It also must allow the startingand acceleration of the largestmotor on the feeder while carryingall the other loads on the feeder.

Protection of Conductors (Excerptsfrom NFPA 70-2011, Article 240.4)

Conductors, other than flexible cordsand fixture wires, shall be protectedagainst overcurrent in accordance withtheir ampacities as specified in Section310.15, unless otherwise permitted orrequired in (A) through (G).

A. Power Loss Hazard. Conductoroverload protection shall not berequired where the interruption ofthe circuit would create a hazard,such as in a material handlingmagnet circuit or fire pump circuit.Short-circuit protection shall beprovided.

Note: FPN See NFPA 20-2003, standardfor the Installation of Stationary Pumpsfor Fire Protection.

B. Devices Rated 800A or Less. The

next higher standard overcurrentdevice rating (above the ampacityof the conductors being protected)shall be permitted to be used,provided all of the followingconditions are met.

1. The conductors being protectedare not part of a branch circuitsupplying more than one recepta-cle for cord-and-plug-connectedportable loads.

2. The ampacity of the conductorsdoes not correspond with thestandard ampere rating of a fuse ora circuit breaker without overloadtrip adjustments above its rating(but that shall be permitted to haveother trip or rating adjustments).

3. The next higher standard ratingselected does not exceed 800A.

C. Overcurrent Devices Rated Over800A. Where the overcurrentdevice is rated over 800A, theampacity of the conductors itprotects shall be equal to orgreater than the rating of theovercurrent device as defined inSection 240.6.

D. Small Conductors. Unless

specifically permitted in 240.4(E)or 240.4(G), the overcurrentprotection shall not exceed 15Afor 14 AWG, 20A for 12 AWG, and30A for 10 AWG copper; or 15Afor 12 AWG and 25A for 10 AWGaluminum and copper-cladaluminum after any correctionfactors for ambient temperatureand number of conductors havebeen applied.

E. Tap Conductors. Tap conductorsshall be permitted to be protectedagainst overcurrent in accordancewith the following:

1. 210.19(A)(3) and (A)(4) HouseholdRanges and Cooking Appliances

and Other Loads.

2. 240.5(B)(2) Fixture Wire.

3. 240.21 Location in Circuit.

4. 368.17(B) Reduction in AmpacitySize of Busway.

5. 368.17(C) Feeder or Branch Circuits(busway taps).

6. 430.53(D) Single Motor Taps.

Circuit Breaker CableTemperature Ratings

UL listed circuit breakers rated 125A or

less shall be marked as being suitablefor 60ºC (140ºF), 75ºC (167ºF) only or60/75ºC (140/167ºF) wire. All Eatonbreakers rated 125A or less are marked60/75ºC (140/167ºF). All UL listed circuitbreakers rated over 125A are suitablefor 75ºC conductors. Conductors ratedfor higher temperatures may be used,but must not be loaded to carry morecurrent than the 75ºC ampacity of thatsize conductor for equipment markedor rated 75ºC or the 60ºC ampacity ofthat size conductor for equipmentmarked or rated 60ºC. However, whenapplying derated factors, so long asthe actual load does not exceed the

lower of the derated ampacity or the75ºC or 60ºC ampacity that applies.

Zone Selective Interlocking

Trip elements equipped with zoneselective interlocking, trip withoutintentional time delay unless arestraint signal is received froma protective device downstream.Breakers equipped with this featurereduce the damage at the point offault if the fault occurs at a locationbetween the zone of protection.

The upstream breaker upon receiptof the restraint signal will not trip until

its time-delay setting times out. If thebreaker immediately downstream of thefault does not open, then after timingout, the upstream breaker will trip.

Breakers equipped with ground faulttrip elements should also be specifiedto include zone interlocking for theground fault trip element.



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Ground Fault ProtectionArticle 230.95 of NEC requires ground-fault protection of equipment shall beprovided for solidly grounded wyeelectrical services of more than 150Vto ground, but not exceeding 600V

phase-to-phase for each servicedisconnect rated 1000A or more.

The rating of the service disconnectshall be considered to be the ratingof the largest fuse that can be installedor the highest continuous current tripsetting for which the actual overcurrentdevice installed in a circuit breaker israted or can be adjusted.

The maximum allowable settings are:1200A pickup, 1 second or less tripdelay at currents of 3000A or greater.

The characteristics of the ground-faulttrip elements create coordination

problems with downstream devicesnot equipped with ground faultprotection. The National ElectricalCode exempts fire pumps andcontinuous industrial processesfrom this requirement.

It is recommended that in solidly grounded 480/277V systems where main breakers are specified to be equipped with ground fault trip elements that the feeder breakers be specified to be equipped with ground fault trip elements as well.

Suggested Ground Fault Settings

For the main devices:A ground fault pickup setting equalto 20–30% of the main breaker ratingbut not to exceed 1200A, and a timedelay equal to the delay of the short-time element, but not to exceed1 second.

For the feeder ground fault setting:A setting equal to 20–30% of the feederampacity and a time delay to coordinatewith the setting of the main (at least6 cycles below the main).

If the desire to selectively coordinateground fault devices results in settingsthat do not offer adequate damageprotection against arcing single line-ground faults, the design engineershould decide between coordinationand damage limitation.

For low voltage systems with high-magnitude available short-circuitcurrents, common in urban areas andlarge industrial installations, severalsolutions are available. High interrupt-ing Series C® molded case breakers,current-limiting circuit breakers, orcurrent-limiting fuses, limiters integralwith molded-case circuit breakers(TRI-PAC®) or mounted on powercircuit breakers (MDSL) can be used tohandle these large fault currents. Toprovide current limiting, these devicesmust clear the fault completely withinthe first half-cycle, limiting the peakcurrent (Ip) and heat energy (I2t)

let-through to considerably less thanwhat would have occurred withoutthe device. For a fully fusible system,rule-of-thumb fuse ratios or moreaccurate I2t curves can be used toprovide selectivity and coordination.For fuse-breaker combinations, thefuse should be selected (coordinated)so as to permit the breaker to handlethose overloads and faults within itscapacity; the fuse should operatebefore or with the breaker only onlarge faults, approaching the interrupt-ing capacity of the breaker, to minimizefuse blowing. Recently, unfused, trulycurrent-limiting circuit breakers with

interrupting ratings adequate for thelargest systems (Type Series C, FDC,JDC, KDC, LDC and NDC framesor Type Current Limit-R®) havebecome available.

The Series G high performance,current-limiting circuit breaker seriesoffers interrupting ratings to 200 kA.Frames are EGC, EGU, EGX, JGC,JGU, JGX, LGC, LGU and LGX.

Any of these current-limiting devices—

fuses, fused breakers or current-limit-ing breakers—cannot only clear theselarge faults safely, but also will limitthe Ip and I2t let-through significantlyto prevent damage to apparatusdownstream, extending their zoneof protection. Without the currentlimitation of the upstream device,the fault current could exceed thewithstand capability of the down-stream equipment. UnderwritersLaboratories tests and lists theseseries combinations. Applicationinformation is available forcombinations that have been testedand UL®-listed for safe operation

downstream from MDSL, TRI-PAC,and Current Limit-R, or Series Cbreakers of various ratings, underhigh available fault currents.

Protective devices in electricaldistribution systems may be properlycoordinated when the systems aredesigned and built, but that is noguarantee that they will remaincoordinated. System changes andadditions, plus power source changes,frequently modify the protectionrequirements, sometimes causing lossof coordination and even increasingfault currents beyond the ratings of

some devices. Consequently, periodicstudy of protective-device settingsand ratings is as important for safetyand preventing power outagesas is periodic maintenance of thedistribution system.




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Grounding/Ground Fault Protection063

Grounding

Grounding encompasses severaldifferent but interrelated aspects ofelectrical distribution system designand construction, all of which are

essential to the safety and properoperation of the system and equip-ment supplied by it. Among theseare equipment grounding, systemgrounding, static and lightningprotection, and connection to earthas a reference (zero) potential.

1. Equipment Grounding

Equipment grounding is essentialto safety of personnel. Its function isto ensure that all exposed noncurrent-carrying metallic parts of all structuresand equipment in or near the electricaldistribution system are at the samepotential, and that this is the zero

reference potential of the earth.Equipment grounding is requiredby both the National Electrical Code(Article 250) and the National ElectricalSafety Code regardless of how thepower system is grounded. Equipmentgrounding also provides a return pathfor ground fault currents, permittingprotective devices to operate. Acciden-tal contact of an energized conductorof the system with an improperlygrounded noncurrent-carry metallicpart of the system (such as a motorframe or panelboard enclosure) wouldraise the potential of the metal object

above ground potential. Any personcoming in contact with such an objectwhile grounded could be seriouslyinjured or killed. In addition, currentflow from the accidental grounding ofan energized part of the system could

generate sufficient heat (often witharcing) to start a fire. To prevent theestablishment of such unsafe potentialdifference requires that (1) the equip-ment grounding conductor provide areturn path for ground fault currents ofsufficiently low impedance to preventunsafe voltage drop, and (2) the equip-ment grounding conductor be largeenough to carry the maximum groundfault current, without burning off, forsufficient time to permit protectivedevices (ground fault relays, circuitbreakers, fuses) to clear the fault. Thegrounded conductor of the system(usually the neutral conductor),although grounded at the source, mustnot be used for equipment grounding.

The equipment grounding conductormay be the metallic conduit or racewayof the wiring system, or a separateequipment grounding conductor,run with the circuit conductors, aspermitted by NEC. If a separateequipment grounding conductor isused, it may be bare or insulated; ifinsulated, the insulation must be green,green with yellow stripe or green tape.Conductors with green insulation maynot be used for any purpose other thanfor equipment grounding.

The equipment grounding systemmust be bonded to the groundingelectrode at the source or service;however, it may be also connectedto ground at many other points.This will not cause problems with

the safe operation of the electricaldistribution system. Where computers,data processing, or microprocessor-based industrial process controlsystems are installed, the equipmentgrounding system must be designedto minimize interference with theirproper operation. Often, isolatedgrounding of this equipment, orisolated electrical supply systems arerequired to protect microprocessorsfrom power system “noise” that doesnot in any way affect motors or otherelectrical equipment. Such systemsmust use single-point ground conceptto minimize “noise” and still meetthe NEC requirements. Any separateisolated ground mat must be tied tothe rest of the facility ground matsystem for NEC compliance.

2. System Grounding

System grounding connects theelectrical supply, from the utility, fromtransformer secondary windings, orfrom a generator, to ground. A systemcan be solidly grounded (no intentionalimpedance to ground), impedancegrounded (through a resistance orreactance), or ungrounded (with nointentional connection to ground.

3. Medium Voltage System: GroundingTable 1.4-1. Features of Ungrounded and Grounded Systems (from ANSI C62.92)

Description AUngrounded

BSolidly Grounded

CReactance Grounded

DResistance Grounded

EResonant Grounded

(1) Apparatusinsulation

Fully insulated Lowest Partially graded Partially graded Partially graded

(2) Fault toground current

Usually low Maximum value rarelyhigher than three-phaseshort circuit current

Cannot satisfactorily bereduced below one-halfor one-third of values forsolid grounding

Low Negligible except whenPetersen coil is shortcircuited for relaypurposes when it maycompare with solidlygrounded systems

(3) Stability Usually unimportant Lower than with othermethods but can bemade satisfactory by useof high-speed breakers

Improved over solidgrounding particularlyif used at receiving endof system

Improved over solidgrounding particularlyif used at receiving endof system

Is eliminated fromconsideration duringsingle line-to-groundfaults unless neutralizeris short circuited toisolate fault by relays

(4) Relaying Difficult Satisfactory Satisfactory Satisfactory Requires specialprovisions but can bemade satisfactory

(5) Arcinggrounds

Likely Unlikely Possible if reactance isexcessive

Unlikely Unlikely

(6) Localizingfaults

Effect of fault transmittedas excess voltage onsound phases to allparts of conductivelyconnected network

Effect of faults localizedto system or part ofsystem where they occur

Effect of faults localized tosystem or part of systemwhere they occur unlessreactance is quite high

Effect of faultstransmitted as excessvoltage on sound phasesto all parts of conductivelyconnected network

Effect of faultstransmitted as excessvoltage on sound phasesto all parts of conductivelyconnected network

(7) Doublefaults

Likely Likely Unlikely unlessreactance is quite highand insulation weak

Unlikely unlessresistance is quite highand insulation weak

Seem to be more likelybut conclusive informationnot available



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Table 1.4-1. Features of Ungrounded and Grounded Systems (Continued)

Because the method of groundingaffects the voltage rise of the unfaultedphases above ground, ANSI C62.92classifies systems from the point ofview of grounding in terms of acoefficient of grounding

This same standard also definessystems as effectively grounded whenCOG ≤ .8 such a system would haveX0 /X1 ≤ 3.0 and R0 /X1 ≤ 1.0. Any othergrounding means that does not satisfythese conditions at any point in asystem is not effectively grounded.

The aforementioned definition isof significance in medium voltagedistribution systems with long linesand with grounded sources removedduring light load periods so that insome locations in the system theX

0 /X

1, R

0 /X

1may exceed the defining

limits. Other standards (cable andlightning arrester) allow the use of100% rated cables and arrestersselected on the basis of an effectivelygrounded system only where thecriteria in the above are met. Ineffectively grounded system the line-to-ground fault current is high andthere is no significant voltage rise inthe unfaulted phases.

With selective ground fault isolationthe fault current should be at least 60%

of the three-phase current at the pointof fault. Damage to cable shields mustbe checked. Although this fact is nota problem except in small cables, it isa good idea to supplement the cableshields returns of ground fault currentto prevent damage, by installing anequipment grounding conductor.

The burdens on the current transformers must be checked also (for saturationconsiderations), where residuallyconnected ground relays are usedand the current transformers supplycurrent to phase relays and meters.

If ground sensor current transformers(zero sequence type) are used theymust be of high burden capacity.

Description AUngrounded

BSolidly Grounded

CReactance Grounded

DResistance Grounded

EResonant Grounded

(8) Lightningprotection

Ungrounded neutralservice arresters must beapplied at sacrifice in cost

and efficiency

Highest efficiency andlowest cost

If reactance is very higharresters for ungroundedneutral service must be

applied at sacrifice in costand efficiency

Arresters for ungrounded,neutral service usuallymust be applied at

sacrifice in cost andefficiency

Ungrounded neutralservice arresters mustbe applied at sacrifice

in cost and efficiency

(9) Telephoneinterference

Will usually be lowexcept in cases of doublefaults or electrostaticinduction with neutraldisplaced but durationmay be great

Will be greatest inmagnitude due to higherfault currents but canbe quickly clearedparticularly with highspeed breakers

Will be reduced fromsolidly grounded values

Will be reduced fromsolidly grounded values

Will be low in magnitudeexcept in cases of doublefaults or series resonanceat harmonic frequencies,but duration may be great

(10) Radiointerference

May be quite high duringfaults or when neutralis displayed

Minimum Greater than forsolidly grounded,when faults occur

Greater than forsolidly grounded,when faults occur

May be high during faults

(11) Lineavailability

Will inherently clearthemselves if total lengthof interconnected line islow and require isolationfrom system in increas-ing percentages as lengthbecomes greater

Must be isolated foreach fault



Need not be isolated butwill inherently clear itselfin about 60 to 80 percentof faults

(12) Adaptabilityto interconnection

Cannot be interconnectedunless interconnectingsystem is ungroundedor isolating transformersare used

Satisfactory indefinitelywith reactance-groundedsystems

Satisfactory indefinitelywith solidly-groundedsystems

Satisfactory with solidly-or reactance-groundedsystems with properattention to relaying

Cannot be interconnectedunless interconnectedsystem is resonantgrounded or isolatingtransformers are used.Requires coordinationbetween interconnectedsystems in neutralizersettings

(13) Circuitbreakers

Interrupting capacitydetermined by three-phase conditions

Same interruptingcapacity as required forthree-phase short circuitwill practically always besatisfactory

Interrupting capacitydetermined by three-phase fault conditions



(14) Operatingprocedure

Ordinarily simple butpossibility of doublefaults introducescomplication in times

of trouble

Simple Simple Simple Taps on neutralizers mustbe changed when majorsystem switching is per-formed and difficulty may

arise in interconnectedsystems. Difficult to tellwhere faults are located

(15) Total cost High, unless conditionsare such that arc tendsto extinguish itself, whentransmission circuits maybe eliminated, reducingtotal cost

Lowest Intermediate Intermediate Highest unless the arcsuppressing characteris-tic is relied on to eliminatetransmission circuitswhen it may be lowestfor the particular typesof service

CO G

Highest Power Frequencyrms Line – Ground Voltage

rms Line – Line Voltage at FaultLocation with the Fault Removed

---------------------------------------------------------------------------------------------=




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Table 1.4-2 taken from ANSI-C62.92indicates the characteristics of thevarious methods of grounding.

Reactance Grounding

It is generally used in the groundingof the neutrals of generators directlyconnected to the distribution systembus, in order to limit the line-to-groundfault to somewhat less than the three-phase fault at the generator terminals.If the reactor is so sized, in all probabilitythe system will remain effectivelygrounded.

Resistance Grounded

Medium voltage systems in generalshould be low resistance grounded.The ground fault is typically limited toabout 200–400A but less than 1000A(a cable shield consideration). With aproperly sized resistor and relayingapplication, selective fault isolation

is feasible. The fault limit providedhas a bearing on whether residuallyconnected relays are used or groundsensor current transformers are usedfor ground fault relaying.

In general, where residually connectedground relays are used (51N), the faultcurrent at each grounded source

should not be limited to less than thecurrent transformers rating of thesource. This rule will provide sensitivedifferential protection for wye-connected generators and transformers againstline-to-ground faults near the neutral.

Of course, if the installation of groundfault differential protection is feasible,or ground sensor current transformersare used, sensitive differential relayingin resistance grounded system withgreater fault limitation is feasible.In general, ground sensor currenttransformers (zero sequence) do nothave high burden capacity. Resistancegrounded systems limit the circulatingcurrents of triple harmonics and limitthe damage at the point of fault. Thismethod of grounding is not suitablefor line-to-neutral connection of loads.

On medium voltage systems, 100%cable insulation is rated for phase-to-

neutral voltage. If continued operationwith one phase faulted to ground isdesired, increased insulation thick-ness is required. For 100% insulation,fault clearance is recommended withinone minute; for 133% insulation, onehour is acceptable; for indefiniteoperation, as long as necessary,173% insulation is required.

Table 1.4-2. Characteristics of Grounding

Values of the coefficient of grounding (expressed as a percentage of maximum phase-to-phasevoltage) corresponding to various combinations of these ratios are shown in the ANSI C62.92Appendix figures. Coefficient of grounding affects the selection of arrester ratings.

Ground-fault current in percentage of the three-phase short-circuit value. Transient line-to-ground voltage, following the sudden initiation of a fault in per unit of the crest

of the prefault line-to-ground operating voltage for a simple, linear circuit. In linear circuits, Class A1 limits the fundamental line-to-ground voltage on an unfaulted phase to

138% of the prefault voltage; Class A2 to less than 110%. See ANSI 62.92 para. 7.3 and precautions given in application sections. Usual isolated neutral (ungrounded) system for which the zero-sequence reactance is capacitive

(negative). Same as NOTE (6) and refer to ANSI 62.92 para. 7.4. Each case should be treated on its own merit. Under restriking arcing ground fault conditions (e.g., vacuum breaker interrupter operation),

this value can approach 500%. Under arcing ground fault conditions, this value can easily reach 700%, but is essentially unlimited.

Grounding Classesand Means

Ratios of SymmetricalComponent Parameters

Percent FaultCurrent

Per Unit TransientLG Voltage

A. Effectively➃1. Effective

2. Very effective

X0 /X1

0-3

0-1

R0 /X1

0-1

0-0.1

R0 /X0

—

—

>60

>95

≤2

<1.5

B. Noneffectively1. Inductance

a. Low inductanceb. High inductance

2. Resistancea. Low resistanceb. High resistance

3. Inductance and resistance4. Resonant5. Ungrounded/capacitance

a. Range Ab. Range B

3-10>10

0-10—>10

-∞ to -40

-40 to 0

0-1—

—>100——

——

—<2

≥2≤(-1)>2—

——

>25<25

<25<1<10<1

<8>8

<2.3≤2.73

<2.5≤2.73≤2.73≤2.73

≤3

>3

Grounding Point

The most commonly used groundingpoint is the neutral of the system or theneutral point created by means of azigzag or a wye-broken delta groundingtransformer in a system that was oper-

ating as an ungrounded delta system.In general, it is a good practice that allsource neutrals be grounded with thesame grounding impedance magnitude.However, neutrals should not be tiedtogether to a single resistor. Whereone of the medium voltage sources isthe utility, their consent for impedancegrounding must be obtained.

The neutral impedance must have avoltage rating at least equal to the ratedline-to-neutral voltage class of the sys-tem. It must have at least a 10-secondrating equal to the maximum futureline-to-ground fault current and a

continuous rating to accommodate thetriple harmonics that may be present.

4. Low Voltage System: Grounding

Solidly grounded three-phase systems(Figure 1.4-2) are usually wye-connected, with the neutral pointgrounded. Less common is the “red-leg” or high-leg delta, a 240V systemsupplied by some utilities with onewinding center-tapped to provide 120Vto ground for lighting. This 240V, three-phase, four-wire system is used where120V lighting load is small comparedto 240V power load, because theinstallation is low in cost to the utility.A corner-grounded three-phase deltasystem is sometimes found, withone phase grounded to stabilize allvoltages to ground. Better solutionsare available for new installations.

Figure 1.4-2. Solidly Grounded Systems

•

• • ••

Phase B

Phase CPhase A

Neutral

Center-Tapped (High-Leg) Delta

Grounded Wye

•

•• •

• Phase C

Phase APhase B

Neutral

N

• Phase A

Phase BPhase C•

• •

Corner-Grounded Delta



.4-10


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Ungrounded systems (Figure 1.4-3)can be either wye or delta, althoughthe ungrounded delta system is farmore common.

Figure 1.4-3. Ungrounded Systems

Resistance-grounded systems(Figure 1.4-4) are simplest with awye connection, grounding the neutralpoint directly through the resistor.Delta systems can be grounded bymeans of a zig-zag or other groundingtransformer. Wye broken deltatransformer banks may also be used.

Figure 1.4-4. Resistance-Grounded Systems

This derives a neutral point, whichcan be either solidly or impedance-grounded. If the grounding transformerhas sufficient capacity, the neutralcreated can be solidly grounded andused as part of a three-phase, four-wiresystem. Most transformer-suppliedsystems are either solidly groundedor resistance grounded. Generatorneutrals are often grounded througha reactor, to limit ground fault (zerosequence) currents to values thegenerator can withstand.

Selecting the Low Voltage SystemGrounding Method

There is no one “best” distributionsystem for all applications. In choosingamong solidly grounded, resistancegrounded, or ungrounded power

distribution, the characteristics of thesystem must be weighed against therequirements of power loads, lightingloads, continuity of service, safetyand cost.

Under ground fault conditions, eachsystem behaves very differently. Asolidly grounded system produceshigh fault currents, usually with arcing,and the faulted circuit must be clearedon the first fault within a fraction of asecond to minimize damage. Anungrounded system will pass limitedcurrent into the first ground fault—only the charging current of the system,caused by the distributed capacitanceto ground of the system wiring andequipment. In low voltage systems,this is rarely more than 1 or 2A.Therefore, on first ground fault, anungrounded system can continue inservice, making it desirable wherepower outages cannot be tolerated.However, if the ground fault isintermittent, sputtering or arcing, ahigh voltage—as much as 6 to 8 timesphase voltage—can be built up acrossthe system capacitance, from thephase conductors to ground. Similarhigh voltages can occur as a resultof resonance between systemcapacitance and the inductancesof transformers and motors in thesystem. The phase-to-phase voltageis not affected. This high transientphase-to-ground voltage can punctureinsulation at weak points, such asmotor windings, and is a frequentcause of multiple motor failures onungrounded systems. Locating a firstfault on an ungrounded system canbe difficult. If, before the first fault iscleared, a second ground fault occurson a different phase, even on adifferent, remote feeder, it is a high-current phase-to-ground-to-phasefault, usually arcing, that can causesevere damage if at least one of the

grounds is not cleared immediately.If the second circuit is remote, enoughcurrent may not flow to causeprotection to operate. This can leavehigh voltages and stray currents onstructures and jeopardize personnel.

In general, where loads will beconnected line-to-neutral, solidlygrounded systems are used. Highresistance grounded systems are

used as substitutes for ungroundedsystems where high systemavailability is required.

With one phase grounded, the voltageto ground of the other two phasesrises 73%, to full phase-to-phase

voltage. In low voltage systems thisis not important, since conductorsare insulated for 600V.

A low voltage resistance groundedsystem is normally grounded so thatthe single line-to-ground fault currentexceeds the capacitive chargingcurrent of the system. If data for thecharging current is not available, use40–50 ohm resistor in the neutralof the transformer.

In commercial and institutional installations, such as office buildings,shopping centers, schools and hospitals, lighting loads are often 50% or moreof the total load. In addition, a feederoutage on first ground fault is seldomcrucial—even in hospitals, that haveemergency power in critical areas. Forthese reasons, a solidly grounded wye distribution, with the neutral used forlighting circuits, is usually the mosteconomical, effective and convenientdesign. In some instances, it is anNEC requirement.

In industrial installations, the effectof a shutdown caused by a singleground fault could be disastrous.An interrupted process could causethe loss of all the materials involved,

often ruin the process equipmentitself, and sometimes create extremelydangerous situations for operatingpersonnel. On the other hand, lightingis usually only a small fraction of thetotal industrial electrical load. A solidlygrounded neutral circuit conductoris not imperative and, when required,can be obtained from inexpensivelighting transformers.

Because of the ability to continue inoperation with one ground fault onthe system, many existing industrialplants use ungrounded delta distribu-tion. Today, new installations can haveall the advantages of service continuityof the ungrounded delta, yet minimizethe problems of the system, suchas the difficulty of locating the firstground fault, risk of damage from asecond ground fault, and damagetransient overvoltages. A high-resistance grounded wye distributioncan continue in operation with aground fault on the system and willnot develop transient overvoltages.

Phase B•

Phase A

Phase C• •

Ungrounded Delta

Ungrounded Wye

•• •

• Phase C

Phase APhase B

N

•

Resistance-Grounded Wye

• •

• Phase C

Phase APhase B

RN

• • Phase A

••

•

•

Phase B

Phase C

• •

Delta With Derived Neutral Resistance-Grounded Using Zig-Zag Transformer

•R

N




1.4September 2011


Sheet 01



And, because the ground point isestablished, locating a ground fault isless difficult than on an ungroundedsystem especially when a “pulsingcontactor” design is applied. Whencombined with sensitive ground-fault

protection, damage from a secondground fault can be nearly eliminated.Ungrounded delta systems can beconverted to high-resistance groundedsystems, using a zig-zag or othergrounding transformer to derive aneutral, with similar benefits, seeTab 36. While the majority ofmanufacturing plants use solidlygrounded systems, in many instances,the high-resistance grounded distribu-tion will be the most advantageous.

Ground Fault Protection

A ground fault normally occurs in oneof two ways: by accidental contact of

an energized conductor with normallygrounded metal, or as a result ofan insulation failure of an energizedconductor. When an insulation failureoccurs, the energized conductorcontacts normally noncurrent-carryinggrounded metal, which is bonded toor part of the equipment groundingconductor. In a solidly groundedsystem, the fault current returns to thesource primarily along the equipmentgrounding conductors, with a smallpart using parallel paths such as build-ing steel or piping. If the ground returnimpedance was as low as that of thecircuit conductors, ground fault currents

would be high, and the normal phaseovercurrent protection would clearthem with little damage. Unfortunately,the impedance of the ground returnpath is usually higher, the fault itselfis usually arcing and the impedanceof the arc further reduces the faultcurrent. In a 480Y/277V system, thevoltage drop across the arc can befrom 70 to 140V. The resulting groundfault current is rarely enough to causethe phase overcurrent protectiondevice to open instantaneously andprevent damage. Sometimes, theground fault is below the trip setting ofthe protective device and it does not

trip at all until the fault escalates andextensive damage is done. For thesereasons, low level ground protectiondevices with minimum time delaysettings are required to rapidly clearground faults. This is emphasized bythe NEC requirement that a groundfault relay on a service shall have amaximum delay of one second forfaults of 3000A or more.

