cutler hammer - a - power distribution system design

January 1999

Cutler-Hammer

A-1Power Distribution System Design

CAT.71.01.T.E

A

Index

Description Page

Basic Principles ......................................................................................................................... A-2Modern Electric Power Technologies ......................................................................................A-2Goals of System Design............................................................................................................A-3Voltage Classifications ............................................................................................................. A-4Types of Systems...................................................................................................................... A-5

1. Simple Radial....................................................................................................................A-52. Loop Primary System - Radial Secondary System........................................................A-63. Primary Selective System - Secondary Radial System.................................................A-74. Two Source Primary - Secondary Selective System .....................................................A-85. Simple Spot Network Systems .......................................................................................A-96. Medium-Voltage Distribution System Design..............................................................A-10

Systems Analysis.................................................................................................................... A-12Short Circuit Currents - General ............................................................................................ A-13Fault Current Wave Form Relationships ............................................................................... A-14Fault Current Calculations...................................................................................................... A-15Fault Current Calculations for Specific Equipment .............................................................. A-16

1. Medium-Voltage VCP-W Metal-Clad Switchgear.........................................................A-162. Medium-Voltage Fuses ..................................................................................................A-213. Low-Voltage Power Circuit Breakers.............................................................................A-224. Molded Case Breakers ...................................................................................................A-22

Short Circuit Calculations - Short Cut Method..................................................................... A-23How To Calculate Short Circuit Currents at Ends of Conductors ....................................... A-26

1. Method 1 (Adding Zs) ....................................................................................................A-262. Chart Approximate Method...........................................................................................A-27

Determine X and R From Transformer Loss Data................................................................ A-30Voltage Drop ........................................................................................................................... A-31

Capacitor Switching Device Selections................................................................................. A-351. Medium-Voltage Capacitor Switching ..........................................................................A-352. Low-Voltage Capacitor Switching .................................................................................A-35

Motor Power Factor Correction ............................................................................................. A-36

Overcurrent Protection and Coordination ............................................................................ A-37

Grounding ............................................................................................................................... A-401. Equipment Grounding ...................................................................................................A-402. System Grounding .........................................................................................................A-403. Medium-Voltage System - Grounding..........................................................................A-404. Low-Voltage System - Grounding.................................................................................A-42

Ground Fault Protection ......................................................................................................... A-43Lightning and Surge Protection............................................................................................. A-45Grounding Electrodes............................................................................................................. A-46

Terms, Technical Overview.................................................................................................... A-47Harmonics and Nonlinear Loads ........................................................................................... A-48

Secondary Voltages................................................................................................................ A-50Energy Conservation .............................................................................................................. A-52Building Control Systems ...................................................................................................... A-53Cogeneration........................................................................................................................... A-53Emergency Power................................................................................................................... A-53Peak Shaving........................................................................................................................... A-54Computer Power ..................................................................................................................... A-55Sound Levels........................................................................................................................... A-56Codes and Standards ............................................................................................................. A-57

Motor Protective Device Data ................................................................................................ A-58Secondary Short Circuit Capacity of Typical Power Transformers .................................... A-59Transformer Full Load Amperes and Impedances............................................................... A-60Transformer Losses ................................................................................................................ A-61Power Equipment Losses....................................................................................................... A-62NEMA Enclosure Definitions.................................................................................................. A-63Cable R, X, Z Data ................................................................................................................... A-64Conductor Ampacities ............................................................................................................ A-65Conduit Fill .............................................................................................................................. A-66Formulas.................................................................................................................................. A-67Seismic Requirements............................................................................................................ A-68

System Design

Systems Analysis

Capacitors

Protection/Coordination

Grounding/Ground Fault Protection

Power Quality

Reference Data

Other Design Considerations

CAT.71.01.T.E

Cutler-Hammer

A-2

January 1999

Power Distribution System Design

A

System Design

Basic Principles

The best distribution system is one that will cost effectively and safely supply adequate electric service to both present and future probable loads—this section is included to aid in selecting, designing, and installing such a system.

The function of the electric power distribution system in a building or installation site is to receive power at one or more supply points and deliver it to the individual lamps, motors, and all other electrically operated devices. The importance of the distribution system to the function of a building makes it almost imperative that the best system be designed and installed.

In order to design the best distribution sys-tem, the system design engineer must have information concerning the loads and a knowledge of the various types of distribu-tion systems that are applicable. The various categories of buildings have many specific problems, but certain basic principles are common to all. Such principles, if followed, will provide a soundly executed design.

The basic principles or factors requiring consideration during design of the power distribution system include:

●

Functions of structure, present and future

●

Life and flexibility of structure

●

Locations of service entrance and distri-bution equipment, locations and charac-teristics of loads, locations of unit substations

●

Demand and diversity factors of loads

●

Sources of power

●

Continuity and quality of power available and required.

●

Energy efficiency and management

●

Distribution and utilization voltages

●

Bus and/or cable feeders

●

Switchgear and distribution equipment

●

Power and lighting panelboards and motor control centers

●

Types of lighting fixtures

●

Installation methods

●

Degree of power equipment monitoring

Modern Electric Power Technologies

Several new factors to consider in modern power distribution systems result from two relatively recent changes. The first recent change is the beginnings of utility deregula-tion. The traditional dependence on the utility for problem analysis; energy conservation measurements and techniques; and a simpli-fied cost structure for electricity will change to some degree in the next decade. The sec-ond change is less obvious to the designer yet will have an impact on the types of equip-ment and systems being designed. It is the diminishing quantity of qualified building electrical operators; maintenance depart-ments; and facility engineers.

Modern electric power technologies may be of use to the designer and building owner in addressing these new challenges. The advent of microprocessor devices (smart devices) into power distribution equipment has expanded facility owners’ options and capa-bilities, allowing for automated communica-tion of vital power system information (both energy data and system operation informa-tion) and electrical equipment control.

These technologies may be grouped as:

●

Power monitoring

●

Building management systems interfaces

●

Lighting control

●

Automated energy management

Various sections of this guide cover the appli-cation and selection of such systems and components that may be incorporated into the power equipment being designed.

January 1999

Cutler-Hammer


CAT.71.01.T.E

A

Goals of System Design

When considering the design of an electrical distribution system for a given customer and facility, the electrical engineer must consider alternate design approaches which best fit the following overall goals:

1. Safety

– The number one goal is to design a power system which will not present any electrical hazard to the people who utilize the facility, and/or the utilization equipment fed from the electrical system. It is also important to design a system which is inherently safe for the people who are responsible for electri-cal equipment maintenance and upkeep. The National Electric Code (N.E.C.) as well as local electrical codes provide

minimum

stan-dards and requirements in the area of wiring design and protection, wiring methods and materials as well as equipment for general use with the overall goal of providing safe electrical distribution systems and equipment. The N.E.C. also covers

minimum

require-ments for special occupancies including hazardous locations and special use type facilities such as health care facilities, places of assembly, theaters, etc. and the equipment and systems located in these facilities. Spe-cial equipment and special conditions such as emergency systems, standby systems and communication systems are also covered in the code. It is the responsibility of the design engineer to be familiar with the code requirements as well as the customer's facility, process, and operating procedures; to design a system which protects personnel from electrical live conductors and utilizes adequate circuit pro-tective devices which will selectively isolate overloaded or faulted circuits or equipment as quickly as possible.

2. Minimum Initial Investment

– The owner’s overall budget for first cost purchase and in-stallation of the electrical distribution system and electrical utilization equipment will be a key factor in determining which of various alternate system designs are to be selected. When trying to minimize initial investment for electrical equipment, consideration should be given to the cost of installation, floor space requirements and possible extra cooling requirements as well as the initial purchase price.

3. Maximum Service Continuity

– The degree of service continuity and reliability needed will vary depending on the type and use of the facility as well as the loads or processes being supplied by the electrical distribution system. For example, for a smaller commer-cial office building a power outage of consid-erable time, say several hours, may be acceptable, whereas in a larger commercial building or industrial plant only a few min-utes may be acceptable. In other facilities

such as hospitals, many critical loads permit a maximum of 10 seconds outage and certain loads, such as real time computers, cannot tolerate a loss of power for even a few cycles. Typically service continuity and reliability can be increased by: A) supplying multiple utility power sources or services; B) supplying mul-tiple connection paths to the loads served; C) providing alternate customer-owned pow-er sources such as generators or batteries supplying uninterruptable power supplies; D) selecting highest quality electrical equip-ment and conductors; and E) using the best installation methods.

4. Maximum Flexibility and Expandability

– In many industrial manufacturing plants, electrical utilization loads are periodically re-located or changed requiring changes in the electrical distribution system. Consideration of the layout and design of the electrical dis-tribution system to accommodate these changes must be considered. For example, providing many smaller transformers or loadcenters associated with a given area or specific groups of machinery may lend more flexibility for future changes than one large transformer; the use of plug-in busways to feed selected equipment in lieu of conduit and wire may facilitate future revised equip-ment layouts. In addition, consideration must be given to future building expansion, and/or increased load requirements due to added utilization equipment when designing the electrical dis-tribution system. In many cases considering transformers with increased capacity or fan cooling to serve unexpected loads as well as including spare additional protective devices and/or provision for future addition of these devices may be desirable. Also to be consid-ered is increasing appropriate circuit capaci-ties or quantities for future growth.

5. Maximum Electrical Efficiency (Minimum Operating Costs)

– Electrical efficiency can generally be maximized by designing sys-tems that minimize the losses in conductors, transformers and utilization equipment. Prop-er voltage level selection plays a key factor in this area and will be discussed later. Selecting equipment, such as transformers, with lower operating losses, generally means higher first cost and increased floor space requirements; thus, there is a balance to be considered be-tween the owner’s utility energy change for the losses in the transformer or other equip-ment versus the owner’s first cost budget and cost of money.

6. Minimum Maintenance Cost

– Usually the simpler the electrical system design and the simpler the electrical equipment, the less the associated maintenance costs and operator errors. As electrical systems and equipment become more complicated to provide greater service continuity or flexibility, the mainte-nance costs and chance for operator error

increases. The systems should be designed with an alternate power circuit to take electri-cal equipment (requiring periodic mainte-nance) out of service without dropping essential loads. Use of draw-out type protec-tive devices such as breakers and combina-tion starters can also minimize maintenance cost and out-of-service time.

7. Maximum Power Quality

– The power in-put requirements of all utilization equipment has to be considered including the acceptable operating range of the equipment and the electrical distribution system has to be de-signed to meet these needs. For example, what is the required input voltage, current, power factor requirement? Consideration to whether the loads are affected by harmonics (multiples of the basic 60 cycle per second sine wave) or generate harmonics must be taken into account as well as transient volt-age phenomena.

The above goals are interrelated and in some ways contradictory. As more redundancy is added to the electrical system design along with the best quality equipment to maximize service continuity, flexibility and expandabil-ity, and power quality, the more initial invest-ment and maintenance are increased. Thus, the designer must weigh each factor based on the type of facility, the loads to be served, the owner’s past experience and criteria.

Summary

It is to be expected that the engineer will never have complete load information available when the system is designed. The engineer will have to expand the information made available to him on the basis of experience with similar problems. Of course, it is desirable that the engineer has as much definite information as possible concerning the function, require-ments, and characteristics of the utilization devices. The engineer should know whether certain loads function separately or together as a unit, the magnitude of the demand of the loads viewed separately and as units, the rated voltage and frequency of the devices, their physical location with respect to each other and with respect to the source and the proba-bility and possibility of the relocation of load devices and addition of loads in the future.

Coupled with this information, a knowledge of the major types of electric power distribution systems equips the engineers to arrive at the best system design for the particular building.

It is beyond the scope of this book to present a detailed discussion of loads that might be found in each of several types of buildings. Assuming that the design engineer has assembled the necessary load data, the following pages dis-cuss some of the various types of electrical dis-tribution systems being utilized today. A discussion of short circuit calculations, coordi-nation, voltage selection, voltage drop, ground fault protection, motor protection, and other specific equipment protection is presented.

System Design

CAT.71.01.T.E

Cutler-Hammer

A-4

January 1999


A

System Design

Voltage Classifications

ANSI and IEEE standards define various voltage classifications for single-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 A1 presents the nominal system volt-ages for these classifications.

Table A1 – Standard Nominal System Voltages and Voltage Ranges

Voltage Class Nominal System Voltage

3-Wire 4-Wire

Low Voltage 240480600

208Y/120240/120

480Y/277

Medium Voltage 2400416048006900

1380023000345004600069000

4160Y/24008320Y/4800

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

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

High Voltage 115000138000161000230000

Extra-High Voltage

Ultra-High Voltage

345000500000765000

1100000

January 1999

Cutler-Hammer


CAT.71.01.T.E

A

System Design

Types of Systems

In the great majority of cases, power is sup-plied by the utility to a building at the utiliza-tion voltage. In practically all of these cases, the distribution of power within the building is achieved through the use of a simple radial distribution system. This system is the first type described on the following pages.

In those cases where utility service is avail-able at the building at some voltage higher than the utilization voltage to be used, the system design engineer has a choice of a number of types of systems which the engi-neer may use. This discussion covers several major types of distribution systems and prac-tical modifications of them.

1. Simple Radial

2. Loop-Primary System - Radial Secondary System

3. Primary Selective System - Secondary Radial System

4. Two Source Primary - Secondary Selec-tive System

5. Simple Spot Network

6. Medium-Voltage Distribution System Design

1. Simple Radial System

The conventional simple-radial system re-ceives power at the utility supply voltage at a single substation and steps the voltage down to the utilization level. In those cases where the customer receives his supply from the primary system and owns the primary switch and transformer along with the secondary low voltage switchboard or switchgear, the equipment may take the form of a separate primary switch, separate transformer, and separate low voltage switchgear or switch-board. This equipment may be combined in the form of an outdoor pad mounted trans-former with internal primary fused switch and secondary main breaker feeding an indoor switchboard.

Another alternative would be a secondary unit substation where the primary fused switch, transformer and secondary switch-gear or switchboard are designed and in-stalled as a close coupled single assembly.

In those cases where the utility owns the pri-mary equipment and transformer, the supply to the customer is at the utilization voltage, and the service equipment then becomes a low voltage main distribution switchgear or switchboard.

Low-voltage feeder circuits run from the switchgear or switchboard assemblies to panelboards that are located closer to their respective loads as shown in Fig. 1.

Each feeder is connected to the switchgear or switchboard bus through a circuit breaker or other overcurrent protective device. A relatively small number of circuits are used to distribute power to the loads from the switch-gear or switchboard assemblies and panel-boards.

Since the entire load is served from a single source, full advantage can be taken of the di-versity among the loads. This makes it possi-ble to minimize the installed transformer capacity. However, the voltage regulation and efficiency of this system may be poor be-cause of the low-voltage feeders and single source. The cost of the low voltage-feeder cir-cuits and their associated circuit breakers are high when the feeders are long and the peak demand is above 1000 kVA.

A fault on the secondary low voltage bus or in the source transformer will interrupt service to all loads. Service cannot be restored until the necessary repairs have been made. A low-voltage feeder circuit fault will interrupt service to all loads supplied over that feeder.

A modern and improved form of the conven-tional simple radial system distributes power at a primary voltage. The voltage is stepped down to utilization level in the several load areas within the building typically through secondary unit substation transformers. The transformers are usually connected to their associated load bus through a circuit breaker, as shown in Fig. 1A. Each secondary unit sub-station is an assembled unit consisting of a three-phase, liquid-filled or air-cooled trans-former, an integrally connected primary fused switch, and low-voltage switchgear or switchboard with circuit breakers or fused switches. Circuits are run to the loads from these low voltage protective devices.

Since each transformer is located within a spe-cific load area, it must have sufficient capacity to carry the peak load of that area. Conse-quently, if any diversity exists among the load area, this modified primary radial system re-quires more transformer capacity than the ba-sic form of the simple radial system. However, because power is distributed to the load areas at a primary voltage, losses are reduced, volt-age regulation is improved, feeder circuit costs are reduced substantially, and large low-voltage feeder circuit breakers are eliminated. In many cases the interrupting duty imposed on the load circuit breakers is reduced.

This modern form of the simple radial system will usually be lower in initial investment than most other type of primary distribution system for buildings in which the peak load is above 1000 kVA. A fault on a primary feeder circuit or in one transformer will cause an outage to only those secondary loads served by that feeder or transformer. In the case of a primary main bus fault or an utility service outage, service is interrupted to all loads until the trouble is eliminated.

Reducing the number of transformers per pri-mary feeder by adding more primary feeder circuits will improve the flexibility and service continuity of this system; the ultimate being one secondary unit substation per primary feeder circuit. This of course increases the in-vestment in the system but minimizes the ex-tent of an outage resulting from a trans-former or primary feeder fault.

Primary connections from one secondary unit substation to the next secondary unit substation can be made with “double” lugs on the unit substation primary switch as shown, or with separable connectors made in manholes or other locations.

Figure 1. Simple Radial System

Primary Fused Switch

Transformer

600V ClassSwitchboard

DistributionDry-TypeTransformer

LightingPanelboard

DistributionPanel

MCC DistributionPanel

CAT.71.01.T.E

Cutler-Hammer

A-6

January 1999


A

System Design

Depending on the load kVA connected to each primary circuit and if no ground fault protec-tion is desired for either the primary feeder conductors and transformers connected to that feeder or the main bus, the primary main and/or feeder breakers may be changed to pri-mary fused switches. This will significantly re-duce the first cost, but also decrease the level of conductor and equipment protection. Thus, should a fault or overload condition occur, down time could increase significantly and higher costs associated with increased dam-age levels and the need for fuse replacement would be typically encountered. In addition, should only one primary fuse on a circuit blow, the secondary loads could be single phased, causing damage to low voltage motors.

Another approach to reducing costs would be to eliminate the primary feeder breakers com-pletely, and just utilize a single primary main breaker or fused switch for protection of a sin-gle primary feeder circuit with all the second-ary unit substations supplied from this circuit. Although this system would result in less ini-tial equipment cost, system reliability would be reduced drastically since a single fault in any part of the primary conductor would cause an outage to all loads within the facility.

2. Loop Primary System - Radial Secondary System

This system consists of one or more “PRI-MARY LOOPS” with two or more transform-ers connected on the loop. This system is typically most effective when two services are available from the utility as shown in Fig. 2. Each primary loop is operated such that one of the loop sectionalizing switches is kept open to prevent parallel operation of the sources. When secondary unit substations are utilized, each transformer has its own duplex (2-load break switches with load side bus connection) sectionalizing switches and primary load break fused switch as shown in Fig. 2A.

When pad mounted compartmentalized transformers are utilized, they are furnished with loop feed oil immersed gang operated load break sectionalizing switches and draw-out current limiting fuses in dry wells as shown in Fig. 2B. By operating the appropri-ate sectionalizing switches, it is possible to disconnect any section of the loop conductors from the rest of the system. In addition, by opening the transformer primary switch (or removing the load break draw-out fuses in the pad mounted transformer) it is possible to disconnect any transformer from the loop. A key interlocking scheme is normally recom-mended to prevent closing all sectionalizing devices in the loop. Each primary loop sec-tionalizing switch and the feeder breakers to the loop are interlocked such that to be closed they require a key (which is held captive until the switch or breaker is opened) and one less key than the number of key interlock cylinders is furnished. An extra key is provided to de-feat the interlock under qualified supervision.

Figure 1A. Primary and Secondary Simple Radial System

Figure 2. Loop Primary - Radial Secondary System

NC NCNO

Loop ALoop 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

52 52

52

5252

52 52

Fault Sensors

Primary Main Breaker 1

Secondary UnitSubstation

Primary Main Breaker

Primary Feeder Breakers

Primary Cables

52 52 52 52 52 52

52

January 1999

Cutler-Hammer


CAT.71.01.T.E

A

System Design

In addition, the two primary main breakers which are normally closed and primary tie breaker which is normally open are either mechanically or electrically interlocked to prevent paralleling the incoming source lines. For slightly added cost, an automatic throw-over scheme can be added between the two main breakers and tie breaker. During the more common event of a utility outage, the automatic transfer scheme provides sig-nificantly reduced power outage time.

This system of Fig. 2 provides for increased equipment costs over Fig. 1, but offers in-creased reliability and quick restoration of service when 1) a utility outage occurs, 2) a primary feeder conductor fault occurs, or 3) a transformer fault or overload occurs.

Should a utility outage occur on one of the in-coming lines, the associated primary main breaker can be opened and then the tie break-er closed either manually or through an auto-matic transfer scheme.

When a primary feeder conductor fault oc-curs, the associated loop feeder breaker opens and interrupts service to all loads up to the normally open primary loop load break switch (typically half of the loads). Once it is determined which section of primary cable has been faulted, then the loop sectionalizing switches on each side of the faulted conduc-tor can be opened, the loop sectionalizing switch which had been previously left open then closed and service restored to all sec-ondary unit substations while the faulted conductor is replaced. If the fault should oc-cur in a conductor directly on the load side of one of the loop feeder breakers, the loop feeder breaker would be kept open after trip-ping and the next load side loop sectionaliz-ing switch manually opened so that the faulted conductor could be sectionalized and replaced. Note under this condition, all sec-ondary unit substations would be supplied through the other loop feeder circuit breaker, and thus all conductors around the loop should be sized to carry the entire load con-nected to the loop. Increasing the number of primary loops (two loops shown in Fig. 2) will reduce the extent of the outage from a con-ductor fault, but will also increase the system investment.

When a transformer fault or overload occurs, the transformer primary fuses would blow, and then the transformer primary switch manually opened, disconnecting the trans-former from the loop, and leaving all other secondary unit substation loads unaffected.

A basic primary loop system which utilizes a single primary feeder breaker connected di-rectly to two loop feeder switches which in turn then feed the loop is shown in Fig. 2C. In this basic system the loop may be normally operated with one of the loop sectionalizing switches open as described above or with all

loop sectionalizing switches closed. If a fault occurs in the basic primary loop system, the single loop feeder breaker trips, and second-ary loads are lost until the faulted conductor is found and eliminated from the loop by opening the appropriate loop sectionalizing switches and then reclosing the breaker.

Figure 2A. Secondary Unit Substation Loop Switching

Figure 2B. Pad Mounted Transformer LoopSwitching

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

Figure 2C. Single Primary Feeder - Loop System

3. Primary Selective System - Secondary Radial System

The primary selective - Secondary radial sys-tem, as shown in Fig. 3, differs from those previously described in that it employs at least two primary feeder circuits in each load area. It is designed so that when one primary circuit is out of service, the remaining feeder or feeders have sufficient capacity to carry the total load. Half of the transformers are normally connected to each of the two feed-ers. When a fault occurs on one of the prima-ry feeders, only half of the load in the building is dropped.

Duplex fused switches as shown in Fig. 3 and detailed in Fig. 3A are the normal choice for this type of system. Each duplex fused switch consists of two (2) load break 3 pole switches each in their own separate structure, connect-ed together by bus bars on the load side. Typically the load break switch closest to the transformer includes a fuse assembly with fuses. Mechanical and/or key interlocking is furnished such that both switches cannot be closed at the same time (to prevent parallel operation) and interlocking such that access to either switch or fuse assembly cannot be obtained unless both switches are opened.

As an alternate to the duplex switch arrange-ment, a non-load break selector switch me-chanically interlocked with a load break fused switch can be utilized as shown in Fig. 3B. The non-load break selector switch is physi-cally located in the rear of the load break fused switch, thus only requiring one struc-ture and a lower cost and floor space savings over the duplex arrangement. The non-load break switch is mechanically interlocked to prevent its operation unless the load break switch is opened. The main disadvantage of the selector switch is that conductors from both circuits are terminated in the same structure. This means limited cable space es-pecially if double lugs are furnished for each line as shown in Fig. 3 and should a faulted primary conductor have to be changed, both lines would have to be deenergized for safe changing of the faulted conductors.

In Fig. 3 when a primary feeder fault occurs the associated feeder breaker opens, and the transformers normally supplied from the faulted feeder are out of service. Then manu-ally, each primary switch connected to the faulted line must be opened and then the al-ternate line primary switch can be closed connecting the transformer to the live feeder, thus restoring service to all loads. Note that each of the primary circuit conductors for Feeder A1 and B1 must be sized to handle the sum of the loads normally connected to both A1 and B1. Similar sizing of Feeders A2 and B2, etc. is required.

LoopFeeder

LoopFeeder

LoadbreakLoop Switches

FusedDisconnectSwitch

LoopFeeder

LoopFeeder

LoadbreakLoop Switches

LoadbreakDrawout Fuses

CAT.71.01.T.E

Cutler-Hammer

A-8

January 1999


A

System Design

If a fault occurs in one transformer, the asso-ciated primary fuses blows and interrupts the service to just the load served by that trans-former. Service cannot be restored to the loads normally served by the faulted trans-former until the transformer is repaired or replaced.

Cost of the primary selective - secondary radi-al system is greater than that of the simple primary radial system of Fig. 1 because of the additional primary main breakers, tie breaker, two sources, increased number of feeder breakers, the use of primary-duplex or selec-tor switches, and the greater amount of pri-mary feeder cable required. The benefits derived from the reduction in the amount of load dropped when a primary feeder is fault-ed, plus the quick restoration of service to all or most of the loads, may more than offset the greater cost. Having two sources allows for ei-ther manual or automatic transfer of the two primary main breakers and tie breaker should one of the sources become unavailable.

The primary selective-secondary radial sys-tem, however, may be less costly or more costly than a primary loop - secondary radial system of Fig. 2 depending on the physical lo-cation of the transformers while offering comparable down-time and reliability. The cost of conductors for the two types of sys-tems may vary greatly depending on the lo-cation of the transformers and loads within the facility and greatly over-ride primary switching equipment cost differences be-tween the two systems.

4. Two Source Primary - Secondary Selective System

This system uses the same principle of dupli-cate sources from the power supply point utilizing two primary main breakers and a primary tie breaker. The two primary main breakers and primary tie breaker being either manually or electrically interlocked to pre-vent closing all three at the same time and paralleling the sources. Upon loss of voltage on one source, a manual or automatic trans-fer to the alternate source line may be utilized to restore power to all primary loads.

Each transformer secondary is arranged in a typical double-ended unit substation arrangement as shown in Fig. 4. The two secondary main breakers and secondary tie breaker of each unit substation are again either mechanically or electrically interlocked to prevent parallel operation. Upon loss of secondary source voltage on one side, manu-al or automatic transfer may be utilized to transfer the loads to the other side, thus restoring power to all secondary loads.

This arrangement permits quick restoration of service to all loads when a primary feeder or transformer fault occurs by opening the associated secondary main and closing the secondary tie breaker. If the loss of secondary

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

52

5252

52 52

NO

NC

NO

NC

NO

NC

Figure 3A. Duplex Fused Switch In TwoStructures

Figure 3. Basic Primary Selective - Radial Secondary System

PrimaryFeeders

LoadbreakSwitches

Fuses

Figure 3B. Fused Selector Switch In OneStructure

PrimaryFeeders

Interlock

Non-loadbreakSelector Switch

LoadbreakDisconnect

Fuses

voltage has occurred because of a primary feeder fault with the associated primary feed-er breaker opening, then

all

secondary loads normally served by the faulted feeder would have to be transferred to the opposite prima-ry feeder. This means each primary feeder conductor must be sized to carry the load on both sides of all the secondary buses it is serving under secondary emergency trans-fer. If the loss of voltage was due to a failure of one of the transformers in the double-ended unit substation, then the associated primary fuses would blow taking only the failed transformer out of service, and then only the secondary loads normally served by the faulted transformer would have to be transferred to the opposite transformer.

In either of the above emergency conditions, the in service transformer of a double-ended unit substation would have to have the capa-bility of serving the loads on both sides of the tie breaker. For this reason, transformers uti-lized in this application have equal kVA rating on each side of the double-ended unit substa-tion and the normal operating maximum load on each transformer is typically about 2/3 base nameplate kVA rating. Typically these transformers are furnished with fan-cooling and/or lower than normal temperature rise such that under emergency conditions they can carry on a continuous basis the maxi-mum load on both sides of the secondary tie breaker. Because of this spare transformer capacity, the voltage regulation provided by

January 1999

Cutler-Hammer


CAT.71.01.T.E

A

System Design

the double-ended unit substation system under normal conditions is better than that of the systems previously discussed.

The double-ended unit substation arrange-ment can be utilized in conjunction with any of the previous systems discussed which involve two primary sources. Although not recom-mended, if allowed by the utility, momentary re-transfer of loads to the restored source may be made closed transition (anti-parallel inter-lock schemes would have to be defeated) for either the primary or secondary systems. Un-der this condition, all equipment interrupting and momentary ratings should be suitable for the fault current available from both sources.

For double-ended unit substations equipped with ground fault systems special consider-ation to transformer neutral grounding and equipment operation should be made - see “grounding and ground fault protection.” Where two single-ended unit substations are connected together by external tie conduc-tors, it is recommended that a tie breaker be furnished at each end of the tie conductors.

5. Simple Spot Network Systems

The ac secondary network system is the sys-tem that has been used for many years to dis-tribute electric power in the high-density, downtown areas of cities, usually in the form of utility grids. Modifications of this type of system make it applicable to serve loads within buildings.

The major advantage of the secondary net-work system is continuity of service.

No sin-gle fault anywhere on the primary system will interrupt service to any of the systems loads. Most faults will be cleared without in-terrupting service to any load.

Another out-standing advantage that the network system offers is its flexibility to meet changing and growing load conditions at minimum cost and minimum interruption in service to other loads on the network. In addition to flexibility and service reliability, the secondary network system provides exceptionally uniform and good voltage regulation, and its high efficien-cy materially reduces the costs of system losses.

Three major differences between the network system and the simple radial system account for the outstanding advantages of the net-work. First, a network protector is connected in the secondary leads of each network trans-former in place of, or in addition to, the sec-ondary main breaker, as shown in Fig. 5. Also, the secondaries of each transformer in a given location (spot) are connected togeth-er by a switchgear or ring bus from which the loads are served over short radial feeder cir-cuits. Finally, the primary supply has suffi-cient capacity to carry the entire building load without overloading when any one primary feeder is out of service.

Figure 4. Two Source Primary - Secondary Selective System

A network protector is a specially designed heavy duty air power breaker, spring close with electrical motor-charged mechanism, or motor operated mechanism, with a network relay to control the status of the protector (tripped or closed). The network relay is usually a solid-state microprocessor based component integrated into the protector enclosure which functions to automatically close the protector only when the voltage conditions are such that its associated transformer will supply power to the secondary network loads, and to automati-cally open the protector when power flows from the secondary to the network transform-er. The purpose of the network protector is to protect the integrity of the network bus voltage and the loads served from it against transform-er and primary feeder faults by quickly discon-necting the defective feeder-transformer pair from the network when backfeed occurs.

The simple spot network system resembles the secondary-selective radial system in that each load area is supplied over two or more primary feeders through two or more trans-formers. In network systems, the transform-ers are connected through network protectors to a common bus, as shown in Fig. 5, from which loads are served. Since the transform-ers are connected in parallel, a primary feeder or transformer fault does not cause any ser-vice interruption to the loads. The paralleled transformers supplying each load bus will normally carry equal load currents, whereas equal loading of the two separate transform-ers supplying a substation in the secondary-selective radial system is difficult to obtain.

The interrupting duty imposed on the out-going feeder breakers in the network will be greater with the spot network system.

The optimum size and number of primary feeders can be used in the spot network sys-tem because the loss of any primary feeder and its associated transformers does not re-sult in the loss of any load even for an instant. In spite of the spare capacity usually supplied in network systems, savings in primary switchgear and secondary switchgear costs often result when compared to a radial sys-tem design with similar spare capacity. This occurs in many radial systems because more and smaller feeders are often used in order to minimize the extent of any outage when a pri-mary fault event occurs.