The NEC (Sec. 230.95) requires thatground fault protection, set at no morethan 1200A, be provided for each service

disconnecting means rated 1000A ormore on solidly grounded wye servicesof more than 150V to ground, butnot exceeding 600V phase-to-phase.Practically, this makes ground faultprotection mandatory on 480Y/277V

services, but not on 208Y/120V services.On a 208V system, the voltage toground is 120V. If a ground faultoccurs, the arc goes out at currentzero, and the voltage to ground isoften too low to cause it to restrike.Therefore, arcing ground faults on208V systems tend to be self-extin-guishing. On a 480V system, with 277Vto ground, restrike usually takes placeafter current zero, and the arc tends tobe self-sustaining, causing severe andincreasing damage, until the fault iscleared by a protective device.

The NEC requires ground faultprotection on the service disconnecting

means. This protection works so fastthat for ground faults on feeders, oreven branch circuits, it will often openthe service disconnect before thefeeder or branch circuit overcurrentdevice can operate. This is highlyundesirable, and in the NEC (230.95)a Fine Print Note (FPN) states thatadditional ground fault protectiveequipment will be needed on feedersand branch circuits where maximumcontinuity of electric service is neces-sary. Unless it is acceptable to discon-nect the entire service on a groundfault almost anywhere in the system,such additional stages of ground

fault protection must be provided.At least two stages of protection aremandatory in health care facilities(NEC Sec. 517.17).

Overcurrent protection is designed toprotect conductors and equipmentagainst currents that exceed theirampacity or rating under prescribedtime values. An overcurrent can resultfrom an overload, short circuit or (highlevel) ground fault condition. Whencurrents flow outside the normalcurrent path to ground, supplementaryground fault protection equipment willbe required to sense low-level ground

fault currents and initiate the protectionrequired. Normal phase overcurrentprotection devices provide no protectionagainst low-level ground faults.

There are three basic means of sensingground faults. The most simple anddirect method is the ground returnmethod as illustrated in Figure 1.4-5.This sensing method is based on the fact that all currents supplied by a trans-former must return to that transformer.

Figure 1.4-5. Ground Return Sensing Method

When an energized conductor faultsto grounded metal, the fault currentreturns along the ground return path tothe neutral of the source transformer.This path includes the main bondingjumper as shown in Figure 1.4-5.A current sensor on this conductor(which can be a conventional bar-type

or window type CT) will respond toground fault currents only. Normalneutral currents resulting fromunbalanced loads will return alongthe neutral conductor and will not bedetected by the ground return sensor.

This is an inexpensive method of sensing ground faults where protection perNEC (230.95) is desired. For it tooperate properly, the neutral must begrounded in only one place as indicatedin Figure 1.4-5. In many installations,the servicing utility grounds the neutralat the transformer and additionalgrounding is required in the serviceequipment per NEC (250.24(A)(2)).In such cases, and others includingmultiple source with multiple, inter-connected neutral ground points,residual or zero sequence groundsensing methods should be employed.

A second method of detecting groundfaults involves the use of a zerosequence sensing method, as illus-trated in Figure 1.4-6. This sensingmethod requires a single, speciallydesigned sensor either of a toroidalor rectangular shaped configuration.This core balance current transformersurrounds all the phase and neutralconductors in a typical three-phase,

four-wire distribution system. Thesensing method is based on the factthat the vectorial sum of the phase andneutral currents in any distributioncircuit will equal zero unless a groundfault condition exists downstream fromthe sensor. All currents that flow onlyin the circuit conductors, includingbalanced or unbalanced phase-to-phaseand phase-to-neutral normal or faultcurrents, and harmonic currents, willresult in zero sensor output.

Main

GFR

Neutral

TypicalFeeder

Sensor

Main BondingJumper

EquipmentGroundingConductor

GroundingElectrodeConductor

Typical4W Load

ServiceTransformer

Ground Bus



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However, should any conductor becomegrounded, the fault current will returnalong the ground path—not the normalcircuit conductors—and the sensor willhave an unbalanced magnetic fluxcondition, and a sensor output will

be generated to actuate the groundfault relay.

Figure 1.4-6. Zero Sequence Sensing Method

Zero sequence sensors are availablewith various window openings forcircuits with small or large conductors,and even with large rectangular win-dows to fit over bus bars or multiplelarge size conductors in parallel. Somesensors have split cores for installationover existing conductors withoutdisturbing the connections.

This method of sensing ground faultscan be employed on the main discon-nect where protection per NEC (230.95)is desired. It can also be easily employed in multi-tier systems where additional

levels of ground fault protection aredesired for added service continuity.Additional grounding points may beemployed upstream of the sensor, butnot on the load side.

Ground fault protection employingground return or zero sequence sensingmethods can be accomplished by theuse of separate ground fault relays(GFRs) and disconnects equipped withstandard shunt trip devices or by circuitbreakers with integral ground faultprotection with external connectionsarranged for these modes of sensing. Insome cases, a reliable source of controlpower is needed.

The third basic method of detectingground faults involves the use ofmultiple current sensors connected ina residual sensing method as illustratedin Figure 1.4-7. This is a very commonsensing method used with circuit break-ers equipped with electronic trip units,current sensors and integral groundfault protection. The three-phase sensors are required for normal phase overcur-rent protection. Ground fault sensingis obtained with the addition of anidentically rated sensor mounted on the

ZeroSequenceSensor

Main

Neutral

TypicalFeeder

AlternateSensorLocation

Typical4W Load

GFR

neutral. In a residual sensing scheme,the relationship of the polarity markings—as noted by the “X” on each sensor—is critical. Because the vectorial sum ofthe currents in all the conductors willtotal zero under normal, non-ground

faulted conditions, it is imperativethat proper polarity connections areemployed to reflect this condition.

Figure 1.4-7. Residual Sensing Method

As with the zero sequence sensingmethod, the resultant residual sensoroutput to the ground fault relay orintegral ground fault tripping circuitwill be zero if all currents flow onlyin the circuit conductors. Should aground fault occur, the current fromthe faulted conductor will return alongthe ground path, rather than on theother circuit conductors, and the resid-ual sum of the sensor outputs will notbe zero. When the level of ground faultcurrent exceeds the pre-set current

and time delay settings, a groundfault tripping action will be initiated.

This method of sensing ground faultscan be economically applied on mainservice disconnects where circuit break-ers with integral ground fault protectionare provided. It can be used in protec-tion schemes per NEC (230.95) or inmulti-tier schemes where additional

levels of ground fault protection aredesired for added service continuity.Additional grounding points may beemployed upstream of the residualsensors, but not on the load side.

Both the zero sequence and

residual sensing methods havebeen commonly referred to as“vectorial summation” methods.

Most distribution systems can useeither of the three sensing methodsexclusively or a combination of thesensing methods depending uponthe complexity of the system andthe degree of service continuity andselective coordination desired.Different methods will be requireddepending upon the number of supplysources, and the number and locationof system grounding points.

As an example, one of the morefrequently used systems wherecontinuity of service to critical loadsis a factor is the dual source systemillustrated in Figure 1.4-8. This systemuses tie-point grounding as permittedunder NEC Sec. 250.24(A)(3). The useof this grounding method is limitedto services that are dual fed (double-ended) in a common enclosure orgrouped together in separate enclosures,employing a secondary tie.

This scheme uses individual sensorsconnected in ground return fashion.Under tie breaker closed operatingconditions, either the M1 sensor or

M2 sensor could see neutral unbalancecurrents and possibly initiate animproper tripping operation. However,with the polarity arrangements ofthese two sensors along with the tiebreaker auxiliary switch (T/a) andinterconnections as shown, thispossibility is eliminated.

Figure 1.4-8. Dual Source System—Single Point Grounding

GFR

Typical4W Load

SensorPolarityMarks

Neutral

TypicalFeeder

Main

ResidualSensors

Typical4-WireFeeder

4-WireLoad

Neutral

ØA, ØB, ØC

PowerTransformer

PowerTransformer

4-WireLoad

Typical4-WireFeeder

Neutral

ØA, ØB, ØC

33-52-T

52-Ta

52-Ta

Tie Bkr.52-T

Neutral SensorMain Bkr. 52-2

Neutral SensorTie Bkr. 52-T

Neutral SensorMain Bkr. 52-1

DigitripMain Bkr.52-1

MainBkr.52-2

MainBkr.52-1

Digitrip

DigitripMain Bkr.52-2 Digitrip

B4 B5

B5 B4 B4 B5 B4 B5

B4 B5

( )B4

( )B5

M 1 N

M 1 G

M 2 G

M 2 N

T G

T N

( )B4

( )B5

DigitripMain Bkr.52-2




1.4September 2011


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Selective ground fault tripping coordi-nation between the tie breaker and thetwo main circuit breakers is achievedby pre-set current pickup and timedelay settings between devices GFR/1,GFR/2 and GFR/T.

The advantages of increased servicecontinuity offered by this system canonly be effectively used if additionallevels of ground fault protection areadded on each downstream feeder.Some users prefer individual groundingof the transformer neutrals. In suchcases, a partial differential groundfault scheme should be used for themains and tie breaker.

An example of a residual partial differ-ential scheme is shown in Figure 1.4-9.The scheme typically relies upon thevector sum of at least two neutralsensors in combination with each

breakers’ three-phase sensors. Toreduce the complexity of the drawing,each of the breakers’ three-phasesensors have not been shown. It isabsolutely critical that the sensors’polarities are supplied as shown, theneutral sensor ratings of the mains andtie are the same, and that there areno other grounds on the neutral busmade downstream of points shown.

An infinite number of ground faultprotection schemes can be developeddepending upon the number of alternate sources, the number of grounding points and system interconnections involved.Depending upon the individual system

configuration, either mode of sensing

or a combination of all types may beemployed to accomplish the desiredend results.

Because the NEC (230.95) limits themaximum setting of the ground faultprotection used on service equipment

to 1200A (and timed tripping at 3000Afor one second), to prevent trippingof the main service disconnect on afeeder ground fault, ground faultprotection must be provided on all thefeeders. To maintain maximum servicecontinuity, more than two levels (zones)of ground fault protection will berequired, so that ground fault outagescan be localized and service interrup-tion minimized. To obtain selectivitybetween different levels of groundfault relays, time delay settings shouldbe employed with the GFR furthestdownstream having the minimumtime delay. This will allow the GFR

nearest the fault to operate first.With several levels of protection, thiswill reduce the level of protection forfaults within the upstream GFR zones.Zone interlocking was developed forGFRs to overcome this problem.

GFRs (or circuit breakers with integralground fault protection) with zoneinterlocking are coordinated in asystem to operate in a time delayedmode for ground faults occurring mostremote from the source. However, thistime delayed mode is only actuatedwhen the GFR next upstream from thefault sends a restraining signal to the

upstream GFRs. The absence of arestraining signal from a downstream

Figure 1.4-9. Dual Source System—Multiple Point Grounding

Trip UnitMain Breaker

52-1

Trip UnitTie Breaker

52-T

PowerTransformer

52-Ta

52-2a

Neutral SensorTie Breaker 52-T

X

X

TypicalFour-WireFeeder T

r i p U n i t

Four-Wire Load

X

X

52-1a

Neutral Neutral

Tie Breaker52-T

NeutralSensor MainBreaker 52-1

XX

X

X

MainBreaker52-1

Phase A,Phase B,Phase C

Trip UnitMain Breaker

52-2

TypicalFour-WireFeeder T

r i p U n i t

Four-Wire Load

X

X

Phase A,Phase B,Phase C

PowerTransformer

NeutralSensor MainBreaker 52-2 Main

Breaker52-2

GFR is an indication that any occurringground fault is within the zone of theGFR next upstream from the fault andthat device will operate instantaneouslyto clear the fault with minimum dam-age and maximum service continuity.

This operating mode permits all GFRsto operate instantaneously for a faultwithin their zone and still providecomplete selectivity between zones.The National Electrical ManufacturersAssociation (NEMA) states, in theirapplication guide for ground faultprotection, that zone interlocking isnecessary to minimize damage fromground faults. A two-wire connectionis required to carry the restrainingsignal from the GFRs in one zone tothe GFRs in the next zone.

Circuit breakers with integral groundfault protection and standard circuitbreakers with shunt trips activated

by the ground fault relay are ideal forground fault protection. Many fusedswitches over 1200A, and Eaton TypeFDP fusible switches with ratings from400 to 1200A, are listed by UL as suitable for ground fault protection. Fusibleswitches so listed must be equippedwith a shunt trip, and be able toopen safely on faults up to 12 timestheir rating.

Power distribution systems differwidely from each other, dependingupon the requirements of each user,and total system overcurrent protec-tion, including ground fault currents,

must be individually designed to meetthese needs. Experienced and knowl-edgeable engineers must consider thepower sources (utility or on-site), theeffects of outages and costs of down-time, safety for people and equipment,initial and lifecycle costs, and manyother factors. They must apply protec-tive devices, analyzing the time-currentcharacteristics, fault interruptingcapacity, and selectivity and coordina-tion methods to provide the most safeand cost-effective distribution system.

Further Information

■ PRSC-4E—System Neutral Ground-ing and Ground Fault Protection(ABB Publication)

■ PB 2.2—NEMA Application Guidefor Ground Fault Protective Devicesfor Equipment

■ IEEE Standard 142—Grounding ofIndustrial and Commercial PowerSystems (Green Book)

■ IEEE Emerald Book (Standard 1100)

■ UL 96A, Installation Requirementsfor Lightning Protection Systems



.4-14


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Lightning and Surge ProtectionPhysical protection of buildingsfrom direct damage from lightningis beyond the scope of this section.Requirements will vary with geographiclocation, building type and environ-

ment, and many other factors (seeIEEE/ANSI Standard 142, Groundingof Industrial and Commercial PowerSystems). Any lightning protectionsystem must be grounded, and thelightning protection ground must bebonded to the electrical equipmentgrounding system.

Grounding Electrodes

At some point, the equipment andsystem grounds must be connectedto the earth by means of a groundingelectrode system.

Outdoor substations usually use a

ground grid, consisting of a number ofground rods driven into the earth andbonded together by buried copperconductors. The required groundingelectrode system for a building isspelled out in the NEC Article 250.

The preferred grounding electrodeis a metal underground water pipe indirect contact with the earth for at least10 ft (3m). However, because under-ground water piping is often plasticoutside the building, or may later bereplaced by plastic piping, the NECrequires this electrode to be supple-mented by and bonded to at least one

other grounding electrode, such asthe effectively grounded metal frameof the building, a concrete-encasedelectrode, a copper conductor groundring encircling the building, or a madeelectrode such as one or more drivenground rods or a buried plate. Whereany of these electrodes are present,they must be bonded together intoone grounding electrode system.

One of the most effective groundingelectrodes is the concrete-encasedelectrode, sometimes called the Uferground, named after the man whodeveloped it. It consists of at least20 ft (6m) of steel reinforcing bars or

rods not less than 1/2 inches (12.7 mm)in diameter, or at least 20 ft (6m) ofbare copper conductor, size No. 4 AWGor larger, encased in at least 2 inches(50.8 mm) of concrete. It must belocated within and near the bottom ofa concrete foundation or footing thatis in direct contact with the earth. Testshave shown this electrode to providea low-resistance earth ground even inpoor soil conditions.

The electrical distribution system andequipment ground must be connectedto this grounding electrode system bya grounding electrode conductor. Allother grounding electrodes, such asthose for the lightning protection sys-

tem, the telephone system, televisionantenna and cable TV system grounds,and computer systems, must be bondedto this grounding electrode system.

Medium Voltage Equipment SurgeProtection Considerations

Transformers

If the voltage withstand/BIL rating ofthe transformer is less than that of theswitchgear feeding the transformer,surge protection is recommended atthe transformer terminals, in line withestablished practices. In addition,consideration should be given to using

surge arresters and/or surge capacitorsfor transformers having equal orgreater withstand/BIL ratings than thatof the switchgear feeding the trans-former for distribution systems wherereflected voltage waves and/or reso-nant conditions may occur. Typicallyincoming voltage surges are reflectedat the transformer primary terminals(because of the change in impedance)resulting in voltages at the ends of thetransformer primary terminals/wind-ings of up to two times the incomingvoltage wave. System capacitance andinductance values combined with thetransformer impedance values can

cause resonant conditions resultingin amplified reflected waves. Surgearresters/capacitors when required,should be located as close to the trans-former primary terminals as practical.

Motors

Surge capacitors and, where appropri-ate, surge arresters should be appliedat the motor terminals.

Generators

Surge capacitors and stationclass surge arresters at the machineterminals.

Surge ProtectionEaton’s VacClad-W metal-clad switch-gear is applied over a broad range ofcircuits, and is one of the many typesof equipment in the total system. Thedistribution system can be subject to

voltage transients caused by lightingor switching surges.

Recognizing that distribution systemcan be subject to voltage transientscaused by lighting or switching, theindustry has developed standards toprovide guidelines for surge protectionof electrical equipment. Those guide-lines should be used in design andprotection of electrical distributionsystems independent of the circuitbreaker interrupting medium. Theindustry standards are:

ANSI C62Guides and Standards for Surge

Protection

IEEE 242—Buff BookIEEE Recommended Practice for Protection and Coordination of Industrial and Commercial Power Systems

IEEE 141—Red BookRecommended Practice for Electric Power Distribution for Industrial Plants

IEEE C37.20.2Standards for Metal-Clad Switchgear

Eaton’s medium voltage metal-clad

and metal-enclosed switchgear thatuses vacuum circuit breakers is appliedover a broad range of circuits. It is oneof the many types of equipment in thetotal distribution system. Whenever aswitching device is opened or closed,certain interactions of the powersystem elements with the switchingdevice can cause high frequency voltagetransients in the system. Due to thewide range of applications and varietyof ratings used for different elementsin the power systems, a given circuitmay or may not require surge protec-tion. Therefore, Eaton does not includesurge protection as standard with its

metal-clad or metal-enclosed mediumvoltage switchgear. The user exercisesthe options as to the type and extentof the surge protection necessarydepending on the individual circuitcharacteristics and cost considerations.

The following are Eaton’s recommen-dations for surge protection of mediumvoltage equipment. Please note theserecommendations are valid whenusing Eaton’s vacuum breakers only.




1.4September 2011


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Surge Protection RecommendationsNote: The abbreviation ZORC® used in thetext below refers to Surge Protection Devicemanufactured by Strike Technology (Pty)Ltd. An equivalent device offered by othermanufacturers, such as Type EHZ by ABB,and Protec Z by Northern Technologies SA

can also be used.

1. For circuits exposed to lightning,surge arresters should be appliedin line with Industry standardpractices.

2. Transformers

a. Close-Coupled to mediumvoltage primary breaker:Provide transients surge pro-tection, such as Surge Arresterin parallel with RC Snubber, orZORC. The surge protectiondevice selected should belocated and connected at the

transformer primary terminalsor it can be located inside theswitchgear and connected onthe transformer side of theprimary breaker.

b. Cable-Connected to mediumvoltage primary breaker:Provide transient surge protec-tion, such as Surge Arrester inparallel with RC Snubber, orZORC for transformers con-nected by cables with lengthsup to 75 feet. The surge protec-tion device should be locatedand connected at the trans-former terminals. No surgeprotection is needed for trans-formers with lightning impulsewithstand ratings equal to thatof the switchgear and connectedto the switchgear by cables atleast 75 feet or longer. Fortransformers with lower BIL,provide surge arrester in parallelwith RC Snubber or ZORC.

RC Snubber and/or ZORC dampinternal transformer resonance:

The natural frequency of transformerwindings can under some circumstances be excited to resonate. Transformerwindings in resonance can produce

elevated internal voltages that produceinsulation damage or failure. An RCSnubber or a ZORC applied at thetransformer terminals as indicatedabove can damp internal windingresonance and prevent the productionof damaging elevated internal voltages.This is typically required where rectifiers, UPS or similar electronic equipment ison the transformer secondary.

3. Arc-Furnace Transformers—Provide Surge Arrester in parallelwith RC Snubber, or ZORC at thetransformer terminals.

4. Motors—Provide Surge Arrester inparallel with RC Snubber, or ZORCat the motor terminals. For thosemotors using VFDs, surge protec-tion should be applied and pre-cede the VFD devices as well.

5. Generators—Provide station classSurge Arrester in parallel with RCSnubber, or ZORC at the generatorterminals.

6. Capacitor Switching—No surgeprotection is required. Make surethat the capacitor’s lightningimpulse withstand rating is equalto that of the switchgear.

7. Shunt Reactor Switching—

Provide Surge Arrester in parallelwith RC Snubber, or ZORC at thereactor terminals.

8. Motor Starting Reactors or ReducedVoltage Auto-Transformers—Provide Surge Arrester in parallelwith RC Snubber, or ZORC at thereactor or RVAT terminals.

9. Switching Underground Cables—Surge protection not needed.

Types of Surge Protection Devices

Generally surge protective devicesshould be located as closely as possible

to the circuit component(s) that requireprotection from the transients, andconnected directly to the terminals ofthe component with conductors thatare as short and flat as possible tominimize the inductance. It is alsoimportant that surge protection devicesshould be properly grounded foreffectively shunting high frequencytransients to ground.

Figure 1.4-10. Surge Protection Devices



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Surge Arresters

The modern metal-oxide surgearresters are recommended becausethis latest advance in arrester designensures better performance and highreliability of surge protection schemes.

Manufacturer’s technical data mustbe consulted for correct applicationof a given type of surge arrester.Notice that published arrester MCOV(Maximum Continuous OperatingVoltage) ratings are based on 40º or45ºC ambient temperature. In general,the following guidelines are recom-mended for arrester selections, wheninstalled inside Eaton’s mediumvoltage switchgear:

A. Solidly Grounded Systems:Arrester MCOV rating should beequal to 1.05 x VLL /(1.732 x T),where VLL is nominal line-to-lineservice voltage, 1.05 factor allowsfor +5% voltage variation abovethe nominal voltage accordingto ANSI C84.1, and T is deratingfactor to allow for operation at55ºC switchgear ambient, whichshould be obtained from thearrester manufacturer for the typeof arrester under consideration.Typical values of T are: 0.946 to 1.0.

B. Low Resistant Grounded Systems(systems grounded throughresistor rated for 10 seconds):Arrester 10-second MCOV capability at 60ºC, which is obtained frommanufacturer’s data, should be

equal to 1.05 x VLL, where VLL isnominal line-to-line service voltage, and 1.05 factor allows for +5%voltage variation above thenominal voltage.

C. Ungrounded or SystemsGrounded through impedanceother than 10-second resistor:Arrester MCOV rating should beequal to 1.05 x VLL /T, where VLL and T are as defined above.

Refer to Table 1.4-3 for recommendedratings for metal-oxide surge arrestersthat are sized in accordance with theabove guidelines, when located in

Eaton’s switchgear.

Surge Capacitors

Metal-oxide surge arresters limit themagnitude of prospective surge over-voltage, but are ineffective in control-ling its rate of rise. Specially designedsurge capacitors with low internal

inductance are used to limit the rate ofrise of this surge overvoltage to protectturn-to-turn insulation. Recommendedvalues for surge capacitors are: 0.5 µfon 5 and 7.5 kV, 0.25 µf on 15 kV, and0.13 µf on systems operating at 24 kVand higher.

RC Snubber

A RC Snubber device consists of anon-inductive resistor R sized to matchsurge impedance of the load cables,typically 20 to 30 ohms, and connectedin series with a Surge Capacitor C. TheSurge Capacitor is typically sized to be0.15 to 0.25 microfarad. Under normal

operating conditions, impedance ofthe capacitor is very high, effectively“isolating” the resistor R from thesystem at normal power frequencies,and minimizing heat dissipation duringnormal operation. Under high frequencytransient conditions, the capacitoroffers very low impedance, thus effec-tively “inserting” the resistor R in thepower system as cable terminatingresistor, thus minimizing reflection ofthe steep wave-fronts of the voltagetransients and prevents voltage dou-bling of the traveling wave. The RCSnubber provides protection againsthigh frequency transients by absorb-ing and damping and the transients.Please note RC Snubber is most effec-tive in mitigating fast-rising transientvoltages, and in attenuating reflectionsand resonances before they have achance to build up, but does not limitthe peak magnitude of the transient.Therefore, the RC Snubber alone maynot provide adequate protection. Tolimit peak magnitude of the transient,application of surge arrester shouldalso be considered.

ZORC

A ZORC device consists of parallelcombination of Resistor (R) and ZincOxide Voltage Suppressor (ZnO), con-nected in series with a Surge Capacitor.The resistor R is sized to match surge

impedance of the load cables, typically20 to 30 ohms. The ZnO is a gaplessmetal-oxide nonlinear arrester, setto trigger at 1 to 2 PU voltage, where1 PU = 1.412*(VL-L /1.732). The SurgeCapacitor is typically sized to be 0.15to 0.25 microfarad. As with RC Snubber,under normal operating conditions,impedance of the capacitor is veryhigh, effectively “isolating” the resistorR and ZnO from the system at normalpower frequencies, and minimizingheat dissipation during normal opera-tion. Under high frequency transientconditions, the capacitor offers verylow impedance, thus effectively

“inserting” the resistor R and ZnO inthe power system as cable terminatingnetwork, thus minimizing reflection ofthe steep wave-fronts of the voltagetransients and prevents voltage dou-bling of the traveling wave. The ZnOelement limits the peak voltage magni-tudes. The combined effects of R, ZnO,and Capacitor of the ZORC deviceprovides optimum protection againsthigh frequency transients by absorbing,damping, and by limiting the peakamplitude of the voltage wave-fronts.Please note that the ZORC is not alightning protection device. If lightningcan occur or be induced in the electrical

system, a properly rated and appliedsurge arrester must precede the ZORC.




1.4September 2011


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Surge Protection SummaryMinimum protection: Surge Arresterfor protection from high overvoltagepeaks, or Surge Capacitor for protec-tion from fast-rising transient. Pleasenote that the surge arresters or surge

capacitor alone may not provideadequate surge protection fromescalating voltages caused by circuitresonance. Note that when applyingsurge capacitors on both sides of acircuit breaker, surge capacitor onone side of the breaker must beRC Snubber or ZORC, to mitigatepossible virtual current chopping.

Good protection: Surge Arresterin parallel with Surge Capacitor forprotection from high overvoltagepeaks and fast rising transient. Thisoption may not provide adequatesurge protection from escalating

voltages caused by circuit resonance.When applying surge capacitors onboth sides of a circuit breaker, surgecapacitor on one side of the breakermust be RC Snubber or ZORC,to mitigate possible virtualcurrent chopping.

Better protection: RC Snubber inparallel with Surge Arrester forprotection from high frequencytransients and voltage peaks.

Best protection: ZORC, plus propersurge arrester preceding ZORC whereneeded for protection against lightning.ZORC provides protection from highfrequency voltage transients and limitspeak magnitude of the transient to

1 to 2 PU (see ZORC description onPage 1.4-16 for more detail). Surgearrester provides protection fromhigher voltage peaks resulting fromlightning surges.

Further Information

■ IEEE/ANSI Standard 142—GroundingIndustrial and Commercial PowerSystems (Green Book)

■ IEEE Standard 241—Electric PowerSystems in Commercial Buildings(Gray Book)

■ IEEE Standard 141—Electric PowerDistribution for Industrial Plants(Red Book)

Table 1.4-3. Surge Arrester Selections—Recommended Ratings

ServiceVoltageLine-to-LinekV

Distribution Class Arresters Station Class Arresters

SolidlyGrounded System

Low ResistanceGrounded System

High Resistance orUngrounded System

SolidlyGrounded System

Low ResistanceGrounded System

High Resistance orUngrounded System

Arrester Ratings kV Arrester Ratings kV

Nominal MCOV Nominal MCOV Nominal MCOV Nominal MCOV Nominal MCOV Nominal MCOV

2.302.403.30

333

2.552.552.55

333

2.552.552.55

366

2.555.105.10

333

2.552.552.55

333

2.552.552.55

366

2.555.105.10

4.004.164.76

366

2.555.105.10

666

5.105.105.10

669

5.105.107.65

366

2.555.105.10

666

5.105.105.10

669

5.105.107.65

4.806.606.90

666

5.105.105.10

666

5.105.105.10

999

7.657.657.65

666

5.105.105.10

669

5.105.107.65

999

7.657.657.65

7.20

8.328.40

6

99

5.10

7.657.65

6

99

5.10

7.657.65

10

1212

8.40

10.2010.20

6

99

5.10

7.657.65

9

99

7.65

7.657.65

10

1212

8.40

10.2010.20

11.0011.5012.00

99

10

7.657.658.40

91010

7.658.408.40

151818

12.7015.3015.30

99

10

7.657.658.40

101212

8.4010.2010.20

151818

12.7015.3015.30

12.4713.2013.80

101212

8.4010.2010.20

121212

10.2010.2010.20

181818

15.3015.3015.30

101212

8.4010.2010.20

121215

10.2010.2012.70

181818

15.3015.3015.30

14.4018.0020.78

121518

10.2012.7015.30

121518

10.2012.7015.30

212730

17.0022.0024.40

121518

10.2012.7015.30

151821

12.7015.3017.00

212730

17.0022.0024.40

22.0022.8623.00

181818

15.3015.3015.30

182121

15.3017.0017.00

30——

24.40——

181818

15.3015.3015.30

212424

17.0019.5019.50

303636

24.4029.0029.00

24.9425.8026.40

212121

17.0017.0017.00

242424

19.5019.5019.50

———

———

212121

17.0017.0017.00

242427

19.5019.5022.00

363639

29.0029.0031.50

33.00

34.5038.00

27

3030

22.00

24.4024.40

30

30—

24.40

24.40—

—

——

—

——

27

3030

22.00

24.4024.40

36

3636

29.00

29.0029.00

45

48—

36.50

39.00—



.4-18


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Power Quality074

Power Quality TermsTechnical Overview

Introduction

Sensitive electronic loads deployed

today by users require strict require-ments for the quality of power deliveredto loads.

For electronic equipment, powerdisturbances are defined in terms ofamplitude and duration by the elec-tronic equipment operating envelope.Electronic loads may be damagedand disrupted, with shortened lifeexpectancy, by disturbances.

The proliferation of computers, variablefrequency motor drives, UPS systemsand other electronically controlledequipment is placing a greater demandon power producers for a disturbance-

free source of power. Not only do thesetypes of equipment require qualitypower for proper operation; manytimes, these types of equipment arealso the sources of power disturbancesthat corrupt the quality of power in agiven facility.

Power quality is defined accordingto IEEE Standard 1100 as the conceptof powering and grounding electronicequipment in a manner that is suitableto the operation of that equipment.IEEE Standard 1159 notes that “withinthe industry, alternate definitions orinterpretations of power quality have

been used, reflecting different pointsof view.”

In addressing power quality problemsat an existing site, or in the designstages of a new building, engineersneed to specify different services ormitigating technologies. The lowestcost and highest value solution isto selectively apply a combinationof different products and servicesas follows:

Key services/technologies in the“power quality” industry:

■ Power quality surveys, analysisand studies

■ Power monitoring

■ Grounding products and services

■ Surge protection

■ Voltage regulation

■ Harmonic solutions

■ Lightning protection (ground rods,hardware, etc.)

■ Uninterruptible power supply (UPS)or motor-generator (M-G) set

Defining the Problem

Power quality problems can be resolvedin three ways: by reducing the variationsin the power supply (power distur-bances), by improving the load equip-ment’s tolerance to those variations, or

by inserting some interface equipment(known as power conditioning equip-ment) between the electrical supplyand the sensitive load(s) to improve thecompatibility of the two. Practicalityand cost usually determine the extentto which each option is used.

Many methods are used to definepower quality problems. For example,one option is a thorough on-siteinvestigation, which includes inspectingwiring and grounding for errors,monitoring the power supply forpower disturbances, investigatingequipment sensitivity to power distur-bances, and determining the loaddisruption and consequential effects(costs), if any. In this way, the powerquality problem can be defined,alternative solutions developed,and optimal solution chosen.

Before applying power-conditioningequipment to solve power qualityproblems, the site should be checkedfor wiring and grounding problems.Sometimes, correcting a relativelyinexpensive wiring error, such as aloose connection or a reversed neutraland ground wire, can avoid a moreexpensive power conditioning solution.

Sometimes this approach is not practical because of limitations in time; expenseis not justified for smaller installations;monitoring for power disturbancesmay be needed over an extendedperiod of time to capture infrequentdisturbances; the exact sensitivities ofthe load equipment may be unknownand difficult to determine; and finally,the investigative approach tends tosolve only observed problems. Thusunobserved or potential problemsmay not be considered in the solution.For instance, when planning a newfacility, there is no site to investigate.Therefore, power quality solutions areoften implemented to solve potentialor perceived problems on a preventivebasis instead of a thorough on-siteinvestigation.

Another option is to buy power condi-tioning equipment to correct any andall perceived power quality problemswithout any on-site investigation.

Power Quality Terms

Power disturbance: Any deviationfrom the nominal value (or from someselected thresholds based on loadtolerance) of the input AC powercharacteristics.

Total harmonic distortion or distortionfactor: The ratio of the root-mean-square of the harmonic content to theroot-mean-square of the fundamentalquantity, expressed as a percentageof the fundamental.

Crest factor: Ratio between thepeak value (crest) and rms value ofa periodic waveform.

Apparent (total) power factor: The

ratio of the total power input in wattsto the total volt-ampere input.

Sag: An rms reduction in the ACvoltage, at the power frequency, forthe duration from a half-cycle to a fewseconds. An undervoltage would havea duration greater than several seconds.

Interruption: The complete loss ofvoltage for a time period.

Transient: A sub-cycle disturbancein the AC waveform that is evidencedby a sharp brief discontinuity of thewaveform. May be of either polarityand may be additive to or subtractive

from the nominal waveform.

Surge or impulse: See transient.

Noise: Unwanted electrical signalsthat produce undesirable effectsin the circuits of control systemsin which they occur.

Common-mode noise: The noisevoltage that appears equally and inphase from each current-carryingconductor to ground.

Normal-mode noise: Noise signalsmeasurable between or among activecircuit conductors feeding the subjectload, but not between the equipmentgrounding conductor or associatedsignal reference structure and the activecircuit conductors.




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Power Quality075

Methodology for Ensuring EffectivePower Quality to Electronic Loads

The power quality pyramid is aneffective guide for addressing powerquality problems at an existing facility.The framework is also effective for

specifying engineers who are design-ing a new facility. Power quality startswith grounding (the base of thepyramid) and then moves upwardto address the potential issues. Thissimple, yet proven methodology,will provide the most cost-effectiveapproach. As we move higher up thepyramid, the cost per kVA of mitigatingpotential problems increase and thequality of the power increases (referto Figure 1.4-11).

Figure 1.4-11. Power Quality Pyramid

1. Grounding

Grounding represents the foundationof a reliable power distributionsystem. Grounding and wiringproblems can be the cause of up to80% of all power quality problems.All other forms of power qualitysolutions are dependent upon goodgrounding procedures.

5. Uninterruptible Power Supply(UPS, Gen. Sets, etc.)

4. Harmonic Distortion

3. Voltage Regulation

2. Surge Protection

1. Grounding

C o s t P e r k V A

The proliferation of communicationand computer network systemshas increased the need for propergrounding and wiring of AC and data/ communication lines. In addition toreviewing AC grounding and bonding

practices, it is necessary to preventground loops from affecting the signalreference point.

2. Surge ProtectionSurge protection devices (SPDs)are recommended as the next stagepower quality solutions. NFPA,UL 96A, IEEE Emerald Book andequipment manufacturers recommendthe use of surge protectors. TheSPD shunt short duration voltagedisturbances to ground, therebypreventing the surge from affectingelectronic loads. When installed aspart of the facility-wide design, SPDs

are cost-effective compared to allother solutions (on a $/kVA basis).

The IEEE Emerald Book recommendsthe use of a two-stage protectionconcept. For large surge currents,diversion is best accomplished intwo stages: the first diversion shouldbe performed at the service entranceto the building. Then, any residualvoltage resulting from the actioncan be dealt with by a secondprotective device at the powerpanel of the computer room(or other critical loads).

The benefit of implementing cascadednetwork protection is shown inFigure 1.4-12. Combined, the twostages of protection at the serviceentrance and branch panel locationsreduce the IEEE 62.41 recommended

test wave (C3–20 kV, 10 kA) to less than200V voltage, a harmless disturbancelevel for 120V rated sensitive loads.

If only building entrance feederprotection were provided, the let-through voltage will be approximately950V in a 277/480V system exposedto induced lightning surges. Thislevel of let-through voltage can causedegradation or physical damage ofmost electronic loads.

Wherever possible, consultants,specifiers and application engineersshould ensure similar loads are fedfrom the same source. In this way,

disturbance-generating loads areseparated from electronic circuitsaffected by power disturbances. Forexample, motor loads, HVAC systemsand other linear loads should beseparated from the sensitive processcontrol and computer systems.

The most effective and economicsolution for protecting a large numberof loads is to install parallel SPDs atthe building service entrance feederand panelboard locations. This reducesthe cost of protection for multiplesensitive loads.

Figure 1.4-12. Cascaded Network Protection

Input—high energytransient disturbance; IEEE CategoryC3 Impulse 20,000V; 10,000A

Two stage (cascadeapproach) achieves best

possible protection (lessthan 200V at Stage 2)

Best achievableperformance with single SPDat main panel (950V, at Stage 1)

25 uS 50 uSTIME (MICROSECONDS)

20,000V

800V

400V

0

CP

SPD

SPD

480V 120/208V

Stage 1 Protection(Service Entrance) Stage 2 Protection

(Branch Location)

Computer orSensitive

Loads

System Test Parameters:

IEEE C62.41[10] and C62.45 [10]

test procedures using category;480V main entrance panels;

100 ft (30m) of three-phase wire;480/208V distribution transformer;

and 208V branch panel.= SPD

P E A K V O L T A G E



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Power Quality076

The recommended system approachfor installing SPDs is summarized inFigure 1.4-13.

Figure 1.4-13. System Approach for Installing SPDs

There may be specific critical loadswithin a facility that require a higherlevel of protection. A series SPD is bestsuited for protecting such loads.

Advantages of the system approach are:

■ The lowest possible investmentin mitigating equipment to protecta facility

■ Building entrance SPDs protectthe facility against large externaltransients, including lightning

■ SPDs are bi-directional and preventtransient and noise disturbancesfrom feeding back within a system

when installed at distribution orbranch panels

■ Two levels of protection safeguardsensitive loads from physicaldamage or operational upset

Side-Mounted SPD vs. Integral SPD

Directly connecting the surge sup-presser to the bus bar of electricaldistribution equipment results inthe best possible level of protection.Compared to side-mounted devices,connecting the SPD unit to the busbar eliminates the need for lead wiresand reduces the let-through voltageup to 50% (see Figure 1.4-14).

Given that surges are high frequencydisturbances, the inductance of theinstallation wiring increases thelet-through voltage of the protectivedevice. Figure 1.4-15 shows thatfor every inch of lead length, thelet-through voltage is increased byan additional 15–25V above themanufacturers stated suppressionperformance.

Lead length has the greatest effect onthe actual level of protection realized.Twisting of the installation wires isthe second most important installationconsideration. By twisting the installa-

tion wires, the area between wires isreduced and the mutual inductanceaffect minimized.

Increasing the diameter of the installation wires is of negligible benefit. Induc-tance is a “skin effect” phenomenon and

a function of wire circumference. Sinceonly a marginal reduction in inductanceis achieved when the diameter of theinstallation conductors is increased,the use of large diameter wire resultsin only minimal improvement (seeFigure 1.4-15).

Further benefits provided by integratedsurge suppression designs are theelimination of field installation costs andthe amount of expensive “outboard”wall space taken up by side-mountedSPD devices.

Building Entrance Feeder InstallationConsiderations

Installing an SPD device immediatelyafter the switchgear or switchboardmain breaker is the optimal locationfor protecting against external distur-bances such as lightning. When placedin this location, the disturbance is“intercepted” by the SPD and reducedto a minimum before reaching thedistribution and/or branch panel(s).

The use of a disconnect breakereliminates the need to de-energizethe building entrance feeder equip-ment should the SPD fail or requireisolation for Megger testing.

Figure 1.4-14. Performance Comparison of Side-Mounted vs. Integrated SPD

1.Identify Critical Loads

2.Identify Non-Critical Loads

3.Identify Noise and

Disturbance Generating Loads

4.Review Internal Power Distribution Layout

5.Identify Facility Exposure to

Expected Levels of Disturbance

6.Apply Mitigating Equipment to:a) Service Entrance Main Panelsb) Key Sub-Panelsc) Critical Loadsd) Data and Communication Lines

\

G R O U N D

G

N

G R O U N D

G

NSPD

208Y/120 Panelboard(integrated versus side mounted SPD)

Side-Mounted SPD Device(assuming 14-inch (355.6 mm) lead length to bus)

Integrated SPD(direct bus bar connection)

SurgeEvent

Microseconds

SPD

Side-Mounted SPDused for RetrofitApplications

SPD Integratedinto Panelboards,Switchboards, MCCs

1000

800

600

400

200

0

–200–2.00 0.00 2.00 4.00 6.00 8.00 10.00

L e t - T h r o u g h V o l t a g e a t B u s B a r




1.4September 2011


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Power Quality077

Figure 1.4-15. The Effect of Installation Lead Length on Let-Through Voltage Additional to UL 1449 ratings.

The size or capacity of a suppressor ismeasured in surge current per phase.Larger suppressers rated at approxi-mately 250 kA per phase should beinstalled at the service entrance to

survive high-energy surges associatedwith lightning.

A 250 kA per phase surge rating allowsfor over a 25-year life expectancyassuming an IEEE defined highexposure environment. Lower surgerating devices may be used; however,device reliability and long-termperformance may be compromised.

For aerial structures, the 99.8 percentilerecorded lightning stroke current isless than 220 kA. The magnitude ofsurges conducted or induced into afacility electrical distribution system isconsiderably lower given the presence

of multiple paths for the surge to travelalong. It is for this reason that IEEEC62.41 recommends the C3 (20 kV,10 kA) test wave for testing SPDsinstalled at building entrance feeders.

SPDs with surge ratings greater than250 kA are not required, however, higherratings are available and may providelonger life.

Installing Panelboard SurgeProtection Devices

Smaller surge capacity SPDs (120 kAper phase) are installed at branch pan-elboards where power disturbancesare of lower energy, but occur muchmore frequently. This level of surgecurrent rating should result in agreater than 25-year life expectancy.

When isolated ground systems areused, the SPD should be installed suchthat any common mode surges areshunted to the safety ground.

The use of a disconnect breaker isoptional. The additional let-throughvoltage resulting from the increasedinductance caused by the disconnect

switch is about 50–60V. This increasein disturbance voltage can result inprocess disruption and downtime.

Installing Dataline Surge Protection

Most facilities also have communica-tion lines that are potential sourcesfor external surges. As identified bythe power quality pyramid, propergrounding of communication lines isessential for dependable operation.NEC Article 800 states that all data,power and cable lines be groundedand bonded.

Power disturbances such as lightningcan elevate the ground potentialbetween two communicating piecesof electronic equipment with differentground references. The result is currentflowing through the data cable, causingcomponent failure, terminal lock-up,

data corruption and interference.

NFPA 780 D—4.8 warns that “surgesuppression devices should be installedon all wiring entering or leaving elec-tronic equipment, usually power, dataor communication wiring.”

Surge suppressers should be installedat both ends of a data or communica-tion cable. In those situations whereone end of the cable is not connectedinto an electronic circuit (e.g., contactorcoil), protection on the electronic endonly is required.

To prevent the coupling or inducing of

power disturbances into communication lines, the following should be avoided:

■ Data cables should not be run overfluorescent lighting fixtures

■ Data cables should not be in thevicinity of electric motors

■ The right category cable shouldbe used to ensure transmissionperformance

■ Data cables must be grounded atboth ends when communicatingbetween buildings

14 AWG

10 AWG

4 AWG

0100200300400500600700800900

209V (23%)

673V (75%)

A d d i t i o n a l L e t - T h r o u g h V o l t a g e ➀

Loose Wiring Twisted Wires

3 ft (914.4 mm)Lead Length

1 ft (304.8 mm)Lead Length,Twisted Wires

Additional Let-Through Voltage Using IEEE C1(6000V, 3000A)[3]Waveform (UL 1449 Test Wave)[12]

Reference Tab 34 for detailedinformation on SPDs.

3. Voltage RegulationVoltage regulation (i.e., sags or over-voltage) disturbances are generally

site- or load-dependent. A variety ofmitigating solutions are availabledepending upon the load sensitivity,fault duration/magnitude and thespecific problems encountered. It isrecommended to install monitoringequipment on the AC power lines toassess the degree and frequency ofoccurrences of voltage regulationproblems. The captured data will allowfor the proper solution selection.

4. Harmonics Distortion

Harmonics and Nonlinear Loads

Until recently, most electrical loads were

linear. Linear loads draw the full sinewave of electric current at its 60 cycle(Hz) fundamental frequency—Figure1.4-16 shows balance single-phase,linear loads. As the figure shows,little or no current flows in the neutralconductor when the loads are non-linear and balanced.

With the arrival of nonlinear electronicloads, where the AC voltage is con-verted to a DC voltage, harmonics arecreated because of the use of only partof the AC sine wave. In this conversionfrom AC to DC, the electronics are turned on in the 60 cycle wave at a given pointin time to obtain the required DC level.The use of only part of the sign wavecauses harmonics.

It is important to note that the currentdistortion caused by loads such as rec-tifiers or switch mode power suppliescauses the voltage distortion. Thatvoltage distortion is caused by distortedcurrents flowing through an impedance.The amount of voltage distortiondepends on:

■ System impedance

■ Amount of distorted current

Devices that can cause harmonic

disturbances include rectifiers, thrust-ers and switching power supplies, allof which are nonlinear. Further, theproliferation of electronic equipmentsuch as computers, UPS systems,variable speed drives, programmablelogic controllers, and the like: non-linear loads have become a significantpart of many installations. Other typesof harmonic-producing loads includearcing devices (arc furnaces, fluores-cent lights) and iron core storabledevices (transformers, especiallyduring energization).



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Power Quality078

Nonlinear load currents vary widelyfrom a sinusoidal wave shape; oftenthey are discontinuous pulses. Thismeans that nonlinear loads areextremely high in harmonic content.

Triplen harmonics are the 3rd, 9th,

15th,...harmonics. Further, triplenharmonics are the most damagingto an electrical system because theseharmonics on the A-phase, B-phaseand C-phase are in sequence with eachother. Meaning, the triplen harmonics

present on the three phases addtogether in the neutral, as shown inFigure 1.4-17, rather than cancel eachother out, as shown in Figure 1.4-16.Odd non-triplen harmonics areclassified as “positive sequence”or “negative sequence” and are the1st, 5th, 7th, 11th, 13th, etc.

In general, as the order of a harmonicgets higher, its amplitude becomessmaller as a percentage of the funda-mental frequency.

Figure 1.4-16. Balanced Neutral Current Equals Zero

Figure 1.4-17. Unbalanced Single-Phase Loads with Triplen Harmonics

A Phase

B Phase

C Phase

60 Hz Fundamental

BalanceNeutralCurrent

120ºLagging

120ºLagging

A Phase

B Phase

C Phase

60 Hz Fundamental

NeutralTriplenCurrent

120ºLagging

120ºLagging

3rd Harmonic

Phase Triplen HarmonicsAdded in the Neutral

à

Harmonic Issues

Harmonic currents perform no workand result in wasted electrical energythat may over burden the distributionsystem. This electrical overloadingmay contribute to preventing an

existing electrical distribution systemfrom serving additional future loads.

In general, harmonics present ona distribution system can have thefollowing detrimental effects:

1. Overheating of transformers androtating equipment.

2. Increased hysteresis losses.

3. Decreased kVA capacity.

4. Overloading of neutral.

5. Unacceptable neutral-to-groundvoltages.

6. Distorted voltage and currentwaveforms.

7. Failed capacitor banks.

8. Breakers and fuses tripping.

9. Double or ever triple sized neutralsto defy the negative effects oftriplen harmonics.

In transformers, generators anduninterruptible power supplies (UPS)systems, harmonics cause overheatingand failure at loads below their ratingsbecause the harmonic currents causegreater heating than standard 60 Hzcurrent. This results from increased

eddy current losses, hysteresis lossesin the iron cores, and conductor skineffects of the windings. In addition,the harmonic currents acting on theimpedance of the source causeharmonics in the source voltage, whichis then applied to other loads such asmotors, causing them to overheat.

The harmonics also complicate theapplication of capacitors for powerfactor correction. If, at a given harmonicfrequency, the capacitive impedanceequals the system reactive impedance,the harmonic voltage and current canreach dangerous magnitudes. At thesame time, the harmonics createproblems in the application of powerfactor correction capacitors, theylower the actual power factor. Therotating meters used by the utilities forwatthour and various measurementsdo not detect the distortion componentcaused by the harmonics. Rectifierswith diode front ends and large DC sidecapacitor banks have displacementpower factor of 90% to 95%. Morerecent electronic meters are capableof metering the true kVA hours takenby the circuit.




1.4September 2011


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Power Quality079

Single-phase power supplies forcomputer and fixture ballasts arerich in third harmonics and theirodd multiples.

Even with the phase currents perfectlybalanced, the harmonic currents in

the neutral can total 173% of thephase current. This has resulted inoverheated neutrals. The InformationTechnology Industry Council (ITIC)formerly known as CBEMA, recom-mends that neutrals in the supply toelectronic equipment be oversizedto at least 173% of the ampacity ofthe phase conductors to preventproblems. ITIC also recommendsderating transformers, loading themto no more than 50% to 70% of theirnameplate kVA, based on a rule-of-thumb calculation, to compensatefor harmonic heating effects.

In spite of all the concerns theycause, nonlinear loads will continueto increase. Therefore, the design ofnonlinear loads and the systems thatsupply them will have to be designedso that their adverse effects are greatlyreduced. Table 1.4-4 shows the typicalharmonic orders from a variety ofharmonic generating sources.

Table 1.4-4. Source and Typical Harmonics

Generally, magnitude decreases as harmonicorder increases.

Total Harmonic DistortionRevised standard IEEE 519-1992 indicates the limits of current distor-tion allowed at the PCC (Point ofCommon Coupling) point on thesystem where the current distortion

is calculated, usually the point ofconnection to the utility or the mainsupply bus of the system.

The standard also covers the harmoniclimits of the supply voltage from theutility or cogenerators.

Table 1.4-5. Low Voltage System Classificationand Distortion Limits for 480V Systems

Special systems are those where the rateof change of voltage of the notch might

mistrigger an event. AN is a measurementof notch characteristics measured involt-microseconds, C is the impedanceratio of total impedance to impedanceat common point in system. DF isdistortion factor.

Table 1.4-6. Utility or Cogenerator SupplyVoltage Harmonic Limits

Percentages are x 100 for eachharmonic

and

It is important for the system designerto know the harmonic content of theutility’s supply voltage because it willaffect the harmonic distortion ofthe system.

Table 1.4-7. Current Distortion Limits forGeneral Distribution Systems (120– 69,000V)

All power generation equipment is limitedto these values of current distortion,regardless of actual ISC /IL where:ISC = Maximum short-circuit current at PCC.IL = Maximum demand load current(fundamental frequency component) at PCC.

TDD = Total Demand Distortion. Evenharmonics are limited to 25% of the oddharmonic limits above. Current distortionsthat result in a DC offset, e.g., half-waveconverters, are not allowed.

Harmonic Solutions

In spite of all the concerns nonlinearloads cause, these loads will continueto increase. Therefore, the designof nonlinear loads and the systemsthat supply them will need design soadverse harmonic effects are greatlyreduced. Table 1.4-8 and depicts manyharmonic solutions along with theiradvantages and disadvantages.

Eaton’s Engineering Services &Systems Group (EESS) can performharmonic studies and recommendsolutions for harmonic problems.

Source TypicalHarmonics

6-pulse rectifier12-pulse rectifier18-pulse rectifier

5, 7, 11, 13, 17, 19…11, 13, 23, 25…17, 19, 35, 37…

Switch-mode powersupplyFluorescent lightsArcing devicesTransformer energization

3, 5, 7, 9, 11, 13…3, 5, 7, 9, 11, 13…2, 3, 4, 5, 7…2, 3, 4

Class C AN DF

Special application

General systemDedicated system

1052

16,40022,80036,500

3%5%

10%

VoltageRange

2.3–69 kV 69–138 kV >138 kV

Maximumindividualharmonic

3.0% 1.5% 1.0%

Totalharmonicdistortion

5.0% 2.5% 1.5%

Vh

V1

−−−−

Vthd =

h = hmax

h = 2

V2h

1/2

∑

Maximum Harmonic Current Distortion inPercent of IL

Individual Harmonic Order (Odd Harmonics)

ISC/IL <11 11

h<17

17

h<23

23

h<35

35

h

TDD

<20

20<5050<100

100<1000>1000

4.07.0

10.012.015.0

2.03.54.55.57.0

1.52.54.05.06.0

0.61.01.52.02.5

0.30.50.71.01.4

5.08.0

12.015.020.0

< < < <



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Power Quality080

Table 1.4-8. Harmonic Solutions for Given Loads

LoadType

Solutions Advantages Disadvantages

Drives and rectifiers—includes three-phaseUPS loads

Line reactors ■ Inexpensive

■ For 6-pulse standard drive/rectifier, canreduce harmonic current distortion from

80% down to about 35–40%

■ May require additional compensation

K-rated/drive isolationtransformer

■ Offers series reactance (similar to linereactors) and provides isolation forsome transients

■ No advantage over reactors forreducing harmonics unless in pairsfor shifting phases

DC choke ■ Slightly better than AC line reactorsfor 5th and 7th harmonics

■ Not always an option for drives

■ Less protection for input semiconductors

12-pulse convertor ■ 85% reduction versus standard6-pulse drives

■ Cost difference approaches 18-pulse driveand blocking filters, which guaranteeIEEE 519 compliance

Harmonic mitigatingtransformers/phase shifting

■ Substantial (50–80%) reduction in harmonicswhen used in tandem

■ Harmonic cancellation highly dependenton load balance

■ Must have even multiples of matched loads

Tuned filters ■ Bus connected—accommodatesload diversity

■ Provides PF correction

■ Requires allocation analysis

■ Sized only to the requirements of that system;must be resized if system changes

Broadband filters ■ Makes 6-pulse into the equivalentof 18-pulse

■ Higher cost

■ Requires one filter per drive

18-pulse converter ■ Excellent harmonic control for drivesabove 100 hp

■ IEEE 519 compliant

■ High cost

Active filters ■ Handles load/harmonic diversity

■ Complete solution up to 50th harmonic

■ High cost

Computers/ switch-modepower supplies

Neutral blocking filter ■ Eliminates the 3rd harmonic from load

■ Relieves system capacity

■ Possible energy savings

■ High cost

■ May increase voltage distortion

Harmonic mitigatingtransformers

■ 3rd harmonic recalculated back to the load

■ When used as phase-shifted transformers,reduces other harmonics

■ Reduces voltage “flat-topping”

■ Requires fully rated circuits andoversized neutrals to the loads

Oversized neutral/deratedtransformer

■ Tolerate harmonics rather than correct

■ Typically least expensive

■ Upstream and downstream equipmentfully rated for harmonics

K-rated transformer ■ Tolerate harmonics rather than correct ■ Does not reduce system harmonics

Fluorescentlighting


■ 3rd harmonic recalculated back to the load■ When used as phase-shifted transformers,

reduces other harmonics

■ Reduces voltage “flat-topping”

■ Requires fully rated circuits andoversized neutrals to the loads

K-rated transformer ■ Tolerate harmonics rather than correct them ■ Does not reduce system harmonics

Low distortion ballasts ■ Reduce harmonics at the source ■ Additional cost and typically moreexpensive than “system” solutions

Welding/arcingloads

Active filters ■ Fast response and broadbandharmonic correction

■ Reduces voltage flicker

■ High cost

Tuned filters ■ SCR controlled tuned filters simulatesan active filter response

■ SCR controlled units are high costbut fixed filters are reasonable

Systemsolutions

Tuned filters ■ Provides PF correction

■ Lower cost compared to other systems

■ System analysis required to verify application.Must be resized if system changes


■ Excellent choice for new design or upgrade ■ No PF correction benefit

Active filters ■ Ideal solution and handles system diversity ■ Highest cost




1.4September 2011


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Uninterruptible Power Systems (UPS)081

5. Uninterruptible PowerSystems (UPS)

The advent of solid-state semiconduc-tors over 40 years ago, and theirsubsequent evolution to transistors,and the miniaturization of electronicsinto microprocessor over 25 years ago,has created numerous computationmachines that assist us in everyconceivable manner. These machines,and their clever configurations,whether they take the form ofcomputers, appliance controls, faxmachines, phone systems, computersof all sizes, server systems and serverfarms, emergency call centers, dataprocessing at banks, credit companies,private company communicationnetworks, government institutions anddefense agencies, all rely on a narrowrange of nominal AC power in orderfor these devices to work properly.Indeed, many other types of equip-ment also require that the AC electricalpower source be at or close to nominalvoltage and frequency. Disturbancesof the power translate into failedprocesses, lost data, decreasedefficiency and lost revenue.