In spot networks, when a fault occurs on a pri-mary feeder or in a transformer, the fault is isolated from the system through the auto-matic tripping of the primary feeder circuit breaker and all of the network protectors as-sociated with that feeder circuit. This opera-tion does not interrupt service to any loads. After the necessary repairs have been made, the system can be restored to normal operat-ing conditions by closing the primary feeder breaker. All network protectors associated with that feeder will close automatically.

The chief purpose of the network bus normal-ly closed ties is to provide for the sharing of loads and a balancing of load currents for each primary service and transformer regard-less of the condition of the primary services.

Primary Main Breakers

Primary Feeder Breakers

To Other SubstationsTo Other Substations

Secondary Main BreakerTie BreakerPrimary FusedSwitch

Transformer

TypicalDouble-EndedUnitSubstation

52 52

52

5252

52 52

CAT.71.01.T.E

Cutler-Hammer

A-10

January 1999


A

System Design

Also, the ties provide a means for isolating and sectionalizing ground fault events within the switchgear network bus, thereby saving a portion of the loads from service interrup-tions, yet isolating the faulted portion for cor-rective action.

The use of spot network systems provides us-ers with several important advantages. First, they save transformer capacity. Spot networks permit equal loading of transformers under all conditions. Also, networks yield lower system losses and greatly improve voltage condi-tions. The voltage regulation on a network system is such that both lights and power can be fed from the same load bus. Much larger motors can be started across-the-line than on a simple radial system. This can result in sim-plified motor control and permits the use of relatively large low voltage motors with their less expensive control. Finally, network sys-tems provide a greater degree of flexibility in adding future loads; they can be connected to the closest spot network bus.

Spot network systems are economical for buildings which have heavy concentrations of loads covering small areas, with considerable distance between areas, and light loads within the distances separating the concentrated loads. They are commonly used in hospitals, high rise office buildings, and institutional buildings where a high degree of service reli-ability is required from the utility sources. Co-generation equipment is not recommended for use on networks unless the protectors are manually opened and the utility source com-pletely disconnected and isolated from the temporary generator sources. Spot network systems are especially economical where three or more primary feeders are available. Princi-pally, this is due to supplying each load bus through three or more transformers and the re-duction in spare cable and transformer capaci-ty required. They are also economical when compared to two transformer double-ended substations with normally opened tie breakers.

6. Medium-Voltage Distribution System Design

a. Single Bus, Fig. 6A

The sources (utility and/or generator(s)) are connected to a single bus. All feeders are connected to the same bus. Generators are used where cogeneration is employed.

This configuration is the simplest system, however, outage of the utility results in total outage.

Normally the generator does not have ade-quate capacity for the entire load. A properly relayed system equipped with load shedding, automatic voltage/frequency control may be able to maintain partial system operation. Note that the addition of breakers to the bus requires shutdown of the bus.

b. Single Bus with Two Sources From the Utility, Fig. 6B

Same as the single bus, except that two utility sources are available. This system is operated normally with the main breaker to one source open. Upon loss of the normal service the transfer to the standby Normally open (NO) breaker can be automatic or manual. Auto-matic transfer is preferred for rapid service restoration especially in unattended stations.

Retransfer to the “Normal” can be closed transition subject to the approval of the utility. Closed transition momentarily (5-10 cycles) parallels both utility sources. Caution – When both sources are paralleled, the fault current available on the load side of the main device is the sum of the available fault current from each source plus the motor fault contribution. It is recommended that the short circuit rat-ings of the bus, feeder breakers and all load side equipment are rated for the increased available fault current. If the utility requires open transfer, the disconnection of motors from the bus must be ensured by means of suitable time delay on reclosing as well as su-pervision of the bus voltage and its phase with respect to the incoming source voltage.

This busing scheme does not preclude the use of cogeneration, but requires the use of sophisticated automatic synchronizing and synchronism checking controls, in addition to the previously mentioned load shedding, automatic frequency and voltage controls.

This scheme is more expensive than scheme shown in Fig. 6A, but service restoration is quicker. Again a utility outage results in total outage to the load until transfer occurs. Extension of the bus or adding breakers requires a shutdown of the bus.

If paralleling sources, reverse current, re-verse power, and other appropriate relaying protection should be added as requested by the utility.

Figure 5. 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

Figure 6A. Single Bus

52

Utility

Main Bus

G

One of Several Feeders

52

52

Figure 6B. Single Bus with Two Sources

Utility #2Utility #1

Normal Standby

NC NO

Loads

52 52

January 1999

Cutler-Hammer


CAT.71.01.T.E

A

System Design

c. Multiple Sources with Tie Breaker, Figs. 6C and 6D

This scheme is similar to scheme B. It differs significantly in that both utility sources nor-mally carry the loads and also by the incorpo-ration of a normally open tie breaker. The outage to the system load for a utility outage is limited to half of the system. Again the closing of the tie breaker can be manual or automatic. The statements made for the re-transfer of scheme B apply to this scheme al-so.

If looped or primary selective distribution system for the loads is used, the buses can be extended without a shutdown by closing the tie breaker and transferring the loads to the other bus.

This system is more expensive than B. The system is not limited to two buses only. Another advantage is that if the paralleling of the buses is momentary, no increase in the interrupting capacity of the circuit breakers is required as other buses are added provided only two buses are paralleled momentarily for switching.

In Fig. 6D, closing of the tie breaker following the opening of a main breaker can be manual or automatic. However since a bus can be fed through two tie breakers the control scheme should be designed to make the selection.

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

Caution For Figures 6B, 6C and 6D:

If

continuous

paralleling of sources is planned, reverse current, reverse power and other appropriate relaying protection should be added. When both sources are paralleled, the fault current available on the load side of the main device is the sum of the available fault current from each source plus the motor fault contribution. It is required that bus brac-ing, feeder breakers and all load side equip-ment is rated for the increased available fault current.

Summary

The schemes shown are based on using metal-clad medium-voltage draw-out switch-gear. The service continuity required from electrical systems makes the use of single source systems impractical.

In the design of modern medium-voltage sys-tem the engineer should:

1. Design a system as simple as possible.

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

3. Provide means for expanding the system

Figure 6C. Two Source Utility with Tie Breaker

NC

Bus #1 Bus #2

Load Load

Utility #1 Utility #2

NC

NO

52 52

52

52 52

Figure 6D. Triple Ended Arrangement

without major shutdowns.

4. Relay the system so that only the faulted part is removed from service, and dam-age to it is minimized consistent with selectivity.

5. Specify and apply all equipment within its published ratings and national stan-dards pertaining to the equipment and its installation.

NO

NC

Bus #1 Bus #2

Utility #1 Utility #2

NC

NO NO

Utility #3

Bus #3

NC

Tie Busway

52 52 52

52

52

52

52 NOTypical Feeer52 5252

CAT.71.01.T.E

Cutler-HammerA-12January 1999


A

Systems Analysis

Systems Analysis

A major consideration in the design of a dis-tribution system is to ensure that it provides the required quality of service to the various loads. This includes serving each load under normal conditions and, under abnormal con-ditions, providing the desired protection to service and system apparatus so that inter-ruptions of service are minimized consistent with good economic and mechanical design.

Under normal conditions, the important tech-nical factors include voltage profile, losses, load flow, effects of motor starting, service continuity and reliability. The prime consider-ations under faulted conditions are apparatus protection, fault isolation and service continu-ity. During the system preliminary planning stage, before selection of the distribution ap-paratus, several distribution systems should be analyzed and evaluated including both economic and technical factors. During this stage if system size or complexity warrant, it may be appropriate to provide a thorough re-view of each system under both normal and abnormal conditions.

The principal types of computer programs utilized to provide system studies include:

Short circuit–identify three-phase and line-to-ground fault currents and system impedances.

Circuit breaker duty–identify asymmetrical fault current based on X/R ratio.

Protective device coordination–determine characteristics and settings of medium-voltage protective relays and fuses, and en-tire low-voltage circuit breaker and fuse coordination.

Load flow–simulate normal load conditions of system voltages, power factor, line and transformer loadings.

Motor starting–identify system voltages and motor torques when starting large motors.

Short-circuit calculations define momentary fault currents for LV breaker and fuse duty and bus bracings at any selected location in the system and also determine the effect on the system after removal of lines due to breaker operation or scheduled line outages. With the use of computer programs it is pos-sible to identify the fault current at any bus, in every line or source connected to the fault bus, or to it and every adjacent bus, or to it and every bus which is one and two buses away, or currents in every line or source in the system. The results of these calculations per-mit optimizing service to the loads while properly applying distribution apparatus within their intended limits.

January 1999

Cutler-Hammer


CAT.71.01.T.E

A

Short-Circuit Currents – General

Structure of an Asymmetrical Current Wave

Short-Circuit Currents – General

The amount of current available in a short-circuit fault is determined by the capacity of the system voltage sources and the imped-ances of the system, including the fault. Con-stituting voltage sources are the power supply (utility or on-site generation) plus all rotating machines connected to the system at the time of the fault. A fault may be either an arcing or bolted fault. In an arcing fault, part of the circuit voltage is consumed across the fault and the total fault current is somewhat smaller than for a bolted fault, so the latter is the worst condition, and therefore is the value sought in the fault calculations.

Basically, the short-circuit current is deter-mined by Ohm’s Law except that the imped-ance is not constant since some reactance is included in the system. The effect of reactance in an ac system is to cause the initial current to be high and then decay toward steady-state (the Ohm’s Law) value. The fault current

consists of an exponentially decreasing direct-current component superimposed upon a decaying alternating-current. The rate of decay of both the dc and ac components depends upon the ratio of reactance to resis-tance (X/R) of the circuit. The greater this ratio, the longer the current remains higher than the steady-state value which it would eventually reach.

The total fault current is not symmetrical with respect to the time-axis because of the direct-current component, hence it is called asym-metrical current. The dc component depends on the point on the voltage wave at which the fault is initiated.

See Table A2 for multiplying factors that relate the RMS asymmetrical value of Total Current to the RMS symmetrical value, and the peak asymmetrical value of Total Current to the RMS symmetrical value.

The ac component is not constant if rotating machines are connected to the system be-cause the impedance of this apparatus is not constant. The rapid variation of motor and generator impedance is due to these factors:

Subtransient Reactance

(

x

d"), determines fault current during the first cycle, and after about 6 cycles this value increases to the tran-sient reactance. It is used for the calculation of the momentary and interrupting duties of equipment and/or system.

Transient Reactance

(

x

d’), which determines fault current after about 6 cycles and this val-ue in

1

⁄

2

to 2 seconds increases to the value of the synchronous reactance. It is used in the setting of the phase OC relays of generators.

Synchronous Reactance

(

x

d), which deter-mines fault current after steady state condi-tion is reached. It has no effect as far as short-circuit calculations are concerned but is useful in the determination of relay settings.

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 CurrentAlternating Component-A Symmetrical Wave

Rms Value ofAlternating Component

Direct Component - The Axisof Asymmetrical Wave Time in Cycles of

a 60 Cps Wave

1 2 3 4

Sca

le o

f C

ure

nt

Valu

es

Transformer Impedance

, in percent, is defined as that percent of rated primary voltage that must be applied to the transformer to produce rated current flowing in the secondary, with secondary shorted through zero resistance. Therefore, assuming the primary voltage can be sustained (generally referred to as an infi-nite or unlimited supply), the maximum cur-rent a transformer can deliver to a fault condition is the quantity of (100 divided by percent impedance) times the transformer rated secondary current. Limiting the power source fault capacity will thereby reduce the maximum fault current from the transformer.

The electric network which determines the short-circuit current consists of an ac driving voltage equal to the pre-fault system voltage at the fault location and an impedance corre-sponding to that observed when looking back into the system from the fault location. In medium- and high-voltage work, it is general-ly satisfactory to regard reactance as the en-tire impedance; resistance may be neglected. However, this is normally permissible only if the X/R ratio of the medium-voltage system is equal to or more than 25. In low-voltage (1000 volts and below) calculations, it is usu-ally worthwhile to attempt greater accuracy by including resistance with reactance in dealing with impedance. It is for this reason, plus ease of manipulating the various imped-ances of cables and buses and transformers of the low-voltage circuits, that computer studies are recommended before final selec-tion of apparatus and system arrangements.

When evaluating the adequacy of short circuit ratings of medium voltage circuit breakers and fuses, both the RMS symmetri-cal value and asymmetrical value of the short circuit current should be determined.

For low voltage circuit breakers and fuses, the RMS symmetrical value should be deter-mined along with either: the X/R ratio of the fault at the device or the asymmetrical short circuit current.

CAT.71.01.T.E

Cutler-Hammer

A-14

January 1999


A

Fault Current Wave Form Relationships

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

PEAK M

ULTIP

LICATI

ON FACTO

R

RMS MULTIPLICATION FA

CTOR

CIRCUIT X/R RATIO (TAN Ø)

Based Upon: Rms Asym = Dc2 + Rms Sym2

with Dc ValueTaken at Current Peak

RM

S M

ULT

IPLI

CA

TIO

N F

AC

TO

R =

RM

S M

AX

IMU

M A

SY

MM

ET

RIC

AL

RM

S S

YM

ME

TR

ICA

L

PE

AK

MU

LTIP

LIC

AT

ION

FA

CT

OR

=P

EA

K M

AX

IMU

M A

SY

MM

ET

RIC

AL

RM

S S

YM

ME

TR

ICA

L

Fault Current Wave Form Relationships

The following formulas and Table arereproduced from ANSI/IEEE C37.48. Table A2 describes the relationship between faultcurrent peak values, rms symmetrical values and rms asymmetrical depending on thecalculated X/R ratio.

The formulas are:1.

Ip 2 2∈–

wtX R⁄------------

in per unit.+=

For example, for X/R = 15,

∈

= 2.718w = 2

π

f for 60 hertz = 377t =

1

⁄

2

cycle or

1

⁄

120

seconds then

= 2.56122.

Ip 2 2 2.718–

×37715

---------- 1120----------×

+=

IRms Asymm= I2

2 ∈–

wtX R⁄------------

×2

+1 2 2.718

– 37715 x 120-----------------------

2

×

+=

1.5217=

Table A2: Relation of X/R Ratio to Multiplication Factor

January 1999

Cutler-Hammer A-15Power Distribution System Design

CAT.71.01.T.E

A

Fault Current Calculations

Fault Current Calculations

The calculation of asymmetrical currents is a laborious procedure since the degree of asymmetry is not the same on all three phas-es. It is common practice to calculate the rms symmetrical fault current, with the assump-tion being made that the dc component has decayed to zero, and then apply a multiply-ing factor to obtain the first half-cycle rms asymmetrical current, which is called the “momentary current.” For medium-voltage systems (defined by IEEE as greater than 1000 volts up to 69,000 volts) the multiplying factor is established by NEMA and ANSI standards depending upon the operating speed of the breaker; for low-voltage sys-tems, 600 volts and below, the multiplying factor is usually 1.17 (based on generally accepted use of X/R ratio of 6.6 representing a source short-circuit power factor of 15%). These values take into account that medium-voltage breakers are rated on maximum asymmetry and low voltage breakers are rated average asymmetry.

To determine the motor contribution to the first half-cycle fault current when the system motor load is known, the following assump-tions generally are made:

Induction Motors – Use 4.0 times motor full load current (impedance value of 25%).

Synchronous Motors – Use 5.0 times motor full load current (impedance value of 20%).

When the motor load is not known, the fol-lowing assumptions generally are made:

208Y/120-volt systems● Assume 50% lighting and 50% motor load.

or● Assume motor feedback contribution of

twice full load current of transformer.

240-480-600-volt 3-phase, 3-wire systems● Assume 100% motor load.

or● Assume motors 25% synchronous and

75% induction.or

● Assume motor feedback contribution of four times full load current of transformer.

480Y/277-volt systems in commercial buildings● Assume 50% induction motor load.

or● Assume motor feedback contribution of

two times full load current of transformer or source.

or● For industrial plants, make same assump-

tions as for 3-phase, 3-wire systems (above).

Medium-Voltage Motors● If known use actual values otherwise use

the values indicated in the above for the same type of motor.

Types of CalculationsThe following pages describe various meth-ods of calculating short circuit currents for both medium and low voltage systems. A summary of the types of methods and types of calculations is as follows:

● Medium Voltage Switchgear – exact method

● Medium Voltage Switchgear – quick check table

● Medium Voltage Switchgear Example 1 – verify ratings of breakers

● Medium Voltage Switchgear Example 2 – verify ratings of breakers with rotating loads

● Medium Voltage Switchgear Example 3 – verify ratings of breakers with generators

● Medium Voltage Fuses – exact method

● Power Breakers – asymmetry derating factors

● Molded Case Breakers – asymmetry derating factors

● Short Circuit Calculations – short cut method for a system

● Short Circuit Calculations – short cut method for end of cable

● Short Circuit Calculations – short cut method for end of cable chart method

CAT.71.01.T.E



AFault Current Calculations for Specific Equipment

The purpose of the fault current calculations is to determine the fault current at the location of a circuit breaker, fuse or other fault inter-rupting device in order to select a device ade-quate for the calculated fault current or to check the thermal and momentary ratings of non-interrupting devices. When the devices to be used are ANSI-rated devices, the fault current must be calculated and the device selected as per ANSI standards.

The calculation of available fault current and system X/R rating is utilized to verify ade-quate bus bar bracing and momentary with-stand ratings of devices such as contactors.

Medium-Voltage VCP-W Metal-Clad Switchgear

The applicable ANSI Standards C37.06. is the latest applicable edition. The following is a review of the meaning of the ratings. (See section C1 of this catalog.)

The Rated Maximum VoltageThis designates the upper limit of design and operation of a circuit breaker. For example, a circuit breaker with a 4.76 kV rated maximum voltage cannot be used in a 4.8 kV system.

K-Rated Voltage FactorThe rated voltage divided by this factor deter-mines the system kV a breaker can be applied up to the short circuit kVA rating calculated by the formula

Rated Short Circuit Current–This is the sym-metrical rms value of current that the breaker can interrupt at rated maximum voltage. It should be noted that the product x 4.76 x 29,000 = 239,092 kVA is less than the nominal 250,000 kVA listed. This rating (29,000 Amps) is also the base quantity that all the “related” capabilities are referred to.

Maximum Symmetrical Interrupting Capability–This is expressed in rms symmet-rical amperes or kiloamperes and is K x I rated; 29,000 x 1.24 = 35,960 rounded to 36 kA.

This is the rms symmetrical current that the breaker can interrupt down to a voltage = maximum rated voltage divided by K (for example, 4.76/1.24 = 3.85). If this breaker is applied in a system rated at 2.4 kV the calcu-lated fault current must be less than 36 kA.

For example, consider the following case:

Assume a 12.47 kV system with 20,000 am-peres symmetrical available. In order to deter-mine if a Cutler-Hammer type 150 VCP-W 500 vacuum breaker is suitable for this applica-tion, check the following:

3 Rated SC Current Rated Max. Voltage.××

3

Fault Current Calculations for Specific Equipment

From Table 1 in section C1 under column “Rated Maximum Voltage” 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 x 18 kA = 21.65; also check K x I (which is shown in the column headed “Maximum Symmetrical Interrupting Capability”) or 1.3 x 18 kA = 23.4 kA. Since both of these numbers are greater than the available system fault current of 20,000 amperes, the breaker is acceptable.

Note: If the system available fault current were 22,000 amperes symmetrical, this breaker could not be utilized even through the “Maximum Symmetrical Interrupting Capa-bility” is greater than 22,000 since Test 1 cal-culation is not satisfied.

The close and latch capability is also a related quantity expressed in rms asymmetrical am-peres by 1.6 x maximum symmetrical inter-rupting 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 close and latch rating is in terms of the peak current, which is the instantaneous value of the cur-rent at the crest. ANSI Standard C37.09 indi-cates that the ratio of the peak to rms asymmetrical value for any asymmetry of 100% to 20% (percent asymmetry is defined as the ratio of dc component of the fault in per unit to ) varies not more than ±2% from a ratio of 1.69. Therefore the close and latch current expressed in terms of the peak amperes is = 1.6 x 1.69 x K x rated short-circuit current.

2

Table A4: Typical System X/R Ratio Range (for Estimating Purposes)

Type of Circuit X/R Range

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

15 or less

Remote generation connected through transformer rated 10 MVA to 100 MVA for each three-phase bank, where the transformers provide 90 percent or more of the total equivalent impedance to the fault point.

15-40

Remote generation connected through transformers rated 100 MVA or larger for each three-phase bank where the transformers provide 90 percent or more of the total equivalent impedance to the fault point.

30-50

Synchronous machines connected through transformers rated 25 to 100 MVA for 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

Table A3: Reactance X for E/X Amperes

System Component Reactance X Used for Typical Values and Range on Component Base

Short-CircuitDuty

Close and Latch (Momentary)

% Reactance X/R Ratio

2-Pole Turbo Generator

4-Pole Turbo Generator

Hydro Gen. with Damper Wdgs. andSyn. Condensers

Hydro Gen. without Damper Windings

All Synchronous Motors

Ind. Motors Above 1000 Hp, 1800 Rpmand Above 250 Hp, 3600 Rpm

All Other Induction Motors 50 Hpand Above

Ind. Motors Below 50 Hp andAll Single-Phase Motors

Distribution System From RemoteTransformers

Current Limiting Reactors

TransformersOA to 10 MVA, 69 kV

OA to 10 MVA, above 69 kV

FOA 12 to 30 MVA

FOA 40 to 100 MVA

X

X

X

.75X

1.5X

1.5X

3.0X

NeglectX

X

X

X

X

X

X

X

X

.75X

1.0X

1.0X

1.2X

NeglectX

X

X

X

X

X

97-141412-172013-323020-502413-352515-252515-25

As Specifiedor CalculatedAs Specifiedor Calculated

5.55-77.57-11108-24158-35

8040-1208040-1203010-603010-603010-603015-40155-20

155-158040-120

106-12128-152010-303020-40

January 1999


CAT.71.01.T.E

A6

5

4

CO

NTA

CT

PAR

TIN

GTI

ME

3

5-CYCLEBREAKER

1.0 1.1 1.2 1.3 1.4Multiplying Factors for E / X Amperes

Rat

io 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

Multiplying Factors for E / X Amperes

34

5

Rat

io X

/R

130

120

110

100

90

80

70

60

50

40

30

20

10

4

5-CYCLEBREAKER

1.0 1.1 1.2 1.3 1.4

Multiplying Factors for E / X Amperes

6

81012

CON

TACT

PART

ING

TIM

E3

Rat

io X

/R

130

120

110

100

90

80

70

60

50

40

30

20

10


In the calculation of faults for the purposes of breaker selection the rotating machine im-pedances specified in ANSI Standard C37.010 Article 5.4.1 should be used. The value of the impedances and their X/R ratios should be ob-tained from the equipment manufacturer. At initial short-circuit studies, data from manu-facturers is not available. Typical values of im-pedances and their X/R ratios are given in Tables A3 and A4.

The ANSI Standard C37.010 requires the use of the X values only in determining the E/X value of a fault current. The R values are used to determine the X/R ratio, in order to apply the proper multiplying factor, to account for the total fault clearing time, asymmetry, and decrement of the fault current.

The steps in the calculation of fault currents and breaker selection are described herein-after:Step 1–Collect the X and R data of the circuit elements. Convert to a common kVA and volt-age base. If the reactances and resistances are given either in ohms or per unit on a different voltage or kVA base, all should be changed to the same kVA and voltage base. This caution does not apply where the base voltages are the same as the transformation ratio.

Table A5: Three-Phase Fault Multiplying Factors Which Include Effects of Ac and Dc Decrement.

Table A6: Line-to-Ground Fault Multiplying Factors Which Include Effects of Ac and Dc Decrement.

Step 2–Construct the sequence networks and connect properly for the type of fault under consideration. Use the X values required by ANSI Standard C37.010 for the “interrupting” duty value of the short-circuit current.

Step 3–Reduce the reactance network to an equivalent reactance. Call this reactance XI.

Step 4–Set-up the same network for resis-tance values.

Step 5–Reduce the resistance network to an equivalent resistance. Call this resistance RI. The above calculations of XI and RI may be calculated by several computer programs.

Step 6–Calculate the E/XI value, where E is the prefault value of the voltage at the point of fault nominally assumed 1.0 pu.

Step 7–Determine X/R = as previously calculated.

Step 8–Go to the proper curve for the type of fault under consideration (3-phase, phase-to-phase, phase-to-ground), type of breaker at the location (2, 3, 5, or 8 cycles), and contact parting time to determine the multiplier to the calculated E/XI.

XIRI-----

See Tables A5, A6, and A7 for 5-cycle breaker multiplying factors. Use Table A7 if the short cricuit is fed predominantly from generators removed from the fault by two or more trans-formations or the per unit reactance external to the generation is 1.5 times or more than the subtransient reactance of the generation on a common base. Also use Table A7 where the fault is supplied by a utility only.

Step 9–Interrupting duty short-circuit current = E/XI x MF.

Step 10–Construct the sequence (positive, negative and zero) networks properly con-nected for the type of fault under consider-ation. Use the X values required by ANSI Standard C37.010 for the “Close and Latch” duty value of the short-circuit current.

Step 11–Reduce the network to an equivalent reactance. Call the reactance X. Calculate E/X x 1.6 if the breaker close and latch capabil-ity is given in rms amperes or E/X x 2.7 if the breaker close and latch capability is given in peak or crest amps.

Table A7: Three-Phase and Line-to-Ground Fault Multiplying Factors Which Include Effects of Dc Decrement Only.

CAT.71.01.T.E



A


Step 12–Select a breaker whose:

a. maximum voltage rating exceeds the operating voltage of the system;

b. See Table 1, Page C1-4.

Where:I = Rated short circuit currentVmax = Rated maximum voltage of

the breakerVD = Actual system voltageKI = Maximum symmetrical

interrupting capacityc. E/XM x 1.6 ≤ closing and latch capability

of the breaker.

The ANSI standards do not require the inclusion of resistances in the calculation of the required interrupting and close and latch capabilities. Thus the calculated values are conservative. However when the capa-bilities of existing switchgears are investi-gated, the resistances should be included.

For single line-to-ground faults the sym-metrical interrupting capability is 1.15 x the symmetrical interrupting capability at any operating voltage but not to exceed the maxi-mum symmetrical capability of the breaker. Paragraphs 5.2, 5.3 and 5.4 of ANSI C37.010.1979 provide further guidance for medium-voltage breaker application.

Reclosing DutyANSI Standard C37.010 indicates the reduc-tion factors to use when circuit breakers are used as reclosers. Cutler-Hammer VCP-W breakers are listed at 100% rating factor for reclosing.

EXI----- I

VmaxVo

--------------- KI<×≤

Application Quick Check TableFor application of circuit breakers in a radial system supplied from a single source trans-former. Short-circuit duty was determined using E/X amperes and 1.0 multiplying factor for X/R ratio of 15 or less and 1.25 multiplying factor for X/R ratios in the range of 15 to 40.

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

Application Above 3300 FeetThe rated one-minute power frequency with-stand voltage, the impulse withstand voltage, the continuous current rating, and the maxi-mum voltage rating must be multiplied by the appropriate correction factors below to obtain modified ratings which must equal or exceed the application requirements. Note that intermediate values may be obtained by interpolation.

Altitude(Feet)

Correction Factor

Current Voltage

3,300 (and Below) 5,00010,000

1.000.990.96

1.000.950.80

SourceTransformerMVA Rating

Operating Voltage kV

Motor Load 2.4 4.16 6.6 12 13.8

100% 0%

11.52

1.522.5

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 kA7.510➀

1010

50 VCP-W 35049 kA

10 12➀

12 15 50 VCP-W 35046.9 kA

75 VCP-W 50041.3 kA

15 20

20➀ 20 Breaker Type andSym. Interrupting Capacityat the Operating Voltage

150 VCP-W 75035 kA

150 VCP-W 75030.4 kA25

30

50➀ 150 VCP-W 100046.3 kA

150 VCP-W 100040.2 kA

January 1999


CAT.71.01.T.E

AApplication on Symmetrical Current Rating Basis

Note: Interrupting capabilities I1 and I2 atoperating voltage must not exceed max. sym.interrupting capability Kl.

Example 1 — Fault CalculationsGiven 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.

Type Breaker V Max. 3ø Sym. Interrupting Capability Close and Latch or Momentary@ V. Max. Max. KI @4.16 kV Oper. Voltage

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

58 kA I3

LG Sym. Interrupting Capability

36 kA 1.15 (33.2) = 38.2 kA I2


Check capabilities I1, I2 and I3 on the following utility system where there is no motor contribution to short circuit.

From transformer losses R is calculated

31,000 Watts Full Load–6,800 Watts No Load24,200 Watts Load Losses

For 3-Phase Fault

is the highest typical line-to-neutral operating voltage

or I3ø = IB

where X is per unit reactanceX

IB is base current

1.0 multiplying factor for short-circuit duty, therefore, short-circuit duty is 8.6 kA sym. for 3 ø fault I1 and momentary duty is 8.6 x 1.6 = 13.7 kA I3.

For Line-to-Ground Fault

For this system, X0 is the zero sequence reac-tance of the transformer which is equal to the transformer positive sequence reactance and X1 is the positive sequence reactance of the system.

Therefore,

Using 1.0 multiplying factor, short-circuit duty = 9.1 kA Sym. LG (I2)

Answer

The 50VCPW250 breaker capabilities exceed the duty requirements and may be applied.

With this application, short cuts could have been taken for a quicker check of the applica-tion. If we assume unlimited short circuit available at 13.8 kV and that Trans. Z = X

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

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

I3ø EX---- where X is ohms per phase and E=

Base current IB3.75 MVA

3 (4.16 kV)------------------------------- .52 kA= =

I3øI1X---- .52

.0604------------- 8.6 kA Sym.= = =

System XR--- 9 (is less than 15) would use=

ILG3E

2X1 X0+----------------------- or

3IB2X1 X0+-----------------------= =

ILG3(.52)

2(.0604) .0505+--------------------------------------- 9.1 kA Sym.= =

Then I3øIBX---- .52

.055---------- 9.5 kA Sym.= = =

13.8 kV

375 MVAAvailable

13.8 kV

3750 kVA

4.16 kV

50VPC-W250

= 15X

R

On 13.8 kV System, 3.75 MVA Base

Transformer Standard 5.5% Impedance hasa ±7.5% Manufacturing Tolerance

Transformer Z =

5.50 Standard Impedance–.41 (–7.5% Tolerance)5.09%

Z3.75 MVA375 MVA------------------------ .01 pu or 1%= =

Z2

X2

R2

R2 X

2

R2------ 1+

=+=

RZ

X2

R2

------ 1+

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

226------------- 1

15.03------------- .066%= = = =

XXR--- R( ) 15 (.066) .99%= = =

R24.2 kW

3750 kVA----------------------- .0065 pu or .65%= =

X = 5.05%

Transformer X Z2

R2– (5.09)

2(.65)

2– 25.91 .42– 25.48= = =

X R X/R

13.8 kV SystemTransformer

.99%5.05

.066%

.6515 8

System Totalor

6.04% .0604 pu

.716

.00716 pu 9

4.764.16---------[ ]

CAT.71.01.T.E

Cutler-Hammer

A-20

January 1999


A

Short Circuit Duty = 10.1 kA

Answer

Either breaker could be properly applied, but price will make the type 150VCPW500 the more economical selection.

Type Breaker

VMax.

3ø Sym. Interrupting Capability Close and Latchor Momentary@ V. Max. Max. KI @ 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


Example 2 — Fault Calculations

Given the system shown with motor loads, calculate the fault currents and determine proper circuit breaker selection.