The normal power source supplied bythe local utility or provider is not stableenough over time to continuouslyserve these loads without interruption.It is possible that a facility outside amajor metropolitan area served by the

utility grid will experience outages ofsome nature 15–20 times in one year.Certain outages are caused by theweather, and others by the failureof the utility supply system due toequipment failures or constructioninterruptions. Some outages areonly several cycles in duration, whileothers may be for hours at a time.

In a broader sense, other problemsexist in the area of power quality, andmany of those issues also contributeto the failure of the supply to providethat narrow range of power to thesensitive loads mentioned above.Power quality problems take the

form of any of the following: powerfailure, power sag, power surge,undervoltage, overvoltage, line noise,frequency variations, switchingtransients and harmonic distortion.Regardless of the reason for outagesand power quality problems, thesensitive loads can not functionnormally without a backup powersource, and in many cases, the loadsmust be isolated from the instabilitiesof the utility supply and power qualityproblems and given clean reliablepower on a continuous basis, or beable to switch over to reliable cleanelectrical power quickly.

Uninterruptible power supply (UPS)systems have evolved to serve theneeds of sensitive equipment andcan supply a stable source of electricalpower, or switch to backup to allowfor an orderly shutdown of the loads

without appreciable loss of data orprocess. In the early days of main-frame computers, motor-generatorsets provide isolation and clean powerto the computers. They did not havedeep reserves, but provided extensiveride-through capability while othersources of power (usually standbyemergency engine generator sets) werebrought to serve the motor-generatorsets while the normal source of powerwas unstable or unavailable.

UPS systems have evolved along thelines of rotary types and static typesof systems, and they come in manyconfigurations, and even hybrid

designs having characteristics ofboth types. The discussion thatfollows attempts to compare andcontrast the two types of UPSsystems, and give basic guidanceon selection criteria. This discussionwill focus on the medium, large andvery large UPS systems required byusers who need more than 10 kVA ofclean reliable power.



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Power Ratings of UPS Systems

■ Small UPS: Typically 300 VA to 10 kVA,and sometimes as high as 18 kVA

■ Medium UPS: 10–60 kVA

■ Large UPS: 100–200 kVA units, and

higher when units are paralleled■ Very Large UPS: 200–750 kVA

units, and higher when unitsare paralleled

Each of these categories is arbitrarybecause manufacturers have manydifferent UPS offerings for the sameapplication. The choice of UPS typeand the configuration of UPS modulesfor a given application depends uponmany factors, including how manypower quality problems the UPS isexpected to solve; how much futurecapacity is to be purchased now forfuture loads; the nature of the sensi-tive loads and load wiring; which

type of UPS system is favored, rotaryor static; choices of battery or DCstorage technology considered; anda host of other application issues.

Rotary UPS Systems

Typical Ratings

300–900 kVA/720 kW maximum.

Typical Rotary Configurations

Rotary UPS systems are among theoldest working systems developedto protect sensitive loads. Many ofthese systems are complicated engine-generator sets coupled with high

inertial flywheels operated at relativelylow rotational speeds. These legacy

types of hybrid UPS systems are notthe focus of this discussion, becauseonly one or two vendors offer thesehybrid types of rotary UPS systems,although admittedly they continue tobe used in very large-scale data center

applications. SeeFigure 1.4-18

for themodern high speed Rotary UPSsystems discussed in this sectionof the guide. These types of modernrotary UPS systems are advanced,integrated designs using scalableconfigurations of high-speed fly-wheel, motor and generator in onecompact UPS package. The new rotarytechnologies have the potential toreplace battery backup systems, orat least reduce the battery contentfor certain applications. The appealof rotary systems is the avoidance ofthe purchase, maintenance and facilityspace required by DC battery basedbackup systems.

High-Speed RotaryConcept of Operation

The modern rotary type of UPSoperation is understood by reviewingthe four topics below: startup mode,normal operation mode, dischargemode and recharge mode.

Startup Mode

The UPS output is energized onbypass as soon as power is appliedfrom the source to the system input.The UPS continues the startupprocedure automatically when the

front panel controls are placed intothe “Online” position. Internal UPS

system checks are performed thenthe input contactor is closed. The staticdisconnect switch is turned on and theconduction angle is rapidly increasedfrom zero to an angle that causes theDC bus voltage between the utility

converter and the flywheel converterto reach approximately 650V throughthe rectifying action of the freewheel-ing diodes in the utility converter.As soon as this level of DC voltage isreached, the static disconnect turnson fully. The next steps involved theutility converter IGBTs to start firing,which allows the converter to act asa rectifier, a regulating voltage sourceand an active harmonic filter. As theIGBTs begin to operate, the DC busis increased to a normal operatingvoltage of approximately 800V, andthe output bus is transferred frombypass to the output of the powerelectronics module. The transfer frombypass is completed when the outputcontactor is closed and the bypasscontactor opened in a make-before-break manner.

The firing of the SCRs in the staticdisconnect switch is now changed sothat each SCR in each phase is onlyturned on during the half-cycle, whichpermits real power to flow from theutility supply to the UPS. This firingpattern at the static disconnect switchprevents power from the flywheelfrom feeding backward into theutility supply and ensures that all ofthe flywheel energy is available to

support the load.

Figure 1.4-18. Typical-High Speed Modern Rotary UPS

It = Ir + Ic + Ig

Id = Output CurrentIh = Harmonic CurrentIx = Reactive Load CurrentIr = Real Load Current

Source

Field CoilDriver

Integrated Motor/Flywheel/ and Generator

ac

dc

dc

ac

Ih

Ix

Flywheel Converter Utility Converter Ic

IgFilter Inductor

Inverter

Fuse

Line InductorOutputContactor

InputContactor

Static DisconnectSwitch

Bypass Contactor

Static Bypass Option

Load

Output Transformer

Id = Ih + Ix + Ir

It = Input CurrentIr = Real Load CurrentIc = Charging CurrentIg = Voltage Regulation Current




1.4September 2011


Sheet 01


Immediately after the output is trans-ferred from bypass to the power elec-tronic module, the flywheel field isexcited, which also provides magneticlift to unload the flywheel bearings.The flywheel inverter is turned on

and gradually increases frequencyat a constant rate to accelerate theflywheel to approximately 60 rpm.Once the flywheel reaches 60 rpm,the flywheel inverter controls theacceleration to keep currents below themaximum charging and the maximuminput settings. Once the flywheelreaches 4000 rpm, the UPS is fullyfunctional and capable of supportingthe load during a power quality event.flywheel acceleration continues untilthe Flywheel reaches “full charge” at7700 rpm. The total time to completestartup is less than 5 minutes.

Normal Operation Mode

Once the UPS is started and theflywheel is operating at greater than4000 rpm, the UPS is in the normaloperating mode where it is regulatingoutput voltage and supplying reactiveand harmonic currents required by theload. At the same time it cancels theeffect of load current harmonics on theUPS output voltage.

Input current consists of three compo-nents: real load current, chargingcurrent, and voltage regulation current.Real current is current that is in phasewith the supply voltage and suppliesreal power to the load. Real current

flowing through the line inductor causesa slight phase shift of the currentlagging the voltage by 10 degreesand ensures that the UPS can quicklytransfer to bypass without causingunacceptable switching transients. Thesecond component is charging currentrequired by the flywheel to keep therotating mass fully charged at ratedrpm, or to recharge the rotating massafter a discharge. The power to main-tain full charge is low at 2 kW andis accomplished by the IGBTs of theflywheel converter gating to providesmall pulses of motoring current to theflywheel. This current can be much

higher if fast recharge times areselected. The final component of inputcurrent is the voltage regulation current,which is usually a reactive current thatcirculates between the input and theutility converter to regulate the outputvoltage. Leading reactive current

causes a voltage boost across the lineinductor, and a lagging current causesa bucking voltage. By controlling theutility converter to maintain nominaloutput voltage, just enough reactivecurrent flows through the line inductor

to make up the difference between theinput voltage and the output voltage.

The load current consists of threecomponents: the harmonic currentrequired by the load, the reactive loadcurrent, and the real current, whichdoes the work. The utility convertersupplies both the harmonic andreactive currents. Because thesecurrents supply no net power to theload, the flywheel supplies no energyfor these currents. They circulatebetween the utility converter and theload. The power stage controls analyzethe harmonic current requirements ofthe load and set the firing angle of

the inverter IGBTs to make the utilityconverter a very low impedance sourceto any harmonic currents. Thus,nonlinear load currents are suppliedalmost entirely from the utilityconverter with little effect on thequality of the UPS output voltagewaveform and with almost notransmission of load harmonicscurrents to the input of the UPS.

Discharge Mode

The UPS senses the deviation ofthe voltage or frequency beyondprogrammed tolerances and quicklydisconnects the supply source by

turning off the static disconnect switchand opening the input contactor. Thedisconnect occurs in less than one-halfcycle. Then the utility converter startsdelivering power from the DC bus tothe load, and the flywheel converterchanges the firing point of its IGBTsto deliver power to the DC bus. TheUPS maintains a clean output voltagewithin 3% or nominal voltage to theload when input power is lost.

Recharge Mode

When input power is restored toacceptable limits, the UPS synchronizesthe output and input voltages, closes

the input contactor and turns on thestatic disconnect switch. The utilityconverter then transfers power fromthe flywheel to the input source bylinearly increasing the real inputcurrent. The transfer time is program-mable from 1 to 15 seconds. As soon

as the load power is completelytransferred to the input source, the util-ity converter and flywheel converterstart to recharge the flywheel andreturn to normal operation mode. Theflywheel recharge power is program-

mable between a slow and fast rate,and using the fast rate results in anincrease of UPS input current overnominal levels. Recharging the flywheelis accomplished by controlling theutility and flywheel converter in asimilar manner as is used to maintainfull charge in the normal operationmode, however the IGBT gating pointsare changed to increase current intothe flywheel.

High-Speed Rotary Advantages

■ Addresses all power qualityproblems

■ Battery systems are not required

or used■ No battery maintenance required

■ Unlimited discharge cycles

■ 150-second recharge time available

■ Wide range of operating tempera-tures can be accommodated(–20° to 40°C)

■ Small compact size and less floorspace required (500 kW systemstakes 20 sq ft)

■ N+1 reliability available up to900 kVA maximum

■ No disposal issues

High-Speed Rotary Disadvantages

■ Flywheel does not have deepreserve capacity—rides throughfor up to 13 seconds at 100% load

■ Some enhanced flywheel systemsmay extend the ride through to30 seconds at 100% load

■ Mechanical flywheel maintenancerequired every 2–3 years, and oilchanges required every year

■ Recharge fast rates require theinput to be sized for 125% ofnominal current

■ Flywheels failures in field notunderstood

■ Requires vacuum pumps for

high-speed flywheels■ Limited number of vendors and

experience



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Static UPS Systems

Typical Ratings

40–750 kVA/600 kW, and higher whenmultiple units are paralleled.

Typical Static UPS Configurations

Static UPS systems modules areavailable in three basic types ofconfigurations known as standby, lineinteractive and double conversion.See Tab 33 in this guide for details onall the UPS configurations availablefrom Eaton. The lighter power ratingsare likely to be one of the first twotypes of configurations, e.g., standbyor line interactive. Most medium orlarge static UPS installations use thedouble conversion technology in oneor multiple module configurations,i.e., or multiple UPS units in parallel.Figure 1.4-19 illustrates the one-line

diagram of a simple single DoubleConversion UPS module. Briefexplanations appear for the standbyand line interactive UPS systemsafter the text explaining the DoubleConversion static UPS type of system.

A. Double conversion concept ofoperation—the basic operation ofthe Double Conversion UPS is:

1. Normal power is connected tothe UPS input through the facilityelectrical distribution system.This usually involves two inputcircuits that must come from thesame source.

2. The Rectifier/Charger functionconverts the normal AC power toDC power to charge the batteryand power the inverter. The loadis isolated from the normalinput source.

3. The battery stores DC energyfor use when input power to theUPS fails. The amount of poweravailable from the DC batterysystem and time to dischargevoltage is a function of the type ofbattery selected and the ampere-hour sized used. Battery systemsshould be sized for no less than5 minutes of clean power usagefrom a fully charged state, and, inmany cases, are sized to providemore time on battery power.

4. The DC link connects the outputof the rectifier/charger to the input

of the inverter and to the battery.Typically the rectifier/charger issized slightly higher than 100% ofUPS output because it must powerthe inverter and supply chargerpower to the battery.

5. The bypass circuit provides apath for unregulated normalpower to be routed around themajor electronic sub-assembliesof the UPS to the load so that theload can continue to operate duringmaintenance, or when the UPSelectronics fails. The bypass staticswitch can switch to conducting

mode in 150–120 milliseconds.When the UPS recognizes arequirement to transfer to thebypass mode, it simultaneouslyturns the static switch ON, theoutput breaker to OPEN, and the

bypass breaker to CLOSE. Theoutput breaker opens and thebypass breaker closes in about50 milliseconds. The restorationof normal conditions at the UPSresults in the automatic restorationof the UPS module powering theload through the rectifier/chargerand inverter with load isolationfrom power quality problems, andthe opening of the bypass circuit.

Static Double Conversion Advantages

■ Addresses all power qualityproblems

■ Suitable for applications from

5 kVA to over 2500 kVA■ Simple battery systems are

sized for application

■ Long battery backup times andlong life batteries are available

■ Higher reliability is availableusing redundant UPS modules

Figure 1.4-19. Typical Static UPS, Double Conversion Type with Battery Backup

Source

Battery

AC

DC

DC

AC

InverterOutputBreaker

NormalBreaker

Bypass Static Switch

UPS Module

Load

Rectifier/Charger

Battery Breaker

Bypass Breaker (Optional)




1.4September 2011


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Static Double Conversion Disadvantages

■ Battery systems, battery maintenance and battery replacement are required

■ Large space requirement forbattery systems (higher life takesmore space, e.g., 500 kW takes

80–200 sq ft depending upon thetype of battery used, VRLA 10 year,VRLA 20 year or flooded)

■ Limited discharge cycles ofbattery system

■ Narrow temperature rangefor application

■ Efficiencies are in the 90–94%range, which is lower than someline interactive configurations

■ Bypass mode places load at riskunless bypass has UPS backup

■ Redundancy of UPS modulesresults in higher costs

■ Output faults are cleared by the

bypass circuit■ Output rating of the UPS is 150%

for 30 seconds

■ Battery disposal and safetyissues exist

B. Standby UPS concept ofoperation—The basic operation ofthe Standby UPS is:

1. The Standby UPS topology issimilar to the double conversiontype, but the operation of the UPSis different in significant ways.Normal power is connected tothe UPS input through the facility

electrical distribution system. Thisusually involves two input circuitsthat must come from the samesource. See Figure 1.4-20 fordetails.

2. The rectifier/charger functionconverts the normal AC power toDC power to charge the batteryonly, and does not simultaneouslypower the inverter. The load isconnected to the input sourcethrough the bypass static switch.The inverter is in the standbymode ready to serve the loadfrom battery power if the inputpower source fails.

3. The battery stores DC energy foruse by the inverter when inputpower to the UPS fails. Theamount of power available fromthe DC battery system and time todischarge voltage is a function of

the type of battery selected andthe ampere-hour sized used.Battery systems should be sizedfor the anticipated outage.

4. The DC link connects the output ofthe rectifier/charger to the input ofthe inverter and to the battery.Typically the rectifier/chargeris sized only to supply chargerpower to the battery, and israted far lower than in thedouble conversion UPS.

5. The bypass circuit provides adirect connection of input sourceto the load. The load operates

from unregulated power. Thebypass static switch can switchto non-conducting mode in 150–120 milliseconds. When the UPSrecognizes the loss of normalinput power, it transfers to battery/ inverter mode by simultaneouslyturning the Inverter ON and thestatic switch OFF.

Static Standby UPS Advantages

■ Lower costs than double conversion

■ Rectifier and charger areeconomically sized

■ Efficient design

■ Batteries are sized for the

application

Static Standby UPS Disadvantages

■ Impractical over 2 kVA

■ Little to no isolation of load frompower quality disturbances

■ Standby power is from battery alone

■ Battery systems, battery mainte-nance and battery replacementare required

■ Limited discharge cycles ofbattery system

■ Narrow temperature range forapplication

■ Output faults are cleared by the

bypass circuit■ Battery disposal and safety

issues exist

C. Static line interactive UPSconcept of operation—the basicoperation of the Line InteractiveUPS is:

1. The Line Interactive type of UPShas a different topology than the

static double conversion andstandby systems. The normalinput power is connected to theload in parallel with a batteryand bi-directional inverter/chargerassembly. The input source usu-ally terminates at a line inductorand the output of the inductor isconnected to the load in parallelwith the battery and inverter/ charger circuit. See Figure 1.4-21 for more details.

2. The traditional rectifier circuitis eliminated and this resultsin a smaller footprint and

weight reduction. However, lineconditioning is compromised.

3. When the input power fails, thebattery/inverter charger circuitreverses power and supplies theload with regulated power.

Static Line Interactive UPS Advantages

■ Slight improvement of powerconditioning over standbyUPS systems

■ Small footprints and weights

■ Efficient design

■ Batteries are sized for theapplication

Static Line Interactive UPS Disadvantages

■ Impractical over 5 kVA

■ Not as good conditioning asdouble conversion

■ Standby power is from battery alone

■ Battery systems, battery mainte-nance and battery replacementare required

■ Limited discharge cycles for thebattery system

■ Narrow temperature range forapplication

■ Battery disposal and safetyissues exist



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Figure 1.4-20. Typical Static UPS, Standby Type with Battery Backup

Figure 1.4-21. Typical Static UPS, Line Interactive Type with Battery Backup

Source

AC

DC

DC

AC

UPS Module

NormalBreaker

Rectifier/ Charger Inverter

Bypass Static Switch

BatteryBreaker

OutputBreaker

Battery

Load

Source

DC

AC

UPS Module

BidirectionalInverter/Charger

Battery

Load

Inductor




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Other Application Considerations087

Secondary Voltage SelectionThe choice between 208Y/120V and480Y/277V secondary distribution forcommercial and institutional buildingsdepends on several factors. The mostimportant of these are size and types

of loads (motors, fluorescent lighting,incandescent lighting, receptacles)and length of feeders. In general, largemotor and fluorescent lighting loads,and long feeders, will tend to make thehigher voltages, such as 480Y/277V,more economical. Very large loadsand long runs would indicate the useof medium voltage distribution andloadcenter unit substations close tothe loads. Conversely, small loads,short runs and a high percentage ofincandescent lighting would favorlower utilization voltages such as208Y/120V.

Industrial installations, with largemotor loads, are almost always 480V,often ungrounded delta or resistancegrounded delta or wye systems (seesection on ground fault protection).

Practical Factors

Because most low voltage distributionequipment available is rated for up to600V, and conductors are insulated for600V, the installation of 480V systemsuses the same techniques and isessentially no more difficult, costly, orhazardous than for 208V systems. Themajor difference is that an arc of 120Vto ground tends to be self-extinguishing,while an arc of 277V to ground tendsto be self-sustaining and likely tocause severe damage. For this reason,the National Electrical Code requiresground fault protection of equipmenton grounded wye services of morethan 150V to ground, but not exceeding600V phase-to-phase (for practicalpurpose, 480Y/277V services), for anyservice disconnecting means rated1000A or more. The National ElectricalCode permits voltage up to 300Vto ground on circuits supplyingpermanently installed electric dischargelamp fixtures, provided the luminairesdo not have an integral manual switchand are mounted at least 8 ft (2.4m)above the floor. This permits a three-phase, four-wire, solidly grounded480Y/277V system to supply directly allof the fluorescent and high-intensitydischarge (HID) lighting in a buildingat 277V, as well as motors at 480V.

Technical Factors

The principal advantage of the use ofhigher secondary voltages in buildingsis that for a given load, less currentmeans smaller conductors and lowervoltage drop. Also, a given conductor

size can supply a large load at thesame voltage drop in volts, but a lowerpercentage voltage drop because ofthe higher supply voltage. Fewer orsmaller circuits can be used to transmitthe power from the service entrancepoint to the final distribution points.Smaller conductors can be used in many branch circuits supplying power loads,and a reduction in the number of light-ing branch circuits is usually possible.

It is easier to keep voltage drops withinacceptable limits on 480V circuits thanon 208V circuits. When 120V loads are

supplied from a 480V system throughstep-down transformers, voltage dropin the 480V supply conductors can becompensated for by the tap adjust-ments on the transformer, resultingin full 120V output. Because these

transformers are usually located closeto the 120V loads, secondary voltagedrop should not be a problem. If it is,taps may be used to compensate byraising the voltage at the transformer.

The interrupting ratings of circuitbreakers and fuses at 480V haveincreased considerably in recent years,and protective devices are now available for any required fault duty at 480V.In addition, many of these protectivedevices are current limiting, and canbe used to protect downstream equip-ment against these high fault currents.

Figure 1.4-22. Typical Power Distribution and Riser Diagram for a Commercial Office Building Include ground fault trip.

➀

➀

Spare

Building andMiscellaneousLoads

4000 AMain CB

AutomaticTransfer Switch

Typical

Gen. CB

4000A at 480Y/277V100,000A Available Fault Current

Utility

MeteringCTs PTs

UtilityService

HVACFeeder BuswayRiser ElevatorRiser

ElevatorPanel

(Typical EveryThird Floor)

480Y/277 VPanel

208Y/120 VPanel

EmergencyLightingRiser

HVACPanel

Dry Type Transformer480∆-208Y/120 V(Typical Every Floor)

EmergencyLighting Panel

Typical

Typical

Typical

Typical

Typical

Typical

Typical

Emergency

or StandbyGenerator

➀ ➀ ➀ ➀ ➀ ➀



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Economic Factors

Utilization equipment suitable forprincipal loads in most buildingsis available for either 480V or 208Vsystems. Three-phase motors andtheir controls can be obtained for either

voltage, and for a given horsepowerare less costly at 480V. Fluorescent andHID lamps can be used with either 277Vor 120V ballasts. However, in almost allcases, the installed equipment will havea lower total cost at the higher voltage.

Energy Conservation

Because of the greatly increased costof electrical power, designers mustconsider the efficiency of electricaldistribution systems, and design forenergy conservation. In the past,especially in commercial buildings,design was for lowest first cost,because energy was inexpensive.

Today, even in the speculative officebuilding, operating costs are so highthat energy-conserving designs canjustify their higher initial cost with arapid payback and continuing savings.Buildings that must meet LEED certifi-cations may require energy-savingdesigns. There are four major sourcesof energy conservation in a commercialbuilding—the lighting system, themotors and controls, the transformersand the HVAC system.

The lighting system must takeadvantage of the newest equipmentand techniques. New light sources,

familiar light sources with higherefficiencies, solid-state ballasts withdimming controls, use of daylight,environmental design, efficientluminaires, computerized orprogrammed control, and the like,are some of the methods that canincrease the efficiency of lightingsystems. They add up to providingthe necessary amount of light, with thedesired color rendition, from the mostefficient sources, where and when it isneeded, and not providing light whereor when it is not necessary. Using thebest of techniques, office spaces thatoriginally required as much as 3.5W

per square foot have been givenimproved lighting, with less glareand higher visual comfort, using aslittle as 1.0 to 2.0W per square foot.In an office building of 200,000 squarefeet (60,960m), this could mean asaving of 400 kW, which, at $0.05 perkWh, 250 days per year, 10 hours perday, could save $50,000 per year inenergy costs. Obviously, efficientlighting is a necessity.

Motors and controls are another causeof wasted energy that can be reduced.New, energy-efficient motor designsare available using more and bettercore steel, and larger windings.

For any motor operating 10 or more

hours per day, it is recommended touse the energy-efficient types. Thesemotors have a premium cost of about20% more than standard motors.Depending on loading, hours of useand the cost of energy, the additionalinitial cost could be repaid in energysaved within a few months, and itrarely takes more than two years.Because, over the life of a motor, thecost of energy to operate it is manytimes the cost of the motor itself, anymotor with many hours of use shouldbe of the energy-efficient type.

Where a motor drives a load with

variable output requirements suchas a centrifugal pump or a large fan,customary practice has been to run themotor at constant speed, and to throttlethe pump output or use inlet vanes oroutlet dampers on the fan. This is highlyinefficient and wasteful of energy. Inrecent years, solid-state variable-frequency, variable-speed drives forordinary induction motors have beenavailable, reliable and relativelyinexpensive. Using a variable-speeddrive, the throttling valves, inlet vanesor output dampers can be eliminated,saving their initial cost and energyover the life of the system. An

additional benefit of both energy-efficient motors and variable-speeddrives (when operated at less thanfull speed) is that the motors operateat reduced temperatures, resulting inincreased motor life.

Transformers have inherent losses.Transformers, like motors, are designedfor lower losses by using more andbetter core materials, larger conductors,etc., and this results in increased initialcost. Because the 480V to 208Y/120Vstepdown transformers in an officebuilding are usually energized 24 hoursa day, savings from lower losses canbe substantial, and should be consid-

ered in all transformer specifications.One method of obtaining reducedlosses is to specify transformers with220°C insulation systems designed for150°C average winding temperaturerise, with no more than 80°C (orsometimes 115°C) average windingtemperature rise at full load. Abetter method would be to evaluatetransformer losses, based on actualloading cycles throughout the day,

and consider the cost of losses as wellas the initial cost of the transformersin purchasing.

NEMA standard TP-1 is being adoptedby many states and is another methodof energy-efficient design. NEMA TP-1

establishes minimum operatingefficiencies for each distributiontransformer size at a loading equal to35% of the transformer full load kVA.The 35% loading value in the NEMAstandard reflects field studies con-ducted by the U.S. Department ofEnergy, which showed that dry-typetransformers installed in commercialfacilities are typically loaded at anaverage of 35% of their full loadcapacity over a 24-hour time period.Table 1.4-9 compares losses forboth low temperature rise and TP-1transformers using a 75 kVA design.

Table 1.4-9. Load Losses

Efficiencies above TP-1. CandidatesStandard Level (CSL) is a DOEefficiency evaluation for transformers.CSL-1 is equivalent to TP-1. Levelsare from CSL-1 to CSL-5. CSL-3 isbeing promoted for higher efficiencyapplications. A NEMA white paperClarifications on the Use of DOE Design—Lines 6, 7 and 8 is availablefrom NEMA that elaborates onthe matter.

HVAC systems have traditionally beenvery wasteful of energy, often beingdesigned for lowest first cost. This,too, is changing. For example, reheatsystems are being replaced by variableair volume systems, resulting in equalcomfort with substantial increases inefficiency. While the electrical engineerhas little influence on the design of theHVAC system, he/she can specify thatall motors with continuous or long duty

cycles are specified as energy-efficienttypes, and that the variable-air-volumefans do not use inlet vanes or outletdampers, but are driven by variable-speed drives. Variable-speed drivescan often be desirable on centrifugalcompressor units as well. Since someof these requirements will be in HVACspecifications, it is important for theenergy-conscious electrical engineerto work closely with the HVAC engineerat the design stage.

Temp.Rise ºC

Load Losses in Watts

NoLoss

25%Load

35%Load

50%Load

75%Load

FullLoad

150115

360420

490480

620610

885805

15351170

24501950

80TP-1 150

500230

535310

615480

730745

9451235

14102280




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Building Control SystemsIn order to obtain the maximum benefitfrom these energy-saving lighting,power and HVAC systems, they mustbe controlled to perform their functionsmost efficiently. Constant monitoring

would be required for manual operation, so some form of automatic controlis required. The simplest of theseenergy-saving controls, often veryeffective, is a time clock to turn varioussystems on and off. Where flexiblecontrol is required, programmablecontrollers may be used. These rangefrom simple devices, similar to multi-function time clocks, up to full micro-processor-based, fully programmabledevices, really small computers. Forcomplete control of all building systems,computers with specialized softwarecan be used. Computers can not onlycontrol lighting and HVAC systems,

and provide peak demand control, tominimize the cost of energy, but theycan perform many other functions.Fire detection and alarm systems canoperate through the computer, whichcan also perform auxiliary functionssuch as elevator control and buildingcommunication in case of fire. Buildingsecurity systems, such as closed-circuittelevision monitoring, door alarms andintruder sensing, can be performed bythe same building computer system.

The time clocks, programmablecontrollers and computers canobtain data from external sensors

and control the lighting, motors andother equipment by means of hardwiring-separate wires to and fromeach piece of equipment. In the morecomplex systems, this would result ina tremendous number of controlwires, so other methods are frequentlyused. A single pair of wires, with elec-tronic digital multiplexing, can controlor obtain data from many differentpoints. Sometimes, coaxial cable isused with advanced signaling equip-ment. Some systems dispense withcontrol wiring completely, sendingand receiving digital signals over thepower wiring. The newest systemsmay use fiber-optic cables to carrytremendous quantities of data, freefrom electromagnetic interference.The method used will depend onthe type, number and complexityof functions to be performed.

Because building design and controlfor maximum energy saving is impor-tant and complex, and frequentlyinvolves many functions and severalsystems, it is necessary for the designengineer to make a thorough building

and environmental study, and toweigh the costs and advantages ofmany systems. The result of gooddesign can be economical, efficientoperation. Poor design can be wastefuland extremely costly.

Distributed Energy Resources

Distributed energy resources (DER)are increasingly becoming prominentsources of electric power. Distributedenergy resources are usually small-to-medium sources of electric generation,either from renewable or non-renewable sources. Sources include:

■ Photovoltaic (PV) systems(solar systems)

■ Wind

■ Fossil-fueled (diesel, natural gas,landfill gas, coal-bed methane)generators (reciprocating engines)

■ Gas-fired turbines (natural gas,landfill gas, coal-bed methane)

■ Water-powered (hydro)

■ Fuel cells

■ Microturbines

■ Wave power

■ Coal-fired boilers

Distributed energy resources may also

be termed alternative energy resources.Prime Power

DER can be used for generating primepower or for cogeneration. Prime powerconcerns a system that is electricallyseparated from the electrical grid.Prime power is generated at remotesites where commercial electricalpower is not available.

Cogeneration

Cogeneration is another outgrowth ofthe high cost of energy. Cogenerationis the production of electric powerconcurrently with the production of

steam, hot water and similar energyuses. The electric power can be themain product, and steam or hot waterthe byproduct, as in most commercialinstallations, or the steam or hot watercan be the most required product,and electric power a byproduct, asin many industrial installations. Insome industries, cogeneration hasbeen common practice for manyyears, but until recently it has not beeneconomically feasible for mostcommercial installations. This has

been changed by the high cost ofpurchased energy, plus a federal law(Public Utility Regulatory Policies Act,known as PURPA) that requires publicutilities to purchase any excess powergenerated by the cogeneration plant.

In many cases, practical commercialcogeneration systems have been builtthat provide some or all of the electricpower required, plus hot water, steam,and sometimes steam absorption-typeair conditioning. Such cogenerationsystems are now operating success-fully in hospitals, shopping centers,high-rise apartment buildings andeven commercial office buildings.

Where a cogeneration system is beingconsidered, the electrical distributionsystem becomes more complex. Theinterface with the utility company iscritical, requiring careful relayingto protect both the utility and the

cogeneration system. Many utilitieshave stringent requirements thatmust be incorporated into the system.Proper generator control and protec-tion is necessary, as well. An on-siteelectrical generating plant tied to anelectrical utility, is a sophisticatedengineering design.

Utilities require that when theprotective device at their substationopens that the device connecting acogenerator to the utility open also.

One reason is that most cogeneratorsare connected to feeders serving othercustomers. Utilities desire to reclose

the feeder after a transient fault iscleared. Reclosing in most cases willdamage the cogenerator if it hadremained connected to their system.

Islanding is another reason why theutility insists on the disconnection ofthe cogenerator. Islanding is the eventthat after a fault in the utility’s systemis cleared by the operation of theprotective devices, a part of thesystem may continue to be suppliedby cogeneration. Such a condition isdangerous to the utility’s operationduring restoration work.

Major cogenerators are connected tothe subtransmission or the transmissionsystem of a utility. Major cogeneratorshave buy-sell agreements. In suchcases, utilities use a trip transferscheme to trip the cogenerator breaker.

Guidelines that are given in ANSIGuide Standard 1001 are a goodstarting point, but the entire designshould be coordinated with the utility.



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PV System Design ConsiderationsSuccessful photovoltaic (PV) designand construction is a complex multi-discipline endeavor. Proper planningincludes the site-layout study formaximizing the sun’s energy harvest-

ing for solar module selection, andfor updating the electrical/mechanicaldesign and construction to the latestcode and local constraints, includingfire marshal and seismic regulations.Professionally prepared bid, permit,construction and as-build drawingsshall be required and maintained.For installation in/on/for existingstructures and sites, it is advisedthat, at the minimum, pre-designand construction tests be performedfor existing power-quality issues,water drainage and the utility feeder/ transformer, and that electricaldistribution panel ratings are verified

sufficient for the planned solar system,and the necessary arc flash studies beperformed. Connection to the utilityis always a utility interconnect agree-ment (application) process, and istypically required for the availablesolar incentives and programs offeredby the utility, municipality, state, andvarious federal agencies and depart-ments. State, and IRS tax incentivesrequire well-documented records.

Solar systems, while low mainte-nance, do require periodic service.The solar modules need to be washed-clean on a regular basis and electrical

terminations require initial and annualchecks. Cooling system filters areperiodic maintenance items, with there-fresh rate dependent upon typicaland unusual circumstances.

Solar systems installed near other newconstruction where dust is generated(e.g., grading, paving) or agriculturalenvironments may require additionalsolar-system checks and services.Planning for such contingencies isthe business of solar-system design,construction and on-going operation.Performance-based incentivesrequire verifiable metering, oftenby registered/approved independent

third parties. Such monitoring periodsare typically for 60 or more months.

The S-Max inverter offers a wide rangeof features and options to enable asuccessful and long-lived solar-energyharvesting solution. The isolation step-up transformer, coupled to either anegative or a positive grounded solararray, ensures that the S-Max canmatch to all (known) solar moduletechnologies. The S-Max followsstandard industry and code practices

in determining the maximum numberof solar modules per string for theopen-circuit photovoltaic (PV) voltagerise in cold weather (Voc < 600V as perNEC). Its low 300V MPPT lower-limitensures that multiple configurations

are possible for solar systems hotweather voltage drop (i.e., Vmpas a function of temperature, solarirradiance and array-conductor voltagedrop). The following equations are thebasis of all solar system layout anddesign. Consult professional engineer-ing to help when planning any solarsystem. Engineering design firmsoffering complete solar systems“turn-key” calculations, drawings,construction management andprocurement are a good place tostart. Eaton offers professional S-Maxinverter application assistance, on-sitecommissioning and maintenanceservices. Eaton maintains a workingrelationship with the best engineeringservices firms across the country, andhelps arrange the successful implanta-tion of your solar system. The S-Max250 kW inverter and up-fit solutionseasily perform well in Mega-Watt andUtility-Scale systems. Eaton also offersa wide range of balance-of-system(BOS) products, ranging from solarmodule source and array combiners,to DC and AC breakers, electrical anddistribution panels and switchgear.

Low Temperature Equation

Voc_max = Voc + (temp-differential xtemp-coefficient-of-Voc)

The temp-differential is the differencebetween the standard module ratingat 25°C and the low temperature.The voltage (Voc) will rise withtemperatures under 25°C.

Seek the solar module data sheet fora list of standard test condition (STC)data, temperature coefficients, andany special module-related informa-tion to determine the low-temperatureopen circuit voltage. The NEC 2011,and industry practice, requires theuse of the site’s Extreme AnnualMean Minimum Design Dry BulbTemperature data, available in theASHRAE Handbook. Code requiresthat the resulting maximum voltage(Voc) when added in the “string ofmodules” be under 600V. Recordlow temperatures provide anindication of system performancewhen temperatures drop to theselevels. The S-Max inverter is designedto standards higher than 600 Vdc.

High Temperature Equation

Once the maximum number ofmodules per string is established,the minimum number of modules perstring needs to be calculated. Here,more site-related aspects come into

play, as the voltage of solar modulesdecreases with increasing tempera-ture. The modules’ (photovoltaic cell)temperature is influenced by theambient temperature, reflected sun-loads from nearby structures, parapetwalls, roof-coatings, etc. Air-flowabove and behind the solar modulesaffect the cell temperature. Theaccepted industry standards to addto the module heating is listed below.Unusual mounting systems mayadjust these figures, and it is best toseek assistance in establishing andplanning such installations.

■ 20°C for ground or pole mountedsolar systems

■ 25°C for roof-top solar systemsmounted at inclined angles(offers improved air-flow behindthe modules)

■ 30°C for roof-top solar systemsmounted flat, yet at least 6.00 inches(152.4 mm) above the roof surface

Vmp_min = Vmp + (temp-differential xtemp-coefficient-of-Vmp)

The temp-differential in this caseincludes the above temperature“adders.” The Vmp and relatedtemperature coefficients are listed

on the solar module’s data sheets.

While the code doesn’t indicate thehigh temperature to use (i.e., becauseit is an equipment application issue),the industry standard is to evaluate theASHRAE 2% and 4% high temperaturefigures, coupled to known locationdifferences. Record high temperaturesprovide an indication of systemperformance when climatic conditionreaches these levels.

Beyond the damaging temperatureaffects on photovoltaic module Vmpvoltage levels, voltage drop in PVconductors under such conditions also

need to be calculated and evaluated,beyond normal temperatures. Theinverter only uses (knows) the Vmpvoltage at the inverter, not at thePV modules.

Increasing grid voltages also puts aconstraint on the minimum Vmpvoltage at the DC input stage.




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To ensure the full MPPT range withoutpower-clipping (reduced poweroutput), prudent PV system designsshall consider the PV array’s Vmpvoltage drop to the point of theinverter connection, ambient

temperatures and the PV systeminstallation type’s effects on Vmp,solar module miss-match andtolerance variations, degradation ofsolar modules over time (solar systemlife), etc. Typical Vmp design values,based upon known and expectedconditions are 5–10% over theminimum MPPT tracking voltage.Reference NEC 2011 Section 690,Solar Photovoltaic Systems.

Emergency Power

Most areas have requirementsfor emergency and standby powersystems. The National Electrical Code

does not specifically call for anyemergency or standby power, butdoes have requirements for thosesystems when they are legallymandated and classed as emergency(Article 700), legally required standby(Article 701) by municipal, state,

federal or other codes, or by anygovernmental agency having jurisdic-tion. Optional standby systems, notlegally required, are also covered inthe NEC (Article 702).

Emergency systems are intended to

supply power and illumination essen-tial for safety to human life, when thenormal supply fails. NEC requirementsare stringent, requiring periodic testingunder load and automatic transfer toemergency power supply on loss ofnormal supply. See Figure 1.4-23.All wiring from emergency source toemergency loads must be kept separatefrom all other wiring and equipment,in its own distribution and racewaysystem, except in transfer equipmentenclosures and similar locations. Themost common power source for largeemergency loads is an engine-generatorset, but the NEC also permits the

emergency supply (subject to local code requirements) to be storage batteries,uninterruptible power supplies, aseparate emergency service, or aconnection to the service ahead of thenormal service disconnecting means.Unit equipment for emergency illumi-

nation, with a rechargeable battery,a charger to keep it at full capacitywhen normal power is on, one or morelamps, and a relay to connect thebattery to the lamps on loss of normalpower, is also permitted. Because

of the critical nature of emergencypower, ground fault protection is notrequired. It is considered preferableto risk arcing damage, rather than todisconnect he emergency supply com-pletely. For emergency power, groundfault alarm is required by NEC 700.7(D)to indicate a ground fault in solidlygrounded wye emergency systemsof more than 150V to ground andcircuit-protective devices rated 1000Aor more.

Legally required standby systems, asrequired by the governmental agencyhaving jurisdiction, are intended tosupply power to selected loads, other

than those classed as emergencysystems, on loss of normal power.These are usually loads not essentialto human safety, but loss of whichcould create hazards or hamperrescue or fire-fighting operations.

Figure 1.4-23. Typical Emergency Power System

To Normal

DistributionCircuits

Optional Remote PCwith Software

N

LP1

ATS4

BP1 LP2 BP2 LP3 BP3 LP4 BP4

EDP1 EDP2 EDP3 EDP4

ATS3ATS2ATS1 E N E N E N ETo Emergency

Circuits

D1 D2 D3 D4

52G1 52G2 52G3 52G4

G1 G2 G3 G4

MainService

HMITouchscreen

Revenue

Metering

UtilitySource

Paralleling Switchgearwith Distribution

Typical Application: Three engine generator sets serve the load, plus one additional enginegenerator set for redundancy to achieve N+1 level of performance. Open or Closed transition is available.



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NEC requirements are similar to thosefor emergency systems, except thatwiring may occupy the same distribu-tion and raceway system as thenormal wiring if desired. Optionalstandby systems are those not legally

required, and are intended to protectprivate business or property wherelife safety does not depend onperformance of the system. Optionalsystems can be treated as part of thenormal building wiring system. Bothlegally required and optional standbysystems should be installed in sucha manner that they will be fully avail-able on loss of normal power. It ispreferable to isolate these systemsas much as possible, even though notrequired by code.

Where the emergency or standbysource, such as an engine generatoror separate service, has capacity to

supply the entire system, the transferscheme can be either a full-capacityautomatic transfer switch, or, lesscostly but equally effective, normaland emergency main circuit breakers,electrically interlocked such that onfailure of the normal supply theemergency supply is connected to theload. However, if the emergency orstandby source does not have capacityfor the full load, as is usually thecase, such a scheme would requireautomatic disconnection of thenonessential loads before transfer.Simpler and more economical insuch a case is a separate emergency

bus, supplied through an automatictransfer switch, to feed all criticalloads. The transfer switch connectsthis bus to the normal supply, innormal operation. On failure of thenormal supply, the engine-generatoris started, and when it is up to speedthe automatic switch transfers theemergency loads to this source. Onreturn of the normal source, manual orautomatic retransfer of the emergencyloads can take place.

Peak Shaving

Many installations now haveemergency or standby generators.In the past, they were required forhospitals and similar locations, butnot common in office buildings orshopping centers. However, manycostly and unfortunate experiencesduring utility blackouts in recent yearshave led to the more frequent installa-tion of engine generators in commer-cial and institutional systems for safetyand for supplying important loads.

Industrial plants, especially in processindustries, usually have some formof alternate power source to preventextremely costly shutdowns. Thesestandby generating systems arecritical when needed, but they are

needed only infrequently. Theyrepresent a large capital investment.To be sure that their power will beavailable when required, they shouldbe tested periodically under load.

The cost of electric energy has risento new high levels in recent years, andutilities bill on the basis not only ofpower consumed, but also on thebasis of peak demand over a smallinterval. As a result, a new use forin-house generating capacity hasdeveloped. Utilities measure demandcharges on the basis of the maximumdemand for electricity in any givenspecific period (typically 15 or 30

minutes) during the month. Someutilities have a demand “ratchet clause”that will continue demand charges ona given peak demand for a full year,unless a higher peak results in evenhigher charges. One large load, comingon at a peak time, can create higherelectric demand charges for a year.

Obviously, reducing the peak demandcan result in considerable savings inthe cost of electrical energy. For thoseinstallations with engine generatorsfor emergency use, modern controlsystems (computers or programmablecontrollers) can monitor the peak

demand, and start the engine-generatorto supply part of the demand as itapproaches a preset peak value. Theengine-generator must be selectedto withstand the required duty cycle.The simplest of these schemes trans-fer specific loads to the generator.More complex schemes operate thegenerator in parallel with the normalutility supply. The savings in demandcharges can reduce the cost of owningthe emergency generator equipment.

In some instances, utilities with littlereserve capacity have helped financethe cost of some larger customer-owned generating equipment. In

return, the customer agrees to takesome or all of his load off the utilitysystem and on to his own generator atthe request of the utility (with varyinglimitations) when the utility loadapproaches capacity. In some cases,the customer’s generator is paralleledwith the utility to help supply the peakutility loads, with the utility buying thesupplied power. Some utilities havebeen able to delay large capital expen-ditures for additional generatingcapacity by such arrangements.

It is important that the electrical sys-tem designer providing a substantialsource of emergency and standbypower investigate the possibility ofusing it for peak shaving, and evenof partial utility company financing.

Frequently, substantial savings inpower costs can be realized for asmall additional outlay in distributionand control equipment.

Peak shaving equipment operating inparallel with the utility are subject to thecomments made under cogeneration as to separation from the utility underfault conditions.

Sound Levels

Sound Levels of Electrical Equipmentfor Offices, Hospitals, Schools andSimilar Buildings

Insurance underwriters and building

owners desire and require that theelectrical apparatus be installedfor maximum safety and the leastinterference with the normal use ofthe property. Architects should takeparticular care with the designs forhospitals, schools and similar build-ings to keep the sound perception ofsuch equipment as motors, blowersand transformers to a minimum.

Even though transformers arerelatively quiet, resonant conditionsmay exist near the equipment, whichwill amplify their normal 120 Hz hum.Therefore, it is important that consid-

eration be given to the reduction ofamplitude and to the absorption ofenergy at this frequency. This problembegins in the designing stages of theequipment and the building. There aretwo points worthy of consideration: 1)What sound levels are desired in thenormally occupied rooms of this build-ing? 2) To effect this, what sound levelin the equipment room and what typeof associated acoustical treatmentwill give the most economicalinstallation overall?

A relatively high sound level in theequipment room does not indicatean abnormal condition within theapparatus. However, absorption maybe necessary if sound originating inan unoccupied equipment room isobjectionable outside the room.Furthermore, added absorptionmaterial usually is desirable ifthere is a “build-up” of sounddue to reflections.




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Some reduction or attenuation takesplace through building walls, theremainder may be reflected in variousdirections, resulting in a build-up orapparent higher levels, especially ifresonance occurs because of room

dimensions or material characteristics.Area Consideration

In determining permissible sound lev-els within a building, it is necessary toconsider how the rooms are to be usedand what levels may be objectionableto occupants of the building. Theambient sound level values given inTable 1.4-10 are representative averagevalues and may be used as a guide indetermining suitable building levels.

Decrease in sound level varies at anapproximate rate of 6 dB for eachdoubling of the distance from thesource of sound to the listener. For

example, if the level 6 ft (1.8m) froma transformer is 50 dB, the level at adistance of 12 ft (3.7m) would be 44 dBand at 24 ft (7.3m) the level decreasesto 38 dB, etc. However, this rule appliesonly to equipment in large areasequivalent to an out-of-door installation,with no nearby reflecting surfaces.

Table 1.4-10. Typical Sound Levels

Transformer Sound Levels

Transformers emit a continuous120 Hz hum with harmonics when

connected to 60 Hz circuits. Thefundamental frequency is the “hum”that annoys people primarily becauseof its continuous nature. For purposesof reference, sound measuringinstruments convert the differentfrequencies to 1000 Hz and a 40 dBlevel. Transformer sound levels basedon NEMA publication TR-1 are listedin Table 1.4-11.

Description AverageDecibelLevel (dB)

Radio, recording and TV studiosTheatres and music roomsHospitals, auditoriums and churches

25–3030–3535–40

Classrooms and lecture roomsApartments and hotelsPrivate offices and conference rooms

35–4035–4540–45

StoresResidence (radio, TV off)

and small officesMedium office (3 to 10 desks)

45–55

5358

Residence (radio, TV on)Large store (5 or more clerks)Factory office

606161

Large officeAverage factoryAverage street

647080

Table 1.4-11. Maximum Average Sound Levels—Decibels

Because values given in Table 1.4-11 are in general higher than those givenin Table 1.4-10, the difference must beattenuated by distance and by proper

use of materials in the design of thebuilding. An observer may believethat a transformer is noisy becausethe level in the room where it islocated is high. Two transformers ofthe same sound output in the sameroom increase the sound level in theroom approximately 3 dB, and threetransformers by about 5 dB, etc.

Sounds due to structure-transmittedvibrations originating from the trans-former are lowered by mounting thetransformers on vibration dampenersor isolators. There are a number ofdifferent sound vibration isolatingmaterials that may be used with

good results. Dry-type power trans-formers are often built with an isolatormounted between the transformersupport and case members. Thenatural period of the core and coilstructure when mounted on vibrationdampeners is about 10% of the funda-mental frequency. The reduction in the

transmitted vibration is approximately98%. If the floor or beams beneaththe transformer are light and flexible,the isolator must be softer or have

improved characteristics in order tokeep the transmitted vibrations to aminimum. (Enclosure covers andventilating louvers are often improp-erly tightened or gasketed andproduce unnecessary noise.) Thebuilding structure will assist thedampeners if the transformer ismounted above heavy floor membersor if mounted on a heavy floor slab.Positioning of the transformer inrelation to walls and other reflectingsurfaces has a great effect on reflectednoise and resonances. Often, placingthe transformer at an angle to the wall,rather than parallel to it, will reducenoise. Electrical connections to asubstation transformer shouldbe made with flexible braid orconductors; connections to anindividually mounted transformershould be in flexible conduit.

kVA Liquid-Filled Transformers Dry-Type Transformers

Self-CooledRating (OA)

Forced-AirCooled Rating (FA)

Self-CooledRating (AA)

Forced-AirCooled Rating (FA)

300500

750

5556

58

—67

67

5860

64

6767

67

100015002000

586061

676767

646566

676869

250030003750

626364

676767

686870

717173

500060007500

656667

676869

717273

737475

10,000 68 70 — 76



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IEEE Protective Relay Numbers095

Table 1.5-1. Selected IEEE Device Numbers for Switchgear Apparatus

DeviceNumber

Function Definition TypicalUses

2 Time-delay starting or closing relay A device that functions to give a desired amountof time delay before or after any point of operationin a switching sequence or protective relay system,

except as specifically provided by device functions48, 62 and 79 described later.

Used for providing a time-delay forre-transfer back to the normal sourcein an automatic transfer scheme.

6 Starting circuit breaker A device whose principal function is to connecta machine to its source of starting voltage.

—

19 Starting to running transition timer A device that operates to initiate or cause theautomatic transfer of a machine from the startingto the running power connection.

Used to transfer a reduced voltagestarter from starting to running.

21 Distance relay A device that functions when the circuitadmittance, impedance or reactance increases ordecreases beyond predetermined limits.

—

23 Temperature control device A device that functions to raise or to lower thetemperature of a machine or other apparatus, orof any medium, when its temperature falls belowor rises above, a predetermined level.

Used as a thermostat to controlspace heaters in outdoor equipment.

24 Volts per hertz relay A device that operates when the ratio of voltageto frequency is above a preset value or is belowa different preset value. The relay may have any

combination of instantaneous or time delayedcharacteristics.

—

25 Synchronizing or synchronism check device A device that operates when two AC circuits arewithin the desired limits of frequency, phase angleor voltage, to permit or cause the paralleling ofthese two circuits.

In a closed transition breakertransfer, a 25 relay is used to ensuretwo-sources are synchronized beforeparalleling.Eaton FP-5000/EDR-5000feeder protective relays.

27 Undervoltage relay A device which functions on a given value ofundervoltage.

Used to initiate an automatic transferwhen a primary source of power is lost.Eaton FP-5000/FP-4000/MP-4000/EDR-5000/EDR-4000 protective relays.

30 Annunciator relay A non-automatically reset device that gives anumber of separate visual indications upon thefunctioning of protective devices, and which mayalso be arranged to perform a lockout function.

Used to remotely indicate that aprotective relay has functioned, orthat a circuit breaker has tripped.Typically, a mechanical “drop” typeannunciator panel is used.

32 Directional power relay A relay that functions on a desired value of powerflow in a given direction, or upon reverse power

resulting from arc back in the anode or cathodecircuits of a power rectifier.

Used to prevent reverse power fromfeeding an upstream fault. Often

used when primary backup generationis used in a facility. Eaton FP-5000/EDR-5000 protective relays.

33 Position switch A device that makes or breaks contact when themain device or piece of apparatus, which has nodevice function number, reaches a given point.

Used to indicate the position of adrawout circuit breaker (TOC switch).

34 Master sequence device A device such as a motor-operated multi-contactswitch, or the equivalent, or a programmabledevice, that establishes or determines the operatingsequence of the major devices in equipmentduring starting and stopping, or during sequentialswitching operations.

—

37 Undercurrent or underpower relay A relay that functions when the current or powerflow decreases below a predetermined value.

Eaton MP-3000/MP-4000/EMR-3000motor protective relays.

38 Bearing protective device A device that functions on excessive bearingtemperature, or on other abnormal mechanicalconditions, such as undue wear, which mayeventually result in excessive bearing temperature.

Eaton MP-3000/MP-4000 motorprotective relays.

40 Field relay A device that functions on a given or abnormallyhigh or low value or failure of machine field current,or on an excessive value of the reactive componentof armature current in an AC machine indicatingabnormally high or low field excitation.

—

41 Field circuit breaker A device that functions to apply, or to remove,the field excitation of a machine.

—

42 Running circuit breaker A device whose function is to connect a machineto its source of running or operating voltage.This function may also be used for a device, suchas a contactor, that is used in series with a circuitbreaker or other fault-protecting means, primarilyfor frequent opening and closing of the circuit.

—



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Table 1.5-1. Selected IEEE Device Numbers for Switchgear Apparatus (Continued)

DeviceNumber


43 Manual transfer or selector device A manually operated device that transfers controlor potential circuits in order to modify the plan ofoperation of the associated equipment or of some

of the associated devices.

—

44 Unit sequence starting relay A device that functions to start the next availableunit in multiple-unit equipment upon the failure ornon-availability of the normally preceding unit.