All calculations on per unit basis. 7.5 MVA Base

3000 Hp Syn. Motor

2500 Hp Ind. Motor

X R X/R

13.8 kV System

Transformer

.015

.055

.001

.0055

15

10

Total Source Transf. .070 pu .0065 pu 11

Base Curent IB7.5 MVA

3 6.9 kV------------------------ .628 kA= =

X.62821

---------- (6.9)(13.8)-------------- .015= =

X .20 (.628).197

-------------- .638 pu at 7.5 MVA base= =

X .25 (.628)(.173)-------------- .908 pu at 7.5 MVA base= =

I3øEX---

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

Z = 5.53% = 10

13.8 kV

7500 kVA

6.9 kV

13.8 kV System

3

21 kA Sym. Available = 15XR

X = 5.5%R = 0.55%

XR

XR

= 25XR

= 35

3000 Hp1.0 PFSyn.

2500 HpInd.

2197A FLX'' = 20%d

173A FLX'' = 25%d

1

Source ofShort Circuit Current

InterruptingE/X Amperes

MomentaryE/X Amperes

XR

X (1)R (X)

1R

I

3

Source Transf. .682.070

= 8.971 .682.070

= 8.971 11 11.070

= 157

I

1

3000 Hp Syn. Motor .628(1.5) .638 = .656 .628

.638 = .984 25 25.638

= 39

I

1

2500 Hp Syn. Motor .628(1.5) .908 = .461 .628

.908 = .691 35 35.908

= 39

I

3F

= 10.088 or 10.1 kA

10.647 Total 1/R = 235 x 1.617.0 kA Momentary Duty

Total XIBI3F------- .628

10.1---------- .062= = =

System XR--- .062 (235) 14.5 is Mult. Factor 1.0 from Table 2.= =

January 1999


CAT.71.01.T.E

A


Example 3 — Fault CalculationsCheck breaker application or generator bus for the system of generators shown.

Each generator is 7.5 MVA, 4.16 kV 1040 amperes 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 ILG to I3ø or below, we need only check the I3 short-circuit duty.

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

Answer

The 50VCP-W250 breaker could be applied.

3ø Sym. Interrrupting Capability

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

50VCP-W250 4.76 kV 29 kA 36 kA 4.764.16 (29) = 33.2 kA

Gen XR--- ratio is 30

1XS------- 1

X--- 1

X--- 1

X--- 3

X--- and=+ +=

1RS------- 1

R--- 1

R--- 1

R---

3R---=+ +=

or XSX3--- and RS

R3--- Therefore, System

XSRS-------

XR--- Gen

XR--- 30= = = = =

IBøIBX----

IBX----

IBX----

31BX

--------- 3 1.04( ).11

------------------ 28.4 kA Sym. E/X amperes==+ + +=

Table 2 System XR--- of 30 is Mult. factor 1.04

G1 G2 G3

4.16 kV

Medium-Voltage Fuses

There are two basic types of medium-voltage fuses (the following definitions are taken from ANSI Standard C37.40).

Expulsion Fuses

A vented fuse in which the expulsion effect of gases produced by the arc and lining of the fuse holder, either alone or aided by a spring, extinguishes the arc.

Current Limiting Fuses

A fuse unit that when it is melted by a current within its specified current limiting range, abruptly introduces a high resistance to re-duce the current magnitude and duration.

There are two types of fuses; power and dis-tribution. They are distinguished from each other by the current ratings and minimum melting type characteristics.

The current limiting ability of a current limiting fuse is specified by its threshold ratio, peak let-through current and I2t characteristics.

Interrupting Ratings of Fuses

Modern fuses are rated in amps rms symmet-rical. They also have a listed asymmetrical rms rating which is 1.6 x the symmetrical rating.

Refer to ANSI/IEEE C37.48 for fuse interrupt-ing duty guidelines.

Calculation of the fuse required interrupting rating:

Step 1–Convert the fault from the utility to percent or per unit on a convenient voltage and kVA base.

Step 2–Collect the X and R data of all the other circuit elements and convert to a percent or per unit on a convenient kVA and voltage base same as that used in Step 1. Use the sub-stransient X and R for all generators and motors.

Step 3–Construct the sequence networks us-ing reactances and connect properly for the type of fault under consideration and reduce to a single equivalent reactance.

Step 4–Same as above except using resis-tances (omit if a symmetrically rated fuse is to be selected).

Step 5–Calculate the E/XI value, where E is the prefault value of the voltage at the point of fault normally assumed 1.0 in pu. For three-phase faults E/XI is the fault current to be used in determining the required interrupting ca-pability of the fuse.

CAT.71.01.T.E



A


Table A8: Standard Test Power Factors

Type ofCircuitBreaker

InterruptingRating in KA

PowerFactorTestRange

X/RTestRange

Molded CaseMolded CaseMolded CaseLow-VoltagePower

10 or lessover 10 to 20over 20All

0.45-0.500.25-0.300.15-0.200.15 max.

1.98 -1.733.87 -3.186.6 -4.96.6 min.

For distribution systems where the calculated short-circuit current X/R ratio differs from the standard values given in the above table, cir-cuit breaker interrupting rating multiplying factors from the following table should be applied.

Note: These are derating factors applied to the breaker.

Table A9: Circuit Breaker Interrupting Rating Multiplying Factors

%P.F.

X/R Interrupting Rating

≤ = 10kA >10 kA≤ = 20 kA

>20 kA AllLV PCB

50302520151210975

1.73213.17983.87304.89906.59128.27319.9499

11.722114.250719.9750

1.0000.8470.8050.7620.7180.6910.6730.6590.6450.627

1.0001.0000.9500.8990.8470.8150.7940.7780.7610.740

1.0001.0001.0001.0000.9420.9070.8830.8650.8470.823

1.0001.0001.0001.0001.0000.9620.9370.9180.8990.874

If the X/R to the point of fault is greater than 6.6, a derating multiplying factor (MF) must be applied. The X/R ratio is calculated in the same manner as that for medium-voltage cir-cuit breakers.

Calculated symmetrical Amps x MF ≤ breaker interrupting rating.

The multiplying factor MF can be calculated by the formula:

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

For fused breakers by the formula:

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

Refer to Table A8 for the standard ranges of X/R and Power Factors used in testing and rat-ing low-voltage breakers. Refer to Table A9 for the circuit breaker interrupting rating multiply-ing factors to be used when the calculated X/R ratio or power factor at the point the breaker is to be applied in the power distribution system falls outside of the Table A8 X/R or power factors used in testing and rating the circuit breakers. MF is always greater than 1.0.

Molded Case Breakers and Insulated Case Type SPB Breakers

The method of fault calculation is the same as that for low-voltage power circuit breakers. Again the calculated fault current x MF ≤ breaker interrupting capacity. Because molded case breakers are tested at lower X/R ratios the MFs are different than those for low-volt-age power circuit breakers.

X1/R1 = test X/R value.

X2/R2 = X/R at point where breaker is applied.

MF2 1 2.718

2π( ) X R⁄( )⁄–+[ ]

2.29---------------------------------------------------------------=

MF1 2 2.718( )– 2π( )/ X R⁄( )×+

1.25-------------------------------------------------------------------=

MF1 2.718+

-πX2

R2------

⁄

1 2.718+-π

X1

R1------

⁄---------------------------------------=

Note: It is not necessary to calculate a single phase-to-phase fault current. This current is very nearly /2 x three-phase fault. The line-to-ground fault may exceed the three-phase fault for fuses located in generating stations with solidly grounded neutral generators, or in delta-wye transformers with the wye solid-ly grounded, where the sum of the positive and negative sequence impedances on the high-voltage side (delta) is smaller than the impedance of the transformer.

For single line-to-ground fault;XI = XI(+) + XI(-) + XI(0)

Step 6–Select a fuse whose published inter-rupting rating exceeds the calculated fault current.

Table A2 should be used where older fuses asymmetrically rated are involved.

The voltage rating of power fuses used on three-phase systems should equal or exceed the maximum line-to-line voltage rating of the system. Current limiting fuses for three- phase systems should be so applied that the fuse voltage rating is equal to or less than 1.41 x nominal system voltage.

Low-Voltage Power Circuit Breakers Type Magnum DS, DSII or DSLII

The steps for calculating the fault current for the selection of a low-voltage power circuit breaker are the same as those used for medium-voltage circuit breakers except that where the connected loads to the low-voltage bus includes induction and synchronous mo-tor loads the assumption is made that in 208Y/120-volt systems the contribution from motors is 2 times the full load current of step-down transformer. This corresponds to an as-sumed 50% motor aggregate impedance on a kVA base equal to the transformer kVA rating or 50% motor load. For 480-, 480Y/277- and 600-volt systems the assumption is made that the contribution from the motors is 4 times the full load current of the step-down trans-former which corresponds to an assumed 25% aggregate motor impedance on a kVA base equal to the transformer kVA rating or 100% motor load.

In low-voltage systems which contain gener-ators the subtransient reactance should be used.

3

IfEXI----- 3×=

Refer to Table A8 for the standard ranges of X/R and power factors used in testing and rat-ing low-voltage breakers. Refer to Table A9 for the circuit breaker interrupting rating mul-tiplying factors to be used when the calculat-ed X/R ratio or power factor at the point the breaker is to be applied in the power distribu-tion system falls outside of the Table A8 X/R or power factors used in testing and rating the circuit breakers.

Normally the short circuit power factor or X/R ration of a distribution system need not be considered in applying low-voltage circuit breakers. This is because that the ratings established in the applicable standard are based on power factor values which amply cover most applications. Established stan-dard values include the following:

January 1999


CAT.71.01.T.E

A

Short-Circuit Calculations

Short-Circuit Calculations–Short Cut 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 a short cut or approximate

method; proper combining of impedances (e.g., source, cables transformers, conductors, etc.) should use individual R and X components. This Total Z = Total R + j Total X (See IEEE “Red Book” Standard No. 141).

1. Select convenient kVA base for system to be studied.

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

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

4. Change power-source impedance to per-unit or percent impedance on kVA base as selected for 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) as source of fault current: } See IEEE Standard

No. 141

(a) Per unit = pu impedance kVA base

(b) Percent = % impedance kVA base

(a) Per unit impedance = pu

(b) Per unit 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 Amps

Per-unit impedance = pu

(a) —motor kVA— (kV) (I) where motor nameplate full-load Amps.

(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 Amps)

(d) Rms Symmetrical current = Amps = or

(e) = or

(g) =

(a) Sym. 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-phase unit (i.e., 3 x 75 kVA = 225 kVA, Z = 2%).

(c) —from single-phase transformer—see page A-25.

(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/120-volt systems—2.0 times transformer full-load current—on 240-480-600-volt 3-phase, 3-wire systems—4.0 times transformer full-load current—on 480Y/277-volt 3-phase, 4-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)

2 kVA base 2kVA base 1------------------------------- (pu impedance on kVA base 1)×=

2 kVA base 2kVA base 1------------------------------- (% impedance on kVA base 1)×=

Z percent impedance100

------------------------------------------------------(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( )

3-phase kVA3( ) kV( )

----------------------------------- 1-phase kVAkV line-to-neutral------------------------------------------------

ISC1.0

puZ-----------=

3-phase kVA basepuZ( ) 3( ) kV( )

-------------------------------------------------- 1-phase kVA basepuZ( ) kV( )

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

(3-phase kVA base) (100)(%Z) 3( ) kV( )

---------------------------------------------------------------------- 1-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)

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

CAT.71.01.T.E



AUtility Source 500 MVA

1,000 kVA5.75%480 Volts

Switchboard Fault

100 Ft.3-350 Kcmil Cablein Steel Conduit

Mixed Load — Motors and LightingEach Feeder — 100 Ft. of 3-350 Kcmil Cable

in Steel Conduit Feeding Lighting and250 kVA of Motors

Cable Fault

Utility

Transformer

Major Contribution

Cables

Switchboard Fault

Cables

Cable Fault

A B C

.002 pu

Switchboard Fault

.027 pu

Cable Fault

A B C .0575 pu

1.00 pu

.027 pu

1.00 pu

.027 pu

1.00 pu

.027 pu

.342 pu

.027 pu

.0507 pu

.027 pu

E .0777 pu

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

Combining Parallel Impedances:ZTOTAL

1 =Z1

1 +Z2

1 + ...Zn

1

.0595 pu


Example No.1

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

C. Conductor impedance from Tables A-45 and A-46, page A-64.Conductors: 3-350 kcmil copper, single conductorsCircuit length: 100 ft., in steel (magnetic) conduitImpedance Z = 0.00619 ohms/100 ft. ZTOT = 0.00619 ohms (100 circuit feet)

D. Fault current calculations (combining impedances arithmetically, using approximate “short cut” method—see Note 4, page A-23)

EquationStep (See page A-23) Calculation

1 – Select 1000 kVA as most convenient base, since all data except utility source is onsecondary 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 =

ZpukVA base

utility fault kVA------------------------------------------- 1000

500,000--------------------- 0.002 pu= ===

Zpu%Z100---------- 5.75

100----------- 0.0575 pu= = =

ZpukVA base

4 x motor kVA---------------------------------------- 1000

4 x 250-------------------- 1.00 pu= ==

Zpu(ohms) (kVA base)

kV( )2 1000( )---------------------------------------------------- 0.00619( ) 1000( )

0.480( )2 1000( )--------------------------------------------- 0.027pu= = =

3-phase kVA baseZpu( ) 3( ) kV( )

-------------------------------------------------- 10000.0507( ) 3( ) 0.480( )

-------------------------------------------------------- 23,720 Amps rms= =

3-phase kVA baseZpu( ) 3( ) kV( )

-------------------------------------------------- 10000.0777( ) 3( ) 0.480( )

-------------------------------------------------------- 15 480 Amps rms,= =

January 1999


CAT.71.01.T.E

A

RSyst = 0.00054

RCond = 0.00677

RTfmr = 0.0164

RTotal = 0.02371F1

RSyst = 0.00356

RCond = 0.00332

RTfmr = 0.0227

RTotal = 0.02958F1

RSyst = 0.00054

RCond = 0.00677

RTfmr = 0.0246

RTotal = 0.03191F2

XSyst = 0.00356

XCond = 0.00332

XTfmr = 0.0272

XTotal = 0.03408F2

240 VoltsF1

120 VoltsF2 Half-winding of Transformer

Full-winding of Transformer

{Multiply % R by 1.5Multiply % X by 1.2 }Reference: IEEE Standard No. 141

75 kVA Single-Phase 480-120/240 Volts; 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

(From tables page 30)

480-Volt 3-Phase Switchboard Bus at 50,000 Amp Symmetrical, X/R = 6.6{R = 0.1498 ZX = 0.9887 Z


Deriving Transformer R and X:

X = 6.6 R

Z =

R = R = 0.1498Z

X = 6.6R X = 0.9887Z

XR---- 6.6=

X2 R2+ 6.6R( )2 R2

+ 43.56R2 R2+ 44.56R2 6.6753R= = = =

Z6.6753------------------

Example No. 2 Fault Calculation — Secondary Side of Single-Phase TransformerA. System Diagram

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

0.104 75×0.48( )2 1000×

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

0.0051 75×0.48( )2 1000×

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

1.64100-----------

2.27100-----------

1.64100-----------

2.27100-----------

0.02371( )2 0.02958( )2+

0.03191( )2 0.03408( )2+

ZSyst = (From page A-23,Formula 4(b) )

753 0.480× 50,000×

----------------------------------------------------- 0.0018pu=

D. Impedance and Fault Current Calculations—75 kVA Base ➀

ZCond = (From page A-23,Formula 3(a) )

ohms kVA Base×kV( )2 1000×

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

Full-winding of Tfmr (75 kVA Base)

Half-winding of Tfmr (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) = 8,243 Amp sym.

Short-circuit current F2 = 75 ÷ (0.04669 x 0.120 kV) = 13,386 Amp sym.

➀ To account for the outgoing and return paths of single-phase circuits (conductors, systems, etc.) use twice the 3-phase values of R and X.

B. Impedance Diagram—Fault F1 C. Impedance Diagram—Fault F2

CAT.71.01.T.E



A

How to Calculate Short-Circuit Currents at Ends of Conductors

Conductor ohms for 500 kcmil conductor from reference data in this section in mag-netic conduit is 0.00546 ohms per 100 ft. For 100 ft. and 2 conductors per phase we have:

0.00546/2 = 0.00273 ohms (conductor impedance)

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

Next, 277 volts/0.01196 ohms = 23,160 amperes rms at load side of conductors

X 30,000 amperes available

100 ft.2-500 kcmil per phase

X If = 23,160 amperes

Method 1 – Short Cut Methods

This method uses the approximation of adding Zs instead of the accurate method of Rs and Xs.

For Example: For a 480/277-volt system with 30,000 amperes symmetrical available at the line side of a conductor run of 100 feet of 2- 500 kcmil per phase and neutral, the approxi-mate fault current at the load side end of the conductors can be calculated as follows.

277 volts/30,000 amperes = 0.00923 ohms (source impedance)

January 1999


CAT.71.01.T.E

A


Method 2–Chart Approximate Method

The chart method is based on the following:

Motor ContributionFor system voltages of 120/208 volts, it is reasonable to assume that the connected load consists of 50% motor load, and that the motors will contribute four times their full load current into a fault. For system voltages of 240 and 480 volts, it is reasonable to as-sume that the connected load consists of 100% motor load, and that the motors will contribute four times their full load current into a fault. These motor contributions have been factored into each curve as if all motors were connected to the transformer terminals.

Feeder ConductorsThe conductor sizes most commonly used for feeders from molded case circuit breakers are shown. For conductor sizes not shown, the following table has been included for con-version to equivalent arrangements. In some cases it may be necessary to interpolate for unusual feeder ratings. Table A10 is based on using copper conductor.

Table A10: Conductor Conversion(Based on Using Copper Conductor)

If YourConductor is:

Use EquivalentArrangement

3 – No. 4/0 cables4 – No. 2/0 cables3 – 2000 kcmil cables5 – 400 kcmil cables6 – 300 kcmil cables800 Amp busway1000 Amp busway1600 Amp busway

2 – 500 kcmil2 – 500 kcmil4 – 750 kcmil4 – 750 kcmil4 – 750 kcmil2 – 500 kcmil2 – 500 kcmil4 – 750 kcmil

Short-Circuit Current Read-out

The read-out obtained from the charts is the rms symmetrical amperes available at the given distance from the transformer. The circuit breaker should have an interrupting capacity at least as large as this value.

How to Use the Short-Circuit Charts

Step OneObtain the following data:1. System voltage

2. Transformer kVA rating (from transformer nameplate)

3. Transformer impedance (from trans-former nameplate)

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

Step TwoSelect the applicable chart from the following pages. The charts are grouped by secondary system voltage which is listed with each transformer. Within each group, the chart for the lowest kVA transformer is shown first, fol-lowed in ascending order to the highest rated transformer.

Step ThreeSelect the family of curves that is closest to the “available source kVA.” The black line family of curves is for a source of 500,000 kVA. The low-er value line (in red) family of curves is for a source of 50,000 kVA. You may interpolate be-tween curves if necessary, but for values above 100,000 kVA it is appropriate to use the 500,000 kVA curves.

Step FourSelect the specific curve for the conductor size being used. If your conductor size is something other than the sizes shown on the chart, refer to the conductor conversion Table A10.

Step FiveEnter the chart along the bottom horizontal scale with the distance (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 hori-zontal line to the left from this point to the scale along the left side of the chart.

Step SixThe value obtained from the left-hand vertical scale is the fault current (in thousands of am-peres) available at the fault point.

For a more exact determination, see the for-mula method. It should be noted that even the most exact methods for calculating fault energy use some approximations and some assumptions. Therefore, it is appropriate to select a method which is sufficiently accurate for the purpose, but not more burdensome than is justified. The charts which follow make use of simplifications which are rea-sonable under most circumstances and will almost certainly yield answers which are on the safe side. This may, in some cases, lead to application of circuit breakers having inter-rupting ratings higher than necessary, but should eliminate the possibility of applying units which will not be safe for the possible fault duty.

0 2 5 10 20 50 100 200 500 1000 2000 50000

2.5

5.0

7.5

10.0

12.5

15.0

Fau

lt C

urr

ent

in T

ho

usa

nd

s o

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mp

eres

(S

ym.)

Distance in Feet from Transformer to Breaker Location

Chart 1 – 225 kVA Transformer/4.5% Impedance/208 Volts

B

F

4 – 750 kcmil2 – 500 kcmil

250 kcmil#1/0 AWG

#4 AWG

4 – 750 kcmil2 – 500 kcmil250 kcmil#1/0 AWG#4 AWG

UTILITY KVA

A INFINITEB 500,000C 250,000D 150,000E 100,000F 50,000

CAT.71.01.T.E



A

0 2 5 10 20 50 100 200 500 1000 2000 50000

20

40

60

80

100

120

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B

F

4 – 750 kcmil2 – 500 kcmil

250 kcmil#1/0 AWG

#4 AWG


UTILITY KVA

A INFINITEB 500,000C 250,000D 150,000E 100,000F 50,000

0 2 5 10 20 50 100 200 500 1000 2000 50000

20

40

60

80

100

120

Faul

t Cur

rent

in T

hous

ands

of A

mpe

res

(Sym

.)



B

F

4 – 750 kcmil2 – 500 kcmil

250 kcmil#1/0 AWG

#4 AWG


UTILITY KVA

A INFINITEB 500,000C 250,000D 150,000E 100,000F 50,000

0 2 5 10 20 50 100 200 500 1000 2000 50000

10

20

30

40

50

60

Fau

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ym.)



B

F

4 – 750 kcmil2 – 500 kcmil

250 kcmil#1/0 AWG

#4 AWG


UTILITY KVA

A INFINITEB 500,000C 250,000D 150,000E 100,000F 50,000

0 2 5 10 20 50 100 200 500 1000 2000 50000

5

10

15

20

25

30

Fau

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(S

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B

F

4 – 750 kcmil2 – 500 kcmil

250 kcmil#1/0 AWG

#4 AWG


UTILITY KVA

A INFINITEB 500,000C 250,000D 150,000E 100,000F 50,000

0 2 5 10 20 50 100 200 500 1000 2000 50000

5

10

15

20

25

30

Fau

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B

F

4 – 750 kcmil2 – 500 kcmil

250 kcmil#1/0 AWG

#4 AWG


UTILITY KVA

A INFINITEB 500,000C 250,000D 150,000E 100,000F 50,000

0 2 5 10 20 50 100 200 500 1000 2000 50000

10

20

30

40

50

60

Fau

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ent

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(S

ym.)



B

F

4 – 750 kcmil2 – 500 kcmil

250 kcmil#1/0 AWG

#4 AWG


UTILITY KVA

A INFINITEB 500,000C 250,000D 150,000E 100,000F 50,000


January 1999


CAT.71.01.T.E

A

0 2 5 10 20 50 100 200 500 1000 2000 50000

5

10

15

20

25

30

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B

F

UTILITY KVA

A INFINITEB 500,000C 250,000D 150,000E 100,000F 50,000

4 – 750 kcmil2 – 500 kcmil

250 kcmil#1/0 AWG

#4 AWG


0 2 5 10 20 50 100 200 500 1000 2000 50000

10

20

30

40

50

60

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B

F

UTILITY KVA

A INFINITEB 500,000C 250,000D 150,000E 100,000F 50,000

4 – 750 kcmil2 – 500 kcmil

250 kcmil#1/0 AWG

#4 AWG


0 2 5 10 20 50 100 200 500 1000 2000 50000

10

20

30

40

50

60

Fau

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B

F

UTILITY KVA

A INFINITEB 500,000C 250,000D 150,000E 100,000F 50,000

4 – 750 kcmil2 – 500 kcmil

250 kcmil#1/0 AWG

#4 AWG


0 2 5 10 20 50 100 200 500 1000 2000 50000

5

10

15

20

25

30

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B

F

UTILITY KVA

A INFINITEB 500,000C 250,000D 150,000E 100,000F 50,000

4 – 750 kcmil2 – 500 kcmil

250 kcmil#1/0 AWG

#4 AWG


0 2 5 10 20 50 100 200 500 1000 2000 50000

5

10

15

20

25

30

Fau

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B

F

UTILITY KVA

A INFINITEB 500,000C 250,000D 150,000E 100,000F 50,000

4 – 750 kcmil2 – 500 kcmil

250 kcmil#1/0 AWG

#4 AWG


0 2 5 10 20 50 100 200 500 1000 2000 50000

2

4

6

8

10

12

Fau

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B

F

4 – 750 kcmil2 – 500 kcmil

250 kcmil#1/0 AWG

#4 AWG

UTILITY KVA

A INFINITEB 500,000C 250,000D 150,000E 100,000F 50,000

4 – 750 kcmil2 – 500 kcmil

250 kcmil#1/0 AWG

#4 AWG


CAT.71.01.T.E

Cutler-Hammer

A-30

January 1999


A

Determining X and R Values From Transformer Loss Data

Determining X and R Values From Transformer Loss Data

Method 1:

Given a 500 kVA, 5.5% Z transformer with 9000W total loss; 1700W no-load loss; 7300W load loss and primary voltage of 480V.

%R = .0067 ohms

3 500

3 0.480×--------------------------

2

× R 7300 Watts=×

%R 0.0067 500×10 0.48

2×------------------------------- 1.46%==

%X 5.52

1.462

– 5.30%==

Method 2:

Using same values above.

See Tables A31, A32 and A33 on page A-61 for loss data on transformers.

%RI R Losses2

10 kVA×--------------------------=

730010 500×--------------------- 1.46=

%X 5.52

1.462

– 5.30%==

How to Estimate Short Circuit Currents at Transformer Secondaries:

Method 1:

To obtain three-phase RMS symmetrical short-circuit current available at transformer secondary terminals, use the formula:

where %Z is the transformer impedance in percent, from Table A27, page A-60.

This is the maximum three-phase symmetri-cal bolted-fault current, assuming sustained primary voltage during fault, i.e., an infinite or unlimited primary power source (zero source impedance). Since the power source must always have some impedance this a conservative value; actual fault current will be somewhat less.

Note:

This will not include motor short circuit contribution.

Method 2:

Refer to Table A25 in the Reference section, and use appropriate row of data based on transformer kVA and primary short circuit current available. This will yield more accu-rate results and allow for including motor short circuit contribution.

Isc IFLC100%Z--------×=

January 1999

Cutler-Hammer


CAT.71.01.T.E

A

Voltage Drop

Voltage Drop Tables

➀

Tables for calculating voltage drop for copper and aluminum conductors, in either magnetic (steel) or nonmagnetic (aluminum or non-metallic) conduit, appear on page A-32. These tables give voltage drop per ampere per 100 feet of circuit length (not conductor length).

Tables are based on the following conditions:

1. Three or four single conductors in a con-duit, random lay. For three-conductor cable, actual voltage drop will be approxi-mately the same for small conductor sizes and high power factors. Actual voltage drop will be from 10 to 15% lower for larger conductor sizes and lower power factors.

2. Voltage drops are phase-to-phase, for 3-phase, 3-wire or 3-phase, 4-wire 60 Hz circuits. For other circuits, multiply volt-age drop given in the tables by the follow-ing correction factors:3-phase, 4-wire, phase to neutral x 0.5771-phase, 2-wire x 1.1551-phase, 3-wire, phase-to-phase x 1.1551-phase, 3-wire, phase-to-neutral x 0.577

3. Voltage drops are for a conductor temper-ature of 75

°

C. They may be used for conductor temperatures between 60

°

C and 90

°

C with reasonable accuracy (within

±

5%). However, correction factors in the table below can be applied if desired. The values in the table are in

percent of total voltage drop.

For conductor temperature of 60

°

C – SUBTRACT the percentage from Table A11.

For conductor temperature of 90

°

C – ADD the percentage from Table A11.

Table A11: Temperature Correction Factors for Voltage Drop

Conductor Size 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

Calculations

To calculate voltage drop:

1. Multiply current in amperes by the length of the circuit in feet to get ampere-feet (circuit length, not conductor length).

2. Divide by 100.

3. Multiply by proper voltage drop value in tables. Result is voltage drop.

Example:

A 460-volt, 100-hp motor, running at 80% pf, draws 124 amperes full-load current. It is fed by three 2/0 copper conductors in steel con-duit. The feeder length is 150 feet. What is the voltage drop in the feeder? What is the per-centage voltage drop?

1. 124 amperes x 150 ft = 18,600 ampere-feet2. Divided by 100 = 1863. Table: 2/0 copper, magnetic conduit,

80% pf = 0.0187186 x 0.0187 = 3.48 volts drop3.48 x 100 = 0.76% drop — 460

4. Conclusion – .76% voltage drop is very acceptable

To select minimum conductor size:

1. Determine maximum desired voltage drop, in volts.

2. Divide voltage drop by (amperes x circuit feet).

3. Multiply by 100.

4. Find nearest

lower

voltage drop value in tables, in correct column for type of con-ductor, conduit, and power factor. Read conductor size for that value.

5.

Where

this results in an oversized cable, verify cable lug sizes for molded case breakers and fusible switches. Where lug size available is exceeded, go to next higher

rating.

Example:

A three-phase, four-wire lighting feeder on a 208-volt circuit is 250 feet long. The load is 175 amps at 90% pf. It is desired to use alumi-num conductors in aluminum conduit. What size conductor is required to limit the voltage drop to 2% phase-to-phase?

1.

2.

3.

4. In table, under Aluminum Conductors, nonmagnetic conduit, 90% pf, the nearest lower value is 0.0091. Conductor required is 500 kcmil. (Size 4/0 THW would have adequate ampacity, but the voltage drop would be excessive.)

VD 2100-------- 208 4.16 volts=×=

4.16175 250×------------------------ 0.0000951=

0.0000951 100 0.00951=×

➀

Busway voltage drop tables are shown in section H2 of this catalog.

Voltage Drop

CAT.71.01.T.E



ATable A12: Voltage DropVolts per Ampere per 100 Feet; 3-Phase, Phase-to-Phase

Copper Conductors

Conductor Size AWG or 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

1412108

.3390

.2170

.1390

.0905

.3910

.2490

.1590

.1030

.4430

.2810

.1790

.1150

.4940

.3130

.1980

.1260

.5410

.3410

.2150

.1350

.3370

.2150

.1370

.0888

.3900

.2480

.1580

.1010

.4410

.2800

.1780

.1140

.4930

.3120

.1970

.1250

.5410

.3410

.2150

.1350

6421

.0595

.0399

.0275

.0233

.0670

.0443

.0300

.0251

.0742

.0485

.0323

.0267

.0809

.0522

.0342

.0279

.0850

.0534

.0336

.0267

.0579

.0384

.0260

.0218

.0656

.0430

.0287

.0238

.0730

.0473

.0312

.0256

.0800

.0513

.0333

.0270

.0849

.0533

.0335

.0266

1/02/03/04/0

.0198

.0171

.0148

.0130

.0211

.0180

.0154

.0134

.0222

.0187

.0158

.0136

.0229

.0190

.0158

.0133

.0213

.0170

.0136

.0109

.0183

.0156

.0134

.0116

.0198

.0167

.0141

.0121

.0211

.0176

.0147

.0124

.0220

.0181

.0149

.0124

.0211

.0169

.0134

.0107

250300350500

.0122

.0111

.0104

.0100

.0124

.0112

.0104

.0091

.0124

.0111

.0102

.0087

.0120

.0106

.0096

.0080

.0094

.0080

.0069

.0053

.0107

.0097

.0090

.0078

.0111

.0099

.0091

.0077

.0112

.0099

.0091

.0075

.0110

.0096

.0087

.0070

.0091

.0077

.0066

.0049

600750

1000

.0088

.0084

.0080

.0086

.0081

.0077

.0082

.0077

.0072

.0074

.0069

.0063

.0046

.0040

.0035

.0074

.0069

.0064

.0072

.0067

.0062

.0070

.0064

.0058

.0064

.0058

.0052

.0042

.0035

.0029

Aluminum Conductors

Conductor Size AWG or 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

12108

.3296

.2133

.1305

.3811

.2429

.1552

.4349

.2741

.1758

.4848

.3180

.1951

.5330

.3363

.2106

.3312

.2090

.1286

.3802

.2410

.1534

.4328

.2740

.1745

.4848

.3052

.1933

.5331

.3363

.2115

6421

.0898

.0595

.0403

.0332

.1018

.0660

.0443

.0357

.1142

.0747

.0483

.0396

.1254

.0809

.0523

.0423

.1349

.0862

.0535

.0428

.0887

.0583

.0389

.0318

.1011

.0654

.0435

.0349

.1127

.0719

.0473

.0391

.1249

.0800

.0514

.0411

.1361

.0849

.0544

.0428

1/02/03/04/0

.0286

.0234

.0209

.0172

.0305

.0246

.0220

.0174

.0334

.0275

.0231

.0179

.0350

.0284

.0241

.0177

.0341

.0274

.0217

.0170

.0263

.0227

.0160

.0152

.0287

.0244

.0171

.0159

.0322

.0264

.0218

.0171

.0337

.0274

.0233

.0179

.0339

.0273

.0222

.0172

250300350500

.0158

.0137

.0130

.0112

.0163

.0139

.0133

.0111

.0162

.0143

.0128

.0114

.0159

.0144

.0131

.0099

.0145

.0122

.0100

.0076

.0138

.0126

.0122

.0093

.0144

.0128

.0123

.0094

.0147

.0133

.0119

.0094

.0155

.0132

.0120

.0091

.0138

.0125

.0101

.0072

600750

1000

.0101

.0095

.0085

.0106

.0094

.0082

.0097

.0090

.0078

.0090

.0084

.0071

.0063

.0056

.0043

.0084

.0081

.0069

.0085

.0080

.0068

.0085

.0078

.0065

.0081

.0072

.0058

.0060

.0051

.0038

Voltage Drop

January 1999

Cutler-Hammer


CAT.71.01.T.E

A

Voltage Drop

Voltage Drop Considerations

The first consideration for voltage drop is that under the steady-state conditions of normal load, the voltage at the utilization equipment must be adequate. Fine-print notes in the NEC recommend sizing feeders and branch cir-cuits so that the maximum voltage drop in either does not exceed 3%, with the total volt-age drop for feeders and branch circuits not to exceed 5%, for efficiency of operation. (Fine print notes in the NEC are not mandatory.)

In addition to steady-state conditions, voltage drop under transient conditions, with sudden high-current, short-time loads, must be con-sidered. The most common loads of this type are motor inrush currents during starting. These loads cause a voltage dip on the sys-tem as a result of the voltage drop in conduc-tors, transformers, and generators under the high current. This voltage dip can have numerous adverse effects on equipment in the system, and equipment and conductors must be designed and sized to minimize these problems. In many cases, reduced-voltage starting of motors to reduce inrush current will be necessary.

Recommended Limits of Voltage Variation

General Illumination:

Flicker in incandescent lighting from voltage dip can be severe; lu-men output drops about three times as much as the voltage dips. That is, a 10% drop in voltage will result in a 30% drop in light out-put. While the lumen output drop in fluores-cent lamps is roughly proportional to voltage drop, if the voltage dips about 25% the lamp will go out momentarily and then restrike. For high-intensity discharge (HID) lamps such as mercury vapor, high-pressure sodium, or metal halide, if the lamp goes out because of an excessive voltage dip, it will not restrike

until it has cooled. This will require several minutes. These lighting flicker effects can be annoying, and in the case HID lamps, some-times serious. In areas where close work is being done, such as drafting rooms, precision assembly plants, and the like, even a slight variation, if repeated, can be very annoying, and reduce efficiency. Voltage variation in such areas should be held to 2 or 3% under motor-starting or other transient conditions.

Computer Equipment:

With the proliferation of data-processing and computer- or micro-processor-controlled manufacturing, the sensi-tivity of computers to voltage has become an important consideration. Severe dips of short duration can cause a computer to “crash” — shut down completely, and other voltage tran-sients caused by starting and stopping motors can cause data-processing errors. While volt-age drops must be held to a minimum, in many cases computers will require special power-conditioning equipment to operate properly.

Industrial Plants:

Where large motors exist, and unit substation transformers are relatively limited in size, voltage dips of as much as 20% may be permissible in some cases, if they do not occur too frequently. Lighting is often sup-plied from separate transformers, and is mini-mally affected by voltage dips in the power systems. However, it is usually best to limit dips to between 5 and 10% at most. One criti-cal consideration is that a large voltage dip can cause a dropout (opening) of magnetic motor contactors and control relays. The actual drop-out voltage varies considerably among start-ers of different manufacturers. The only standard that exists is that of NEMA, which states that a starter must

not

drop out at 85% of its nominal coil voltage, allowing only a 15% dip. While most starters will tolerate consider-ably more voltage dip before dropping out, limiting dip to 15% is the only way to ensure continuity of operation in all cases.

X-Ray Equipment:

Medical X-Ray and similar diagnostic equipment, such as CAT-scanners, are extremely sensitive to low voltage. They present a small, steady load to the system until the instant the X-Ray tube is “fired.” This presents a brief but extremely high instanta-neous momentary load. In some modern X-Ray equipment, the firing is repeated rapidly to create multiple images. The voltage regulation must be maintained within the manufacturer’s limits, usually 2 to 3%, under these momen-tary loads, to ensure proper X-Ray exposure.

Motor Starting:

Motor inrush on starting must be limited to minimize voltage dips. The table below will help select the proper type of motor starter for various motors, and to select generators of adequate size to limit voltage dip. See section J4 for additional data on reduced voltage motor starting.

Where the power is supplied by a utility net-work, the motor inrush can be assumed to be small compared to the system capacity, and voltage at the source can be assumed to be constant during motor starting. Voltage dip resulting from motor starting can be calculat-ed on the basis of the voltage drop in the con-ductors between the power source and the motor resulting from the inrush current. Where the utility system is limited, the utility will often specify the maximum permissible inrush current or the maximum hp motor they will permit to be started across-the-line.

If the power source is a transformer, and the inrush kVA or current of the motor being start-ed is small compared to the full-rated kVA or current of the transformer, the transformer voltage dip will be small and may be ignored. As the motor inrush becomes a significant percentage of the transformer full-load rating, an estimate of the transformer voltage drop must be added to the conductor voltage drop to obtain the total voltage drop to the motor. Accurate voltage drop calculation would be

Table A13: Factors Governing Voltage Drop

Type of Motor

➀

StartingTorque

StartingCurrent

➁

HowStarted

StartingCurrent% Full-Load

➂

Starting Torque per Unit of Full Load Torque

Full-Load Amps per kVA Generator Capacity for Each 1% Voltage Drop1750 Rpm

Motor1150 RpmMotor

➂

850 RpmMotor

Design B Normal Normal Across-the-Line ResistanceAutotransformer

600-700480-560

➁

375-450

➁

1.5.96.96

1.35.87.87

1.25.80.80

.0109-.00936

.0136-.0117

.0170-.0146

Design C Normal Low Across-the-Line ResistanceAutotransformer

500-600400-480

➁

320-400

➁

1.5.96.96

1.35.87.87

1.25.80.80

.0131-.0109

.0164-.01365

.0205-.0170

Design D High Low Across-the-Line ResistanceAutotransformer

500-600400-480

➁

320-400

➁

. . . .

. . . .

. . . .

.2 to 2.51.28 to 1.61.28 to 1.6

. . . .

. . . .

. . . .

.0131-.0109

.0164-.01365

.0205-.0170

Design E Normal High Across-the-Line 800-1000 . . . . . . . . . . . .

Wound Rotor High Low Secondary Controller 100% currentfor 100%Torque

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . . .0655

Synchronous (for compressors)Synchronous (for centrifugal pumps)

LowLow

. . . .

. . . .Across-the-Line Across-the-Line Autotransformer

300450-550288-350

➃

40% Starting, 40% Pull-In60% Starting, 110% Pull-In38% Starting, 110% Pull-In

.0218

.0145-.0118

.0228-.0197

➀

Consult NEMA MG-1 sections 1 and 12 for theexact definition of the design letter.

➁

In each case, a solid-state reduced voltage starter can be adjusted and controlled to provide the re-quired inrush current and torque characteristics.

➂

Where accuracy is important, request the code let-ter of the the motor and starting and breakdown torques from the motor vendor.

➃

Using 80% taps.

CAT.71.01.T.E

Cutler-Hammer

A-34

January 1999


A

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 pf are known.

where:E

VD

= Voltage drop, line-to-neutral, voltsE

S

= Source voltage, line-to-neutral, voltsI = Line (Load) current, ampsR = Circuit (branch, feeder) resistance,

ohmsX = Circuit (branch, feeder) reactance,

ohms

COS

θ

= Power factor of load, decimal

SIN

θ

= Reactive factor of load, decimal

If the receiving end voltage, load current and power factor (pf) are known.

E

R

is the receiving end voltage.

Exact Method 2–If receiving or sending mVA and its power factor are known at a known sending or receiving voltage.

or

where:

E

R

= Receiving Line-Line voltage in kVE

S

= Sending Line-Line voltage in kVMVA

R

= Receiving 3-phase mVAMVA

S

= Sending 3-phase mVAZ = Impedance between and

receiving ends

γ

= The angle of impedance Z

θ

R

= Receiving end PF

θ

S

= Sending end PF, positive when lagging

EVD IR cos θ IX SIN θ+=

EVD ES IRCOSθ+ +=

IXSINθ ES

2 IXcosθ IRSINθ–( )2––

EVD ER θcos( IR )2ER θsin IX )2

E– R+(+ +=

ES2 ER2ZMVAR2

ER2------------------- 2ZMVARCOS γ θR–( )+ +=

ER2 E

S2

ZMVAR2

ES2

------------------- 2ZMVASCOS γ θS–( )–+=

Voltage Drop

complex and depend upon transformer and conductor resistance, reactance, and imped-ance, as well as motor inrush current and power factor. However, an approximation can be made on the basis of the low power-factor motor inrush current (30-40%) and imped-ance of the transformer.

For example, if a 480V transformer has an impedance of 5%, and the motor inrush current is 25% of the transformer full-load current (FLC), then volt-age drop will be 0.25 x 5%, or 1.25%.

The allowable motor inrush current is determined by the total permissible voltage drop in trans-former and conductors.

With an engine generator as the source of power, the type of starter that will limit the in-rush depends on the characteristics of the generator. Although automatic voltage regu-lators are usually used with all ac engine-gen-erators, the initial dip in voltage is caused by the inherent regulation of the generator and occurs too rapidly for the voltage regulator to respond. It will occur whether or not a regula-tor is installed. Consequently, the percent of initial voltage drop depends on the ratio of the starting kVA taken by the motor to the generator capacity, the inherent regulation of the generator, the power-factor of the load thrown on the generator, and the percentage load carried by the generator.

A standard 80% power-factor engine-type generator (which would be used where power is to be supplied to motor loads) has an inher-ent regulation of approximately 40% from no-load to full-load. This means that a 50% varia-tion in load would cause approximately 20% variation in voltage (50% x 40% = 20%).

Assume that a 100 kVA, 80% pf engine-type generator is supplying the power and that the voltage drop should not exceed 10%. Can a 7

1

/

2

hp, 220-volt, 1750 rpm, 3-phase, squirrel-cage motor be started without exceeding this voltage drop?

Starting ratio =

From the nameplate data on the motor the full-load amperes of a 7

1

/

2

hp. 220-volt, 1750 rpm, 3-phase, squirrel-cage motor is 19.0 am-peres. Therefore:

Starting current (%F.L.) =

From Table A13, a NEMA design C or NEMA design D motor with an autotransformer starter gives approximately this starting ratio. It could also be obtained from a properly set solid-state adjustable reduced voltage starter.

Percent voltage drop gen. kVA× 1000×F.L. amps volts× 3× reg. of gen.×

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

10 100× 1000×19.0 220× 3× 0.40×------------------------------------------------------- 3.45 or 345%.=

The choice will depend upon the torque requirements of the load since the use of an autotransformer starter reduces the starting torque in direct proportion to the reduction in starting current. In other words, a NEMA design C motor with an autotransformer would have a starting torque of approximately full-load (see Table A13) whereas the NEMA de-sign D motor under the same conditions would have a starting torque of approximately 1

1

/

2

times full-load.

Note:

If a resistance starter were used for the same motor terminal voltage, the starting torque would be the same as that obtained with autotransformer type, but the starting current would be higher, as shown.

Short-Cut Method

Column 7 in Table A13 has been worked out to simplify checking. The figures were obtained by using the formula above and assuming 1 kVA generator capacity and 1% voltage drop.

Example:

Assuming a project having a 1000 kVA gener-ator, where the voltage variation must not exceed 10%. Can a 75 hp, 1750 rpm, 220-volt, 3-phase, squirrel-cage motor be started with-out objectionable lamp flicker (or 10% voltage drop)?

From tables in the circuit protective devices reference section the full-load amperes of this size and type of motor is 158.0 amperes. To convert to same basis as column 7, 158 Amps must be divided by the generator capacity and % voltage drop, or:

Checking against the table, 0.0158 falls within the .0170-.0146 range. This indicates that a general-purpose motor with autotransformer starting can be used.

The calculation results in conservative results. The engineer should provide to the engine-generator vendor the starting kVA of all motors that we will be connected to, the generator and their starting sequence. The en-gineer should also specify the maximum al-lowable drop. The engineer should request that the engine-generator vendor consider the proper generator size when closed-transition autotransformer reduced voltage starters, and soft-start solid-state starter are used; so the most economical method of installation is obtained.

1581000 10×------------------------ 0.0158 amps per kVA per 1%

voltage drop=

January 1999


CAT.71.01.T.E

A

Capacitor Switching Device Selections

Capacitor Switching DeviceSelections

Medium-Voltage Capacitor Switching

Capacitance switching constitutes severe operating duty for a circuit breaker. At the time the breaker opens at near current zero the capacitor is fully charged. After interruption, when the alternating voltage on the source side of the breaker reaches its opposite maxi-mum, the voltage that appears across the contacts of the open circuited breaker is at least twice the normal line-to-neutral voltage of the circuit. Due to the circuit constants on the supply side of the breaker the voltage across the open contact can reach three times the normal line-to-neutral. If a breakdown occurs across the open contact the arc is reestablished. After it is interrupted and with subsequent alternation of the supply side voltage, the voltage across the open contact is even higher.

ANSI Standard C37.06 (indoor oilless circuit breakers) Table 1A indicates the preferred rat-ings of Cutler-Hammer type VCP-W vacuum breaker. For capacitor switching careful atten-tion should be paid to the notes accompany-ing the table. The definition of the terms are in ANSI Standard C37.04 Article 5.13 (for the lat-est edition). The application guide ANSI/IEEE Standard C37.012 covers the method of calcu-lation of the quantities covered by C37.06 Standard.

Note that the definitions in C37.04 make the switching of two capacitors banks in close proximity to the switchgear bus a back-to-back mode of switching. This classification re-quires a definite purpose circuit breaker (breakers specifically designed for capaci-tance switching).

We recommend that such application be re-ferred to Cutler-Hammer.

A breaker specified for capacitor switching should include as applicable.

1. Rated maximum voltage.

2. Rated frequency.

3. Rated open wire line charging switching current.

4. Rated isolated cable charging and shunt capacitor switching current.

5. Rated back-to-back cable charging and back-to-back capacitor switching current.

6. Rated transient overvoltage factor.

7. Rated transient inrush current and its frequency.

8. Rated interrupting time.

9. Rated capacitive current switching life.

10.Grounding of system and capacitor bank.

Loadbreak interrupter switches are permitted by ANSI/IEEE Standard C37.30 to switch capacitance but they must have tested ratings for the purpose. Refer to Cutler-Hammer type WLI ratings.

Low-Voltage Capacitor Switching

Circuit breakers and switches for use with a capacitor must have a current rating in excess

of rated capacitor current to provide for over-current from overvoltages at fundamental frequency and harmonic currents. The fol-lowing percent of the capacitor-rated current should be used:

Fused and unfused switches ................. 165%Molded case breaker or equivalent ...... 150%DSII power circuit breakers ................... 135%Magnum DS power circuit breaker....... 135%

Contactors:Open type................................................ 135%Enclosed type ......................................... 150%

The NEC, Section 460-8(c)(4), requires the disconnecting means to be rated not less than 135% of the rated capacitor current (for 600V and below).

➀ Switching device ratings are based on percentage of capacitor-rated current as indicated (above). The interrupting rating of the switch must be selected to match the system fault current available at the point of capacitor application.

Table A14: Recommended Switching Devices➀

Capacitor

Rating

Amperes Capacitor

Rating

Amperes

Volts kvar Capaci-

tor

Rated

Current

Safety

Switch

Fuse

Rating

Molded

Case

Breaker

Trip

Rating

DSIIBreaker

Trip

Rating

Volts kvar Capaci-

tor

Rated

Current

Safety

Switch

Fuse

Rating

Molded

Case

Breaker

Trip

Rating

DSIIBreaker

Trip

Rating

240 21⁄2 5 71⁄2 10 15 20 25 30 45 50 60 75 90100120125135150180200225240250270300360375

6.0 12.0 18.0 24.1 36.1 48.1 60 72.2108120144180217240289301325361433480541578602650720866903

152030406080

100125200200250300400400500500600600800800900

100010001200120016001500

152030407090

100125175200225275350400500500500600700800900900900100

0. . . .. . . .. . . .

15203040507090

100150175200250300350400450500500600700800800900

1000120012001200

480 120125150160180200225240250300320360375400450

144150180192216241271289301361385433451481541

250250300350400400500500500600700800800800900

225225300300350400500500500600600700700800900

200200250300300350400400400500600600600800800

600 5 71⁄2 10 15 20 25 30 35 40 45 50 60 75 80100120125150160180200225240250300320360375400450

4.8 7.2 9.6 14.4 19.2 24.1 28.9 33.6 38.5 43.3 48.1 57.8 72.2 77.0 96.2115120144154173192217231241289306347361385433

1515202535405060708080

100125150175200200250300300350400400400500600600600700800

15151530304050507070

100100125125150175200225250300300350350400500500600600600700

151515203040405070707090

100125150175175200225250300300350350400500500500600600

480 2 5 71⁄2 10 15 20 25 30 35 40 45 50 60 75 80 90100

2.41 6.01 9.0 12.0 18.0 24.0 30.0 36.1 42 48.1 54 60.1 72.2 90.2 96.2108120

1515152030405060708090

100125150175200200

151515203040507070

100100100125150150175200

151515203040505060708090

100125150150175

Whenever a capacitor bank is purchased with less than the ultimate kvar capacity of the rack or enclosure, the switch rating should be selected based on the ultimate kvar capacity – not the initial installed capacity.

CAT.71.01.T.E



A

Motor Power Factor Correction

Motor Power Factor Correction

Tables A15 and A16 contain suggested maxi-mum capacitor ratings for induction motors switched with the capacitor. The data is gen-eral in nature and representative of general purpose induction motors of standard design. The preferable means to select capacitor rat-ings is based on the “maximum recommend-ed kvar” information available from the motor manufacturer. If this is not possible or feasible, the tables can be used.

An important point to remember is that if the capacitor used with the motor is too large, self-excitation may cause a motor-damaging overvoltage when the motor and capacitor combination is disconnected from the line. In addition, high transient torques capable of damaging the motor shaft or coupling can occur if the motor is reconnected to the line while rotating and still generating a voltage of self-excitation.

Definitionskvar—rating of the capacitor in reactive kilovolt-amperes. This value is approximately equal to the motor no-load magnetizing kilovars.

% AR—percent reduction in line current due to the capacitor. A capacitor located on the motor side of the overload relay reduces line current through the relay. Therefore, a differ-ent overload relay and/or setting may be nec-essary. The reduction in line current may be determined by measuring line current with and without the capacitor or by calculation as follows:

If a capacitor is used with a lower kVAR rating than listed in tables, the % AR can be calcu-lated as follows:

The tables can also be used for other motor ratings as follows:

A. For standard 60 Hz motors operating at 50 Hz:

Kvar = 1.7 – 1.4 of kVAR listed% AR = 1.8 – 1.35 of % AR listed

B. For standard 50 Hz motors operating 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-rotor motors: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 = 1.65 mult., etc.

% AR 100 100(Original Pf)

(Improved Pf)----------------------------------×–=

% AR Listed % ARActual kvar

kvar in Table----------------------------------×=

D. To derate a capacitor used on a system voltage lower than the capacitor voltage rating, such as a 240-volt capacitor used on a 208-volt system, use the following formula:

For the kVac required to correct the power fac-tor from a given value of COS φ1 to COS φ2, the formula is:

kVAC = KW (tan ø1 - tan φ2)

Actual kvar =

Nameplate kvarApplied Voltage( )2

Nameplate Voltage( )2-------------------------------------------------------×

Induction-Motor/Capacitor Application Tables for Motors(Manufactured in 1956 or Later)230-, 460- and 575-Volt Motors

Table A15: NEMA Design B–Normal Starting Torque and Current

Induction-Motor Horse-powerRating

Nominal Motor Speed in Rpm and Number of Poles

36002

18004

12006

9008

72010

60012

kvar % AR kvar % AR kvar % AR kvar % AR kvar % AR kvar % AR

5 71⁄2 10 15 20

2 21⁄2 3 5 6

1313121110

2 3 3 5 6

1716141413

3 3 4 5 71⁄2

2319181716

3 4 5 71⁄2 71⁄2

2825242120

4 6 6 71⁄2 10

3633302725

5 71⁄2 10 10 15

4946393431

25 30 40 50 60

7.5 7.5 7.51010

101010109

6 7.5101515

1312111111

71⁄2 10 15 20 25

1616151514

10 10 15 20 20

1918181817

10 15 15 20 25

2321201919

20 20 25 30 35

3128282827

75100125150200

1520252535

99999

2025303040

1010999

25 30 30 35 50

1311111110

25 30 40 45 60

1413131212

30 35 40 50 70

1615141313

40 45 50 60 80

1917171717

250300350400450

4045507075

99987

5060707080

88777

60 70 80 80100

101010109

70 80100110120

1212121211

80 90100125125

1212121212

100110125150150

1717161616

500 90 7 90 7 120 9 125 11 140 12 175 16

Table A16: Design C–High Starting Torque, Normal Current

Induction-Motor HorsepowerRating

Nominal Motor Speed in Rpm and Number of Poles

18004

12006

9008

72010

kvar % AR kvar % AR kvar % AR kvar % AR

5 71⁄2 10 15 20

23344

1818151515

21⁄2 3 4 5 5

2319171717

4 4 5 71⁄2 71⁄2

2925222019

. . .

. . .

. . .

. . .

. . .

. .

. .

. .

. .

. .

25 30 40 50 60

55

101515

1313131312

5 71⁄2101020

1515151515

1010152025

1919181818

. . .20. . .2525

. .23. .2323

75100125150200

2025303545

11101099

2025354050

1312111010

3040404560

1717141313

3540455060

2317161212

250300350

506070

888

607075

10109

708090

131212

7580

100

121212

Capacitors cause a voltage rise. At light load periods the capacitive voltage rise can raise the voltage at the location of the capacitors to an unacceptable level. This voltage rise can be calculated approximately by the formula

XS is the impedance of the circuit elements from the utility to the location of the capaci-tors. kVAB is the base kVA.

With the introduction of variable speed drives and other harmonic current generating loads, the capacitor impedance value determined must not be resonant with the inductive reac-tances of the system. This matter is discussed further under the heading “Harmonics and Non-Linear Loads.”

% VRkVAC XS

kVAB---------------------=

January 1999

Cutler-Hammer


CAT.71.01.T.E

A

Overcurrent Protection and Coordination

Time-Current Characteristic Curves for Typical Power Distribution System Protective Devices Coordination Analysis.

Overcurrent Protectionand Coordination

Overcurrents in a power distribution system can occur as a result of both normal (motor starting, transformer inrush, etc.) and abnormal (ground fault, line-to-line fault, etc.) condi-tions. In either case, the fundamental purposes of current-sensing protective devices are to detect the abnormal overcurrent and with proper coordination, to operate selectively to protect equipment, property and personnel while minimizing the outage of the remainder of the system. With the increase in electric power consumption over the past few decades, dependence on the continued supply of this power has also increased so that the direct costs of power outages have risen significantly. Power outages can create dangerous and unsafe conditions as a result of failure of lighting, elevators, ventilation, fire pumps, security systems, communications systems, and the like. In addition, economic loss from outages can be extremely high as a result of computer downtime, or, especially in indus-trial process plants, interruption of production.

Protective equipment must be adjusted and maintained in order to function properly when a current abnormality occurs, but coor-dination begins during power system design with the knowledgeable analysis and selection and application of each overcurrent protective device in the series circuit from the power source(s) to each load apparatus. The objective of coordination is to localize the overcurrent disturbance so that the protective device closest to the fault on the power-source side has the first chance to operate; but each preceding protective device upstream toward the power source should be capable, within its designed settings of current and time, to provide back-up and effect the isolation if the fault persists. Sensitivity of coordination is the degree to which the protective devices can minimize the damage to the faulted equipment.

To study and accomplish coordination requires a: (a) one-line diagram, the roadmap of the power distribution system, showing all protective devices and the major or important distribution and utilization apparatus, (b) identification of desired degrees of power continuity or criticality of loads throughout system, (c) definition of operating-current characteristics (normal, peak, starting) of each utilization circuit, (d) calculation of max-imum short-circuit currents (and ground fault currents if ground fault protection is included) possible at each protective device location, (e) understanding of operating characteristics and available adjustments of each protective device, (f) any special overcurrent protection requirements including utility limitations.

Standard definitions have been established for overcurrent protective devices covering ratings, operation and application systems.

M

—Motor (100 hp). Dashed line shows initial inrush current, starting current during 9-sec acceleration, and drop to 124A normal run-ning current, all well below CB

A

trip curve.

A

—CB (175A) coordinates selectively with motor

M

on starting and running and with all upstream devices, except that CB

B

will trip first on ground faults.

B

—CB (600A) coordinates selectively with all upstream and downstream devices, except will trip before

A

on limited ground faults, since

A

has no ground fault trips.

C

—Main CB (1600A) coordinates selectively with all downstream devices and with primary fuse

D

, for all faults on load side of CB.

D

—Primary fuse (250A, 4,160V) coordinates selectively with all secondary protective

devices. Curve converted to 480V basis. Clears transformer inrush point (12 x FLC for 0.1 sec), indicating that fuse will not blow on inrush. Clears ANSI 3

φ

withstand curve, indi-cating fuse will protect transformer for full duration of faults up to ANSI rating.

Delta-Wye secondary side short circuit is not reflected to the primary by the relation

for L-L and L-G faults. For line-to-line fault the secondary (low voltage) side fault current is 0.866 x I 3

φ

fault current.

However the primary (high voltage) side fault is the same as if the secondary fault was a three-phase fault. Therefore in close,

IP

VSVP------- IS×=

1000

109

76

.9

4

5

.5

.3

.2

10090

30

20

500

300

200

10,0

00

8000

6000

9000

7000

5000

4000

3000

2000

1000

800

600

900

700

500

400

300

200

100

8060 907050403020109875 6431 2.9.8.7.5 .6

600

900800700

400

40

8

50

80

6070

3

1

2

.8

.7

.6

.4

.1.09.08.07.06

.05

.04

.03

.02

.01

10,0

00

8000

6000

9000

7000

5000

4000

3000

2000

1000800

600

900

700

500

400

300

200

1008060 907050403020109875 6431 2.9.8.7.5 .6

1000

109

76

.9

4

5

.5

.3

.2

10090

30

20

500

300

200

600

900800700

400

40

8

50

80

6070

3

1

2

.8

.7

.6

.4

.1

.09

.08

.07

.06

.05

.04

.03

.02

.01

TIME IN

SEC

ON

DS

SCALE X 100 = CURRENT IN AMPERES AT 480 VOLTS

SCALE X 100 = CURRENT IN AMPERES AT 480 VOLTS

TIM

E IN

SEC

ON

DS

250 MVA4.16 kV

250 Amps1000kVA

5.75%4,160 V ∆480/277 V

19,600 Amps

1,600 Amps

24,400 Amps

600 Amps

D

C

B

A

M

20,000 Amps

175 Amps

100 Hp –124 Amps FLC

X = Available fault currentincluding motorcontribution.

D

ANSI 3-PhaseThru FaultProtection Curve(More Than 10 inLifetime)

C

B

A

CB

A

B

C

TransformerInrush

GroundFault Trip

Max

.48

0V F

ault

Max

. 3Ø

4.16

kV

Fau

lt

M

CAT.71.01.T.E



A

Overcurrent Protection and Coordination

coordination studies the knee of the short-time pick-up setting should be multiplied by

before it is compared to the minimum melting time of the fuse curve. In the example shown, 4000 Amps 30 sec., the 30-sec. trip time should be compared to the MMT (minimum melt time) of the fuse curve at 4000 x 1.1547 = 4619 Amps. In this case there is adequate clearance to the fuse curve.

In the example shown the ANSI 3ø thru fault protection curve must be multiplied by 0.577 and replotted in order to determine the pro-tection given by the primary for single line to ground fault in the secondary.

Maximum 480V 3φ fault indicated.

Maximum 4160V 3φ fault indicated, converted to 480V basis.

The ANSI protection curves are specified in ANSI C57.12.109 for liquid-filled transformers and C57.12.59 for dry-type transformers.

Illustrative examples such as shown here start the coordination study from the lowest rated device proceeding upstream. In practice the setting or rating of the utility’s protective de-vice sets the upper limit. Even in cases where the customer owns the medium-voltage or higher distribution system, the setting or rating of the lowest set protective device source determines the settings of the downstream devices and the coordination. Therefore the coordination study should start at the present setting or rating of the upstream device and work towards the lowest rated device. If this procedure results in unacceptable settings, the setting or rating of the upstream device should be reviewed. Where the utility is the sole source they should be consulted. Where the owner has its own medium or higher voltage distribution the settings or ratings of all upstream devices should be checked.

If perfect coordination is not feasible, then lack of coordination should be limited to the smallest part of the system.

Application data is available for all protective equipment to permit systems to be designed for adequate overcurrent protection and co-ordination. For circuit breakers of all types, time-current curves permit selection of in-stantaneous and inverse-time trips. For more complex circuit breakers, with solid-state trip units, trip curves include long- and short-time delays, as well as ground-fault tripping, with a wide range of settings and features to pro-

10.866------------- or 1.1547

I480V I4160V4160480----------- ×=

vide selectivity and coordination. For current-limiting circuit breakers, fuses, and circuit breakers with integral fuses, not only are time-current characteristic curves available, but also data on current-limiting performance and protection for downstream devices.

In a fully rated system, all circuit breakers must have an interrupting capacity adequate for the maximum available fault current at their point of application. All breakers are equipped with long-time-delay (and possibly short delay) and instantaneous overcurrent trip devices. A main breaker may have short time-delay tripping to allow a feeder breaker to isolate the fault while power is maintained to all the remaining feeders.

A selective or fully coordinated system per-mits maximum service continuity. The trip-ping characteristics of each overcurrent device in the system must be selected and set so that the breaker nearest the fault opens to isolate the faulted circuit, while all other breakers remain closed, continuing power to the entire unfaulted part of the system. All breakers must have an interrupting capacity not less than the maximum available short-circuit current at their point of application. A selective system is a fully-rated system with tripping devices chosen and adjusted to pro-vide the desired selectivity. The tripping char-acteristics of each overcurrent device should not overlap, but should maintain a minimum time interval for devices in series (to allow for normal operating tolerances) at all current val-ues. Generally, a maximum of four low-volt-age circuit breakers can be operated selectively in series, with the feeder or branch breaker downstream furthest from the source.

Specify true rms sensing devices in order to avoid false trips due to rapid currents or spikes. Specify tripping elements with I2t or I4t feature for improved coordination with other devices having I2t or I4t (such as OPTIM trip units) characteristics, and fuses.