—

46 Reverse-phase, or phase balance,current relay

A relay that functions when the polyphasecurrents are of reverse-phase sequence, or whenthe polyphase currents are unbalanced or containthe negative phase-sequence components abovea given amount.

Eaton FP-5000/FP-4000/EDR-5000/EDR-4000 feeder protective relays andMP-3000/MP-4000/EMR-3000 motorprotective relays.

47 Phase-sequence voltage relay A relay that functions upon a predeterminedvalue of polyphase voltage in the desired phasesequence.

Eaton FP-5000/FP-4000/EDR-5000/EDR-4000 feeder protective relaysand MP-3000/MP-4000 motorprotective relays.

48 Incomplete sequence relay A relay that generally returns the equipment to thenormal, or off, position and locks it out of thenormal starting, or operating or stopping sequenceis not properly completed within a predeterminedamount of time. If the device is used for alarm

purposes only, it should preferably be designatedas 48A (alarm).

—

49 Machine, or transformer, thermal relay A relay that functions when the temperature of amachine armature, or other load carrying windingor element of a machine, or the temperatureof a power rectifier or power transformer(including a power rectifier transformer) exceedsa predetermined value.

Eaton MP-3000/MP-4000/EMR-3000/ETR-4000 motor protective relays.

50 Instantaneous overcurrent,or rate-of-rise relay

A relay that functions instantaneously on anexcessive value of current, or an excessive rate ofcurrent rise, thus indicating a fault in the apparatusof the circuit being protected.

Used for tripping a circuit breakerinstantaneously during a high-levelshort circuit. Can trip on phase-phase (50), phase-neutral (50N),phase-ground (50G) faults.Eaton Digitrip 3000, FP-5000/FP-4000/EDR-5000/EDR-4000/EDR-3000 protective relays,MP-3000/MP-4000/EMR-3000/ETR-4000 motor protective relays.

51 AC time overcurrent relay A relay with either a definite or inverse timecharacteristic that functions when the current in anAC circuit exceeds a predetermined value.

Used for tripping a circuit breakerafter a time delay during a sustainedovercurrent. Used for tripping acircuit breaker instantaneouslyduring a high-level short circuit.Can trip on phase (51), neutral (51N)or ground (51G) overcurrents.Eaton Digitrip 3000, FP-5000/FP-4000/EDR-5000/EDR-4000/EDR-3000 protective relays,MP-3000/MP-4000/EMR-3000/ETR-4000 motor protective relays.

52 AC circuit breaker A device that is used to close and interrupt anAC power circuit under normal conditions or tointerrupt this circuit under fault or emergencyconditions.

A term applied typically to mediumvoltage circuit breakers, or lowvoltage power circuit breakers.Eaton VCP-W vacuum circuitbreaker, magnum DS low voltagepower circuit breaker

53 Exciter or DC generator relay A device that forces the DC machine field excitationto build up during starting or that functions whenthe machine voltage has built up to a given value.

—

55 Power factor relay A relay that operates when the power factorin an AC circuit rises above or below apredetermined value.

Eaton FP-5000/FP-4000/EDR-5000feeder protective relays and MP-4000motor protective relay.

56 Field application relay A device that automatically controls the applicationof the field excitation to an AC motor at somepredetermined point in the slip cycle.

—

59 Overvoltage relay A relay that functions on a given value ofovervoltage.

Used to trip a circuit breaker,protecting downstream equipmentfrom sustained overvoltages.Eaton FP-5000/FP-4000/EDR-5000feeder protective relays and MP-4000motor protective relay.




1September 2011


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Reference Data



DeviceNumber


60 Voltage or current balance relay A relay that operates on a given difference involtage, or current input or output of two circuits.

—

62 Time-delay stopping or opening relay A time-delay relay that serves in conjunction with

the device that initiates the shutdown, stoppingor opening operation in an automatic sequence.

Used in conjunction with a 27 device

to delay tripping of a circuit breakerduring a brief loss of primary voltage,to prevent nuisance tripping.

63 Pressure switch A switch that operates on given values or on agiven rate of change of pressure.

Used to protect a transformer duringa rapid pressure rise during a shortcircuit. This device will typically actto open the protective devices aboveand below the transformer. Typicallyused with a 63-X auxiliary relay totrip the circuit breaker.

64 Ground protective relay A relay that functions on a failure of the insulationof a machine, transformer or of other apparatus toground, or on flashover of a DC machine to ground.

Used to detect and act on a ground-fault condition. In a pulsing highresistance grounding system, a 64device will initiate the alarm.

65 Governor A device consisting of an assembly of fluid,electrical or mechanical control equipment used forregulating the flow of water, steam or other mediato the prime mover for such purposes as starting,

holding speed or load, or stopping.

—

66 Notching or jogging device A device that functions to allow only a specifiednumber of operations of a given device, orequipment, or a specified number of successiveoperations within a given time of each other. It alsofunctions to energize a circuit periodically or forfractions of specified time intervals, or that is usedto permit intermittent acceleration or jogging of amachine at low speeds for mechanical positioning.

Eaton MP-3000/MP-4000/EMR-3000motor protective relays.

67 AC directional overcurrent relay A relay that functions on a desired value of ACovercurrent flowing in a predetermined direction.

Eaton FP-5000/EDR-5000 feederprotective relays.

69 Permissive control device A device that is generally a two-position manuallyoperated switch that in one position permits theclosing of a circuit breaker, or the placing ofequipment into operation, and in the other positionprevents the circuit breaker to the equipment frombeing operated.

Used as a remote-local switch forcircuit breaker control.

71 Level switch A switch that operates on given values, or on agiven rate of change of level. Used to indicate a low liquid level withina transformer tank in order to savetransformers from loss-of-insulationfailure. An alarm contact is availableas a standard option on a liquid levelgauge. It is set to close before an unsafecondition actually occurs.

72 DC circuit breaker A device that is used to close and interrupt aDC power circuit under normal conditions or tointerrupt this circuit under fault or emergencyconditions.

—

73 Load-resistor contactor A device that is used to shunt or insert a step ofload limiting, shifting or indicating resistance ina power circuit; to switch a space heater in circuit;or to switch a light or regenerative load resistorof a power rectifier or other machine in and outof circuit.

—

74 Alarm relay A device other than an annunciator, as covered

under device number 30, which is used to operate,or to operate in connection with, a visible oraudible alarm.

—

78 Phase-angle measuring relay A device that functions at a predetermined phaseangle between two voltages, between two currents,or between voltage and current.

—

79 AC reclosing relay A relay that controls the automatic closing andlocking out of an AC circuit interrupter.

Used to automatically reclose acircuit breaker after a trip, assumingthe fault has been cleared after thepower was removed from the circuit.The recloser will lock-out after apredetermined amount of failedattempts to reclose.



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DeviceNumber


81 Frequency relay A relay that functions on a predetermined value offrequency—either under or over, or on normalsystem frequency—or rate of change frequency.

Used to trip a generator circuitbreaker in the event the frequencydrifts above or below a given value.

Eaton FP-5000/FP-4000/EDR-5000/EDR-4000 feeder protectiverelays and MP-4000 motorprotective relay.

83 Automatic selective control or transfer relay A relay that operates to select automaticallybetween certain sources or conditions inequipment, or performs a transfer operationautomatically.

Used to transfer control powersources in a double-endedswitchgear lineup.

85 Carrier or pilot-wire relay A device that is operated or restrained by a signaltransmitted or received via any communicationsmedia used for relaying.

—

86 Locking-out relay An electrically operated hand, or electrically, resetrelay that functions to shut down and hold anequipment out of service on the occurrence ofabnormal conditions.

Used in conjunction with protectiverelays to lock-out a circuit breaker(or multiple circuit breakers) aftera trip. Typically required to bemanually reset by an operator beforethe breaker can be reclosed.

87 Differential protective relay A protective relay that functions on a percentage or

phase angle or other quantitative difference of twocurrents or of some other electrical quantities.

Used to protect static equipment,

such as cable, bus or transformers,by measuring the current differentialbetween two points. Typically theupstream and/or downstream circuitbreaker will be incorporated into the“zone of protection.” Eaton FP-5000feeder protective relay (87B) andMD-3000 protective relay.

90 Regulating device A device that functions to regulate a quantity orquantities, such as voltage, current, power, speed,frequency, temperature and load, at a certain valueor between certain (generally close) limits formachines, tie lines or other apparatus.

—

91 Voltage directional relay A device that operates when the voltage across anopen circuit breaker or contactor exceeds a givenvalue in a given direction.

—

94 Tripping or trip-free relay A relay that functions to trip a circuit breaker,contactor or equipment, or to permit immediate

tripping by other devices, or to prevent immediatereclosure of a circuit interrupter, in case it shouldopen automatically even though its closing circuitis maintained closed.

—




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Reference Data

Suggested IEEE Designations for Suffix Letters099

Suggested IEEE Designationsfor Suffix Letters

Auxiliary Devices

These letters denote separate auxiliary

devices, such as the following:

C Closing relay/contactor

CL Auxiliary relay, closed(energized when main deviceis in closed position)

CS Control switch

D “Down” position switch relay

L Lowering relay

O Opening relay/contactor

OP Auxiliary relay, open(energized when main deviceis in open position)

PB Push button

R Raising relay

U “UP” position switch relay

X Auxiliary relay

Y Auxiliary relay

Z Auxiliary relay

Actuating Quantities

These letters indicate the condition orelectrical quantity to which the deviceresponds, or the medium in which it islocated, such as the following:

A Amperes/alternating

C Current

F Frequency/fault

I0 Zero sequence current

I-, I2 Negative sequence current

I+, I1 Positive sequence current

P Power/pressure

PF Power factor

S Speed

T TemperatureV Voltage/volts/vacuum

VAR Reactive power

VB Vibration

W Watts

Main DeviceThe following letters denote the maindevice to which the numbered deviceis applied or is related:

A Alarm/auxiliary power

AC Alternating current

BP Bypass

BT Bus tie

C Capacitor

DC Direct current

E Exciter

F Feeder/field

G Generator/ground

M Motor/metering

MOC Mechanism operated contact

S Synchronizing/secondary

T Transformer

TOC Truck-operated contacts

Main Device Parts

These letters denote parts of themain device, except auxiliary contacts,position switches, limit switches andtorque limit switches:

C Coil/condenser/capacitor

CC Closing coil/closing contactor

HC Holding coil

M Operating motor

OC Opening contactor

S Solenoid

SI Seal-in

T Target

TC Trip coil

Other Suffix LettersThe following letters cover all otherdistinguishing features, characteris-tics or conditions not specificallydescribed in Auxiliary Devices throughMain Device Parts, which serve to

describe the use of the device in theequipment, such as:

A Automatic

BF Breaker failure

C Close

D Decelerating/down

E Emergency

F Failure/forward

HS High speed

L Local/lower

M ManualO Open

OFF Off

ON On

R Raise/reclosing/remote/reverse

T Test/trip

TDC Time-delay closing contact

TDDO Time delayed relay coildrop-out

TDO Time-delay opening contact

TDPU Time delayed relay coil pickup

THD Total harmonic distortion



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Codes and Standards100

Codes and StandardsThe National Electrical Code (NEC),NFPA Standard No. 70, is the mostprevalent electrical code in the UnitedStates. The NEC, which is revised everythree years, has no legal standing of

its own, until it is adopted as law bya jurisdiction, which may be a city,county or state. Most jurisdictionsadopt the NEC in its entirety; someadopt it with variations, usually morerigid, to suit local conditions andrequirements. A few large cities, suchas New York and Chicago, have theirown electrical codes, basically similarto the NEC. The designer must deter-mine which code applies in the areaof a specific project.

The Occupational Safety and HealthAct (OSHA) of 1970 sets uniformnational requirements for safety in the

workplace—anywhere that people areemployed. Originally OSHA adoptedthe 1971 NEC as rules for electricalsafety. As the NEC was amended everythree years, the involved process formodifying a federal law such as OSHAmade it impossible for the act to adopteach new code revision. To avoid thisproblem, the OSHA administrationin 1981 adopted its own code, a con-densed version of the NEC containingonly those provisions consideredrelated to occupational safety. OSHAwas amended to adopt this code,based on NFPA Standard 70E, Part 1,which is now federal law.

The NEC is a minimum safetystandard. Efficient and adequatedesign usually requires not justmeeting, but often exceeding NECrequirements to provide an effective,reliable, economical electrical system.

Many equipment standards have beenestablished by the National ElectricalManufacturers’ Association (NEMA)and the American National StandardsInstitute (ANSI). UnderwritersLaboratories (UL) has standards thatequipment must meet before UL willlist or label it. Most jurisdictions andOSHA require that where equipment

listed as safe by a recognized labora-tory is available, unlisted equipmentmay not be used. UL is by far the mostwidely accepted national laboratory,although Factory Mutual InsuranceCompany lists some equipment, and

a number of other testing laboratorieshave been recognized and accepted.The Institute of Electrical and ElectronicEngineers (IEEE) publishes a numberof books (the “color book” series) onrecommended practices for the design

of industrial buildings, commercialbuildings, emergency power systems,grounding, and the like. Most of theseIEEE standards have been adopted asANSI standards. They are excellentguides, although they are not in anyway mandatory.

A design engineer should conformto all applicable codes, and requireequipment to be listed by UL oranother recognized testing laboratorywherever possible, and to meetANSI or NEMA standards. ANSI/IEEE

recommended practices shouldbe followed to a great extent. Inmany cases, standards should beexceeded to get a system of thequality required. The design goalshould be a safe, efficient, long-lasting, flexible and economicalelectrical distribution system.

Professional Organizations

American National Standards Institute (ANSI)

Headquarters:

1819 L Street, NW6th Floor

Washington, DC 20036202-293-8020

Operations:

25 West 43rd Street4th FloorNew York, NY 10036212-642-4900

www.ansi.org

Institute of Electrical and Electronic Engineers (IEEE)

Headquarters:

3 Park Avenue17th Floor

New York, NY 10016-5997212-419-7900

Operations:

445 Hoes LanePiscataway, NJ 08854-1331732-981-0060

www.ieee.org

International Association of Electrical Inspectors (IAEI)

901 Waterfall WaySuite 602Richardson, TX 75080-7702972-235-1455

www.iaei.org

National Electrical Manufacturers Association (NEMA)

1300 North 17th StreetSuite 1847Rosslyn, VA 22209703-841-3200

www.nema.org

National Fire Protection Association (NFPA)

1 Battery March ParkQuincy, MA 02169-7471617-770-3000

www.nfpa.org

Underwriters Laboratories (UL)

333 Pfingsten RoadNorthbrook, IL 60062-2096847-272-8800

www.ul.com

International Code Council (ICC)

5203 Leesburg PikeSuite 600Falls Church, VA 220411-888-422-7233

www.iccsafe.org

The American Institute of Architects (AIA)

1735 New York Avenue, NWWashington, DC 20006-5292202-626-7300

www.aia.org

http://www.ansi.org/

http://www.ieee.org/

http://www.iaei.org/

http://www.nema.org/

http://www.nfpa.org/

http://www.ul.com/

http://www.iccsafe.org/

http://www.aia.org/

http://www.nema.org/

http://www.ul.com/

http://www.nfpa.org/

http://www.ansi.org/

http://www.ieee.org/

http://www.iccsafe.org/

http://www.aia.org/

http://www.iaei.org/




1September 2011


Sheet 01

Reference Data

Motor Protective Device Data101

Motor ProtectionConsistent with the 2011 NEC430.6(A)(1) circuit breaker, HMCP andfuse rating selections are based onfull load currents for induction motorsrunning at speeds normal for belted

motors and motors with normaltorque characteristics using data takenfrom NEC Table 430.250 (three-phase).Actual motor nameplate ratings shallbe used for selecting motor runningoverload protection. Motors builtspecial for low speeds, high torquecharacteristics, special startingconditions and applications willrequire other considerations asdefined in the application sectionof the NEC.

These additional considerations mayrequire the use of a higher rated HMCP,or at least one with higher magnetic

pickup settings.Circuit breaker, HMCP and fuseampere rating selections are inline with maximum rules given inNEC 430.52 and Table 430.250. Basedon known characteristics of Eaton typebreakers, specific units are recom-mended. The current ratings are nomore than the maximum limits set bythe NEC rules for motors with codeletters F to V or without code letters.Motors with lower code letters willrequire further considerations.

In general, these selections werebased on:

1. Ambient—outside enclosure notmore than 40°C (104°F).

2. Motor starting—infrequentstarting, stopping or reversing.

3. Motor accelerating time—10 seconds or less.

4. Locked rotor—maximum 6 timesmotor FLA.

Type HMCP motor circuit protectormay not set at more than 1300% ofthe motor full-load current to complywith NEC 430.52. (Except for NEMADesign B energy high-efficiency

motors that can be set up to 1700%.)

Circuit breaker selections are basedon types with standard interruptingratings. Higher interrupting rating typesmay be required to satisfy specificsystem application requirements.

For motor full load currents of208V and 200V, increase thecorresponding 230V motor valuesby 10 and 15% respectively.

Table 1.5-2. Motor Circuit Protector (MCP), Circuit Breaker and Fusible Switch Selection Guide

Horsepower Full LoadAmperes(NEC) FLA

Fuse Size NEC 430.52MaximumAmperes

Recommended Eaton

CircuitBreaker

Motor CircuitProtector Type HMCP

Time Delay Non-Time Delay Amperes Amperes Adj. Range

230V, Three-Phase

1 1-1/2 2 3

3.6 5.2 6.8 9.6

10 10 15 20

15 20 25 30

15 15 15 20

7 15 15 30

21–70 45–150 45–150 90–300

5 7-1/2 10 15

15.2 22 28 42

30 40 50 80

50 70 90 150

30 50 60 90

30 50 50 70

90–300 150–500 150–500 210–700

20 25 30 40

54 68 80104

100 125 150 200

175 225 250 350

100125150150

100150150150

300–1000 450–1500 450–1500 750–2500

50 60 75100

130154192248

250 300 350 450

400 500 600 800

200225300400

150250400400

750–25001250–25002000–40002000–4000

125

150200

312

360480

600

7001000

1000

12001600

500

600700

600

600600

1800–6000

1800–60001800–6000

460V, Three-Phase

1 1-1/2 2 3

1.8 2.6 3.4 4.8

6 6 6 10

6 10 15 15

15 15 15 15

7 7 7 15

21–70 21–70 21–70 45–150

5 7-1/2 10 15

7.6 11 14 21

15 20 25 40

25 35 45 70

15 25 35 45

15 30 30 50

45–150 90–300 90–300 150–500

20 25 30 40

27 34 40 52

50 60 70 100

90 110 125 175

50 70 70100

50 70100100

150–500 210–700 300–1000 300–1000

50 60

75100

65 77

96124

125 150

175 225

200 150

300 400

110125

150175

150150

150150

450–1500 750–2500

750–2500 750–2500

125150200

156180240

300 350 450

500 600 800

225250350

250400400

1250–25002000–40002000–4000

575V, Three-Phase

1 1-1/2 2 3

1.4 2.1 2.7 3.9

3 6 6 10

6 10 10 15

15 15 15 15

3 7 7 7

9–30 21–70 21–70 21–70

5 7-1/2 10 15

6.1 9 11 17

15 20 20 30

20 30 35 60

15 20 25 40

15 15 30 30

45–150 45–150 90–300 90–300

20 25 30 40

22 27 32 41

40 50 60 80

70 90 100 125

50 60 60 80

50 50 50100

150–500 150–500 150–500 300–1000

50 60 75100

52 62 77 99

100 110 150 175

175 200 250 300

100125150175

100150150150

300–1000 750–2500 750–2500 750–2500

125150200

125144192

225 300 350

400 450 600

200225300

250250400

1250–25001250–25002000–4000

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.5-8


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Sheet 01

Reference Data

Motor Protective Device Data102

Table 1.5-3. 60 Hz, Recommended Protective Setting for Induction Motors

Consult fuse manufacturer’s catalog for smaller fuse ratings. Types are for minimum interrupting capacity breakers. Ensure that the fault duty does not exceed breaker’s I.C.

hp Full LoadAmperes(NEC) FLA

Minimum Wire Size75°C Copper Ampacityat 125% FLA

Minimum Conduit Size,Inches (mm)

Fuse Size NEC 430.52Maximum Amperes

Recommended Eaton:

CircuitBreaker

Amperes

Motor CircuitProtectorTHW THWN

XHHNTimeDelay

Non-TimeDelaySize Amperes Amperes Adjustable Range

115V, Single-Phase

3/411-1/2

13.81620

141412

202030

0.50 (12.7)0.50 (12.7)0.50 (12.7)

0.50 (12.7)0.50 (12.7)0.50 (12.7)

253035

455060

303540

Two-pole devicenot available

2357-1/2

24345680

10843

305085

100

0.50 (12.7)0.75 (19.1)1.00 (25.4)1.00 (25.4)

0.50 (12.7)0.50 (12.7)0.75 (19.1)1.00 (25.4)

4560

100150

80110175250

5070

100150

230V, Single-Phase

3/411-1/2

6.98

10

141414

202020

0.50 (12.7)0.50 (12.7)0.50 (12.7)

0.50 (12.7)0.50 (12.7)0.50 (12.7)

151520

252530

152025

Two-pole devicenot available

2357-1/2

12172840

1412108

20305050

0.50 (12.7)0.50 (12.7)0.50 (12.7)0.75 (19.1)

0.50 (12.7)0.50 (12.7)0.50 (12.7)0.50 (12.7)

25305070

406090

125

30406080

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1September 2011


Sheet 01

Reference Data

Chart of Short Circuit Currents for Transformers103

Table 1.5-4. Secondary Short-Circuit Current of Typical Power Transformers

Short-circuit capacity values shown correspond to kVA and impedances shown in this table. For impedances other than these, short-circuit currentsare inversely proportional to impedance.

The motor’s short-circuit current contributions are computed on the basis of motor characteristics that will give four times normal current.For 208V, 50% motor load is assumed while for other voltages 100% motor load is assumed. For other percentages, the motor short-circuitcurrent will be in direct proportion.

Trans-formerRatingThree-PhasekVA andImpedancePercent

MaximumShort-CircuitkVAAvailablefromPrimarySystem

208V, Three-Phase 240V, Three-Phase 480V, Three-Phase 600V, Three-Phase

RatedLoadContin-uousCurrent,

Amps

Short-Circuit Currentrms Symmetrical Amps


Amps



Amps



Amps


Trans-formerAlone

50%MotorLoad

Com-bined

Trans-formerAlone

100%MotorLoad

Com-bined

Trans-formerAlone

100%MotorLoad

Com-bined

Trans-formerAlone

100%MotorLoad

Com-bined

3005%

50,000100,000150,000

834834834

14,90015,70016,000

170017001700

16,60017,40017,700

722722722

12,90013,60013,900

290029002900

15,80016,50016,800

361361361

640068006900

140014001400

780082008300

289289289

520055005600

120012001200

640067006800

250,000500,000Unlimited

834834834

16,30016,50016,700

170017001700

18,00018,20018,400

722722722

14,10014,30014,400

290029002900

17,00017,20017,300

361361361

700071007200

140014001400

840085008600

289289289

560057005800

120012001200

680069007000

5005%

50,000100,000150,000

138813881388

21,30025,20026,000

280028002800

25,90028,00028,800

120312031203

20,00021,90022,500

480048004800

24,80026,70027,300

601601601

10,00010,90011,300

240024002400

12,40013,30013,700

481481481

800087009000

190019001900

990010,60010,900

250,000500,000Unlimited

138813881388

26,70027,20027,800

280028002800

29,50030,00030,600

120312031203

23,10023,60024,100

480048004800

27,90028,40028,900

601601601

11,60011,80012,000

240024002400

14,00014,20014,400

481481481

930094009600

190019001900

11,20011,30011,500

7505.75%

50,000100,000150,000

208020802080

28,70032,00033,300

420042004200

32,90036,20037,500

180418041804

24,90027,80028,900

720072007200

32,10035,00036,100

902902902

12,40013,90014,400

360036003600

16,00017,50018,000

722722722

10,00011,10011,600

290029002900

12,90014,00014,500

250,000

500,000Unlimited

2080

20802080

34,400

35,20036,200

4200

42004200

38,600

39,40040,400

1804

18041804

29,800

30,60031,400

7200

72007200

37,000

37,80038,600

902

902902

14,900

15,30015,700

3600

36003600

18,500

18,90019,300

722

722722

11,900

12,20012,600

2900

29002900

14,800

15,10015,500

10005.75%

50,000100,000150,000

277627762776

35,90041,20043,300

560056005600

41,50046,80048,900

240624062406

31,00035,60037,500

980098009800

40,60045,20047,100

120312031203

15,50017,80018,700

480048004800

20,30022,60023,500

962962962

12,40014,30015,000

390039003900

16,30018,20018,900

250,000500,000Unlimited

277627762776

45,20046,70048,300

560056005600

50,80052,30053,900

240624062406

39,10040,40041,800

980098009800

48,70050,00051,400

120312031203

19,60020,20020,900

480048004800

24,40025,00025,700

962962962

15,60016,20016,700

390039003900

19,50020,10020,600

15005.75%

50,000100,000150,000

416441644164

47,60057,50061,800

830083008300

55,90065,80070,100

360936093609

41,20049,80053,500

14,40014,40014,400

55,60064,20057,900

180418041804

20,60024,90026,700

720072007200

27,80032,10033,900

144414441444

16,50020,00021,400

580058005800

22,30025,80027,200

250,000500,000Unlimited

416441644164

65,60068,80072,500

830083008300

73,90077,10080,800

360936093609

56,80059,60062,800

14,40014,40014,400

71,20074,00077,200

180418041804

28,40029,80031,400

720072007200

35,60037,00038,600

144414441444

22,70023,90025,100

580058005800

28,50029,70030,900

20005.75%

50,000100,000150,000

———

———

———

———

———

———

———

———

240624062406

24,70031,00034,000

960096009600

34,30040,60043,600

192419241924

19,70024,80027,200

780078007800

27,50032,60035,000

250,000

500,000Unlimited

—

——

—

——

—

——

—

——

—

——

—

——

—

——

—

——

2406

24062406

36,700

39,10041,800

9600

96009600

46,300

48,70051,400

1924

19241924

29,400

31,30033,500

7800

78007800

37,200

39,10041,300

25005.75%

50,000100,000150,000

———

———

———

———

———

———

———

———

300830083008

28,00036,50040,500

12,00012,00012,000

40,00048,50052,500

240524052405

22,40029,20032,400

960096009600

32,00038,80042,000

250,000500,000Unlimited

———

———

———

———

———

———

———

———

300830083008

44,60048,10052,300

12,00012,00012,000

56,60060,10064,300

240524052405

35,60038,50041,800

960096009600

45,20048,10051,400

30005.75%

50,000100,000150,000

———

———

———

———

———

———

———

———

360936093609

30,70041,20046,600

14,00014,00014,000

44,70055,20060,600

288628862886

24,60033,00037,300

11,50011,50011,500

36,10044,50048,800

250,000500,000Unlimited

———

———

———

———

———

———

———

———

360936093609

51,90056,80062,800

14,00014,00014,000

65,90070,80076,800

288628862886

41,50045,50050,200

11,50011,50011,500

53,00057,00061,700

37505.75%

50,000100,000150,000

———

———

———

———

———

———

———

———

451145114511

34,00047,50054,700

18,00018,00018,000

52,00065,50072,700

360836083608

27,20038,00043,700

14,40014,40014,400

41,60052,40058,100

250,000

500,000Unlimited

—

——

—

——

—

——

—

——

—

——

—

——

—

——

—

——

4511

45114511

62,200

69,40078,500

18,000

18,00018,000

80,200

87,40096,500

3608

36083608

49,800

55,50062,800

14,400

14,40014,400

64,200

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.5-10


September 2011


i

2

3

4

5

6

7

8

9

0

1

2

3

4

5

6

7

8

9

0

1

Sheet 01

Reference Data

Transformer Full Load Amperes104

Table 1.5-5. Transformer Full-Load Current, Three-Phase, Self-Cooled Ratings

Voltage, Line-to-Line

kVA 208 240 480 600 2400 4160 7200 12,000 12,470 13,200 13,800 22,900 34,400

304575

83.3125208

72.2108180

36.154.190.2

28.943.372.2

7.2210.818.0

4.166.25

10.4

2.413.616.01

1.442.173.61

1.392.083.47

1.311.973.28

1.261.883.14

0.751.131.89

0.500.761.26

112-1/2150225

312416625

271361541

135180271

108144217

27.136.154.1

15.620.831.2

9.0212.018.0

5.417.22

10.8

5.216.94

10.4

4.926.569.84

4.716.289.41

2.843.785.67

1.892.523.78

300500750

83313882082

72212031804

361601902

289481722

72.2120180

41.669.4

104

24.140.160.1

14.424.136.1

13.923.134.7

13.121.932.8

12.620.931.4

7.5612.618.9

5.048.39

12.6

100015002000

27764164—

240636084811

120318042406

96214431925

241361481

139208278

80.2120160

48.172.296.2

46.369.492.6

43.765.687.5

41.862.883.7

25.237.850.4

16.825.233.6

250030003750

———

———

300736094511

240628873608

601722902

347416520

200241301

120144180

116139174

109131164

105126157

63.075.694.5

42.050.462.9

50007500

10,000

———

———

———

4811——

120318042406

69410411388

401601802

241361481

231347463

219328437

209314418

126189252

83.9126168

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1.5September 2011


Sheet 01

Reference Data

Impedances Data105

Approximate Impedance DataTable 1.5-6. Typical Impedances—Three-Phase Transformers Liquid-Filled

Values are typical. For guaranteed values,refer to transformer manufacturer.