In general for systems such as shown in the example:

1. The settings or ratings of the primary side fuse and main breaker must not exceed the settings allowed by NEC Article 450.

2. At 12 x IFL the minimum melting time characteristic of the fuse should be higher than 0.1 second.

3. The primary fuse should be to the left of the transformer damage curve as much as possible. The correction factor for a single line-to-ground factor must be applied to the damage curve.

4. The setting of the short-time delay element must be checked against the fuse MMT after it is corrected for line-to-line faults.

5. The maximum fault current must be indi-cated at the load side of each protective device.

6. The setting of a feeder protective device must comply with Article 240 and Article 430 of the NEC. It also must allow the starting and acceleration of the largest motor on the feeder while carrying all the other loads on the feeder.

Trip elements equipped with zone selective feature, trip without intentional time delay unless a restraint signal is received from a protective device downstream. Breakers equipped with this feature mainly reduce the damage at the point of fault if the fault occurs at a location between the zone of protection.

The upstream breaker upon receipt of the re-straint signal will not trip until its time-delay setting times out. If the breaker immediately downstream of the fault does not open, then after timing out, the upstream breaker will trip.

Breakers equipped with ground fault trip ele-ments should also be specified to include zone interlocking for the ground fault trip element.

To assure complete coordination, the time-trip characteristics of all devices in series should be plotted on a single sheet of standard log-log paper. Devices of different-voltage systems can be plotted on the same sheet by converting their current scales, using the voltage ratios, to the same voltage basis. Such a coordination plot is shown on page A-37. In this manner, pri-mary fuses and circuit breaker relays on the pri-mary side of a substation transformer can be coordinated with the low-voltage breakers. Transformer damage points, based on ANSI standards, and low-voltage cable heating limits can be plotted on this set of curves to assure that apparatus limitations are not exceeded.

Ground-fault curves may also be included in the coordination study if ground-fault protec-tion is provided, but care must be used in interpreting their meaning.

Article 230-95 of NEC requires ground-fault protection of equipment shall be provided for solidly grounded wye electrical services of more than 150 volts to ground, but not exceed-ing 600 volts phase-to-phase for each service disconnect rated 1000 amperes or more.

The rating of the service disconnect shall be considered to be the rating of the largest fuse that can be installed or the highest continuous current trip setting for which the actual overcur-rent device installed in a circuit breaker is rated or can be adjusted.”

The maximum allowable settings are: 1200 Amps pickup, 1 second or less trip delay at cur-rents of 3000 Amps or greater.

The characteristics of the ground-fault trip elements create coordination problems with downstream devices not equipped with ground fault protection. The National Electric Code exempts fire pumps and continuous industrial processes from this requirement.

January 1999


CAT.71.01.T.E

A

Overcurrent Protection and Coordinaton

It is recommended that in solidly grounded480/277-volt systems where main breakers are equipped with ground fault trip elements that the feeder breakers be equipped with ground-fault trip elements as well.

Suggested Ground Fault SettingsFor the main devices, a ground fault pickup setting equal to 20-30% of the main breaker rating but not to exceed 1200 amperes and a time delay equal to the delay of the short time element, but not to exceed 1 second.

For the feeder ground fault setting, a setting equal to 20-30% of the feeder ampacity and a time delay to coordinate with the setting of the main (at least 6 cycles below the main).

If the desire to selectively coordinate ground fault devices results in settings which do not offer adequate damage protection against arcing single line-ground faults, the design engineer should decide between coordina-tion and damage limitation.

For low-voltage systems with high-magnitude available short-circuit currents, common in urban areas and large industrial installations, several solutions are available. Current-limiting

fuses can be used in fused switch assemblies, or as limiters integral with molded-case circuit breakers (Tri-Pac) or mounted on power circuit breakers (type DSLII) or high interrupting Series C molded case breakers to handle these large fault currents. To provide current limiting, these fuses must clear the fault completely within the first half-cycle, limiting the peak cur-rent (Ip) and heat energy (I2t) let-through to con-siderably less than what would have occurred without the fuse. For a fully fusible system, rule-of-thumb fuse ratios or more accurate I2t curves can be used to provide selectivity and coordination. For fuse-breaker combinations, the fuse should be selected (coordinated) so as to permit the breaker to handle those overloads and faults within its capacity; the fuse should operate before or with the breaker only on large faults, approaching the interrupting capacity of the breaker, to minimize fuse blowing. Recent-ly, unfused, truly current-limiting circuit break-ers with interrupting ratings adequate for the largest systems (type Series C, FDC, JDC, KDC, LDC and NDC frames or type Current-Limit-R) have become available.

Any of these current-limiting devices – fuses, fused breakers, or current-limiting breakers – can not only clear these large faults safely,

but also will limit the Ip and I2t let through significantly to prevent damage to apparatus downstream, extending their zone of protec-tion. Without the current limitation of the up-stream device, the fault current could exceed the withstand capability of the downstream equipment. Underwriters Laboratories tests and lists these series combinations. Applica-tion information is available for combinations which have been tested and UL-listed for safe operation downstream from DSLII, Tri-Pac, and Current-Limit-R, or Series C breakers of various ratings, under high available fault currents.

Protective devices in electrical distribution systems may be properly coordinated when the systems are designed and built, but that is no guarantee that they will remain coordinated. System changes and additions, plus power source changes, frequently modify the pro-tection requirements, sometimes causing loss of coordination and even increasing fault currents beyond the ratings of some devices. Consequently, periodic study of protective-device settings and ratings is as important for safety and preventing power outages as is periodic maintenance of the distribution system.

CAT.71.01.T.E

Cutler-Hammer

A-40

January 1999


A

Grounding

3. Medium-Voltage System – Grounding

Table A17: Features of Ungrounded and Grounded Systems (from ANSI C62.92)

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 rarely higher than three-phase short circuit current

Cannot satisfactorily be reduced below one-half or one-third of values for solid grounding

Low Negligible except when Petersen coil is short circuited for relay purposes when it may compare with solidly-grounded systems

(3) Stability Usually unimportant Lower than with other methods but can be made satisfactory by use of high-speed breakers

Improved over solid grounding particularly if used at receiving end of system

Improved over solid grounding particularly if used at receiving end of system

Is eliminated from consideration during single line-to-ground faults unless neutralizer is short circuited to isolate fault by relays

(4) Relaying Difficult Satisfactory Satisfactory Satisfactory Requires special provisions but can be made satisfactory

(5) Arcing Grounds

Likely Unlikely Possible if reactance is ex-cessive

Unlikely Unlikely

(6) Localizing Faults

Effect of fault transmitted as excess voltage on sound phases to all parts of conductively connected network

Effect of faults localized to system or part of system where they occur

Effect of faults localized to system or part of system where they occur unless reactance is quite high

Effect of faults transmitted as excess voltage on sound phases to all parts of conductively connected network

Effect of faults transmitted as excess voltage on sound phases to all parts of conductively connected network

(7) Double Faults

Likely Likely Unlikely unless reactance is quite high and insulation weak

Unlikely unless resistance is quite high and insulation weak

Seem to be more likely but conclusive information not available

(8) Lightning Protection

Ungrounded neutral service arresters must be applied at sacrifice in cost and efficiency

Highest efficiency and lowest cost

If resistance is very high arresters for ungrounded neutral service must be applied at sacrifice in cost and efficiency

Arresters for ungrounded, neutral service usually must be applied at sacrifice in cost and efficiency

Ungrounded neutral service arresters must be applied at sacrifice in cost and efficiency

Grounding

Grounding encompasses several different but interrelated aspects of electrical distribu-tion system design and construction, all of which are essential to the safety and proper operation of the system and equipment sup-plied by it. Among these are equipment grounding, system grounding, static and light-ning protection, and connection to earth as a reference (zero) potential.

1. Equipment Grounding

Equipment grounding is essential to safety of personnel. Its function is to insure that all exposed noncurrent-carrying metallic parts of all structures and equipment in or near the electrical distribution system are at the same potential, and that this is the zero reference potential of the earth. Grounding is required by both the National Electrical Code (Article 250) and the National Electrical Safety Code. Equipment grounding also provides a return path for ground fault currents, permitting protective devices to operate. Accidental con-tact of an energized conductor of the system with an improperly grounded noncurrent-carry metallic part of the system (such as a motor frame or panelboard enclosure) would

raise the potential of the metal object above ground potential. Any person coming in con-tact with such an object while grounded could be seriously injured or killed. In addition, cur-rent flow from the accidental grounding of an energized part of the system could generate sufficient heat (often with arcing) to start a fire. To prevent the establishment of such un-safe potential difference requires that (1) the equipment grounding conductor provide a return path for ground fault currents of suffi-ciently low impedance to prevent unsafe volt-age drop, and (2) the equipment grounding conductor be large enough to carry the maxi-mum ground fault current, without burning off, for sufficient time to permit protective de-vices (ground fault relays, circuit breakers, fuses) to clear the fault. The grounded con-ductor of the system (usually the neutral con-ductor), although grounded at the source, must not be used for equipment grounding.

The equipment grounding conductor may be the metallic conduit or raceway of the wiring system, or a separate equipment grounding conductor, run with the circuit conductors, as permitted by NEC. If a separate equipment grounding conductor is used, it may be bare or insulated; if insulated, the insulation must be green. Conductors with green insulation may

not be used for any purpose other than for equipment grounding.

The equipment grounding system must be bonded to the grounding electrode at the source or service; however, it may be also connected to ground at many other points. This will not cause problems with the safe operation of the electrical distribution system. Where computers, data processing, or micro-processor-based industrial process control systems are installed, the equipment grounding system must be designed to minimize inter-ference with their proper operation. Often, isolated grounding of this equipment, or completely isolated electrical supply systems are required to protect micro-processors from power system “noise” that does not in any way affect motors or other electrical equipment.

2. System Grounding

System grounding connects the electrical supply, from the utility, from transformer sec-ondary windings, or from a generator, to ground. A system can be solidly grounded (no intentional impedance to ground), imped-ance grounded (through a resistance or reac-tance), or ungrounded (with no intentional connection to ground).

January 1999

Cutler-Hammer


CAT.71.01.T.E

A

Grounding

Table A17: Features of Ungrounded and Grounded Systems

(Continued)

AUngrounded

BSolidly Grounded

CReactance Grounded

DResistance Grounded

EResonant Grounded

(9) TelephoneInterference

Will usually be low except in cases of double faults or electrostatic induction with neutral displaced but duration may be great

Will be greatest in magnitude due to higher fault currents but can be quickly cleared particularly with high speed breakers

Will be reduced from solidly grounded values

Will be reduced from solidly grounded values

Will be low in magnitude except in cases of double faults or series resonance at harmonic frequencies, but duration may be great

(10) Ratio Interference

May be quite high during faults or when neutral is displayed

Minimum Greater than for solidly grounded, when faults occur

Greater than for solidly grounded, when faults occur

May be high during faults

(11) Line Availability

Will inherently clear themselves if total length of interconnected line is low and require isolation from system in increasing percentages as length becomes greater

Must be isolated for each fault



Need not be isolated but will inherently clear itself in about 60 to 80 percent of faults

(12) Adaptability toInterconnection

Cannot be interconnected unless interconnecting system is ungrounded or isolating transformers are used

Satisfactory indefinitely with reactance-grounded systems

Satisfactory indefinitely with solidly-grounded systems

Satisfactory with solidly- or reactance-grounded systems with proper attention to relaying

Cannot be interconnected unless interconnected system is resonant grounded or isolating transformers are used. Requires coordination between interconnected systems in neutralizer settings

(13) Circuit Breakers

Interrupting capacity determined by three-phase conditions

Same interrupting capacity as required for three-phase short circuit will practically always be satisfactory

Interrupting capacity determined by three-phase fault conditions

Interrupting capacity determined by three-phase faultconditions

Interrupting capacity determined by three-phase faultconditions

(14) Operating Procedure

Ordinarily simple but possibility of double faults introduces complication in times of trouble

Simple Simple Simple Taps on neutralizers must be changed when major system switching is per-formed and difficulty may arise in interconnected systems. Difficult to tell where faults are located

(15) Total Cost High, unless conditions are such that arc tends to extinguish itself, when transmission circuits may be eliminated, reducing total cost

Lowest Intermediate Intermediate Highest unless the are suppressing characteristic is relied on to eliminate transmission circuits when it may be lowest for the particular types of service

Because the method of grounding affects the voltage rise of the unfaulted phases above ground, ANSI C62.92 classifies systems from the point of view of grounding in terms of a coefficient of grounding

This same standard also defines systems as effectively grounded when COG

≤

.8 such a system would have X

0

/X

1

≤

3.0 and R

0

/X

1

≤

1.0. Any other grounding means that does not satisfy these conditions at any point in a sys-tem is not effectively grounded.

The aforementioned definition is of signifi-cance in medium voltage distribution sys-tems with long lines and with grounded sources removed during light load periods so that in some locations in the system the X

0

/

X

1

, R

0

/X

1

may exceed the defining limits. Other standards (cable and lightning arrester) allow the use of 100% rated cables and arrest-ers selected on the basis of an effectively grounded system only where the criteria in the above are met. In effectively grounded system the line-to-ground fault current is high and there is no significant voltage rise in the unfaulted phases.

With selective ground fault isolation the fault current will be at 60% of the three-phase current at the point of fault. Damage to cable shields must be checked. Although this fact is not a problem except in small cables. It is a good idea to supplement the cable shields as returns of ground fault current to prevent damage.

The burdens on the current transformers must be checked also, where residually con-nected ground relays are used and the cts supply current to phase relays and meters.

If ground sensor current transformers are used they must be of high burden capacity.

COG

Highest Power FrequencyRms Line - Ground Voltage

Rms Line - Line Voltage at FaultLocation With the Fault Removed

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

Table A18 taken from ANSI-C62.92 indicates the characteristics of the various methods of grounding.

Reactance Grounding

It is generally used in the grounding of the neutrals of generators directly connected to the distribution system bus, in order to limit the line-to-ground fault to somewhat less than the three-phase fault at the generator terminals. If the reactor is so sized in all prob-ability the system will remain effectively grounded.

Resistance Grounded

Medium-voltage systems in general are low resistance grounded. The fault is limited from 25-20% of the three-phase fault value down to about 200A-400A. With a properly sized re-sistor and relaying application, selective fault isolation is feasible. The fault limit provided has a bearing on whether residually connected re-lays are used or ground sensor current trans-formers are used for ground fault relaying.

CAT.71.01.T.E



A

Grounding

Figure 2. Ungrounded Systems

Figure 1. Solidly-Grounded Systems

Table A18: Characteristics of Grounding

Grounding Classes and Means

Ratios of Symmetrical Component Parameters➀

Percent FaultCurrent

Per Unit TransientLG Voltage

A. Effectively ➃1. Effective2. Very effective

X0/X1

0-30-1

R0/X1

0-10-0.1

R0/X0

----

➁

>60>95

➂

≤2<1.5

B. Noneffectively1. Inductance

a. Low inductanceb. High inductance

2. Resistancea. Low resistanceb. High resistance

3. Inductance and resistance

4. Resonant5. Ungrounded/capacitance

a. Range Ab. Range B

3-10>10

0-10

>10

➄

-∞ to -40➅-40 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 ➆

In general, where residually connected relays are used, the fault current at each grounded source should not be limited to less than the current transformers rating of the source. This rule will provide sensitive differential protection for wye-connected generators and transformers against line-to-ground faults near the neutral. Of course, if the installation of ground fault differential protection is feasi-ble, or ground sensor current transformers are used, sensitive differential relaying in resistance grounded system with greater fault limitation is feasible. In general, ground sensor current transformers do not have high burden capacity. Resistance grounded systems limit the circulating currents of triple harmonics and limit the damage at the point of fault. This method of grounding is not suit-able for line-to-neutral connection of loads.

On medium-voltage systems, 100% cable in-sulation is rated for phase-to-neutral voltage. If continued operation with one phase faulted to ground is desired, increased insulation thickness is required. For 100% insulation, fault clearance is recommended within one minute; for 133% insulation, one hour is

acceptable; for indefinite operation, as long as necessary, 173% insulation is required.

Grounding PointThe most commonly used grounding point is the neutral of the system or the neutral point created by means of a zigzag or a wye-broken delta grounding transformer in a system which was operating as an ungrounded delta system.

In general, it is a good practice that all source neutrals be grounded with the same grounding impedance. Where one of the medium-voltage sources is the utility, their consent for impedance grounding must be obtained.

The neutral impedance must have a voltage rating at least equal to the rated line-to-neutral voltage class of the system. It must have at least a 10-second rating equal to the maxi-mum future line-to-ground fault current and a continuous rating to accommodate the triple harmonics that may be present.

•• • •

•

∅B

∅C∅ANeutral

Center-Tapped (High-Leg) Delta

Grounded Wye

•

•• •• ∅C

∅A∅B

Neutral

N

• ∅A

∅B∅C•• •

Corner-Grounded Delta

➀ Values of the coefficient of grounding (expressed as a percentage of maximum phase-to-phase voltage) corresponding to various combination of these ratios are shown in the ANSI C62.92 Appen-dix figures. Coefficient of grounding affects the selection of arrester ratings.

➁ Ground-fault current in percentage of the three-phase short-circuit value.

➂ 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.

➃ 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%.

➄ See ANSI 62.92 para. 7.3 and precautions given in application sections.

➅ Usual isolated neutral (ungrounded) system for which the zero-sequence reactance is capacitive (negative).

➆ Same as NOTE (6) and refer to ANSI 62.92 para. 7.4. Each case should be treated on its own merit.

Figure 3. Resistance-Grounded Systems

•

Resistance-Grounded Wye

• •• ∅C

∅A∅B

RN

• • ∅A

••

•

•∅B∅C

• •

Delta With Derived Neutral Resistance-Grounded Using Zig-Zag Transformer

•R

N

4. Low-Voltage System – Grounding

Solidly-grounded three-phase systems (Fig. 1) are usually wye-connected, with the neutral point grounded. Less common is the “red-leg” or high-leg delta, a 240V system sup-plied by some utilities with one winding cen-ter-tapped to provide 120V to ground for lighting. This 240V, 3-phase, 4-wire system is used where 120V lighting load is small com-pared to 240V power load, because the instal-lation is low in cost to the utility. A corner-grounded three-phase delta system is some-times found, with one phase grounded to sta-bilize all voltages to ground. Better solutions are available for new installations.

Ungrounded systems (Fig. 2) can be either wye or delta, although the ungrounded delta system is far more common.

Resistance-grounded systems (Fig. 3) are simplest with a wye connection, grounding the neutral point directly through the resistor. Delta systems can be grounded by means of a zig-zag or other grounding transformer. Wye broken delta transformer banks may also be used.

This derives a neutral point, which can be either solidly or impedance grounded. If the grounding transformer has sufficient capacity, the neutral created can be solidly grounded and used as part of a three-phase, four-wire

• ∅A

∅B∅C

• •Ungrounded Delta

Ungrounded Wye

•• •• ∅C

∅A∅B

N

January 1999

Cutler-Hammer


CAT.71.01.T.E

A

system. Most transformer-supplied systems are either solidly grounded or resistance grounded. Generator neutrals are often grounded through a reactor, to limit ground-fault (zero sequence) currents to values the generator can withstand.

Selecting the Low-Voltage System Grounding Method

There is no one “best” distribution system for all applications. In choosing among solidly-grounded, resistance-grounded, or unground-ed power distribution the characteristics of the system must be weighed against the require-ments of power loads, lighting loads, continuity of service, safety, and cost.

Under ground-fault conditions, each system behaves very differently. A solidly grounded system produces high fault currents, usually with arcing, and the faulted circuit must be cleared on first fault within a fraction of a second to minimize damage. An ungrounded system will pass limited current into the first ground fault—only the charging current of the system, caused by the distributed capacitance to ground of the system wiring and equip-ment. In low-voltage systems, this is rarely more than 1 or 2 amperes. Therefore, on first ground fault an ungrounded system can con-tinue in service, making it desirable where power outages cannot be tolerated. However, if the ground fault is intermittent, sputtering or arcing, a high voltage—as much as 6 to 8 times phase voltage—can be built up across the system capacitance, from the phase con-ductors to ground. Similar high voltages can occur as a result of resonance between system capacitance and the inductances of trans-formers and motors in the system. The phase-to-phase voltage is not affected. This high transient phase-to-ground voltage can puncture insulation at weak points, such as motor windings, and is frequent cause of multiple motor failures on ungrounded systems. Lo-cating a first fault on an ungrounded system can be difficult. If, before the first fault is cleared, a second ground fault occurs on a dif-ferent phase, even on a different, remote feeder, it is a high-current phase-to-ground-to-phase fault, usually arcing, that can cause severe damage if at least one of the grounds is not cleared immediately.

In general, where loads will be connected line to neutral, solidly grounded systems are used. High resistance grounded systems are used as substitutes for underground systems where high system availability is required.

With one phase grounded, the voltage to ground of the other two phases goes up 73%, to full phase-to-phase voltage. In low-voltage systems this is not important, since conduc-tors are insulated for 600V.

Low-voltage resistance grounded system is normally grounded so that the single line-to-

ground fault current exceeds the capacitive charging current of the system. If data for the charging current is not available use 40-50 ohm resistor in the neutral of the transformer.

In

commercial and institutional

installations, such as office buildings, shopping centers, schools, and hospitals, lighting loads are often 50% or more of the total load. In addition, a feeder outage on first ground fault is seldom crucial—even in hospitals, which have emer-gency power in critical areas. For these rea-sons, a

solidly grounded wye

distribution, with the neutral used for lighting circuits, is usually the most economical, effective, and convenient design.

In

industrial installations

, the effect of a shut-down caused by a single ground fault could be disastrous. An interrupted process could cause the loss of all the materials involved, often ruin the process equipment itself, and sometimes create extremely dangerous situa-tions for operating personnel. On the other hand, lighting is usually only a small fraction of the total industrial electrical load. A solidly-grounded neutral circuit conductor is not im-perative and, when required, can be obtained from inexpensive lighting transformers.

Because of the ability to continue in operation with one ground fault on the system, many existing industrial plants use

ungrounded

del-ta distribution. Today, new installations can have all the advantages of service continuity of the ungrounded delta, yet minimize the problems of the system, such as the difficulty of locating the first ground fault, risk of dam-age from a second ground fault, and damage transient overvoltages. A

high-resistance grounded wye

distribution can continue in operation with a ground fault on the system, will not develop transient overvoltages, and, because the ground point is established, locating a ground fault is less difficult than on an ungrounded system.

When combined with sensitive ground-fault protection, damage from a second ground fault can be nearly eliminated.

Ungrounded delta

systems can be converted to high-resistance grounded systems, using a zig-zag or other grounding transformer to derive a neutral, with similar benefits. In many instances, the high-resis-tance grounded distribution will be the most advantageous for industrial installations.

Ground Fault Protection

A ground fault normally occurs in one of two ways: By accidental contact of an energized conductor with normally grounded metal, or as a result of an insulation failure of an ener-gized conductor. When an insulation failure occurs, the energized conductor contacts nor-mally noncurrent-carrying grounded metal, which is bonded to or part of the equipment grounding conductor. In a solidly grounded system, the fault current returns to the source

primarily along the equipment grounding conductors, with a small part using parallel paths such as building steel or piping. If the ground return impedance were as low as that of the circuit conductors, ground fault currents would be high, and the normal phase over-current protection would clear them with little damage. Unfortunately, the impedance of the ground return path is usually higher, the fault itself is usually arcing and the impedance of the arc further reduces the fault current. In a 480Y/277-volt system, the voltage drop across the arc can be from 70 to 140V. The resulting ground fault current is rarely enough to cause the phase overcurrent protection device to open instantaneously and prevent damage. Sometimes, the ground fault is below the trip setting of the protective device and it does not trip at all until the fault escalates and exten-sive damage is done. For these reasons, low level ground protection devices with minimum time delay settings are required to rapidly clear ground faults. This is emphasized by the NEC requirement that a ground fault relay on a service shall have a maximum delay of one second for faults of 3000 amperes or more.

The NEC (Sec. 230-95) requires that ground fault protection, set at no more than 1200 am-peres, be provided for each service discon-necting means rated 1000 amperes or more on solidly grounded wye services of more than 150 volts to ground, but not exceeding 600 volts phase-to-phase. Practically, this makes ground fault protection mandatory on 480Y/277-volt services, but not on 208Y/120-volt services. On a 208-volt system, the volt-age to ground is 120 volts. If a ground fault oc-curs, the arc goes out at current zero, and the voltage to ground is often too low to cause it to restrike. Therefore, arcing ground faults on 208-volt systems tend to be self-extinguishing. On a 480-volt system, with 277 volts to ground, restrike usually takes place after current zero, and the arc tends to be self-sustaining, doing severe and increasing damage, until the fault is cleared by a protective device.

The NEC requires ground fault protection only on the service disconnecting means. This protection works so fast that for ground faults on feeders, or even branch circuits, it will often open the service disconnect before the feeder or branch circuit overcurrent de-vice can operate. This is highly undesirable, and in the NEC (230-95) a Fine Print Note (FPN) states that additional ground fault pro-tective equipment will be needed on feeders and branch circuits where maximum continuity of electric service is necessary. Unless it is acceptable to disconnect the entire service on a ground fault almost anywhere in the system, such additional stages of ground fault protec-tion must be provided. At least two stages of protection are mandatory in health care facilities (NEC Sec. 517-17).

Grounding/Ground Fault Protection

CAT.71.01.T.E



A

Figure 1. Ground Return Sensing Method

method as illustrated in Figure 3. This is a very common sensing method used with cir-cuit breakers equipped with electronic trip units and integral ground fault protection. The three-phase sensors are required for nor-mal phase overcurrent protection. Ground fault sensing is obtained with the addition of an identically rated sensor mounted on the neutral. In a residual sensing scheme, the re-lationship of the polarity markings–as noted by the “X” on each sensor–is critical. Since the vectorial sum of the currents in all the conductors will total zero under normal, non-ground faulted conditions, it is imperative that proper polarity connections are em-ployed to reflect this condition.

As with the zero sequence sensing method, the resultant residual sensor output to the ground fault relay or integral ground fault tripping circuit will be zero if all currents flow only in the circuit conductors. Should a ground fault occur, the current from the fault-ed conductor will return along the ground path, rather than on the other circuit conduc-tors, and the residual sum of the sensor out-puts will not be zero. When the level of ground fault current exceeds the pre-set cur-rent and time delay settings, a ground fault tripping action will be initiated.

This method of sensing ground faults can be economically applied on main service discon-nects where circuit breakers with integral ground fault protection are provided. It can be used in minimum protection schemes per NEC (230-95) or in multi-tier schemes where additional levels of ground fault protection are desired for added service continuity. Ad-ditional grounding points may be employed upstream of the residual sensors but, not on the load side.

shaped configuration. This core balance cur-rent transformer surrounds all the phase and neutral conductors in a typical 3-phase, 4-wire distribution system. The sensing method is based on the fact that the vectorial sum of the phase and neutral currents in any distribution circuit will equal zero unless a ground fault condition exists downstream from the sensor. All currents that flow only in the circuit conductors, including balanced or unbalanced phase-to-phase and phase-to-neutral normal or fault currents, and harmon-ic currents, will result in zero sensor output. However, should any conductor become grounded, the fault current will return along the ground path–not the normal circuit con-ductors–and the sensor will have an unbal-anced magnetic flux condition and a sensor output will be generated to actuate the ground fault relay.

Overcurrent protection is designed to protect conductors and equipment against currents that exceed their ampacity or rating under prescribed time values. An overcurrent can result from an overload, short-circuit or (high level) ground fault condition. When currents flow outside the normal current path to ground, supplementary ground fault protec-tion equipment will be required to sense low level ground fault currents and initiate the protection required. Normal phase overcur-rent protection devices provide no protection against low level ground faults.

There are three basic means of sensing ground faults. The most simple and direct method is the ground return method as illus-trated in Figure 1. This sensing method is based on the fact that all currents supplied by a transformer must return to that transformer.

When an energized conductor faults to ground-ed metal, the fault current returns along the ground return path to the neutral of the source transformer. This path includes the grounding electrode conductor–sometimes called the “ground strap”–as shown in Figure 1. A current sensor on this conductor (which can be a conventional bar-type or window type CT) will respond to ground fault currents only. Normal neutral currents resulting from unbalanced loads will return along the neutral conductor and will not be detected by the ground return sensor.

This is an inexpensive method of sensing ground faults where only minimum protec-tion per NEC (230-95) is desired. For it to op-erate properly, the neutral must be grounded in only one place as indicated in Figure 1. In many installations, the servicing utility grounds the neutral at the transformer and additional grounding is required in the ser-vice equipment per NEC (250-23a). In such cases, and others including multiple source with multiple, interconnected neutral ground points, residual or zero sequence sensing methods should be employed.

A second method of detecting ground faults involves the use of a zero sequence sensing method as illustrated in Figure 2. This sensing method requires a single, specially-designed sensor either of a torriodial or rectangular

Figure 2. Zero Sequence Sensing Method

Zero sequence sensors are available with various window openings for circuits with small or large conductors, and even with large rectangular windows to fit over bus bars or multiple large size conductors in par-allel. Some sensors have split cores for in-stallation over existing conductors without disturbing the connections.

This method of sensing ground faults can be employed on the main disconnect where min-imum protection per NEC (230-95) is desired. It can also be easily employed in multi-tier systems where additional levels of ground fault protection are desired for added service continuity. Additional grounding points may be employed upstream of the sensor but, not on the load side.

Ground fault protection employing ground return or zero sequence sensing methods can be accomplished by the use of separate ground fault relays (GFRs) and disconnects equipped with standard shunt trip devices or by circuit breakers with integral ground fault protection with external connections ar-ranged for these modes of sensing.

The third basic method of detecting ground faults involves the use of multiple current sensors connected in a residual sensing

Figure 3. Residual Sensing Method

Both the zero sequence and residual sensing methods have been commonly referred to as “vectorial summation” methods.

Most distribution systems can utilize either of the three sensing methods exclusively ora combination of the sensing methods de-pending upon the complexity of the system and the degree of service continuity and

ZeroSequenceSensor

Main

Neutral

TypicalFeeder

AlternateSensorLocation

Typical4W Load

GFR

GFR

Typical4W Load

SensorPolarityMarks

Neutral

TypicalFeeder

Main

ResidualSensors

Main

GFR

Neutral

TypicalFeeder

Sensor

GroundingElectrodeConductor

EquipmentGroundingConductor

GroundingElectrode

Typical4W Load

ServiceTransformer

Ground Fault Protection

January 1999


CAT.71.01.T.E

Asystem configuration, either mode of sensing or a combination of all types may be em-ployed to accomplish the desired end results.

Since the NEC (230-95) limits the maximum setting of the ground fault protection used on service equipment to 1200 ampres (or 3000A for one second), to prevent tripping of the main service disconnect on a feeder ground fault, ground fault protection must be provid-ed on all the feeders. To maintain maximum service continuity, more than two levels (zones) of ground fault protection will be re-quired, so that ground fault outages can be localized and service interruption minimized. To obtain selectivity between different levels of ground fault relays, time delay settings should be employed with the GFR furthest downstream having the minimum time de-lay. This will allow the GFR nearest the fault to operate first. With several levels of protec-tion, this will reduce the level of protection for faults within the upstream GFR zones. Zone interlocking was developed for GFRs to overcome this problem.

GFRs (or circuit breakers with integral ground fault protection) with zone interlock-ing are coordinated in a system to operate in a time delayed mode for ground faults oc-curring most remote from the source. How-ever, this time delayed mode is only actuated when the GFR next upstream from the fault sends a restraining signal to the up-stream GFRs. The absence of a restraining signal from a downstream GFR is an indica-tion that any occurring ground fault is within the zone of the GFR next upstream from the fault and that device will operate instanta-neously to clear the fault with minimum damage and maximum service continuity. This operating mode permits all GFRs to op-erate instantaneously for a fault within their zone and still provide complete selectivity between zones. The National Electrical Manu-facturers Association (NEMA) states, in their application guide for ground fault protection,

selective coordination desired. Different methods will be required depending upon the number of supply sources and the num-ber and location of system grounding points.

As an example, one of the more frequently used systems where continuity of service to critical loads is a factor is the dual source sys-tem illustrated in Figure 4. This system utilizes tie-point grounding as permitted under NEC Sec. 250-23(a). The use of this grounding method is limited to services that are dual fed (double ended) in a common enclosure or grouped together in separate enclosures and employing a secondary tie.

This scheme utilizes individual sensors con-nected in ground return fashion. Under tie breaker closed operating conditions either the M1 sensor or M2 sensor could see neutral unbalance currents and possibly initiate an improper tripping operation. However, with the polarity arrangements of these two sen-sors along with the tie breaker auxiliary switch (T/a) and interconnections as shown, this possibility is eliminated. Selective ground fault tripping coordination between the tie breaker and the two main circuit break-ers is achieved by pre-set current pickup and time delay settings between devices GFR/1, GFR/2 and GFR/T.

The advantages of increased service continu-ity offered by this system can only be effec-tively utilized if additional levels of ground fault protection are added on each down-stream feeder. Some users prefer individual grounding of the transformer neutrals. In such cases a partial differential ground fault scheme should be used for the mains and tie breaker.

An infinite number of ground fault protection schemes can be developed depending upon the number of alternate sources, the number of grounding points and system interconnec-tions involved. Depending upon the individual

that zone interlocking is necessary to mini-mize damage from ground faults. A two-wire connection is required to carry the restrain-ing signal from the GFRs in one zone to the GFRs in the next zone.

Circuit breakers with integral ground fault protection and standard circuit breakers with shunt trips activated by the ground fault relay are ideal for ground fault protection. Many fused switches over 1200A, and Cutler-Hammer Type FDP fusible switches in ratings from 400A to 1200A, are listed by UL as suit-able for ground fault protection. Fusible switches so listed must be equipped with a shunt trip, and be able to open safely on faults up to 12 times their rating.

Power distribution systems differ widely from each other, depending upon the require-ments of each user, and total system overcur-rent protection, including ground fault currents, must be individually designed to meet these needs. Experienced and knowl-edgeable engineers must consider the power sources (utility or on-site), the effects of out-ages and costs of downtime, safety for peo-ple and equipment, initial and life-cycle costs, and many other factors. They must apply pro-tective devices, analyzing the time-current characteristics, fault interrupting capacity, and selectivity and coordination methods to provide the most safe and cost-effective dis-tribution system.

Further InformationAD 29-762 Type GFR Ground Fault

Protection SystemDB 28-850 Systems Pow-R BreakersTD.44A.01.T.E Type DSII Metal-Enclosed

Low-Voltage SwitchgearIB 32-698A C-HRG “Safe Ground” Low-

Voltage High Resistance Pulsing Ground System

PRSC-4E System Neutral Groundingand Ground Fault Protection(ABB Publication)

PB 2.2 NEMA Application Guide forGround Fault ProtectiveDevices for Equipment

IEEE Grounding of Industrial andStandard 142 Commercial Power Systems

(Green Book)

Lightning and Surge Protection

Physical protection of buildings from direct damage from lightning is beyond the scope of this section. Requirements will vary with geographic location, building type and envi-ronment, and many other factors (see IEEE/ANSI Standard 142-1982, Grounding of In-dustrial and Commercial Power Systems). Any lightning protection system must be grounded, and the lightning protection ground must be bonded to the electrical equipment grounding system.

Main 1 Main 2Tie

M1a

T a

Source1

Source2

Neutral Neutral

TypicalFeeder

TypicalFeeder

Center PointGrounding Electrode

Typical4W Load

Typical4W Load

M1Sensor Tie

Sensor

GFR1

GFRT

GFR2

M2

M2Sensor

a

Figure 4. Dual Source System – Single Point Grounding

Ground Fault Protection/Lighting and Surge Protection

CAT.71.01.T.E



AGrounding Electrodes

At some point, the equipment and system grounds must be connected to the earth by means of a grounding electrode system.

Outdoor substations usually use a ground grid, consisting of a number of ground rods driven into the earth and bonded together by buried copper conductors. The required grounding electrode system for a building is spelled out in the NEC, Sec. 250-H. The pre-ferred grounding electrode is a metal under-ground water pipe in direct contact with the earth for at least 10 feet. However, because underground water piping is often plastic out-side the building, or may later be replaced by plastic piping, the NEC requires this electrode to be supplemented by and bonded to at least one other grounding electrode, such as the ef-fectively grounded metal frame of the build-ing, a concrete-encased electrode, a copper conductor ground ring encircling the build-ing, or a made electrode such as one or more driven ground rods or a buried plate. Where any of these electrodes are present, they must be bonded together into one grounding elec-trode system.

One of the most effective grounding elec-trodes is the concrete-encased electrode, sometimes called the Ufer ground, after the man who developed it. It consists of at least 20 feet of steel reinforcing bars or rods not less than 1/2 inch in diameter, or at least 20 feet of bare copper conductor, size No. 4 AWG or larger, encased in at least 2 inches of concrete. It must be located within and near the bottom of a concrete founda-tion or footing that is in direct contact with the earth. Tests have shown this electrode to provide a low-resistance earth ground even in poor soil conditions.

The electrical distribution system and equip-ment ground must be connected to this grounding electrode system by a grounding electrode conductor. All other grounding electrodes, such as those for the lightning protection system, the telephone system, television antenna and cable TV system grounds, and computer systems, must be bonded to this grounding electrode system.

Further Information● IEEE/ANSI Standard 142–Grounding In-

dustrial and Commercial Power Systems (Green Book)

● IEEE Standard 241–Electric Power Sys-tems in Commercial Buildings (Gray Book)

● IEEE Standard 141–Electric Power Distri-bution for Industrial Plants (Red Book)

Grounding Electrodes

January 1999

Cutler-Hammer


CAT.71.01.T.E

A

Power Quality

Power Quality – Terms,Technical Overview

Introduction

Ever since the inception of the electric utility industry, utilities have sought to provide their customers with reliable power main-taining a steady voltage and frequency. Sen-sitive electronic loads deployed today by electrical energy users require strict require-ments for the quality of power delivered to loads.

For electronic equipment, power distur-bances are defined in terms of amplitude and duration by the electronic operating envelope. Electronic systems may be damaged and disrupted, with shortened life expectancy.

The proliferation of computers, variable fre-quency motor drives and other electronically controlled equipment is placing a greater de-mand on power producers for a disturbance-free source of power. Not only do these types of equipment require quality power for proper operation; many times, these types of equipment are also the sources of power dis-turbances that corrupt the quality of power in a given facility.

Power Quality is defined according to IEEE Standard 1100 as the concept of powering and grounding sensitive electronic equip-ment in a manner that is suitable to the oper-ation of that equipment. IEEE Standard 1159 notes that “within the industry, alternate def-initions or interpretations of power quality have been used, reflecting different points of view.”

In addressing power quality problems at an existing site, or in the design stages of a new building, engineers need to specify different services or mitigating technologies. The low-est cost and highest value solution is to selec-tively apply a combination of different products and services as follows:

Key Services/Technologies in the “Power Quality” Industry

●

Power Quality Surveys, Analysis and Studies

●

Power Monitoring

●

Grounding Products & 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 viewed as the difference between the quality of the power supplied and the quality of the power re-quired to reliably operate the load equip-ment. With this viewpoint, power quality problems can be resolved in three ways: by reducing the variations in the power supply

(power disturbances), by improving the load equipment's tolerance to those variations, or by inserting some interface equipment (known as power conditioning equipment) between the electrical supply and the sensi-tive load(s) to improve the compatibility of the two. Practicality and cost usually deter-mine the extent to which each option is used. As in all problem solving, the problem must be clearly defined before it can be resolved. Many methods are used to define power quality problems. For example, one option is a thorough on-site investigation which in-cludes inspecting wiring and grounding for errors, monitoring the power supply for pow-er disturbances, investigating equipment sensitivity to power disturbances, and deter-mining the load disruption and consequen-tial effects (costs), if any. In this way, the power quality problem can be defined, alter-native solutions developed, and optimal solution chosen. Another option is to buy power conditioning equipment to correct any and all perceived power quality problems without any on-site investigation. Sometimes this approach is not practical be-cause of limitations in the time and expense is not justified for smaller installations, mon-itoring for power disturbances may be need-ed over an extended period of time to capture infrequent disturbances, the exact sensitivi-ties of the load equipment may be unknown and difficult to determine, and finally, the investigative approach tends to solve only observed problems. Thus unobserved or potential problems may not be considered in the solution. For instance, when planning a new facility, there is no site to investigate. Therefore, power quality solutions are often implemented to solve potential or perceived problems on a preventive basis instead of a thorough on-site investigation. Before applying power-conditioning equip-ment to solve power quality problems, the site should be checked for wiring and grounding problems. Sometimes, correcting a relatively inexpensive wiring error, such as a loose connection or a reversed neutral and ground wire, can avoid a more expensive power conditioning solution.

Power Quality TermsPower Disturbance

– Any deviation from the nominal value (or from some selected thresholds based on load tolerance) of the input ac power characteristics.

Total Harmonic Distortion or Distortion Factor

– The ratio of the root-mean-square of the harmonic content to the root-mean-square of the fundamental quantity, ex-pressed as a percentage of the fundamental.

Crest Factor

– Ratio between the peak value (crest) and rms value of a periodic waveform.

Apparent (Total) Power Factor

– The ratio of the total power input in watts to the total volt-ampere input.

Sag

– An rms reduction in the ac voltage, at the power frequency, for the duration from a half-cycle to a few seconds. An under-voltage would have a duration greater than several seconds.

Interruption

– The complete loss of voltage for a time period.

Transient

– A sub-cycle disturbance in the ac waveform that is evidenced by a sharp brief discontinuity of the waveform. May be of either polarity and may be additive to or subtractive from the nominal waveform.

Surge or Impulse

– See transient.

Noise

– Unwanted electrical signals that pro-duce undesirable effects in the circuits of control systems in which they occur.

Common-Mode Noise

– The noise voltage that appears equally and in phase from each current-carrying conductor to ground.

Normal-Mode Noise

– Noise signals measur-able between or among active circuit conduc-tors feeding the subject load, but not between the equipment grounding conduc-tor or associated signal reference structure and the active circuit conductors.

Methodology for Ensuring Effective Power Quality to Electronic Loads

The Power Quality Pyramid

TM

is an effective guide for addressing a power quality prob-lem at an existing facility. The framework is also effective for specifying engineers who are creating a specification for a new facility. Power quality starts with grounding (the base of the pyramid) and then moves upward to address the potential issues. This simple, yet proven methodology, will provide the most cost effective approach (refer to figure below).

The Power Quality Pyramid™

6. Uninterruptible Power Supply(UPS, Gen. Sets, etc.)

5. Harmonic Distortion

4. Voltage Regulation

3. Surge Protection

2. Grounding

1. P.Q. Survey, PowerMonitoring, Analysis

CAT.71.01.T.E

Cutler-Hammer

A-48

January 1999


A

Power Quality/Harmonics and Nonlinear Loads

1.

Power Quality Survey, Power Monitoring and Consulting Services

can be conducted on existing facilities to provide the proper analysis of power quality issues prior to the implementation of the many solutions available. A power quality survey is a fact-finding investigation which reviews total power outages, lights flickering, computer malfunctioning, breaker tripping or fuse blowing, transformers operating hot or loud, neutral currents, capacitor fuses blow-ing, VFDs malfunctioning, data processing and process controllers malfunctioning, motors tripping or overheating, transfer schemes response times and power factor correction. The above data is obtained both by on-site investigation and installation of high-speed temporary power measurement devices. Many power quality instruments can not be permanently installed during the initial data collection effort, therefore pro-viding initial and long-term monitoring. The above survey and monitoring result in a power quality evaluation.

Power Quality evaluations can identify defi-ciencies and corrective measures involv-ing: harmonics and filtering, grounding issues, lightning protection, voltage flicker, switching transients, K-factor transformers, high resistance ground units, auto-transfer switches and surge protection devices (SPD/TVSS). In addition, the evaluation can identify problems, which are not related to power quality issues, but are demonstrat-ing power quality-like conditions. This can involve motor inrush currents or repeated starts per hour, isolation transformers in voltage regulating controls, separation of feeders to critical loads and peak-reading circuit breaker trip systems versus updated rms sensing systems.

2. Grounding

represents the foundation of a reliable power distribution system. Grounding and wiring problems can be the cause of up to 80% of all power quality problems. All other forms of power quality solutions are dependent upon good grounding procedures. The following grounding standards are useful references:

●

IEEE Green Book (Standard 142)

●

IEEE Emerald Book (Standard 1100)

●

UL96A, Installation requirements for Lightning Protection Systems

●

IAEA 1996 (International Association of Electrical Inspectors) Soars Book on Grounding

●

EC&M – Practical Guide to Quality Power For Electronic Equipment

●

Military Handbook – Grounding Bonding and Shielding of Electronic Equipment

The proliferation of communication and computer network systems has increased the need for proper grounding/wiring of ac and data/communication lines. In addition to reviewing ac grounding/bonding practic-es, it is necessary to prevent ground loops from affecting the signal reference point.

3. Surge Protection Devices (SPDs)

are rec-ommended as the next stage power quali-ty solutions. NFPA, UL96A, IEEE Emerald Book and equipment manufacturers rec-ommend the use of surge protectors. The transient voltage surge suppressors (also called TVSS) shunt short duration voltage disturbances to ground, thereby prevent-ing the surge from affecting electronic loads. When installed as part of the facility-wide design, SPDs are cost-effective compared to all other solutions (on a $/kVA basis).

Suppressors are installed at the facility entrance and/or key substation locations. They are also recommended on data lines, signal lines or other non-isolated commu-nication lines at the facility’s entrance.

4. Voltage Regulation

(i.e., sags or overvolt-age) disturbances are generally site- or load-dependent. A variety of mitigating solutions are available depending upon the load sensitivity, fault duration/magni-tude and the specific problems encoun-tered. It is recommended to install monitoring equipment on the ac power-lines to assess the degree and frequency of occurrences of voltage regulation prob-lems. The captured data will allow for the proper solution selection.

5. Harmonics

seldom affect the operation of microprocessor-based loads. Mitigating equipment is usually not required to pre-vent operating problems with electronic loads. Engineers are often more concerned about the effects of increased neutral cur-rent on the electrical distribution system (i.e., neutral conductors, transformers). Readings from a power quality meter will determine the level of distortion and iden-tify site-specific problems. Effective distri-bution layout and other considerations can be addressed during the design stage to mitigating harmonic problems. Harmonics related problems can be investigated and solved once loads are up and running.

6. Uninterruptible Power

is often the last component to be selected in the design process. While the proper selection and application of UPS is critical to reliable op-eration of mission critical equipment, a common design error is to assume UPS systems solve all power quality problems. Given the high cost per kVA of UPS, gener-ators, etc., (including capital, efficiency and maintenance costs) and the use of more decentralized network systems, the tech-nology is often applied at specific loads only. To prevent lightning or other surge related damage, IEEE (Standard 1100) recommends surge protection ahead of UPS and associated bypass circuits.

Reference sections L and F1 for detailed information.

Harmonics and Nonlinear Loads

Until recently, most electrical loads were lin-ear. The instantaneous current was directly proportional to the instantaneous voltage at any instant, though lagging by some time depending on the power factor. However, loads that are switched or pulsed, such as rectifiers, thyristors, and switching power supplies, are nonlinear. With the prolifera-tion of electronic equipment such as com-puters, UPS systems, variable speed drives, programmable logic controllers, and the like, nonlinear loads have become a signifi-cant part of many installations.

Nonlinear load currents vary widely from a sinusoidal wave shape; often they are dis-continuous pulses. This means that they are extremely high in harmonic content. The har-monics create numerous problems in electri-cal systems and equipment. The rms value of current is not easy to determine, and true rms measurements are necessary for metering and relaying to prevent improper operation of protective devices. Devices that measure time on the basis of wave shape, such as many generator speed and synchronizing controls, will fail to maintain proper output frequency or to permit paralleling of genera-tors. It is important that with standby genera-tors the harmonic content of the current of the loads that will be transferred to the stand-by generator be reviewed with the generator manufacturer to ensure that the voltage and frequency controls will operate satisfactorily. Computers will crash as their internal timing clocks fail.

Transformers, generators, and UPS systems will overheat and often fail at loads far below their ratings, because the harmonic currents cause greater heating than the same number of rms amperes of 60 Hz current. This results from increased eddy current and hysteresis losses in the iron cores, and skin effect in the conductors of the windings. In addition, the harmonic currents acting on the impedance of the source cause harmonics in the source voltage, which is then applied to other loads such as motors, causing them to overheat.

Some of the harmonic voltages are negative sequence (rotation is ACB instead of ABC). The second, fifth, eighth, and eleventh har-monics are negative sequence harmonics. Triple harmonics are zero sequence harmon-ics and are in phase.

In addition to the above, three-phase non-linear loads contain small quantities of even and third harmonics although in an unbal-anced three-phase system feeding three-phase non-linear loads the unbalance may cause even harmonics to exist.

In general as the order of a harmonic gets higher its amplitude becomes smaller as a percentage of the fundamental frequency.

January 1999

Cutler-Hammer


CAT.71.01.T.E

A

Harmonics and Nonlinear Loads

The harmonics also complicate the applica-tion of capacitors for power factor correction. If at a harmonic frequency the capacitors capacitive impedance at the frequency equals the system’s reactive impedance at the same frequency, as viewed at the point of application of the capacitor the harmonic voltage and current can reach dangerous magnitudes. At the same time that harmon-ics create problems in the application of pow-er factor correction capacitors, they lower the actual power factor. The rotating meters used by the utilities for watt-hour and var-hour measurements do not detect the distor-tion component caused by the harmonics. Rectifiers with diode front ends and large dc side capacitor banks have displacement pow-er factor of 90% to 95%. More recent electron-ic meters are capable of metering the true kVA kW hours taken by the circuit.

Single-phase power supplies for computer and fixture ballasts are rich in third harmon-ics and their odd multiples.

With a 3-phase, 4-wire system, if the 60 Hz phase currents are balanced (equal), the neu-tral current is zero. However, triplens and their odd multiple harmonics are additive in the neutral. Even with the phase currents per-fectly balanced, the harmonic currents in the neutral can total 173% of the phase current. This has resulted in overheated neutrals. The Computer and Business Equipment Manu-facturers Association (CBEMA) recommends that neutrals in the supply to electronic equipment be oversized to at least 173% of the ampacity of the phase conductors to pre-vent problems. CBEMA also recommends derating transformers, loading them to no more than 50% to 70% of their nameplate kVA, based on a rule-of-thumb calculation, to compensate for harmonic heating effects.

Three-phase, 6-pulse rectifiers produce 5th, 7th, 11th, 13th...harmonics. 12-pulse, 3-phase rectifiers produce 11th, 13th, 23rd, 25th, etc.

In spite of all the concerns they cause, non-linear loads will continue to increase. There-fore the design of non-linear loads and the systems that supply them will have to be designed so that their adverse effects are greatly reduced.

Such measures are:

1. Use multipulse conversion (ac to dc) equipment (greater than 6 pulses) to reduce the amplitude of the harmonics.

2. Use active filters that reduce the harmon-ics taken from the system by injecting harmonics equal to and opposite to those generated by the equipment.

3. Where capacitors are required for a power factor correction, design the installation incorporating reactors as tuned filters to 5th, 7th, 11th and 13th harmonics and high pass filters for higher harmonics.

4. Use

∆

-

∆

and

∆

-Y transformers in pairs as supply to conversion equipment. Their effect is the same as that of multi-pulse equipment and should be considered with 6-pulse equipment only.

5. Install reactors between the power sup-ply and the conversion equipment. They reduce the harmonic components of the current drawn by diode type conversion equipment with large filter capacitors. Another benefit is that they protect the filter capacitors from switching surges produced by switched utility or medium-voltage system capacitor.

6. Locate capacitors as far away (in terms of circuit impedance) from non-linear loads.

7. When all the above do not produce the desired reduction, oversize the system components as the last resort, or derate the equipment.

ANSI Standard C57.110 covers the procedure of derating standard (non-K-rated) transformers.

This method is based on determining the load loss due to I

2

R loss including the har-monic current plus the increase in the eddy current losses due the harmonic currents. The winding eddy current loss under rated conditions should be obtained from the transformer manufacturer, or the method shown in C57.110 should be used.

The K-rated transformers calculate the sum of I

h2

(pu) x h

2

where I

h

is the harmonic cur-rent of the hth harmonic as per unit of the fundamental and h is the order of the har-monic. K is the factor that corrects the eddy current loss under rated conditions to reduce the effects of adverse heating due to harmonics.

K-rated transformers have lower impedance than non-K-rated transformer which should

be considered in the selection of the low-voltage side breakers.

Revised standard IEEE 519-1992 indicates the limits of current distortion allowed at the PCC (Point of Common Coupling) point on the system where the current distortion is calcu-lated, usually the point of connection to the utility or the main supply bus of the system.

The standard also covers the harmonic lim-its of the supply voltage from the utility or cogenerators.

Percents are x 100 for each harmonic and

It is important for the customer to know the harmonic content of the utility’s supply volt-age because it will affect the harmonic distor-tion on his premises.

Table A19–Low-Voltage System Classifica-tion and Distortion Limits for 480V Systems

Class C A

N

DF

Special Application*General SystemDedicated System

1052

16,40022,80036,500

3%5%

10%

*Special system are those where the rate ofchange of voltage of the notch might misstriggenan event. A

N

is volt-microseconds, C is the impe-ance ratio of total impedance to impedance atcommon point in system. DF is distortion factor.

Table A20–Utility or Co-gen Supply Voltage Harmonic Limits

Voltage Range 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-------

Vh2

h 2=

h hmax=

∑

12⁄

Vh =

Table A21 is taken from IEEE Standard 519 Table 10.3.

Table A21–“Current Distortion Limits For General Distribution Systems (120V Through 69000V)”

Maximum Harmonic Current Distortion in Percent of I

L

Individual Harmonic Order (Odd Harmonics)

I

SC

/I

L

<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

TDD= Total Demand Distortion.

Even harmonics are limited to 25% of the odd harmonic limits above.

Current distortions that result in a dc offset, e.g., half-wave converters, are not allowed.

*All power generation equipment is limitedto these values of current distortion, regard-less of actual I

SC

/I

L

.

where

I

SC

= maximum short-circuit current at PCC.I

L

= maximum demand load current (funda-mental frequency component) at PCC.

CAT.71.01.T.E

Cutler-Hammer

A-50

January 1999


A

Secondary Voltages

Secondary Voltage

The most prevalent secondary distribution voltage in commercial and institutional build-ings today is 480Y/277 volts, with a solidly grounded neutral. It is also a very common secondary voltage in industrial plants and even in some high-rise, centrally air-conditioned and electrically heated residential buildings, because of the large electrical loads. Up until the early 1950s, most commercial buildings, such as offices and stores, used 208Y/120-volt distribution. About 1950, several simulta-neous developments changed this. First, central air conditioning became standard practice, more than doubling the previous loads for similar non-air-conditioned build-ings. Second, lighting levels were increased, with fluorescent lighting replacing most of the incandescent lighting. Third, the develop-ment of 277-volt ballasts and 277-volt wall switches made it possible to serve this fluo-rescent lighting load from a 480Y/277-volt system. Finally, economical mass-produced dry-type 480-volt to 208Y/120-volt transform-ers became readily available to step down the voltage for 120V incandescent lighting and receptacle loads.

With the increase in loads, the ability to serve the air-conditioning and other motor loads at 480 volts, and to serve increased lighting loads at 277 volts, 480Y/277-volt systems became the most economical distribution. It permitted smaller feeders or larger loads on each feeder, and fewer branch circuits. In addition, the problems of excessive voltage drop from large loads on 208-volt systems was greatly reduced with 480-volt distribution. In some very tall high-rise office buildings, it would have been nearly impossible, and prohibitively expen-sive, to use 208-volt distribution and keep voltage drops within acceptable limits.

The choice between 208Y/120V and 480Y/ 277V secondary distribution for commercial and institutional buildings depends on sever-al factors. The most important of these are size and types of loads (motors, fluorescent lighting, incandescent lighting, receptacles) and length of feeders. In general, large motor and fluorescent lighting loads, and long feed-ers, will tend to make the higher voltages, such as 480Y/277V, more economical. Very large loads and long runs would indicate the use of medium-voltage distribution and load-center unit substations close to the loads. Conversely, small loads, short runs, and a high percentage of incandescent lighting would favor lower utilization voltages such as 208Y/120V.

Industrial installations, with large motor loads, are almost always 480V, often ungrounded delta or resistance grounded delta or wye systems (see section on ground fault protection).

Practical Factors

Since most low-voltage distribution equip-ment available is rated for up to 600 volts, and

conductors are insulated for 600 volts, the in-stallation of 480-volt systems uses the same techniques and is essentially no more diffi-cult, costly, or hazardous than for 208-volt systems. The major difference is that an arc of 120 volts to ground tends to be self-extin-guishing, while an arc of 277 volts to ground tends to be self-sustaining and likely to cause severe damage. For this reason, the National Electrical Code requires ground fault protec-tion of equipment on grounded wye services of more than 150 volts to ground but not ex-ceeding 600 volts phase-to-phase (for practi-cal purpose, 480Y/277V services), for any service disconnecting means rated 1000 am-peres or more. The National Electrical Code permits voltage up to 300 volts to ground on circuits supplying permanently installed elec-tric discharge lamp fixtures, provided the lu-minaires do not have an integral manual switch and are mounted at least eight feet above the floor. This permits a three-phase, four-wire, solidly grounded 480Y/277-volt system to supply directly all of the fluorescent and high-intensity discharge (HID) lighting in a building at 277 volts, as well as motors at 480 volts. While mercury-vapor HID lighting is becoming obsolescent, other HID lighting, such as high-pressure sodium or metal halide, is increasing in use, as color rendition is im-proved, because of the economical high lumen output of light per watt of power consumed.

Technical Factors

The principal advantage of the use of higher secondary voltages in buildings is that for a given load, less current means smaller con-ductors and lower voltage drop. Also, a given conductor size can supply a large load at the same voltage drop in volts, but a lower

per-centage

voltage drop because of the higher supply voltage. Fewer or smaller circuits can be used to transmit the power from the ser-vice entrance point to the final distribution points. Smaller conductors can be used in many branch circuits supplying power loads, and a reduction in the number of lighting branch circuits is usually possible.

It is easier to keep voltage drops within ac-ceptable limits on 480-volt circuits than on 208-volt circuits. When 120-volt loads are sup-plied from a 480-volt system through step-down transformers, voltage drop in the 480-volt supply conductors can be compensated for by the tap adjustments on the transform-er, resulting in full 120-volt output. Since these transformers are usually located close to the 120-volt loads, secondary voltage drop should not be a problem. If it is, taps may be used to compensate by raising the voltage at the transformer.

Fault interruption by protective devices may be more difficult at 480 volts than at 208 volts for two principal reasons. First, the 480-volt arc is more difficult to interrupt than the208-volt arc. Second, the small impedances in the system, such as bus or cable impedances, and upstream protective device impedances, have less effect in reducing fault currents at

the higher voltages. However, the interrupt-ing ratings of circuit breakers and fuses at 480 volts have increased considerably in recent years, and protective devices are now avail-able for any required fault duty at 480 volts. In addition, many of these protective devices are current limiting, and can be used to pro-tect downstream equipment against these high fault currents.

Economic Factors

Utilization equipment suitable for principal loads in most buildings is available for either 480-volt or 208-volt systems. Three-phase motors and their controls can be obtained for either voltage, and for a given horsepower are less costly at 480 volts. Fluorescent and HID lamps can be used with either 277- or120-volt ballasts. However, in almost allcases, the installed equipment will have a lower total cost at the higher voltage.

Incandescent lighting, small fractional-horsepower motors, wall receptacles, and plug-and-cord connected appliances forreceptacle loads require a 120-volt supply. With a 480Y/277-volt service, it is necessary to supply these loads through step-down transformers. If the amount of 120-volt load to be served is high, this can influence the choice of supply voltage, or the relative cost of 480- and 208-volt systems. Therefore, it is economically advantageous to minimize the amount of 120-volt load, using as little incan-descent lighting as possible.

The higher secondary voltage system will usually be more economical in office build-ings, shopping centers, schools, hospitals, and similar commercial and institutional in-stallations, as well as in industrial plants. It is interesting to note that in some recent instal-lations in Canada, these considerations have been carried one step further, using 600Y/346-volt distribution, (600 volts phase-to-phase and 346 volts phase-to-neutral). This system supplies 600-volt three-phase motors, and 346-volt ballasts for the fluorescent and HID lighting. A 346-volt wall switch has been developed to control this fighting. A 277-volt wall switch and 277-volt ballast made the 480Y/277-volt system practical. These Cana-dian installations would violate the National Electrical Code in the United States, since they exceed 300 volts to ground. This prohibi-tion does not exist in Canada.

Utility Service Voltage

Whether the utility service is at primary or sec-ondary voltage will depend upon many fac-tors, such as type of building, total load, class of user, and the utility rate structure and stan-dard practice. In most downtown metropolitan areas, the utility will serve a single commercial or institutional building at secondary voltage only. In more open areas, especially for large buildings or multiple-building installations such as shopping centers, educational institu-tions, and hospitals, the utility may offer a choice of primary or secondary service.

January 1999

Cutler-Hammer


CAT.71.01.T.E

A

Secondary Voltages

Where a choice is available, the decision is essentially an economic one. Utility rate struc-tures provide higher cost for a given load served at secondary voltage than for the same load served at primary voltage, since the utility must provide and maintain the substations and pay for the substation losses on a secondary ser-vice. For the customer, the lower cost of primary service must be weighed against the cost of the primary distribution equipment and substations required and the space they occupy, the cost and availability of qualified maintenance for the primary distribution equipment and substa-tions, reliability of service, the cost of substation (mostly transformer) losses, and similar factors. It is common for industrial plants, with large loads, available room for electrical equipment, and well qualified maintenance, to take advan-tage of primary service. It is also usual for com-

mercial buildings to use secondary service. Institutional services vary, depending upon the size of the institution, the number and arrange-ment of buildings, continuity of service required, and quality of maintenance available.

Where secondary service is delivered, most buildings will use simple radial distribution from the service. The utility will supply the load in various ways, ranging from a single pad-mounted transformer, or several trans-formers for a multi-building installation, through spot networks for a high-rise office building.

Where the service is at primary voltage, the distribution can be from a single substation for smaller installations, or with primary dis-tribution to multiple load-center unit substa-

tions for larger systems. Primary distribution can be radial, or have multiple feeders or one or more loops, to single-ended or double-ended substations. Secondary distribution can be radial, loop, secondary-selective, or even secondary network. Any of the primary and secondary distribution methods previ-ously described may be used. The choice will depend on the continuity of service required, and the cost of the system. Generally, those systems that provide higher service reliability also have higher cost, and the initial andoper-ating costs must be weighed against the cost of downtime. In industrial installations, espe-cially in the process industries, the cost of an outage can be tremendous, and distribution systems with maximum reliability, flexibility, and redundant equipment can easily be justified.