Table 1.5-7. 15 kV Class Primary—Oil Liquid-Filled Substation Transformers

Table 1.5-8. 15 kV Class Primary—Dry-Type Substation Transformers

kVA Liquid-Filled

Network Padmount

37.54550

———

———

75112.5150

———

3.43.22.4

225300500

—5.005.00

3.33.44.6

75010001500

5.005.007.00

5.755.755.75

200025003000

7.007.00—

5.755.756.50

37505000

——

6.506.50

kVA %Z %R %X X/R

65°C Rise

112.5150225

5.005.005.00

1.711.881.84

4.704.634.65

2.752.472.52

300500750

5.005.005.75

1.351.501.41

4.814.775.57

3.573.183.96

100015002000

5.755.755.75

1.331.120.93

5.595.645.67

4.215.046.10

2500 5.75 0.86 5.69 6.61

kVA %Z %R %X X/R

150°C Rise

300500750

4.505.755.75

2.872.662.47

3.475.105.19

1.211.922.11

100015002000

5.755.755.75

2.161.871.93

5.335.445.42

2.472.902.81

2500 5.75 1.74 5.48 3.15

80°C Rise

300500750

4.505.755.75

1.931.441.28

4.065.575.61

2.103.874.38

100015002000

5.755.755.75

0.930.870.66

5.675.685.71

6.106.518.72

2500 5.75 0.56 5.72 10.22

Table 1.5-9. 600V Primary Class Three-PhaseNEMA TP-1 Energy-Efficient Dry-TypeDistribution Transformers, Aluminum Wound

Note: Values are typical. Measurements attemperature rise +20°C.

Table 1.5-10. 600V Primary Class Three-PhaseNEMA TP-1 Energy-Efficient Dry-TypeDistribution Transformers, Copper Wound

Note: Values are typical. Measurements attemperature rise +20ºC.

Table 1.5-11. 600V Primary ClassNEMA Type TP-1 Dry-Type Transformers

kVA %Z %R %X X/R

150°C Rise Aluminum

15

3045

4.8

4.65.1

4.6

3.53.8

1.4

3.03.4

0.30

0.860.91

75112.5150

5.36.05.3

3.52.93.0

4.05.24.4

1.141.791.50

225300500

5.17.67.2

2.62.51.7

4.47.27.0

1.682.884.20

750 8.0 1.5 7.9 5.42

115°C Rise Aluminum

153045

4.44.84.6

4.34.42.8

1.21.83.7

0.270.411.35

75112.5150

5.93.15.2

2.82.52.2

5.11.94.7

1.820.792.16

225300500

6.25.46.6

2.02.01.1

5.84.96.5

2.932.446.09

80°C Rise Aluminum

153045

3.53.43.3

2.62.41.6

2.32.52.9

0.891.021.76

75112.5150

4.34.14.7

1.91.81.4

3.93.74.5

2.052.043.22

225300500

5.66.15.4

1.41.40.8

5.45.95.3

3.774.186.57

kVA %Z %R %X X/R

150°C Rise Copper

15

3045

4.8

5.24.6

4.0

3.13.5

2.6

4.13.0

0.65

1.330.86

75112.5150

4.35.14.3

3.42.92.5

2.54.23.5

0.721.441.39

225300500

7.45.56.8

2.92.41.4

6.84.96.7

2.322.044.86

750 8.2 0.8 8.1 10.13

115°C Rise Copper

153045

4.84.64.4

3.83.03.1

2.93.53.1

0.761.190.99

75112.5150

4.75.04.4

2.72.31.9

3.94.54.0

1.431.982.09

225300500

8.15.26.8

2.61.71.3

7.74.96.6

2.992.805.16

80°C Rise Copper

153045

2.13.03.9

1.72.02.5

1.32.13.1

0.751.051.25

75112.5150

4.33.33.7

2.01.81.8

3.82.83.2

1.931.601.78

225300

5.46.1

1.51.2

5.26.0

3.605.07

kVA Temperature Rise Impedance

300300300

80115150

3.16 at 100ºC3.03 at 135ºC7.06 at 170ºC

500500

115150

5.97 at 135ºC6.04 at 170ºC

750750

115150

7.21 at 135ºCNo test

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.5-12


September 2011


i

2

3

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7

8

9

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2

3

4

5

6

7

8

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0

1

Sheet 01

Reference Data

Transformer Losses106

Transformer Loss DataSee product sections for data.

Transformer Losses at Reduced Loads

Information on losses based on actualtransformer test data can be obtained

from the manufacturer. Transformermanufacturers provide no load wattlosses and total watt losses in accor-dance with ANSI standards. Thecalculated difference between theno load losses and the total lossesare typically described as the loadlosses. Although transformer coilsare manufactured with either aluminumor copper conductors, the industryhas sometimes referred to these loadlosses as the “copper losses.”

Transformer losses for variousloading can be estimated in thefollowing manner. The no load wattlosses of the transformer are due tomagnetization and are presentwhenever the transformer is

energized. The load watt losses arethe difference between the no loadwatt losses and the full load wattlosses. The load watt losses areproportional to I2R and can beestimated to vary with the transformerload by the square of the load current.

For example, the approximate wattsloss data for a 1000 kVA oil-filledsubstation transformer is shown inthe table as having 1800 watts noload losses and 15,100 watts full loadlosses, so the load losses are approxi-mately 13,300 watts (15,100–1800). Thetransformer losses can be calculatedfor various loads as follows.

At 0% load:

1800 watts

At 50% load:

1800 watts + (13,300)(0.5)2 =1800 watts + 3325 watts = 5125 watts

At 100% load:1800 watts + 13,300 watts = 15,100 watts

At 110% load:

1800 watts + (13,300)(1.1)2 =1800 watts + 16,093 watts = 17,893 watts

Because transformer losses varybetween designs and manufacturers,additional losses such as fromcooling fans can be ignored forthese approximations.

Note: 1 watthour = 3.413 Btu.

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1.5September 2011


Sheet 01

Reference Data

Power Equipment Losses and Enclosures/Knockout Dimensions107

Power Equipment LossesTable 1.5-12. Power Equipment Losses

Note: The information provided on powerequipment losses is generic data intendedto be used for sizing of HVAC equipment.

Equipment WattsLoss

Medium Voltage Switchgear (Indoor, 5 and 15 kV)

1200A breaker2000A breaker3000A breaker4000A breaker

600140021003700

Medium Voltage Switchgear (Indoor, 5 and 15 kV)

600A unfused switch1200A unfused switch100A CL fuses

500750840

Medium Voltage Starters (Indoor, 5 kV)

400A starter FVNR800A starter FVNR600A fused switch

1200A fused switch

6001000500800

Low Voltage Switchgear (Indoor, 480V)

800A breaker1600A breaker2000A breaker

40010001500

3200A breaker4000A breaker5000A breaker

240030004700

Fuse limiters—800A CBFuse limiters—1600A CBFuse limiters—2000A CB

200500750

Fuse truck—3200A CBFuse truck—4000A CB

36004500

Structures—3200AStructures—4000AStructures—5000A

400050007000

High resistance grounding 1200

Panelboards (Indoor, 480V)

225A, 42 circuit 300

Low Voltage Busway (Indoor, Copper, 480V)

800A1200A1350A

44 per foot60 per foot66 per foot

1600A2000A2500A

72 per foot91 per foot

103 per foot

3200A4000A5000A

144 per foot182 per foot203 per foot

Motor Control Centers (Indoor, 480V)

NEMA Size 1 starterNEMA Size 2 starterNEMA Size 3 starter

395692

NEMA Size 4 starterNEMA Size 5 starterStructures

124244200

Adjustable Frequency Drives (Indoor, 480V)

Adjustable frequency drives > 96%efficiency

EnclosuresThe following are reproduced from NEMA 250.

Table 1.5-13. Comparison of Specific Applications of Enclosures for Indoor Nonhazardous Locations

These enclosures may be ventilated. These fibers and flying are nonhazardous materials and are not considered the Class III type

ignitable fibers or combustible flyings. For Class III type ignitable fibers or combustible flyings,see the National Electrical Code, Article 500.

Table 1.5-14. Comparison of Specific Applications of Enclosures for Outdoor Nonhazardous Locations

These enclosures may be ventilated. External operating mechanisms are not required to be operable when the enclosure is ice covered. External operating mechanisms are operable when the enclosure is ice covered.

Table 1.5-15. Comparison of Specific Applications of Enclosures for Indoor Hazardous Locations

For Class III type ignitable fibers or combustible flyings, see the National Electrical Code, Article 500. Due to the characteristics of the gas, vapor or dust, a product suitable for one class or group may

not be suitable for another class or group unless so marked on the product.

Note: If the installation is outdoors and/or additional protection is required by Tables 1.5-13 and 1.5-14, a combination-type enclosure is required.

Provides a Degree of Protection Against theFollowing Environmental Conditions

Enclosure Type

1 2 4 4X 5 6 6P 12 12K 13

Incidental contact with the enclosed equipmentFalling dirtFalling liquids and light splashing

■

■

■

■

■

■

■

■

■

■

■

■

■

■

■

■

■

■

■

■

■

■

■

■

■

■

■

■

■

Circulating dust, lint, fibers and flyings Settling airborne dust, lint, fibers and flyings Hosedown and splashing water

■

■

■

■

■

■

■

■

■

■

■

■

■

■

■

■

■

■

■

Oil and coolant seepageOil or coolant spraying and splashingCorrosive agents ■ ■

■ ■ ■

■

Occasional temporary submersionOccasional prolonged submersion

■ ■

■

Provides a Degree of Protection Against theFollowing Environmental Conditions

Enclosure Type

3 3R 3S 4 4X 6 6P

Incidental contact with the enclosed equipmentRain, snow and sleet Sleet

■

■

■

■

■

■

■

■

■

■

■

■

■

■

■

Windblown dustHosedownCorrosive agents

■ ■ ■

■

■

■

■

■

■

■

■

■

Occasional temporary submersionOccasional prolonged submersion

■ ■

■

Provides a Degree of Protection Against

Atmospheres Typically Containing(For Complete Listing, See NFPA 497M)

Class Enclosure Types

7 and 8, Class I Groups

Enclosure Type

9, Class II Groups

A B C D E F G 10

AcetyleneHydrogen, manufactured gasdiethyl ether, ethylene, cyclopropane

III

■

■

■

Gasoline, hexane, butane, naphtha, propane,acetone, toluene, isopreneMetal dustCarbon black, coal dust, coke dust

IIIII

■

■

■

Flour, starch, grain dustFibers, flyings Methane with or without coal dust

IIIIIMSHA

■

■

■

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.5-14


September 2011


i

2

3

4

5

6

7

8

9

0

1

2

3

4

5

6

7

8

9

0

1

Sheet 01

Reference Data

Conductor Resistance, Reactance, Impedance108

Average Characteristics of600V Conductors—Ohms per 1000 ft (305m)

The tables below are average charac-teristics based on data from IEEE

Standard 141-1993. Values fromdifferent sources vary because ofoperating temperatures, wirestranding, insulation materialsand thicknesses, overall diameters,random lay of multiple conductorsin conduit, conductor spacing, andother divergences in materials, testconditions and calculation methods.These tables are for 600V 5 kV and15 kV conductors, at an averagetemperature of 75°C. Other parametersare listed in the notes. For mediumvoltage cables, differences amongmanufacturers are considerablygreater because of the wider variations

in insulation materials and thick-nesses, shielding, jacketing, overalldiameters, and the like. Therefore,data for medium voltage cables shouldbe obtained from the manufacturerof the cable to be used.

Application Notes

■ Resistance and reactance arephase-to-neutral values, based on60 Hz AC, three-phase, four-wiredistribution, in ohms per 100 ft(30m) of circuit length (not total

conductor lengths)■ Based upon conductivity of 100%

for copper, 61% for aluminum

■ Based on conductor temperaturesof 75°C. Reactance values willhave negligible variation withtemperature. Resistance of bothcopper and aluminum conductorswill be approximately 5% lowerat 60°C or 5% higher at 90°C.Data shown in tables may beused without significant errorbetween 60° and 90°C

■ For interlocked armored cable,use magnetic conduit data for

steel armor and non-magneticconduit data for aluminum armor

■

■ For busway impedance data, seeTab 21 of this catalog

■ For PF (power factor) values lessthan 1.0, the effective impedance Ze is calculated from

■ For copper cable data, resistancebased on tinned copper at 60 Hz;600V and 5 kV nonshielded cablebased on varnished cambric insula-tion; 5 kV shielded and 15 kV cablebased on neoprene insulation

■ For aluminum cable data, cable iscross-linked polyethylene insulated

Table 1.5-16. 60 Hz Impedance Data for Three-Phase Copper Cable Circuits, in Approximate Ohms per 1000 ft (305m) at 75ºC (a) Three Single Conductors

Note: More tables on Page 1.5-15.

Z X2

R2+=

Ze R PF X sin (arc cos PF)+×=

Wire Size,AWG orkcmil

In Magnetic Duct In Non-Magnetic Duct

600V and 5 kV Non-Shielded 5 kV Shielded and 15 kV 600V and 5 kV Non-Shielded 5 kV Shielded and 15 kV

R X Z R X Z R X Z R X Z

88 (solid)66 (solid)

0.8110.7860.5100.496

0.07540.07540.06850.0685

0.8140.7900.5150.501

0.8110.7860.5100.496

0.08600.08600.07960.0796

0.8160.7910.5160.502

0.8110.7860.5100.496

0.06030.06030.05480.0548

0.8130.7880.5130.499

0.8110.7860.5100.496

0.06880.06880.06360.0636

0.8140.7890.5140.500

44 (solid)21

0.3210.3120.2020.160

0.06320.06320.05850.0570

0.3270.3180.2100.170

0.3210.3120.2020.160

0.07420.07420.06850.0675

0.3290.3210.2140.174

0.3210.3120.2020.160

0.05060.05060.04670.0456

0.3250.3160.2070.166

0.3210.3120.2020.160

0.05940.05940.05470.0540

0.3260.3180.2090.169

1/02/03/04/0

0.1280.1020.08050.0640

0.05400.05330.05190.0497

0.1390.1150.09580.0810

0.1280.1030.08140.0650

0.06350.06300.06050.0583

0.1430.1210.1010.0929

0.1270.1010.07660.0633

0.04320.04260.04150.0398

0.1340.1100.08710.0748

0.1280.1020.08050.0640

0.05070.05040.04840.0466

0.1380.1140.09390.0792

250300350400

0.05520.04640.03780.0356

0.04950.04930.04910.0490

0.07420.06770.06170.0606

0.05570.04730.03860.0362

0.05700.05640.05620.0548

0.07970.07360.06810.0657

0.05410.04510.03680.0342

0.03960.03940.03930.0392

0.06700.05990.05360.0520

0.05470.04600.03750.0348

0.04560.04510.04500.0438

0.07120.06440.05860.0559

450500600750

0.03220.02940.02570.0216

0.04800.04660.04630.0495

0.05780.05510.05300.0495

0.03280.03000.02640.0223

0.05380.05260.05160.0497

0.06300.05050.05800.0545

0.03040.02760.02370.0194

0.03840.03730.03710.0356

0.04900.04640.04400.0405

0.03120.02840.02460.0203

0.04300.04210.04120.0396

0.05310.05080.04790.0445

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1.5September 2011


Sheet 01

Reference Data

Conductor Resistance, Reactance, Impedance109

Table 1.5-17. 60 Hz Impedance Data for Three-Phase Copper Cable Circuits, in Approximate Ohms per 1000 ft (305m) at 75ºC (b) Three Conductor Cable

Table 1.5-18. 60 Hz Impedance Data for Three-Phase Aluminum Cable Circuits, in Approximate Ohms per 1000 Ft (305m) at 90ºC (a) Three Single Conductors

Table 1.5-19. 60 Hz Impedance Data for Three-Phase Aluminum Cable Circuits, in Approximate Ohms per 1000 ft (30m) at 90ºC (b) Three Conductor Cable


In Magnetic Duct and Steel Interlocked Armor In Non-Magnetic Duct and Aluminum Interlocked Armor



88 (solid)

66 (solid)

0.8110.786

0.5100.496

0.05770.0577

0.05250.0525

0.8130.788

0.5130.499

0.8110.786

0.5100.496

0.06580.0658

0.06100.0610

0.8140.789

0.5140.500

0.8110.786

0.5100.496

0.05030.05030.04570.0457

0.8120.7870.5120.498

0.8110.7860.5100.496

0.05740.05740.05310.0531

0.8130.7880.5130.499

44 (solid)21

0.3210.3120.2020.160

0.04830.04830.04480.0436

0.3250.3160.2070.166

0.3210.3120.2020.160

0.05680.05080.05240.0516

0.3260.3170.2090.168

0.3210.3120.2020.160

0.04220.04220.03900.0380

0.3240.3150.2060.164

0.3210.3120.2020.160

0.04950.04950.04570.0450

0.3250.3160.2070.166

1/02/03/04/0

0.1280.1020.08050.0640

0.04140.04070.03970.0381

0.1350.1100.08980.0745

0.1280.1030.08140.0650

0.04860.04820.04630.0446

0.1370.1140.09360.0788

0.1270.1010.07660.0633

0.03600.03550.03460.0332

0.1320.1070.08410.0715

0.1280.1020.08050.0640

0.04230.04200.04030.0389

0.1350.1100.0900.0749

250300350400

0.05520.04640.03780.0356

0.03790.03770.03730.0371

0.06700.05980.05390.0514

0.05570.04730.03860.0362

0.04360.04310.04270.0415

0.07070.06400.05760.0551

0.05410.04510.03680.0342

0.03300.03290.03280.0327

0.06340.05590.04920.0475

0.05470.04600.03750.0348

0.03800.03760.03750.0366

0.06660.05960.05300.0505

450500600750

0.03220.02940.02570.0216

0.03610.03490.03430.0326

0.04840.04560.04290.0391

0.03280.03000.02640.0223

0.04040.03940.03820.0364

0.05200.04950.04640.0427

0.03040.02760.02370.0197

0.03200.03110.03090.0297

0.04410.04160.03890.0355

0.03120.02840.02460.0203

0.03590.03510.03440.0332

0.04760.04530.04220.0389


In Magnetic Duct In Non-Magnetic Duct



6421

0.8470.5320.3350.265

0.0530.0500.0460.048

0.8490.5340.3380.269

—0.5320.3350.265

—0.0680.0630.059

—0.5360.3410.271

0.8470.5320.3350.265

0.0420.0400.0370.035

0.8480.5340.3370.267

—0.5320.3350.265

—0.0540.0500.047

—0.5350.3390.269

1/02/03/04/0

0.2100.1670.1330.106

0.0430.0410.0400.039

0.2140.1720.1390.113

0.2100.1670.1320.105

0.0560.0550.0530.051

0.2170.1760.1420.117

0.2100.1670.1330.105

0.0340.0330.0370.031

0.2130.1700.1370.109

0.2100.1670.1320.105

0.0450.0440.0420.041

0.2150.1730.1390.113

250300350

400

0.08960.07500.0644

0.0568

0.03840.03750.0369

0.0364

0.09750.08390.0742

0.0675

0.08920.07460.0640

0.0563

0.04950.04790.0468

0.0459

0.1020.08870.0793

0.0726

0.08940.07460.0640

0.0563

0.03070.03000.0245

0.0291

0.09450.08040.0705

0.0634

0.08910.07440.0638

0.0560

0.03960.03830.0374

0.0367

0.09750.08370.0740

0.0700

500600700750

1000

0.04590.03880.03380.03180.0252

0.03550.03590.03500.03410.0341

0.05800.05290.04870.04660.0424

0.04530.03810.03320.03100.0243

0.04440.04310.04230.04190.0414

0.06340.05750.05380.05210.0480

0.04530.03810.03300.03090.0239

0.02840.02870.02800.02730.0273

0.05350.04770.04330.04120.0363

0.04500.03770.03260.03040.0234

0.03550.03450.03380.03350.0331

0.05730.05110.04700.04520.0405


In Magnetic Duct and Steel Interlocked Armor In Non-Magnetic Duct and Aluminum Interlocked Armor



6421

0.8470.5320.3350.265

0.0530.0500.0460.048

0.8490.5340.3380.269

——0.3350.265

——0.0560.053

——0.3400.270

0.8470.5320.3350.265

0.0420.0400.0370.035

0.8480.5340.3370.267

——0.3350.265

——0.0450.042

——0.3380.268

1/0

2/03/04/0

0.210

0.1670.1330.106

0.043

0.0410.0400.039

0.214

0.1720.1390.113

0.210

0.1670.1330.105

0.050

0.0490.0480.045

0.216

0.1740.1410.114

0.210

0.1670.1330.105

0.034

0.0330.0370.031

0.213

0.1700.1370.109

0.210

0.1670.1320.105

0.040

0.0390.0380.036

0.214

0.1710.1380.111

250300350400

0.08960.07500.06440.0568

0.03840.03750.03690.0364

0.09750.08390.07420.0675

0.08950.07480.06430.0564

0.04360.04240.04180.0411

0.1000.08600.07670.0700

0.08940.07460.06400.0563

0.03070.03000.02450.0291

0.09450.08040.07050.0634

0.08930.07450.06400.0561

0.03490.03400.03340.0329

0.09590.08190.07220.0650

500600700750

1000

0.04590.03880.03380.03180.0252

0.03550.03590.03500.03410.0341

0.05800.05290.04870.04660.0424

0.04570.03860.03350.03150.0248

0.03990.03900.03810.03790.0368

0.06070.05490.05070.04930.0444

0.04530.03810.03300.03090.0239

0.02840.02870.02800.02730.0273

0.05350.04770.04330.04120.0363

0.04520.03800.03280.03070.0237

0.03190.03120.03050.03030.0294

0.05530.04920.04480.04310.0378

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.5-16


September 2011


i

2

3

4

5

6

7

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9

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1

2

3

4

5

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9

0

1

Sheet 01

Reference Data

Conductor Ampacities110

Current Carrying Capacities of Copper and Aluminum and Copper-Clad Aluminum ConductorsFrom National Electrical Code (NEC), 2011 Edition (NFPA 70-2011)

Table 1.5-20. Allowable Ampacities of Insulated Conductors Rated 0–2000V, 60° to 90°C (140° to 194°F).Not more than three current-carrying conductors in raceway, cable or earth (directly buried), based on ambient temperature of 30°C (86°F).

See NEC Section 240.4 (D).

Note: For complete details of using Table 1.5-20, see NEC Article 310 in its entirety.

Table 1.5-21. Correction Factors From NFPA 70-2011 (See Table 310.15 [B][2][a])

Size Temperature Rating of Conductor (See Table 310.15 [B][16]) Size

AWG orkcmil

60°C (140°F) 75°C (167°F) 90°C (194°F) 60°C (140°F) 75°C (167°F) 90°C (194°F) AWG orkcmilTypes Types

TW, UF RHW, THHW,THW, THWN,XHHW, USE, ZW

TBS, SA, SIS,FEP, FEPB, MI,RHH, RHW-2,THHN, THHW,THW-2, THWN-2,USE-2, XHH,XHHW, XHHW-2,ZW-2

TW, UF RHW, THHW,THW, THWN,XHHW, USE

TBS, SA, SIS,THHN, THHW,THW-2, THWN-2,RHH, RHW-2,USE-2, XHH,XHHW, XHHW-2,ZW-2

Copper Aluminum or Copper-Clad Aluminum

181614

——15

——20

141825

———

———

———

———

12

10

8

203040

253550

304055

202530

203040

253545

12

10

8

643

557085

6585

100

7595

110

405565

506575

607585

643

211/0

95110125

115130150

130150170

7585

100

90100120

100115135

211/0

2/03/04/0

145165195

175200230

195225260

115130150

135155180

150175205

2/03/04/0

250300350

215240260

255285310

290320350

170190210

205230250

230255280

250300350

400500600

280320355

335380420

380430475

225260285

270310340

305350385

400500600

700750800

385400410

460475490

520535555

310320330

375385395

420435450

700750800

90010001250

435455495

520545590

585615665

355375405

425445485

480500545

90010001250

150017502000

520545560

625650665

705735750

435455470

520545560

585615630

150017502000

AmbientTemperature °C

For ambient temperatures other than 30°C (86°F), multiply the allowable ampacities shownabove by the appropriate factor shown below.

AmbientTemperature °F

21–2526–3031–35

1.081.000.91

1.051.000.94

1.041.000.96

1.081.000.91

1.051.000.94

1.041.000.96

070–77078–86087–95

36–4041–4546–50

0.820.710.58

0.880.820.75

0.910.870.82

0.820.710.58

0.880.820.75

0.910.870.82

096–104105–113114–122

51–5556–6061–70

0.41——

0.670.580.33

0.760.710.58

0.41——

0.670.580.33

0.760.710.58

123–131132–140141–158

71–80 — — 0.41 — — 0.41 159–176

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1.5September 2011


Sheet 01

Reference Data


Ampacities for ConductorsRated 0–2000V (Excerptedfrom NFPA 70-2011, 310.15)

Note: Fine Print Note (FPN) was changedto Informational Note in the 2011 NEC.

(A) General.

(1) Tables or Engineering Supervision. Ampacities for conductors shallbe permitted to be determined bytables as provided in 310.15(B) orunder engineering supervision,as provided in 310.15(C).

Note: Informational Note No. 1: Ampacitiesprovided by this section do not take voltagedrop into consideration. See 210.19(A),Informational Note No. 4, for branch circuitsand 215.2(A), Informational No. 2, for feeders.

Note: Informational Note No. 2: For theallowable ampacities of Type MTW wire,see Table 13.5.1 in NFPA 79-2007, Electrical

Standard for Industrial Machinery .

(2) Selection of Ampacity. Wheremore than one ampacity appliesfor a given circuit length, thelowest value shall be used.Exception: Where two different ampacities apply to adjacent portions of a circuit, the higher ampacity shall be permitted to be used beyond the point of transition, a distance equal to 10 ft (3.0m) or 10 percent of the circuit length figured at the higher ampacity, whichever is less.

Note: Informational Note: See 110.14(C) forconductor temperature limitations due totermination provisions.