High-Rise Office Buildings

Over the past 30 years, most major cities have grown rapidly, and their central areas have been the sites for construction of many high-rise office buildings. The distribution system in this type of building is worthy of discussion, because it represents very large loads and of-ten high available short-circuit fault currents. In most cases, the electric utility company serves these buildings at a secondary voltage of 480Y/277 volts from one or more spot net-works. There are exceptions, such as one ma-jor office building in Pittsburgh supplied at 13,800 volts primary service by the utility and feeding 67 building-owned unit substations, but they are not common. At the other ex-treme would be a typical block-square 60-story office building in New York City. The utility would have one spot network in a utility vault under the sidewalk, supplying services in the basement, and another in a specially con-structed fireproof utility vault on the 40th floor of the building, supplying additional services, to reduce the length of secondary feeder runs. Each vault might have six 2500-kVA network transformers, supplying four 4000-ampere 480Y/277-volt service takeoffs. The fault cur-rent available at each service would be nearly 200,000 amperes. Many high-rise office build-ings fall between these extremes, served by a utility network system at 480Y/277 volts, and using a secondary radial distribution system within the building. A typical single-line riser diagram for such a building is shown, along with the arrangement of a typical electrical closet on each floor.

The main and feeder circuit breakers in the switchboard must be able to interrupt the high fault currents available at their line ter-minals. The main circuit breaker and the large feeder circuit breaker supplying the ris-er busway can be of the encased type (Sys-tems Pow-R), with the required interrupting capacity. The smaller feeder circuit breakers in both normal and emergency sections can be of the current-limiting type (Current Limit-R), integrally fused breakers (Tri-Pac), or high interrupting capacity breakers (Series C). Whatever type is chosen, the design should provide that the switchboard breakers not

Typical Power Distribution and Riser Diagram for a Commercial Office Building

➀➀➀➀➀

➀➀

➀ ➀

Spare

Buildingand

MiscellaneousLoads

Include GroundFault Trip.

4000AMain CB

AutomaticTransfer Switch

Typical

Gen. CB

4000A at 480Y/277V100,000A Available Fault Current

UtilityMeteringCTs

PTs

UtilityService

HVACFeeder

BuswayRiser

ElevatorRiser

ElevatorPanel

(TypicalEvery Third

Floor)

480Y/277VPanel

208Y/120VPanel

EmergencyLighting

Riser

HVACPanel

Dry TypeTransformer

480 -208Y/120V(Typical Every Floor)

EmergencyLightingPanel

Typical

Typical

Typical

Typical

Typical

Typical

Typical

Emergencyor StandbyGenerator

CAT.71.01.T.E

Cutler-Hammer

A-52

January 1999


A

Secondary Voltages/Energy Conservation/Building Control Systems

only have adequate interrupting capacity, but also that they limit the fault current let-through to values that the devices they sup-ply can withstand. Current limiting and inte-grally fused circuit breakers have been tested by UL in series with lower-rated circuit break-ers at high fault currents, and the acceptable combinations are listed. The 2500-ampere circuit breaker supplying the busway will provide little current limitation, so the busway takeoff disconnect circuit breakers on each floor will have to be selected to with-stand high fault currents and to protect the devices they supply. Current limiting or inte-grally fused circuit breakers may be required for this duty.

Many commercial office buildings are con-structed at minimum cost, and use fusible service equipment and distribution equip-ment with current limiting fuses. The main switch and busway feeder switch could be the bolted pressure contact type, with Class L fuses. The branch switches should be able to be shunt tripped, to provide ground fault protection (Type FDP, in 400A, and larger siz-es). Busway disconnects must be fusible, to provide sufficient current limiting to protect the circuit breakers in the 480-volt panel-boards. Fusible equipment will often have lower initial cost than circuit breakers, but downtime after a fault will be higher, as fus-es must be replaced. If maintenance is not qualified, incorrect replacement fuse types or sizes may be chosen resulting in loss of selectivity, and, in some cases, reduced safety. Replacement current limiting fuses in all sizes and types used must be stocked, at substantial cost.

Other variations of the typical design shown will be determined by building size, costs, and special requirements. A busway riser might be replaced with cable risers to each floor, supplied from individual switches on a larger switchboard. However, in large instal-lations, the busway riser will provide more diversity for feeding loads, a smaller switch-board, and often a lower installed cost for equal capacity. Buildings of larger size may have two electric closets per floor, on oppo-site sides of the building, each with its own busway riser.

Energy Conservation

Because of the greatly increased cost of electri-cal power, designers must consider the efficien-cy of electrical distribution systems, and design for energy conservation. In the past, especially in commercial buildings, design was for lowest first cost, because energy was inexpensive. Today, even in the speculative office building, operating costs are so high that energy-conserving designs can justify their higher initial cost with a rapid payback and continuing savings. There are four major sources of energy conservation in a commercial building – the lighting system, the motors and controls, the transformers, and the HVAC system.

The lighting system must take advantage of the newest equipment and techniques. New light sources, familiar light sources with high-er efficiencies, solid-state ballasts with dim-ming controls, use of daylight, environmental design, efficient luminaires, computerized or programmed control, and the like, are some of the methods that can increase the efficien-cy of lighting systems. They add up to provid-ing the necessary amount of light, with the desired color rendition, from the most effi-cient sources, where and when it is needed, and not providing light where or when it is not necessary. Using the best of techniques, office spaces that originally required as much as 3.5 watts per square foot have been given improved lighting, with less glare and higher visual comfort, using as little as 1.0 to 2.0 watts per square foot. In an office building of 200,000 sq. ft., this could mean a saving of 400 kW, which, at $.05 per kWh, 250 days per year, 10 hours per day, could save $50,000 per year in energy costs. Obviously, efficient lighting is a necessity.

Motors and controls are another cause of wasted energy that can be reduced New, energy efficient motor designs are available using more and better core steel, and larger windings. For any motor operating ten or more hours per day, it is recommended to use the energy-efficient types. These motors have a premium cost of about 20% more than standard motors. Depending on loading, hours of use, and the cost of energy, the ad-ditional initial cost could be repaid in energy saved within a few months, and it rarely takes more than two years. Since, over the life of a motor, the cost of energy to operate it is many times the cost of the motor itself, any motor with many hours of use should be of the energy-efficient type. For motors operat-ing lightly loaded a high percentage of the time, energy-saving devices, such as those based on the NASA patents, can result in sub-stantial savings, especially when combined with solid-state starters. However, power fac-tor control-type devices can rarely be justified unless the motor is loaded to less than 50% of its rating much of the time.

Where a motor drives a load with variable out-put requirements such as a centrifugal pump or a large fan, customary practice has been to run the motor at constant speed, and to throt-tle the pump output or use inlet vanes or out-let dampers on the fan. This is highly inefficient and wasteful of energy. In recent years, solid-state variable-frequency, vari-able-speed drives for ordinary induction mo-tors have been available, reliable, and relatively inexpensive. Using a variable-speed drive, the throttling valves or inlet vanes or output dampers can be eliminated, saving their initial cost, and energy will be saved over the life of the system. An additional ben-efit of both energy-efficient motors and vari-able-speed drives (when operated at less than full speed) is that the motors operate at reduced temperatures, resulting in increased motor life.

Transformers have inherent losses. Trans-formers, like motors, are designed for lower losses by using more and better core materi-als, larger conductors, etc., and this results in increased initial cost. Since the 480-volt to 208Y/120-volt stepdown transformers in an office building are usually energized 24 hours a day, savings from lower losses can be substantial, and should be considered in all transformer specifications. One method of obtaining reduced losses is to specify trans-formers with 220

°

C insulation systems designed for 150

°

C average winding temper-ature rise, with no more than 80

°

C (or some-times 115

°

C) average winding temperature rise at full load. A better method would be to evaluate transformer losses, based on actual loading cycles throughout the day, and con-sider the cost of losses as well as the initial cost of the transformers in purchasing.

HVAC systems have traditionally been very wasteful of energy, often being designed for lowest first cost. This, too, is changing. For example, reheat systems are being replacedby variable air volume systems, resulting in equal comfort with substantial increases in efficiency. While the electrical engineer has little influence on the design of the HVAC sys-tem, he can specify that all motors with con-tinuous or long duty cycles are specified as energy efficient types, and that the variable-air-volume fans do not use inlet vanes or out-let dampers, but are driven by variable-speed drives. Variable-speed drives can often be desirable on centrifugal compressor units as well. Since some of these requirements will be in HVAC specifications, it is important for the energy-conscious electrical engineer to work closely with the HVAC engineer at the design stage.

Building Control Systems

In order to obtain the maximum benefit from these energy-saving lighting, power, and HVAC systems, they must be controlled to perform their functions most efficiently. Con-stant monitoring would be required for man-ual operation, so some form of automatic control is required. The simplest of these en-ergy-saving controls, often very effective, is a time clock to turn various systems on and off. Where flexible control is required, program-mable controllers may be used. These range from simple devices, similar to multifunction time clocks, up to full microprocessor-based, fully programmable devices, really small computers. For complete control of all build-ing systems, computers with specialized soft-ware can be used. Computers can not only control lighting and HVAC systems, and pro-vide peak demand control, to minimize the cost of energy, but they can perform many other functions. Fire detection and alarm sys-tems can operate through the computer, which can also perform auxiliary functions such as elevator control and building commu-nication in case of fire. Building security sys-tems, such as closed-circuit television monitoring, door alarms, intruder sensing,

January 1999

Cutler-Hammer


CAT.71.01.T.E

A

can be performed by the same building com-puter system.

The time clocks, programmable controllers, and computers can obtain data from exter-nal sensors and control the lighting, motors, and other equipment by means of hard wir-ing-separate wires to and from each piece of equipment. In the more complex systems, this would result in a tremendous number of control wires, so other methods are fre-quently used. A single pair of wires, with electronic digital multiplexing, can control or obtain data from many different points. Sometimes, coaxial cable is used with ad-vanced signaling equipment. Some systems dispense with control wiring completely, sending and receiving digital signals over the power wiring. The newest systems may use fiber-optic cables to carry tremendous quantities of data, free from electromagnetic interference. The method used will depend on the type, number, and complexity of func-tions to be performed.

Because building design and control for max-imum energy saving is important and com-plex, and frequently involves many functions and several systems, it is necessary for the design engineer to make a thorough building and environmental study, and to weigh the costs and advantages of many systems. The result of good design can be economical, effi-cient operation. Poor design can be wasteful, and extremely costly.

Cogeneration

Cogeneration is another outgrowth of the high cost of energy. Cogeneration is the pro-duction of electric power concurrently with the production of steam, hot water, and simi-lar energy uses. The electric power can be the main product, and steam or hot water the by-product, as in most commercial installations, or the steam or hot water can be the most required product, and electric power a by-product, as in many industrial installations. In some industries, cogeneration has been common practice for many years, but until recently it has not been economically feasible for most commercial installations. This has been changed by the high cost of purchased energy, plus a federal law (Public Utility Reg-ulatory Policies Act, known as PURPA) that requires public utilities to purchase any ex-cess power generated by the cogeneration plant. In many cases, practical commercial cogeneration systems have been built that provide some or all of the electric power required, plus hot water, steam, and some-times steam absorption-type air conditioning. Such cogeneration systems are now operat-ing successfully in hospitals, shopping cen-ters, high-rise apartment buildings and even commercial office buildings.

Where a cogeneration system is being con-sidered, the electrical distribution system be-comes more complex. The interface with the

Building Control Systems/Cogeneration/Emergency Power

utility company is critical, requiring careful relaying to protect both the utility and the cogeneration system. Many utilities have stringent requirements that must be incorpo-rated into the system. Proper generator con-trol and protection is necessary, as well. An on-site electrical generating plant tied to an electrical utility, is a sophisticated engineer-ing design.

Utilities require that when the protective device at their substation opens that the device connecting a cogenerator to the utility open also.

One reason is that most cogenerators are connected to feeders serving other custom-ers. Utilities desire to reclose the feeder after a transient fault is cleared. Reclosing in most cases will damage the cogenerator if it had remained connected to their system.

Islanding is another reason why the utility in-sists on the disconnection of the cogenerator. Islanding is the event that after a fault in the utility’s system is cleared by the operation of the protective devices, a part of the system may continue to be supplied by cogeneration. Such a condition is dangerous to the utility’s operation during restoration work.

Major cogenerators are connected to the sub-transmission or the transmission system of a utility. Major cogenerators have buy-sell agreements. In such cases utilities use a trip transfer scheme to trip the cogenerator breaker.

Guidelines that are given in ANSI Guide Stan-dard 1001 are a good starting point, but the entire design should be coordinated with the utility.

Emergency Power

Most areas have requirements for emergency and standby power systems. The National Electrical Code does not specifically call for any emergency or standby power, but does have requirements for those systems when they are legally mandated and classed as emergency (Article 700) or standby (Article 701) by munic-ipal, state, federal, or other codes, or by any governmental agency having jurisdiction. Optional standby systems, not legally required, are also covered in the NEC (Article 702).

Emergency systems are intended to supply power and illumination essential for safety to human life, when the normal supply fails. NEC requirements are stringent, requiring periodic testing under load and automatic transfer to emergency power supply on loss of normal supply. All wiring from emergency source to emergency loads must be kept sep-arate from all other wiring and equipment, in its own distribution and raceway system, ex-cept in transfer equipment enclosures and similar locations. The most common power source for large emergency loads is an

engine-generator set, but the NEC also per-mits the emergency supply (subject to local code requirements) to be storage batteries, uninterruptible power supplies, a separate emergency service, or a connection to the service ahead of the normal service discon-necting means. Unit equipment for emergen-cy illumination, with a rechargeable battery, a charger to keep it at full capacity when nor-mal power is on, one or more lamps, and a re-lay to connect the battery to the lamps on loss of normal power, is also permitted. Because of the critical nature of emergency power, ground fault protection is not required. It is considered preferable to risk arcing damage, rather than to disconnect the emergency sup-ply completely. On 480Y/277-volt emergency systems with protective devices rated 1000 am-peres or more, a ground fault alarm is required if ground fault protection is not provided.

Legally required standby systems, as required by the governmental agency having jurisdic-tion, are intended to supply power to selected loads, other than those classed as emergency systems, on loss of normal power. These are usually loads not essential to human safety, but loss of which could create hazards or ham-per rescue or fire-fighting operations. NEC re-quirements are similar to those for emergency systems, except that wiring may occupy the same distribution and raceway system as the normal wiring if desired. Optional standby systems are those not legally required, and are intended to protect private business or proper-ty where life safety does not depend on perfor-mance of the system. Optional systems can be treated as part of the normal building wiring system. Both legally required and optional standby systems should be installed in such a manner that they will be fully available on loss of normal power. It is preferable to isolate these systems as much as possible, even though not required by code.

Where the emergency or standby source, such as an engine generator or separate service, has capacity to supply the entire system, the transfer scheme can be either a full-capacity automatic transfer switch, or, less costly but equally effective, normal and emergency main circuit breakers, electrically interlocked such that on failure of the normal supply the emer-gency supply is connected to the load. Howev-er, if the emergency or standby source does not have capacity for the full load, as is usually the case, such a scheme would require auto-matic disconnection of the nonessential loads before transfer. Simpler and more economical in such a case is a separate emergency bus, supplied through an automatic transfer switch, to feed all critical loads. The transfer switch connects this bus to the normal supply, in normal operation. On failure of the normal supply, the engine-generator is started, and when it is up to speed the automatic switch transfers the emergency loads to this source. On return of the normal source, manual or au-tomatic retransfer of the emergency loads can take place.

CAT.71.01.T.E

Cutler-Hammer

A-54

January 1999


A

Peak Shaving

Many installations now have emergency or standby generators. In the past, they were re-quired for hospitals and similar locations, but not common in office buildings or shopping centers. However, many costly and unfortu-nate experiences during utility blackouts in recent years have led to the more frequent in-stallation of engine generators in commercial and institutional systems for safety and for supplying important loads. Industrial plants, especially in process industries, usually have some form of alternate power source to pre-vent extremely costly shutdowns. These standby generating systems are critical when needed, but they are needed only infrequent-ly. They represent a large capital investment. To be sure that their power will be available when required, they should be tested period-ically under load.

The cost of electric energy has risen to new high levels in recent years, and utilities bill on the basis not only of power consumed, but also on the basis of peak demand over a small interval. As a result, a new use for in-house generating capacity has developed. Utilities

measure demand charges on the basis of the maximum demand for electricity in any given specific period (typically 15 or 30 minutes) during the month. Some utilities have a demand “ratchet clause” that will continue demand charges on a given peak demand for a full year, unless a higher peak results in even higher charges. One large load, coming on at a peak time, can create higher electric demand charges for a year.

Obviously, reducing the peak demand can re-sult in considerable savings in the cost of electrical energy. For those installations with engine generators for emergency use, mod-ern control systems (computers or program-mable controllers) can monitor the peak demand, and start the engine-generator to supply part of the demand as it approaches a preset peak value. The engine-generator must be selected to withstand the required duty cy-cle. The simplest of these schemes transfer specific loads to the generator. More complex schemes operate the generator in parallel with the normal utility supply. The savings in demand charges can reduce the cost of own-ing the emergency generator equipment. In some instances, utilities with little reserve

capacity have helped finance the cost of some larger customer-owned generating equip-ment. In return, the customer agrees to take some or all of his load off the utility system and on to his own generator at the request of the utility (with varying limitations) when the utility load approaches capacity. In some cas-es, the customer’s generator is paralleled with the utility to help supply the peak utility loads, with the utility buying the supplied power. Some utilities have been able to delay large capital expenditures for additional gen-erating capacity by such arrangements.

It is important that the electrical system designer providing a substantial source of emergency and standby power investigate the possibility of using it for peak shaving, and even of partial utility company financing. Frequently, substantial savings in power costs can be realized for a small additional outlay in distribution and control equipment.

Peak shaving equipment operating in parallel with the utility are subject to the comments made under cogeneration as to separation from the utility under fault conditions.

Peak Shaving

January 1999

Cutler-Hammer


CAT.71.01.T.E

A

Computer Power

Computers require a source of steady, constant-voltage, constant-frequency power, with no transients superimposed. Such “clean” power is not consistently available from utility sources, and utility power is fur-ther degraded by disturbances from the build-ing power distribution system. Power that is entirely satisfactory for motors, Iighting, heat-ing, and other familiar uses in commercial or industrial buildings, can in computers cause loss of data, output errors, incorrect computa-tions, and even sudden computer shutdowns, or “crashes.” These computer problems can be extremely costly, and correction can be very time consuming. For these reasons, raw incoming power is seldom used for critical computer installations. Power to the comput-ers is conditioned to make it more satisfactory. The type and degree of conditioning depends on the types of power disturbances present, the sensitivity of the computer installation, the cost of computer errors and interruptions, and the cost of power improvement equipment.

There are several categories of power distur-bances. One of the most common is the

tran-sient

, a sudden, rapid rise (or dip) in voltage, either singly or as a damped oscillation, A single spike can be as brief as a few micro-seconds; oscillatory transients may have a frequency of several hundred to several thousand kilohertz, lasting up to a full cycle. Transients can reach a peak several times the system voltage. Also very common are

undervoltages

, where the system voltage sags 10% or more for a period as short as one or several cycles to as long as several hours or more. Much less common are

overvoltages

of 10% or more.

Frequency deviations

from 60 Hz are rarely a problem from the power company; they may be a problem from on-site power generation. Least frequent, but most serious when they occur, are complete

power outages

, or blackouts.

The technology to improve raw power falls into two broad categories, power enhancement and power synthesis.

Power enhancement

takes the incoming power, modifies and improves it by clipping spike peaks, filtering transients and harmonics, regulating the voltage, isolating power line “noise,” and the like. Then the im-proved power is delivered to the computer.

Power synthesis

uses the incoming power only as a source of energy, from which it creates a new, completely isolated power output wave-form to supply to the computer. This generated or synthesized output power is designed to meet computer requirements, regardless of the disturbances on the input power.

Power enhancement can be provided by tran-sient (spike) suppressors, harmonic filters, voltage regulators, isolating transformers (best with a Faraday shield), or a combination of some or all of these. Power synthesis can be provided by a wide variety of rotating motor-generator (MG) sets, static semiconductor

rectifier-inverters, or ferro-magnetic synthesiz-ers. Both MG sets and rectifier-inverters can be connected to a battery, which “floats” when normal power is available, and supplies power to the generator or inverted, with no interrup-tion apparent to the computers, on loss of nor-mal power. This comprises the so-called uninterruptible power supply (UPS), which, on loss of normal power, continues power to the computer while the batteries last. Typical bat-tery time ranges from 5 minutes to 1 hour, with 15 to 30 minutes most common. Battery sup-plies are costly, so for most critical operations the UPS is further supplied by a standby gen-erator, which comes on line before the battery supply runs down and keeps the computers operating as long as necessary.

In general, power enhancement is less costly than power synthesis, but provides less isola-tion and protection for the computers. If power must be of the highest quality, and must continue without interruption even if the normal power source fails, only some form of static or rotary UPS can be used. Critical com-puters, such as used by banks, communica-tions systems, reservation systems, and the like, where outages cannot be tolerated, are usually supplied from a UPS system, which is the most costly class of power conditioner.

The computer power center is an increasingly popular method of supplying power to comput-ers. It combines power enhancement, power distribution, and equipotential computer grounding in one unit, which can be located right in or adjacent to the computer room. The power center consists of a shielded isolating transformer, often with 480-volt input and 208Y/120-volt output as required by the computers. This supplies a distribution panelboard with circuits feeding flexible computer connection cables under the raised computer-room floor. The computer units plug into these cables. A transient suppressor is often included, and a constant-voltage transformer or voltage regula-tor may be used to eliminate voltage variations. In addition to the improvement in the quality of power, the computer power center has some financial advantages. Since it is an equipment unit, not part of the permanently installed pre-mises wiring system, it can be depreciated rap-idly (in 5 to 8 years). It can be moved to a new location like other computer equipment, mak-ing the frequent rearrangement or relocation of computer rooms easier and less costly. UPS systems are sometimes used to supply com-puter power centers, for maximum flexibility.

Computer Grounding

Because computers are so sensitive to electri-cal “noise” input, computer grounding is ex-tremely important. Some computer suppliers, familiar with the electronic needs of their equipment but not with power systems, have recommended computer grounding schemes that separate the computer grounding system from the power grounding system.

This is unsafe, a violation of the National Electrical Code, and absolutely unnecessary.

In fact, it

may introduce electrical noise into the com-puters, rather than keep it out. It is possible to ground computer systems with maximum safety, meeting all NEC requirements, and minimizing noise input to the computers through the grounding systems. Each sepa-rate unit of computer equipment must be grounded (usually by the equipment ground-ing conductor in the power cable), back to a common equipotential ground point at the power source to the computers. The ground bus in a computer power center is excellent for this purpose. The computer units should be individually grounded to this point with radial connections, and not interconnected with many grounds that form ground loops.

At the power source, the building service or the separately derived system (the computer power center or MG set or UPS), the grounded conductor (neutral) is connected to the grounding electrode. The ground bus should be connected to the neutral at that point, and only there, for equipotential grounding. If any other grounding electrodes are present on the premises, such as for a lightning protection system, telephone or other communications systems, cable TV, and the like, they must all be bonded to the power system grounding electrodes to make one grounding electrode system. Separate computer grounding elec-trodes, buried counterpoises, and similar schemes, may do more harm than good; if they are present, they must also be bonded to the power system grounding electrode.

This will provide 60 Hz grounding for safety. However, most noise is of much higher fre-quencies, up to about 30 MHz. Ordinary conduc-tors have a high impedance at noise frequencies. To provide effective noise ground-ing, an additional high-frequency grounding system must supplement the 60 Hz system. This requires conductors in a grid or mesh with sides of each square no more than two feet long. This signal reference grid can best be formed by the raised floor stringers, if they are bolted to the pedestals to form good electrical connections. It can also be made of thin copper foil, with con-nections brazed or welded at the intersections, placed under the raised floor. The individual computer unit cabinets should be connected to this high-frequency grid by the shortest possi-ble leads, and the grid itself bonded to the ground bus by a single short connection.

Where “isolated ground” plug-in receptacles are used, they provide a separate grounding connection for plug-and-cord-connected com-puter equipment. The isolated grounds for these receptacles should be run with the sup-ply conductors, back to the source, and there connected to the common ground bus.

Standard equipment grounding for exposed metal must also be provided. This will produce the radial equipotential grounding system that results in minimum ground-system noise to the computers, with no sacrifice in safety.

Computer Power

CAT.71.01.T.E

Cutler-Hammer

A-56

January 1999


A

Sound Levels

Sound Levels of ElectricalEquipment for Offices, Hospitals,Schools and Similar Buildings

Insurance underwriters and building owners desire and require that the electrical appara-tus be installed for maximum safety and the least interference with the normal use of the property. Architects should take particular care with the designs for hospitals, schools and similar buildings to keep the sound per-ception of such equipment as motors, blow-ers and transformers to a minimum.

Even though transformers are relatively quiet, resonant conditions may exist near the equip-ment which will amplify their normal 120 Hertz hum. Therefore, it is important that con-sideration be given to the reduction of ampli-tude and to the absorption of energy at this frequency. This problem begins in the design-ing stages of the equipment and the building. There are two points worthy of consideration: 1) What sound levels are desired in the nor-mally occupied rooms of this building? 2) To effect this, what sound level in the equipment room and what type of associated acoustical treatment will give the most economical in-stallation overall?

A relatively high sound level in the equipment room does not indicate an abnormal condi-tion within the apparatus. However, absorp-tion may be necessary if sound originating in an unoccupied equipment room is objection-able outside the room. Furthermore, added absorption material usually is desirable if there is a “build-up” of sound due to reflections.

Some reduction or attenuation takes place through building walls, the remainder may be reflected in various directions, resulting in a build-up or apparent higher levels, especially if resonance occurs because of room dimen-sions or material characteristics.

Area Consideration

In determining permissible sound levels with-in a building, it is necessary to consider how the rooms are to be used and what levels may be objectionable to occupants of the building. The ambient sound level values given in Table A22 are representative average values and may be used as a guide in determining suitable building levels.

Decrease in sound level varies at an approxi-mate rate of 6 decibels for each doubling of the distance from the source of sound to the listener. For example, if the level six feet from a transformer is 50 db, the level at a distance of twelve feet would be 44 db and at 24 feet the level decreases to 38 db, etc. However, this rule applies only to equipment in large areas equivalent to an out-of-door installa-tion, with no nearby reflecting surfaces.

Transformer Sound Levels

Transformers emit a continuous 120 Hertz hum with harmonics when connected to 60 Hertz circuits. The fundamental frequency is the “hum” which annoys people primarily because of its continuous nature. For purposes of reference, sound measuring instruments convert the different frequencies to 1000 Hertz and a 40 db level. Transformer sound levels based on NEMA publication TR-1 are listed in Table A23.

Table A22: Typical Sound Levels

Radio, Recording and TV StudiosTheatres and Music RoomsHospitals, Auditoriums and ChurchesClassrooms and Lecture RoomsApartments and HotelsPrivate Offices and Conference RoomsStoresResidence (Radio, TV Off) and Small

OfficesMedium Office (3 to 10 Desks)Residence (Radio, TV On)Large Store (5 or More Clerks)Factory OfficeLarge OfficeAverage FactoryAverage Street

25-30 db30-3535-4035-4035-4540-4545-55

5358606161647080

Table A23: Maximum Average Sound Levels - Decibels

kVA Liquid-FilledTransformers

Dry-Type Transformers

Self-CooledRating(OA)

Forced-AirCooledRating(FA)

Self-CooledRating(AA)

Forced-AirCooledRating(FA)

300 500 750100015002000250030003750500060007500

10000

55565858606162636465666768

. .676767676767676767686970

586064646566686870717273. .

67676767686971717373747576

Since values given in Table A23 are in general higher than those given in Table A22, the dif-ference must be attenuated by distance and by proper use of materials in the design of the building. An observer may believe that a transformer is noisy because the level in the room where it is located is high. Two trans-formers of the same sound output in the same room increase the sound level in the room approximately 3 db, and 3 transformers by about 5 db, etc.

Sounds due to structure-transmitted vibra-tions originating from the transformer are lowered by mounting the transformers on vibration dampeners or isolators. There are a number of different sound vibration isolating materials which may be used with good results. Dry-type power transformers are often built with an isolator mounted between the trans-former support and case members. The natural period of the core and coil structure when mounted on vibration dampeners is about 10% of the fundamental frequency. The reduction in the transmitted vibration is approximately 98%. If the floor or beams beneath the transformer are light and flexible, the isolator must be softer or have improved characteristics in order to keep the transmitted vibrations to a minimum. (Enclosure covers and ventilating louvers are often improperly tightened or gasketed and produce unneces-sary noise.) The building structure will assist the dampeners if the transformer is mounted above heavy floor members or if mounted on a heavy floor slab. Positioning of the trans-former in relation to walls and other reflecting surfaces has a great effect on reflected noise and resonances. Often, placing the trans-former at an angle to the wall, rather than parallel to it, will reduce noise. Electrical con-nections to a substation transformer should be made with flexible braid or conductors; connections to an individually-mounted transformer should be in flexible conduit.

Sound Levels

January 1999

Cutler-Hammer


CAT.71.01.T.E

A

Codes and Standards

The National Electrical Code (NEC), NFPA Standard No. 70, is the most prevalent electri-cal code in the United States. The NEC, which is revised every three years, has no legal standing of its own, until it is adopted as law by a jurisdiction, which may be a city, county, or state. Most jurisdictions adopt the NEC in its entirety; some adopt it with variations, usually more rigid, to suit local conditions and requirements. A few large cities, such as New York and Chicago, have their own elec-trical codes, basically similar to the NEC. The designer must determine which code applies in the area of a specific project.

The Occupational Safety and Health Act (OSHA) of 1970 sets uniform national require-ments for safety in the workplace — any-where that people are employed. Originally OSHA adopted the 1971 NEC as rules for elec-trical safety. As the NEC was amended every three years, the involved process for modify-ing a federal law such as OSHA made it im-possible for the act to adopt each new code revision. To avoid this problem, the OSHA ad-ministration in 1981 adopted its own code, a condensed version of the NEC containing only those provisions considered related to occupational safety. OSHA was amended to adopt this code, based on NFPA Standard 70E, Part 1, which is now federal law.

The NEC, Article 90, Introduction, reads: 90-1. (a) The purpose of this Code is the practical safeguarding of persons and property from hazards arising from the use of electricity.(b)This Code contains provisions considered necessary to safety. Compliance therewith and proper maintenance will result in an installation essentially free from hazard, but not necessarily efficient, convenient, or adequate for good service or expansion of electrical use.(c) This Code is not intended as a design specification nor an instruction manual for untrained persons.

The NEC is a minimum safety standard. Effi-cient and adequate design usually requires not just meeting, but often exceeding NEC requirements to provide an effective, reliable, economical electrical system.

Many equipment standards have been estab-lished by the National Electrical Manufacturers Association (NEMA) and the American Nation-al Standards Institute (ANSI). Underwriters Laboratory (UL) has standards that equipment must meet before UL will list or label it. Most jurisdictions and OSHA require that where equipment listed as safe by a recognized labo-ratory is available, unlisted equipment may not be used. UL is by far the most widely ac-cepted national laboratory, although Factory Mutual Insurance Company lists some equip-ment, and a number of other testing laborato-ries have been recognized and accepted. The Institute of Electrical and Electronic Engineers (IEEE) publishes a number of books (the “color book” series) on recommended practices for the design of industrial buildings, commercial

buildings, emergency power systems, grounding, and the like. Most of these IEEE standards have been adopted as ANSI stan-dards. They are excellent guides, although they are not in any way mandatory.

A design engineer should conform to all applicable codes, and require equipment to be listed by UL or another recognized testing laboratory wherever possible, and to meet ANSI or NEMA standards. ANSI/IEEE recom-mended practices should be followed to a great extent. In many cases, standards should be exceeded to get a system of the quality required. The design goal should be a safe, efficient, long-lasting, flexible, and economi-cal electrical distribution system.

Excerpts From ANSI/IEEE C37.100Definitions for Power SwitchgearAvailable (Prospective) Short-Circuit Current

The maximum current that the power system can deliver through a given circuit point to any negligible impedance short circuit applied at the given point.