(B) Tables. Ampacities for conductorsrated 0–2000V shall be as specifiedin the Allowable AmpacityTable 310.15(B)(16) throughTable 310.15(B)(19), andAmpacity Table 310.15(B)(20) andTable 310.15(B)(21) as modifiedby 310.15(B)(1) through (B)(7).

Note: Informational Note: Table310.15(B)(16) through Table 310.15(B)(19)are application tables for use in determiningconductor sizes on loads calculated inaccordance with Article 220. Allowableampacities result from consideration of oneor more of the following:

(1) Temperature compatibility withconnected equipment, especiallythe connection points.

(2) Coordination with circuit andsystem overcurrent protection.

(3) Compliance with the requirementsof product listings or certifications.See 110.3(B).

(4) Preservation of the safety benefitsof established industry practicesand standardized procedures.

(1) General. For explanation of typeletters used in tables and forrecognized sizes of conductors for

the various conductor insulations,see Table 310.104(A) and Table310.104(B). For installationrequirements, see 310.1 through310.15(A)(3) and the variousarticles of this Code. For flexiblecords, see Table 400.4, Table400.5(A)(1) and Table 400.5(A)(2).

(3) Adjustment Factors.

(a) More Than Three Current- Carrying Conductors in a Raceway or Cable. Where the number ofcurrent-carrying conductors in araceway or cable exceeds three, orwhere single conductors or multi-conductor cables are installedwithout maintaining spacing fora continuous length longer than24.00-inch (600 mm) and are notinstalled in raceways, the allowableampacity of each conductor shallbe reduced as shown in Table310.15(B)(3)(a). Each current-carryingconductor of a paralleled set ofconductors shall be counted as acurrent-carrying conductor.

Note: Informational Note No. 1: See AnnexB, Table B.310.15(B)(2)(11), for adjustmentfactors for more than three current-carryingconductors in a raceway or cable withload diversity.

Note: Informational Note No. 2: See 366.23(A) for adjustment factors for conductors insheet metal auxiliary gutters and 376.22(B)for adjustment factors for conductors inmetal wireways.

(1) Where conductors are installed incable trays, the provisions of392.80 shall apply.

(2) Adjustment factors shall not applyto conductors in raceways havinga length not exceeding 24.00-inch(600 mm).

(3) Adjustment factors shall not apply

to underground conductors enter-ing or leaving an outdoor trenchif those conductors have physicalprotection in the form of rigidmetal conduit, intermediate metalconduit, rigid polyvinyl chlorideconduit (PVC), or reinforcedthermosetting resin conduit (RTRC)having a length not exceeding10 ft (3.05m), and if the number ofconductors does not exceed four.

(4) Adjustment factors shall notapply to Type AC cable or toType MC cable under the followingconditions:

a. The cables do not have an overallouter jacket.

b. Each cable has not more than threecurrent-carrying conductors.

c. The conductors are 12 AWG copper.

d. Not more than 20 current-carryingconductors are installed withoutmaintaining spacing, are stacked,or are supported on”bridle rings.”

(5) An adjustment factor of 60 percentshall be applied to Type AC cable orType MC cable under the followingconditions:

a. The cables do not have an overallouter jacket.

b. The number of current carryingconductors exceeds 20.

c. The cables are stacked or bundledlonger that 24.00-inch (600 mm)without spacing being maintained.

(b) More Than One Conduit, Tube,or Raceway. Spacing betweenconduits, tubing, or racewaysshall be maintained.

(c) Circular Raceways Exposed toSunlight on Rooftops.

Where conductors or cables areinstalled in circular raceways exposedto direct sunlight on or above rooftops,the adjustments shown in Table 1.5-22 shall be added to the outdoortemperature to determine theapplicable ambient temperaturefor application of the correctionfactors in Table 310.15(B)(2)(a) orTable 310.15(B)(2)(b).

Note: Informational Note: One source forthe average ambient temperatures in variouslocations is the ASHRAE Handbook—Fundamentals.

Table 1.5-22. NEC (2011) Table 310.15(B)(3)(c)Ambient Temperature Adjustment for CircularRaceways Exposed to Sunlight On or

Above Rooftops

Distance Above Roof toBottom of Conduit

TemperatureAdder ºF (ºC)

0–0.51-inch (0–13.0 mm) 60 (33)

Above 0.51-inch (13.0 mm)–3.54-inch (90.0 mm)

40 (22)


30 (17)


25 (14)

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.5-18


September 2011


i

2

3

4

5

6

7

8

9

0

1

2

3

4

5

6

7

8

9

0

1

Sheet 01

Reference Data


(4) Bare or Covered Conductors. Where bare or covered conductorsare installed with insulatedconductors, the temperaturerating of the bare or coveredconductor shall be equal to the

lowest temperature rating of theinsulated conductors for thepurpose of determining ampacity.

(5) Neutral Conductor.

(a) A neutral conductor that carriesonly the unbalanced current fromother conductors of the samecircuit shall not be required tobe counted when applying theprovisions of 310.15(B)(3)(a).

(b) In a three-wire circuit consistingof two phase conductors and theneutral conductor of a four-wire,three-phase, wye-connectedsystem, a common conductorcarries approximately the same

current as the line-to-neutral loadcurrents of the other conductorsand shall be counted when applyingthe provisions of 310.15(B)(3)(a).

(c) On a four-wire, three-phase wyecircuit where the major portion ofthe load consists of nonlinearloads, harmonic currents arepresent in the neutral conductor;the neutral conductor shall there-fore be considered a current-carrying conductor.

(6) Grounding or Bonding Conductor. A grounding or bonding conductorshall not be counted when applyingthe provisions of 310.15(B)(3)(a).

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1.5September 2011


Sheet 01

Reference Data

Formulas and Terms113

Table 1.5-23. Formulas for Determining Amperes, hp, kW and kVA

For two-phase, three-wire circuits, the current in the common conductor is times that in either of the two other conductors.

Note: Units of measurement and definitions for E (volts), I (amperes), and other abbreviations are given below under Common Electrical Terms.

ToFind

DirectCurrent

Alternating Current

Single-Phase Two-Phase—Four-Wire Three-Phase

Amperes (l) whenhorsepower is known

Amperes (l) whenkilowatts is known

Amperes (l) whenkva is known

—

Kilowatts

kVA —

Horsepower (output)

hp 746×E % eff×−−−−−−−−−−−−− hp 746×

E % eff× pf×−−−−−−−−−−−−−−−−−−−−−−− hp 746×

2 E× % eff× pf×−−−−−−−−−−−−−−−−−−−−−−−−−−−−− hp 746×

3 E× % eff× pf×−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−

kW 1000×E−−−−−−−−−−−−−−−−− kW 1000×E pf×−−−−−−−−−−−−−−−−−kW 1000

×2 E× pf×−−−−−−−−−−−−−−−−−kW 1000×3 E× % pf×−−−−−−−−−−−−−−−−−−−−−−

kVA 1000×E

−−−−−−−−−−−−−−−−−−− kVA 1000×2 E×

−−−−−−−−−−−−−−−−−−−kVA 1000×

3 E×−−−−−−−−−−−−−−−−

I E×1000−−−−−−−− l E× pf×

1000−−−−−−−−−−−−−− l E 2×× pf×

1000−−−−−−−−−−−−−−−−−−−− l E 3×× pf×

1000−−−−−−−−−−−−−−−−−−−−−−

I E×1000−−−−−−−− I E 2××

1000−−−−−−−−−−−− I E 3××

1000−−−−−−−−−−−−−−−

I E× % eff×746

−−−−−−−−−−−−−−−−−−− I E× % eff pf××746

−−−−−−−−−−−−−−−−−−−−−−−−−−− I E 2×× % eff pf××746

−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−− I E 3×× % eff pf××746

−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−−

2

Common Electrical Terms

Ampere (l) = unit of current or rate of flow of electricity

Volt (E) = unit of electromotive force

Ohm (R) = unit of resistance

Ohms law: I = (DC or 100% pf)

Megohm = 1,000,000 ohms

Volt Amperes (VA) = unit of apparent power

= (single-phase)

=

Kilovolt Amperes (kVA) = 1000 volt-amperes

Watt (W) = unit of true power

=

= 0.00134 hp

Kilowatt (kW) = 1000 wattsPower Factor (pf) = ratio of true to apparent power

=

Watthour (Wh) = unit of electrical work

= 1 watt for 1 hour

= 3.413 Btu

= 2655 ft-lbs

Kilowatt-hour (kWh) = 1000 watthours

Horsepower (hp) = measure of time rate of doing work

= equivalent of raising 33,000 lbs 1 ft in 1 minute

= 746 watts

Demand Factor = ratio of maximum demand to the total connected load

Diversity Factor = ratio of the sum of individual maximum demands ofthe various subdivisions of a system to the maximumdemand of the whole system

Load Factor = ratio of the average load over a designated periodof time to the peak load occurring in that period

ER−−

E l×E l× 3×

VA pf×

WVA--------

kWkVA------------

How to Compute Power Factor

1. 1. From watthour meter.Watts = rpm of disc x 60 x Kh

Where Kh is meter constantprinted on face or nameplateof meter.

If metering transformers are used,above must be multiplied by thetransformer ratios.

2. Directly from wattmeter reading.Where:

Volts = line-to-line voltage asmeasured by voltmeter.

Amperes = current measured inline wire (not neutral) by ammeter.

Table 1.5-24. Temperature Conversion

1 Inch = 2.54 centimeters

1 Kilogram = 2.20 lbs

1 Square Inch = 1,273,200 circular mills

1 Circular Mill= 0.785 square mil

1 Btu = 778 ft lbs

= 252 calories

1 Year = 8760 hours

(F° to C°) C° = 5/9 (F°–32°)(C° to F°) F° = 9/5(C°)+32°

C° –15 –10 –5 0 5 10 15 20F° 5 14 23 32 41 50 59 68

Cº 25 30 35 40 45 50 55 60F° 77 86 95 104 113 122 131 140

C° 65 70 75 80 85 90 95 100F° 149 158 167 176 185 194 203 212

Determining Watts pfWatts

Volts Amperes×----------------------------------------------=

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Seismic Requirements114

Seismic Requirements

General

In the 1980s, Eaton embarked on acomprehensive program centeredaround designing and buildingelectrical distribution and controlequipment capable of meeting andexceeding the seismic load require-ments of the Uniform Building Code(UBC) and California Building Code(CBC). These codes emphasize build-ing design requirements. Electricalequipment and distribution systemcomponents are considered attach-ments to the building. The entire

program has been updated to showcompliance with the 2009 InternationalBuilding Code (IBC) and the 2010 CBCseismic requirements. A cooperativeeffort with the equipment user, thebuilding designer and the equipmentinstaller ensures that the equipmentis correctly anchored such that it canwithstand the effects of an earthquake.Eaton’s electrical distribution andcontrol equipment has been testedand seismically proven for require-ments exceeding the IBC and CBC.Over 100 different assembliesrepresenting essentially all productlines have been successfully tested

and verified to seismic levels higherthan the maximum seismic require-ments specified in the IBC and CBC.The equipment maintained structuralintegrity and demonstrated the abilityto function immediately after theseismic tests. A technical paper,Earthquake Requirements and EatonDistribution and Control Equipment Seismic Capabilities (SA12501SE), provides a detailed explanationof the applicable seismic codesand Eaton’s equipment qualificationprogram. The paper may be foundat www.eaton.com/seismic. Typein SA12501SE in the document

search field.

Figure 1.5-1. Typical Earthquake Ground Motion Map for the United States

International Building Code (IBC)

On December 9, 1994, the InternationalCode Council (ICC) was establishedas a nonprofit organization dedicatedto developing a single set of compre-hensive and coordinated codes. TheICC founders—the Building Officialsand Code Administrators (BOCA), theInternational Conference of BuildingOfficials (ICBO), and the SouthernBuilding Code Congress International

(SBCCI)—created the ICC in responseto technical disparities among thethree nationally recognized modelcodes now in use in the U.S. TheICC offers a single, complete set ofconstruction codes without regionallimitations—the InternationalBuilding Code.

Uniform Building Code (UBC)

1997 was the final year in which theUBC was published. It has since beenreplaced by the IBC.

California Building Code

The 2001 CBC was based upon the1997 UBC. In August of 2006, it wasrepealed by the California BuildingStandards Commission (CBSC) andreplaced by the 2007 CBC, CaliforniaCode of Regulations (CCR), Title 24,Part 2 and used the 2006 IBC as thebasis for the code. The 2010 CBCis based upon the 2009 IBC, withamendments as deemed appropriate

by the CBSC. Eaton’s seismicqualification program fully envelopesthe requirements of the 2010 CBC.

Process

According to Chapter 16 of the 2009IBC, structure design, the seismicrequirements of electrical equipmentin buildings may be computed in twosteps. The first step is to determinethe maximum ground motion to beconsidered at the site. The second stepis to evaluate the equipment mountingand attachments inside the buildingor structure. These are then evaluated

to determine appropriate seismic testrequirements. The ground motion,seismic requirements of the equipment,and the seismic response spectrumrequirements are discussed onPage 1.5-22, see Figure 1.5-3.

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1.5September 2011


Sheet 01

Reference Data


Ground MotionAccording to the code, the first andmost important step in the processis to determine the maximumconsidered earthquake spectralresponse acceleration at short

periods of 0.2 seconds (SS) and ata period of 1.0 second (S1). Thesevalues are determined from a setof 24 spectral acceleration maps(Figure 1.5-1) and include numerouscontour lines indicating the severityof the earthquake requirements at aparticular location in the country.

The spectral acceleration mapsindicate low to moderate seismicrequirements for the entire country,with the exception of two particularareas; the West Coast and the Midwest(the New Madrid area). The seismicrequirements at the New Madrid area

are approximately 30% higher than themaximum requirements of the WestCoast. The maps also suggest that thehigh seismic requirements in bothregions, West Coast and Midwest,quickly decrease as one moves awayfrom the fault area. Therefore, the highrequirements are only limited to arelatively narrow strip along the faultlines. Just a few miles away from thisstrip, only a small percentage of themaximum requirements are indicated.

Assuming the worse condition, whichis a site directly located near a fault,the maximum considered earthquakespectral response acceleration at short

periods of 0.2 seconds (SS) is equal to285% gravity and at 1.0 second period(S1) is 124% gravity. These numbersare the maximum numbers for theentire country except for the NewMadrid area. These particular sites areon the border of California and Mexico(S1) and in Northern California (SS).

To help understand the 2009 IBC (and2010 CBC) seismic parameters for aspecific building location, the link tothe US Geological Society is extremelyhelpful: http://earthquake.usgs.gov/ research/hazmaps/design/

Download the file “Java GroundMotion Parameter Calculator”—andsave it to your hard drive, then run theexecutable that was downloaded.

The program will allow one to enterthe latitude and longitude of alocation. (One must be connectedto the Internet to run this application,even after downloading the program.)The IBC (CBC) seismic parameters forthat location will then be displayed.

If the latitude and longitude of thebuilding location is not known,another convenient Web site isavailable that will provide thisinformation based upon a streetaddress: http://geocoder.us/

To determine the maximum consid-ered earthquake ground motion formost site classes (A through D), thecode introduces site coefficients,which when applied against thelocation-specific site class, producesthe adjusted maximum consideredearthquake spectral responseacceleration for the required site.The site coefficients are defined asFa at 0.2 seconds short period andFV at 1.0 second period. From thetables in the code, the highest adjust-ing factor for SS is equal to 1.0 and thehighest adjusting factor for S1 is 1.50.

As a result, the adjusted maximumconsidered earthquake spectralresponse for 0.2 second short period(SMS) and at 1.0 second (SM1), adjustedfor site class effects, are determinedfrom the following equations:

SMS = Fa SS = 1.0 x 2.85g = 2.85g

SM1 = Fv S1 = 1.5 x 1.24g = 1.86g

ASCE 7 (American Society of CivilEngineers), Section 11.4, provides aplot of the final shape of the designresponse spectra of the seismicground motion. The plot is shown inFigure 1.5-2. ASCE 7 is referencedthroughout the IBC as the source fornumerous structural design criteria.

The design spectral acceleration curvecan now be computed. The peak spec-tral acceleration (SDS) and the spectralacceleration at 1.0 second (SD1) maynow be computed from the followingformulas in the code:

SDS = 2/3 x SMS = 2/3 x 2.85g = 1.90g

SD1 = 2/3 x SM1 = 2/3 x 1.8g = 1.24g

SDS, the peak spectral acceleration,extends between the values of T0 andTS. T0 and TS are defined in the codesas follows:

T0 = 0.2 SD1 /SDS = 0.2 x 1.24/1.90 =0.131 seconds (7.63 Hz)

TS = SD1 /SDS = 1.24/1.90 =0.653 seconds (1.53 Hz)

According to the IBC and ASCE 7, thespectral acceleration (Sa) at periodsless than 1.45 seconds may be com-puted by using the following formula:

Sa = SDS (0.6 T/T0 + 0.4)

Where T is the period where Sa isbeing calculated:

Therefore, the acceleration at0.0417 seconds (24 Hz), for example,is equal to:

Sa = 1.90 (0.6 (0.0417/0.131) + 0.4) = 1.12gThe acceleration at 0.03 seconds(33 Hz) is equal to:

Sa = 1.90 (0.6 (0.03/0.131) + 0.4) = 1.02g

At zero period (infinite frequency),T = 0.0, the acceleration (ZPA) isequal to:

Sa = 1.90 (0.6 (0.0/0.131) + 0.4) =0.76g (ZPA)

The acceleration to frequencyrelationship in the frequency rangeof 1.0 Hz to TS is stated equal to:

Sa = SD1 /T

Where Sa is the acceleration at theT period.

At 1.0 Hz (T=1.0) this equation yieldsthe following acceleration:

Sa = 1.24/1 = 1.24g

Figure 1.5-2. Design Response Spectrum

S p e c t u r a l R e s p o n s e A c c e l e r a t i o n S a

( g )

SDS

SD1

T0 TS TL1.0Period T (sec)

Sa =

Sa = SD1

T

SD1 TL

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.5-22


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Testing has demonstrated that thelowest dominant natural frequency ofEaton’s electrical equipment is above3.2 Hz. This indicates that testing at1.24g at 1 Hz is not necessary. Inaddition, having the low end of the

spectra higher than realisticallyrequired forces the shake table tomove at extremely high displacementsto meet the spectral acceleration atthe low frequencies.

Testing to accommodate the low endof the spectra using this accelerationcomponent can result in testing to afactor 2 to 3 times greater than thatrealistically required.

Through testing experience and dataanalysis, the seismic acceleration at1.0 Hz is taken equal to 0.7g, whichwill ensure that the seismic levels areachieved well below 3.2 Hz. This yields

a more vigorous test over a widerrange of seismic intensities.

In developing the seismic requirementsabove, it is important to recognizethe following:

T0 and TS are dependent on SMS andSD1. If SD1 is small relative to SMS thenT0 and TS will be smaller and theassociated frequencies will shifthigher. The opposite is also true.This must be realized in developingthe complete required responsespectrum (RRS). Therefore, it is notadequate to stop the peak spectralacceleration at 7.63 Hz. There are other

contour line combinations that willproduce higher T0. To account for thisvariation it is almost impossible toconsider all combinations. However,a study of the spectral accelerationmaps indicates that all variations withhigh magnitude of contour lines couldvery well be enveloped by a factorof 1.5. Therefore, T0 is recomputedas follows:

T0 = 0.2 SD1 /(SDS x 1.5) = 0.2 x 1.24/ (1.90 x 1.5) = 0.087 seconds (11.49 Hz)

Eaton ensures maximum certificationby requiring peak acceleration duringtesting to extend to 12 Hz.

It can be seen that Eaton has elected todevelop generic seismic requirementsthat envelop two criteria:

■ The highest possible spectral peakaccelerations and ZPA

■ The maximum frequency rangerequired for many different sites

This completes the ground motiondesign response spectrum. Thespectral accelerations are equal to0.76g at ZPA, or 33 Hz, and increaseslinearly to a peak acceleration of 1.90gat 0.09 seconds (or 11.49 Hz) and stays

constant to 0.653 seconds (1.53 Hz),then gradually decreases to 1.24g at1 second (or 1.0 Hz). This curve isshown in Figure 1.5-3.

Figure 1.5-3. Design Response Spectrum

ASCE 7 Section 13.3—Seismic

Demands on Non-StructuralComponents

ASCE 7 Paragraph 13.3.1 (IBC Section1621.1.4) provides a formula forcomputing the seismic requirementsof electrical and mechanical equipmentinside a building or a structure. Theformula is designed for evaluating theequipment attachment to the equip-ment foundations. The seismic loadsare defined as:

Fp = 0.4 ap SDS Wp (1 + 2 Z/h)/(Rp /Ip)

Where:

Fp = Seismic design force imposedat the component’s center of gravity(C.G.) and distributed relative tocomponent mass distribution.

ap = Component amplification factorthat varies from 1.00 to 2.50.

SDS = Ground level spectralacceleration, short period.

Wp = Component operating weight.

Rp = Component response modifica-

tion factor that for electrical equipmentvaries from 2.5 to 6.0.

Ip = Component importance factor thatis either 1.0 or 1.5.

Z = Highest point of equipment in abuilding relative to grade elevation.

h = Average roof height of buildingrelative to grade elevation.

The following parameters produce themaximum required force:

■ Z is taken equal to h (equipmenton roof)

■ Ip is taken equal to 1.5

■ ap is taken equal to 2.5

■ Rp is taken equal to 2.5

■ SDS is equal to 1.90g as indicatedin the previous section

The acceleration (Fp /Wp) at the C.G.of the equipment is then computedequal to:

Acceleration = Fp /Wp = 0.4 x 2.5 x1.90g (1 + 2) / (2.5/1.5) = 3.42g

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Spectrum Dip – Not ImportantBecause Frequency is Not anEquipment Natural Frequency

Zero PeriodAcceleration = Maximum

Table Test Motion

Zero PeriodAcceleration = Maximum

Floor Motion

Required Response Spectrum(RRS)




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For equipment on (or below) grade,the acceleration at the equipment C.G.is then computed equal to:

Acceleration = Fp /Wp = 0.4 x 2.5 x1.90g (1 + 0) / (2.5 /1.5) = 1.14g

It is impractical to attempt to measurethe actual acceleration of the C.G. of apiece of equipment under seismic test.The seismic response at the middle ofbase mounted equipment close to itsC.G. is at least 50% higher than thefloor input at the equipment naturalfrequency. The base accelerationsassociated with the accelerations ofFP /WP at the C.G. of the equipmentcould then be computed as 3.42 /1.5= 2.28g. It is the equipment base inputacceleration that is measured anddocumented during seismic testingand is the acceleration value shownon Eaton’s seismic certificates.

Final Combined Requirements

To better compare all seismic levelsand determine the final envelopeseismic requirements, the 2010 CBC,2009 IBC for California, and 2009 IBCfor New Madrid area seismic require-ments are plotted in Figure 1.5-4. Allcurves are plotted at 5% damping. Anenvelopment of the seismic levels inthe frequency range of 3.2 Hz to 100 Hzis also shown. This level is taken asEaton’s generic seismic test require-ments for all certifications. Eatonperformed additional seismic test runson the equipment at approximately

120% of the generic enveloping seismicrequirements (see Figure 1.5-5). Eatonhas established this methodology toprovide additional margin to accom-modate potential changes with thespectral maps, thus eliminating theneed for additional testing.

Figure 1.5-4. Required Response Spectrum Curve

Figure 1.5-5. Eaton Test Required Response Spectrum Curve

A c c e l e r a t i o n ( g )

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Eaton Seismic

IBC 2009 New MadridIBC 2009/CBC 2010

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Eaton 100% Seismic Envelope

Eaton 120% Seismic Envelope



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Product Specific Test SummariesTable 1.5-25. Distribution EquipmentTested and Seismically Proven AgainstRequirements within IBC 2009

Note: See www.eaton.com/seismic forcurrent seismic certificates.

Eaton Equipment

Low voltage metal-enclosed switchgearDS IIMagnum DSHigh resistance ground

PanelboardsPow-R-Line C 1a, 1a-LX, 2a, 2a-LX, 3a, 3E, 4,5P, F-16 and Pow-R-Command™

SwitchboardsInstant Pow-R-Line 5PIntegrated facilities Pow-R-Line CMultimeter Pow-R-Line i

MCCAdvantage® IT.FlashGard® Series 2100Freedom 2100

Low voltage buswayPow-R-Way® and associated fittingsPow-R-Way III® and associated fittings

Dry type transformersMini powercentersEP, EPT, DS-3, DT-3

Transfer switchesAutomatic transfer switch equipment

Uninterruptible power supplies (UPS)Battery modulesUPSs

Enclosed control safety switchesGeneral-dutyHeavy-dutyElevator control module

Medium voltage switchgearType VacClad-W Type MMVSMEF Type MVS/MEB

MV busMetal-enclosed non-segregated phase bus

Network protectorsType CM-22Type CMD

Medium voltage controlAMPGARD®

SC9000 drives

Substation transformersDry-typeLiquid typeUnitized dry-type power centers Figure 1.5-6. Sample Seismic Certificate

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Additional Design andInstallation Considerations

When installing electrical distributionand control equipment, considerationmust be given as to how the methodsemployed will affect seismic forcesimposed on the equipment, equipmentmounting surface, and conduitsentering the equipment.

Eaton recommends that when specify-ing a brand of electrical distributionand control equipment, the designerreferences the installation manuals ofthat manufacturer to ascertain that therequirements can be met through thedesign and construction process.

For Eaton electrical distribution andcontrol products, the seismic installa-tion guides for essentially all productlines can be found at our Web site:

http://www.eaton.com/seismic.Electrical designers must work closelywith the structural or civil engineersfor a seismic qualified installation.

Consideration must be given to thetype of material providing anchoragefor the electrical equipment.

If steel, factors such as thickness orgauge, attachment via bolts or welding,and the size and type of hardwaremust be considered.

If concrete, the depth, the PSI, the typeof re-enforcing bars used, as well as

the diameter and embedment ofanchorage all must be considered.

The designer must also give consider-ation if the equipment will be securedto the wall, versus stand-alone or free-standing, which requires the equip-ment to withstand the highest level ofseismic forces. Top cable entry shouldbe avoided for large enclosures, asaccommodation for cable/conduitflexibility will need to be designedinto the system.

For a manufacturer to simply state“Seismic Certified” or “SeismicQualified” does not tell the designerif the equipment is appropriate forthe intended installation.

Note: Eaton recommends that designersconfirm with the manufacturer if theseismic certification supplied with theequipment is based on:

1. ACTUAL shaker table test asrequired by the IBC and CBC.

2. The seismic certificate and testdata clearly state if the equipmentwas tested as free-standing—anchored at the bottom of theequipment to the shaker table.

3. Structure attached, that is,anchored at the center of gravity(C.G.) or at the TOP of the equip-ment to a simulated wall on theshaker table.

Stand-Alone or Free-Standing Equipment

If stand-alone or free-standing, thenthis may require that additional widthspace be allowed at each end of theequipment for additional seismicbracing supplied by the manufacturer.

Additional thought must be given tothe clearances around the equipmentto rigid structural edifices. Space mustbe allowed for the differing motions ofthe equipment and the structure, sothat they do not collide during a seis-mic event and damage one another.

Note: If the equipment is installed as stand-alone or free-standing, with additionalseismic bracing at each end and notattached to the structure as tested, and yet,it is fitted tightly against a structural wall,then this would be an incorrect installationfor the application of the seismic certificate.

Furthermore, if conduits are to be

installed overhead into the equipment,does the design call for flexible conduitsof sufficient length to allow for theconflicting motion of the equipmentand the structure during a seismic eventso as to not damage the conductorscontained therein, and the terminationspoints within the equipment.

Structure Attached Equipment

The designer must work closelywith the structural engineer if theequipment is to be attached to thestructure to ascertain that the internalwall re-enforcement of the structure,type of anchor, and depth of embed-

ment is sufficient to secure theequipment so that the equipment,conduits and structure move at ornear the same frequency.






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