Basic Impulse Insulation Level (BIL)

A reference impulse insulation strength expressed in terms of the crest value of the withstand voltage of a standard full impulse voltage wave.

Direct-Current Component (of a Total Current)

That portion of the total current which consti-tutes the asymmetry.

Enclosed Switchboard

A dead-front switchboard that has an overall sheet metal enclosure (not grille) covering back and ends of the entire assembly. (

Note:

Access to the enclosure is usually provided by doors or removable covers. The tops may or may not be covered.)

Ground Bus

A bus to which the grounds from individual pieces of equipment are connected and that, in turn, is connected to ground at one or more points.

Ground Protection

A method of protection in which faults to ground within the protected equipment are detected.

Ground Relay

A relay that by its design or application is intended to respond primarily to system ground faults.

Interrupting (Breaking) Current

The current in a pole of a switching device at the instant of initiation of the arc.

Load-Interrupter Switch

An interrupter switch designed to interrupt currents not in excess of the continuous-current rating of the switch. (

Note:

It may be designed to close and carry abnormal or short-circuit currents as specified).

Metal-Enclosed Low-Voltage Power Circuit Breaker Switchgear

Metal-enclosed power switchgear including the following equipment as required: (1) low-

voltage power circuit breaker (fused or un-fused), (2) bare bus and connections, (3) in-strument and control power transformers, (4) instruments, meters, and relays, and (5) con-trol wiring and accessory devices. The low-voltage power circuit breakers are contained in individual grounded metal compartments and controlled remotely or from the front of the panels. The circuit breakers may be sta-tionary or removable. When removable, me-chanical interlocks are provided to ensure a proper, safe operating sequence.

Molded-Case Circuit Breaker

One that is assembled as an integral unit in a supporting and enclosing housing of molded insulating material.

Stored-Energy Operation

Operation by means of energy stored in the mechanism itself prior to the completion of the operation and sufficient to complete it un-der predetermined conditions.

Switchboard

A type of switchgear assembly that consists of one or more panels with electric devices mounted thereon, and associated framework.

Switchgear

A general term covering switching and inter-rupting devices and their combination with as-sociated control, metering, protective and regulating devices. Also assemblies of these devices with associated interconnections, accessories, enclosures and supporting struc-tures, used primarily in connection with the generation, transmission, distribution and conversion of electric power.

Zone of Protection

The part of an installation guarded by a certain protection.

Professional Organizations

American National Standards Institute1430 BroadwayNew York, New York 10018212-642-4900

Institute of Electrical and Electronics Engineers445 Hoes LaneP.O. Box 1331Piscataway, NJ 08855-9970201-562-5522

International Association of Electrical Inspectors930 Busse HighwayPark Ridge, IL 60068-2398708-696-1455

National Electrical Manufacturers Association2101 L Street, N.W.Washington, DC 20037-1526202-457-8474

National Fire Protection Association1 Battery March DriveP.O. Box 9101Quincy, MA 02269-99591-800-344-3555

Underwriters Laboratories, Inc.333 Pfingsten RoadNorthbrook, IL 60062

Codes and Standards

CAT.71.01.T.E

Cutler-Hammer

A-58

January 1999


A

Table A24: 60 Hz, Induction Motors

Hp FullLoadAmps(NEC)FLA

MinimumWire Size75

°

C CopperAmpacity@125% FLA

MinimumConduitSize, In’s.

Fuse SizeNEC 430-152Max. Amps

➁

Recommended Cutler-Hammer

Circuit

➂

BreakerMotor CircuitProtectorType GMCP/HMCPTHW THWN

XHHNTimeDelay

Non-TimeDelaySize Amps Amps Type Amps Adj. Range

230 Volts, 3-Phase

11

1

⁄

2

2357

1

⁄

2

101520253040506075

100125150200

3.65.26.89.6

15.2222842546880

104130154192248312360480

121212121210

864431

2/03/0250350

(2)3/0(2)4/0

(2)350

20202020203050658585

100130175200255310400460620

1

⁄

21

⁄

21

⁄

21

⁄

21

⁄

21

⁄

23

⁄

4

1111

1

⁄

4

1

1

⁄

4

1

1

⁄

2

22

1

⁄

2

2

1

⁄

2

(2)2(2)2(2)2

1

⁄

2

1

⁄

21

⁄

21

⁄

21

⁄

21

⁄

21

⁄

21

⁄

23

⁄

4

1111

1

⁄

4

1

1

⁄

2

1

1

⁄

2

22

1

⁄

2

(2)1

1

⁄

2

(2)2(2)2

1

⁄

2

1010152030405080

100125150200250300350450600700

1000

15202530507090

150175225250350400500600800

100012001600

1515152030506090

100125150150200225300400500600700

EDEDEDEDEDEDEDEDEDEDEDEDEDEDKDKDLDLDMD

77

151530305070

100100150150150250400600600

——

21-7021-7045-15045-15090-30090-300

150-500210-700300-1000300-1000450-1500450-1500750-2500

1250-25002000-40001800-60001800-6000

——

460 Volts, 3-Phase

11

1

⁄

2

2357

1

⁄

2

101520253040506075

100125150200

1.82.63.44.87.6

11142127344052657796

124156180240

1212121212121210

8886431

2/03/04/0

350

20202020202020305050506585

100130175200230310

1

⁄

21

⁄

21

⁄

21

⁄

21

⁄

21

⁄

21

⁄

21

⁄

23

⁄

43

⁄

43

⁄

4

111

1

⁄

4

1

1

⁄

4

1

1

⁄

2

222

1

⁄

2

1

⁄

21

⁄

21

⁄

21

⁄

21

⁄

21

⁄

21

⁄

21

⁄

21

⁄

21

⁄

21

⁄

23

⁄

4

111

1

⁄

4

1

1

⁄

2

1

1

⁄

2

22

1

⁄

2

666

1015202540506070

100125150175225300350450

61015152535457090

110125175200250300400500600800

1515151515253545507070

100110125150175225250350

EHDEHDEHDEHDEHDEHDEHDEHDEHDEHDEHDEHDFDBFDBJDJDJDJDKD

3777

15153030505070

100100150150150250250400

9-3021-7021-7021-7045-15045-15090-30090-300

150-500150-500210-700300-1000300-1000450-1500450-1500750-2500

1250-25001250-25002000-4000

575 Volts, 3-Phase

11

1

⁄

2

2357

1

⁄

2

101520253040506075

100125150200

1.42.12.73.96.19

11172227324152627799

125144192

121212121212121210

8866431

2/03/0

250

2020202020202020305050656585

100130175200255

1

⁄

21

⁄

21

⁄

21

⁄

21

⁄

21

⁄

21

⁄

21

⁄

21

⁄

21

⁄

23

⁄

4

1111

1

⁄

4

1

1

⁄

4

1

1

⁄

2

22

1

⁄

2

1

⁄

21

⁄

21

⁄

21

⁄

21

⁄

21

⁄

21

⁄

21

⁄

21

⁄

21

⁄

21

⁄

23

⁄

43

⁄

4

111

1

⁄

4

1

1

⁄

2

1

1

⁄

2

2

366

101520203040506080

100110150175225300350

6101015203035607090

100125175200250300400450600

151515151520254050606080

100125150175200225300

HFDHFDHFDHFDHFDHFDHFDHFDHFDHFDHFDHFDHFDHFDHFDHJDHJDHJDHKD

3377

1515153050505070

100100150150250250400

9-309-30

21-7021-7045-15045-15045-15090-300

150-500150-500150-500210-700300-1000300-1000450-1500450-1500875-1750

1250-25002000-4000

115 Volts, Single-Phase

3

⁄

4

11

1

⁄

2

2357

1

⁄

2

13.8162024345680

12121010

843

202030305085

100

1

⁄

21

⁄

21

⁄

21

⁄

23

⁄

4

11

1

⁄

21

⁄

21

⁄

21

⁄

21

⁄

23

⁄

4

1

2530354560

100150

45506080

110175250

3035405070

100150

EDEDEDEDEDEDED

Two-PoleDeviceNotAvailable

230 Volts, Single-Phase

3

⁄

4

11

1

⁄

2

2357

1

⁄

2

6.9 8 10 12 17 28 40

1212121210

88

20202020305050

1

⁄

21

⁄

21

⁄

21

⁄

21

⁄

21

⁄

23

⁄

4

1

⁄

21

⁄

21

⁄

21

⁄

21

⁄

21

⁄

21

⁄

2

15152025305070

252530406090

125

15202530406080

EDEDEDEDEDEDED

Two-PoleDeviceNotAvailable

Motor Protection

➀

In line with NEC 430-6(a), circuit breaker, HMCP and fuse rating selections are based on full load currents for induction motors running at speeds normal for belted motors and motors with normal torque characteristics using data shown taken from NEC tables 430-148 (single-phase) and 430-150 (3-phase). Actual motor nameplate ratings shall be used for selecting motor running overload protection. Motors built special for low speeds, high torque characteristics, special starting conditions and applications will require other considerations as defined in the application section of the NEC.

Circuit breaker, HMCP and fuse ampere rating selections are in line with maximum rules given in NEC 430-52 and table 430-152. Based on known characteristics of Cutler-Hammer type breakers, specific units are recommended. The current rat-ings are no more than the maximum limits set by the NEC rules for motors with code letters F to V or without code letters. Motors with lower code letters will require further considerations.

In general, these selections were based on:

1. Ambient – Outside enclosure not more than 40

°

C (104

°

F).

2. Motor starting – Infrequent starting, stop-ping or reversing.

3. Motor accelerating time – 10 seconds or less.

4. Locked rotor – Maximum 6 times motor FLA.

5. Type HMCP motor circuit protector may not be set at more than 1300% of the motor full-load current, to comply with the NEC, Sec. 430-52. (Except for new E rated motor which can be set up to 1700%.)

Circuit breaker selections are based on types with standard interrupting ratings. Higher inter-rupting rating types may be required to satisfy specific system application requirements.

Cutler-Hammer type circuit breakers rated less than 125 amperes are marked for application with 60/75

°

C wire. Wire size selections shown are minimum sizes based on the use of 75

°

C copper wire per NEC table 310-16.

Conduit sizes shown are minimum sizes for the type conductors (75

°

C) indicated and are based on the use of three conductors for three-phase motors and two conductors for single-phase motors. Conduits with internal equipment grounding conductors or conductors with differ-ent insulation will require further considerations.

For motor full load currents of 208 and 200 volts, increase the corresponding 230-volt motor values by 10 and 15 percent respectively. Wire and conduit sizes as well as equipment ratings will vary accordingly.

➀

These recommendations are based on previous code interpretations. See the current NEC for exact up-to-date information.

➁

Consult fuse manufacturer’s catalog for smaller fuse ratings.

➂

Types are for minimum interrupting capacity breakers. Ensure that the fault duty does not exceed breakers I.C.

Reference Data – Motor Protection

January 1999


CAT.71.01.T.E

ATable A25: Secondary Short Circuit Capacity of Typical Power Transformers

Trans-Former Rating 3-Phase kVA and Imped-ance Percent

Maximum Short Circuit kVA Available From Primary System

208 Volts, 3-Phase 240 Volts, 3-Phase 480 Volts, 3-Phase 600 Volts, 3-Phase

Rated Load Contin-uous Current, Amps

Short-Circuit CurrentRMS Symmetrical Amps







Trans-former Alone ➀

50% Motor Load ➁

Com-bined


100% Motor Load ➁

Com-bined


100% Motor Load ➁

Com-bined


100% Motor Load ➁

Com-bined

3005%

50000100000150000250000500000Unlimited

834 149001570016000163001650016700

1700 166001740017700180001820018400

722 129001360013900141001430014400

2900 158001650016800170001720017300

361 640068006900700071007200

1400 780082008300840085008600

289 520055005600560057005800

1200 640067006800680069007000

5005%

50000100000150000250000500000Unlimited

1388 213002520026000267002720027800

2800 259002800028800295003000030600

1203 200002190022500231002360024100

4800 248002670027300279002840028900

601 100001090011300116001180012000

2400 124001330013700140001420014400

481 800087009000930094009600

1900 99001060010900112001130011500

7505.75%

50000100000150000250000500000Unlimited

2080 287003200033300344003520036200

4200 329003620037500386003940040400

1804 249002780028900298003060031400

7200 321003500036100370003780038600

902 124001390014400149001530015700

3600 160001750018000185001890019300

722 100001110011600119001220012600

2900 129001400014500148001510015500

10005.75%

50000100000150000250000500000Unlimited

2776 359004120043300452004670048300

5600 415004680048900508005230053900

2406 310003560037500391004040041800

9600 406004520047100487005000051400

1203 155001780018700196002020020900

4800 203002260023500244002500025700

962 124001430015000156001620016700

3900 163001820018900195002010020600

15005.75%

50000100000150000250000500000Unlimited

4164 476005750061800656006880072500

8300 559006580070100739007710080800

3609 412004980053500568005960062800

14400 556006420057900712007400077200

1804 206002490026700284002980031400

7200 278003210033900356003700038600

1444 165002000021400227002390025100

5800 223002580027200285002970030900

20005.75%

50000100000150000250000500000Unlimited

2406 247003100034000367003910041800

9600 343004060043600463004870051400

1924 197002480027200294003130033500

7800 275003260035000372003910041300

25005.75%

50000100000150000250000500000Unlimited

3008 280003650040500446004810052300

12000 400004850052500566006010064300

2405 224002920032400356003850041800

9600 320003880042000452004810051400

➀ Short-circuit capacity values shown correspond to kVA and impedances shown in this table. For impedances other than these, short-circuit cur-rents are inversely proportional to impedance.

➁ The motor’s short-circuit current contributions are computed on the basis of motor characteris-tics that will give four times normal current. For 208 volts, 50% motor load is assumed while for

other voltages 100% motor load is assumed. For other percentages, the motor short-circuit current will be in direct proportion.

Reference Data – Secondary, Short Circuit Capacity of Typical Power Transformers

CAT.71.01.T.E

Cutler-Hammer

A-60

January 1999


A

Table A30: 600-Volt Primary Class Dry-Type Distribution Transformers

150

°

C Rise

kVA %Z %R %X X/R

3 6 9 15 30 45 75 112.5 150 225 300 500 7501000

7.933.703.425.205.604.504.905.906.206.407.105.506.306.50

6.603.281.944.834.673.563.473.914.073.513.131.461.271.08

4.401.712.811.923.102.763.464.424.685.356.375.306.176.41

0.670.521.450.400.660.781.001.131.151.522.033.634.875.93

115

°

C Rise

kVA %Z %R %X X/R

15 30 45 75 112.5 150 225 300 500 750

5.204.603.704.606.506.207.206.305.504.10

3.674.333.112.532.313.532.361.931.021.00

3.691.542.003.846.085.096.806.005.403.98

1.010.360.641.522.631.442.893.105.303.98

80

°

C Rise

kVA %Z %R %X X/R

15 30 45 75 112.5 150 225 300 500

2.302.902.903.704.304.105.303.304.50

2.002.251.782.072.491.701.421.000.62

1.141.832.293.073.513.735.113.144.46

0.570.811.291.491.412.193.593.147.19

Table A28: 15 kV Class Primary – Oil Liquid-Filled Substation Transformers

65

°

C Rise

kVA %Z %R %X X/R

112.5 150 225 300 500 7501000150020002500

5.005.005.005.005.005.755.755.755.755.75

1.711.881.841.351.501.411.331.120.930.86

4.704.634.654.814.775.575.595.645.675.69

2.75 2.47 2.52 3.57 3.18 3.96 4.21 5.04 6.10 6.61

Table A29: 15 kV Class Primary – Dry-Type Substation Transformers

150

°

C Rise

kVA %Z %R %X X/R

300 500 7501000150020002500

4.505.755.755.755.755.755.75

2.872.662.472.161.871.931.74

3.475.105.195.335.445.425.48

1.21 1.92 2.11 2.47 2.90 2.81 3.15

80

°

C Rise

300 500 7501000150020002500

4.505.755.755.755.755.755.75

1.931.441.280.930.870.660.56

4.065.575.615.675.685.715.72

2.10 3.87 4.38 6.10 6.51 8.7210.22

Table A26: Transformer Full-load Current, Three-Phase, Self-cooled Ratings

Voltage, Line-to-Line

kVA 208 240 480 600 2,400 4,160 7,200 12,000 12,470 13,200 13,800 22,900 34,400

304575

112

1

/

2

83.3125208312

72.2108180271

36.154.190.2

135

28.943.3

72.2 108

7.2210.818.027.1

4.166.25

10.415.6

2.413.616.019.02

1.442.173.615.41

1.392.083.475.21

1.311.973.284.92

1.261.883.144.71

0.751.131.892.84

0.500.761.261.89

150225300500

416625833

1,388

361541722

1,203

180271361601

144 217 289 481

36.154.172.2

120

20.831.241.669.4

12.018.024.140.1

7.2210.814.424.1

6.9410.413.923.1

6.569.84

13.121.9

6.289.41

12.620.9

3.785.677.56

12.6

2.523.785.048.39

7501,0001,5002,000

2,0822,7764,164. . . .

1,8042,4063,6084,811

9021,2031,8042,406

722 9621,4431,925

180241361481

104139208278

60.180.2

120160

36.148.172.296.2

34.746.369.492.6

32.843.765.687.5

31.441.862.883.7

18.925.237.850.4

12.616.825.233.6

2,5003,0003,7505,0007,50010,000

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

3,0073,6094,511. . . .. . . .. . . .

2,4062,8873,6084,811. . . .. . . .

601722902

1,2031,8042,406

347416520694

1,0411,388

200241301401601802

120144180241361481

116139174231347463

109131164219328437

105126157209314418

63.075.694.5

126189252

42.050.462.983.9

126168

➀

Values are typical. For guaranteed values, refer to transformer manufacturer.

Reference Data – Transformer Full Load Amperes and Impedances

Note:

K factor rated distribution dry type transformers may have significantly lower impedances.

Table A27: Typical Impedances – Three-Phase Transformers

a

kVA Liquid-Filled

Network Padmount

37.5455075

112.5150225300500750

1000150020002500300037505000

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .5.005.005.005.007.007.007.00. . . .. . . .. . . .

. . . .

. . . .

. . . .3.43.22.43.33.44.65.755.755.755.755.756.506.506.50

Approximate Impedance Data

January 1999

Cutler-Hammer


CAT.71.01.T.E

A

Reference Data – Transformer Losses

Note:

1 watt hour = 3.413 Btu

Table A33: 600-Volt Primary Class Dry-Type Distribution Transformers

150

°

C Rise

kVA No LoadWatts Loss

Full LoadWatts Loss

3 6 9 15 30 45 75 112.5 150 225 300 500 7501000

335877

150200300400500600700800

170022002800

231255252875

160019003000490067008600

102009000

1170013600

115

°

C Rise


Full LoadWatts Loss

15 30 45 75 112.5 150 225 300 500 750

150200300400500600700800

17001500

700150017002300310059006000660068009000

80

°

C Rise


Full LoadWatts Loss

15 30 45 75 112.5 150 225 300 500

200300300400600700800

13002200

500975

1100195034003250400043005300

Approximate Transformer Loss Data

Table A31: 15 kV Class Primary – Oil Liquid-Filled Substation Transformers

65

°

C Rise

kVA No Load Watts Loss

Full LoadWatts Loss

112.5 150 225 300 500 7501000150020002500

550545650950

120016001800300040004500

24703360480050008700

1216015100198002260026000

Table A32: 15 kV Class Primary – Dry-Type Substation Transformers

150

°

C Rise

kVA No Load Watts Loss

Full LoadWatts Loss

300 500 7501000150020002500

1600190027003400450057007300

10200152002120025000326004420050800

80

°

C Rise

300 500 7501000150020002500

1800230034004200590069007200

76009500

1300013500190002000021200

CAT.71.01.T.E



A

Reference Data – Power Equipment Losses

Power Equipment Losses

Table A34: Medium Voltage Switchgear (Indoor, 5 and 15 kV)

Equipment Watts Loss

1200 Ampere Breaker 600



Table A35: Medium Voltage Switchgear (Indoor, 5 and 15 kV)


600 Ampere Unfused Switch 500

1200 Ampere Unfused Switch 750

100 Ampere CL Fuses 840

Table A36: Medium Voltage Starters (Indoor, 5 kV)


400 Ampere Starter FVNR 600

800 Ampere Starter FVNR 1000

600 Ampere Fused Switch 500

1200 Ampere Fused Switch 800

Table A37: Low Voltage Switchgear (Indoor, 480 volts)








Fuse Limiters – 800 A CB 200



Fuse Truck – 3200 A CB 3600

Fuse Truck – 4000 A CB 4500

Structures – 3200 Ampere 4000



High Resistance Grounding 1200

Table A38: Motor Control Centers (Indoor, 480 volts)


NEMA Size 1 Starter 39





Structures 200

Table A39: Panelboards (Indoor, 480 volts)


225 Ampere, 42 Circuit 300

Table A40: Low Voltage Busway (Indoor, Copper, 480 volts)


800 Ampere 44 per foot









January 1999


CAT.71.01.T.E

AEnclosures

The following are reproduced from NEMA 250-1991.

Table A41: Comparison of Specific Applications of Enclosures for Indoor Nonhazardous Locations

Provides a Degree of Protection Against theFollowing Environmental Conditions

Type of Enclosures

1➀ 2➀ 4 4X 5 6 6P 12 12K 13

Incidental contact with the enclosed equipmentFalling dirtFalling liquids and light splashingCirculating dust, lint, fibers, and flyings➁Settling airborne dust, lint, fibers, and flyings➁Hosedown and splashing waterOil and coolant seepageOil or coolant spraying and splashingCorrosive agentsOccasional temporary submersionOccasional prolonged submersion

XX. . .. . .. . .. . .. . .. . .. . .. . .. . .

XXX. . .. . .. . .. . .. . .. . .. . .. . .

XXXXXX. . .. . .. . .. . .. . .

XXXXXX. . .. . .X. . .. . .

XXX. . .X. . .. . .. . .. . .. . .. . .

XXXXXX. . .. . .. . .X. . .

XXXXXX. . .. . .XXX

XXXXX. . .X. . .. . .. . .. . .

XXXXX. . .X. . .. . .. . .. . .

XXXXX. . .XX. . .. . .. . .

Table A42: Comparison of Specific Applications of Enclosures for Outdoor Nonhazardous Locations

Provides a Degree of Protection Against theFollowing Environmental Conditions

Type of Enclosures

3 3R➂ 3S 4 4X 6 6P

Incidental contact with the enclosed equipmentRain, snow, and sleet➃Sleet➄Windblown dustHosedownCorrosive agentsOccasional temporary submersionOccasional prolonged submersion

XX. . .X. . .. . .. . .. . .

XX. . .. . .. . .. . .. . .. . .

XXXX. . .. . .. . .. . .

XX. . .XX. . .. . .. . .

XX. . .XXX. . .. . .

XX. . .XX. . .X. . .

XX. . .XXXXX

Table A43: Comparison of Specific Applications of Enclosures for Indoor Hazardous Locations (See Paragraph 3.6)(If the installation is outdoors and/or additional protection is required by Tables A41 and A42, a combination-type enclosure is required.

Provides a Degree of Protection Against Atmospheres Typically Containing (For Complete Listing, See NFPA 497M-1986, Classification of Gases, Vapors and Dusts for Electrical Equipment in Hazardous (Classified) Locations) Class

Type of Enclosure7 and 8, Class I Groups➅

Type of Enclosure9, Class II Groups➅

A B C D E F G 10

AcetyleneHydrogen, manufactured gasDiethel ether, ethylene, cyclopropaneGasoline, hexane, butane, naphtha, propane, acetone, toluene, isopreneMetal dustCarbon black, coal dust, coke dustFlour, starch, grain dustFibers, flyings➆Methane with or without coal dust

IIIIIIIIIIIIIMSHA

X. . .. . .. . .. . .. . .. . .. . .. . .

. . .X. . .. . .. . .. . .. . .. . .. . .

. . .

. . .X. . .. . .. . .. . .. . .. . .

. . .

. . .

. . .X. . .. . .. . .. . .. . .

. . .

. . .

. . .

. . .X. . .. . .. . .. . .

. . .

. . .

. . .

. . .

. . .X. . .. . .. . .

. . .

. . .

. . .

. . .

. . .

. . .XX. . .

. . .

. . .

. . .

. . .

. . .

. . .

. . .

. . .X

Table A44: Knockout Dimensions

Conduit TradeSize, Inches

Knockout Diameter, Inches

Minimum Nominal Maximum

1/23/4

111/411/2

221/2331/24

56

0.8591.0941.3591.7191.958

2.4332.9383.5634.0634.563

5.6256.700

0.8751.1091.3751.7341.984

2.4692.9693.5944.1254.641

5.7196.813

0.9061.1411.4061.7662.016

2.5003.0003.6254.1564.672

5.7506.844

➀ These enclosures may be ventilated. However, Type 1 may not provide protection against small particles of falling dirt when ventilation is provid-ed in the enclosure top. Consult the manufacturer.

➁ These fibers and flying are nonhazardous materi-als and are not considered the Class III type ignit-able fibers or combustible flyings. For Class III

type ignitable fibers or combustible flyings see the National Electrical Code, Article 500.

➂ External operating mechanisms are not required to be operable when the enclosure is ice covered.

➃ External operating mechanisms are operable when the enclosure is ice covered.

➄ These enclosures may be ventilated.

➅ For Class III type ignitable fibers or combustible flyings see the National Electrical Code, Article 500.

➆ 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.

Reference Data – Enclosures

CAT.71.01.T.E



A

➂ Based on conductor temperatures of 75°C. Reactance values will have negligible variation with temperature. Resistance of both copper and aluminum conductors will be approximately 5% lower at 60°C or 5% higher at 90°C. Data shown in tables may be used without significant error between 60°C and 90°C.

➃ For interlocked armored cable, use magnetic conduit data for steel armor and non-magnetic conduit data for aluminum armor.

➄➅ For busway impedance data, see section H2 of

this catalog.

Z X2 R2+=

Reference Data – Conductor Resistance, Reactance, Impedance ➅

The tables below are average characteristics based on data from several manufacturers of copper and aluminum conductors and cable, and also NEC Table 9. Values from different sources vary because of operating tempera-tures, wire stranding, insulation materials and thicknesses, overall diameters, random

lay of multiple conductors in conduit, con-ductor spacing, and other divergences in materials, test conditions and calculation methods. These tables are for 600-volt con-ductors, at an average temperature of 75°C. Other parameters are listed in the notes. For medium-voltage cables, differences among

manufacturers are considerably greater because of the wider variations in insulation materials and thicknesses, shielding, jacket-ing, overall diameters, and the like. There-fore, data for medium-voltage cables should be obtained from the manufacturer of the cable to be used.

Average Characteristics of 600-Volt Conductors (Ohms per 100 Feet)

Table A45: Two or Three Single Conductors

Wire Size, AWG or kcmil

Copper Conductors Aluminum Conductors

Magnetic Conduit Nonmagnetic Conduit Magnetic Conduit Nonmagnetic Conduit

R X Z R X Z R X Z R X Z

14121086421

1/02/03/04/0250300350400450500600700750

1000

.3130

.1968

.1230

.0789

.0490

.0318

.0203

.0162

.0130

.0104

.00843

.00696

.00588

.00512

.00391

.00369

.00330

.00297

.00261

.00247

.00220 –

.00780

.00730

.00705

.00691

.00640

.00591

.00548

.00533

.00519

.00511

.00502

.00489

.00487

.00484

.00480

.00476

.00467

.00458

.00455

.00448

.00441 –

.3131

.1969

.1232

.0792

.0494

.0323

.0210

.0171

.01340

.01159

.00981

.00851

.00763

.00705

.00619

.00602

.00595

.00546

.00525

.00512

.00493 –

.3130

.1968

.1230

.0789

.0490

.0318

.0203

.0162

.0129

.0103

.00803

.00666

.00578

.00501

.00380

.00356

.00310

.00275

.00241

.00247

.00198 –

.00624

.00584

.00564

.00553

.00512

.00473

.00438

.00426

.00415

.00409

.00402

.00391

.00390

.00387

.00384

.00381

.00374

.00366

.00364

.00358

.00353 –

.3131

.1969

.1231

.0791

.0493

.0321

.0208

.0168

.01360

.01108

.00898

.00772

.00697

.00633

.00540

.00521

.00486

.00458

.00437

.00435

.00405 –

– – – –.0833.0530.0335.0267.0212.0170.01380.01103.00936.00810.00694.00618.00548.00482.00409.00346.00308.00250

– – – –.00509.00490.00457.00440.00410.00396.00386.00381.00375.00366.00360.00355.00350.00346.00355.00340.00331.00330

– – – –.0835.0532.0338.0271.0216.0175.0143.0117.01008.00899.00782.00713.00650.00593.00542.00485.00452.00414

– – – –.0833.0530.0335.0267.0212.0170.01380.01097.00933.00797.00688.00610.00536.00470.00395.00330.00278.00230

– – – –.00407.00392.00366.00352.00328.00317.00309.00305.00300.00293.00288.00284.00280.00277.00284.00272.00265.00264

– – – –.0834.0531.0337.0269.0215.0173.01414.01139.00980.00849.00746.00673.00605.00546.00486.00428.00384.00350

Table A46: Three-conductor Cables (and Interlocked Armored Cable)

Wire Size, AWG or kcmil

Copper Conductors Aluminum Conductors

Magnetic Conduit Nonmagnetic Conduit Magnetic Conduit Nonmagnetic Conduit

R X Z R X Z R X Z R X Z

14121086421

1/02/03/04/0250300350400450500600700750

1000

.3130

.1968

.1230

.0789

.0490

.0318

.0203

.0162

.0130

.0104

.00843

.00696

.00588

.00512

.00391

.00369

.00360

.00297

.00261

.00247

.00220 –

.00597

.00558

.00539

.00529

.00491

.00452

.00420

.00408

.00398

.00390

.00384

.00375

.00373

.00370

.00365

.00360

.00351

.00343

.00337

.00330

.00323 –

.3131

.1969

.1231

.0790

.0492

.0321

.0207

.0167

.0136

.0111

.00926

.00791

.00696

.00632

.00535

.00516

.00503

.00454

.00426

.00412

.00391 –

.3130

.1968

.1230

.0789

.0490

.0318

.0203

.0162

.0129

.0103

.00803

.00666

.00578

.00501

.00380

.00356

.00310

.00275

.00241

.00227

.00198 –

.00521

.00487

.00470

.00461

.00427

.00394

.00366

.00355

.00346

.00341

.00335

.00326

.00325

.00323

.00320

.00318

.00312

.00305

.00303

.00298

.00294 –

.3130

.1969

.1231

.0790

.0492

.0320

.0206

.0166

.0134

.0108

.00870

.00742

.00663

.00596

.00497

.00477

.00440

.00411

.00387

.00375

.00354 –

– – – –.0833.0530.0335.0267.0212.0170.01380.01103.00936.00810.00694.00618.00548.00482.00409.00346.00308.00250

– – – –.00509.00490.00457.00440.00410.00396.00389.00381.00375.00366.00360.00355.00350.00346.00355.00341.00331.00330

– – – –.0834.0532.0338.0271.0216.0175.0143.0117.01006.00889.00782.00713.00650.00593.00542.00486.00452.00414

– – – –.0833.0530.0335.0267.0212.0170.01380.01097.00933.00797.00688.00610.00536.00470.00395.00330.00278.00230

– – – –.00407.00392.00366.00352.00328.00317.00309.00305.00300.00293.00288.00284.00280.00277.00284.00272.00265.00264

– – – –.0834.0531.0337.0269.0215.0173.01414.01139.00980.00849.00746.00673.00605.00546.00486.00428.00384.00350

➀ Resistance and reactance are phase-to-neutral values, based on 60 Hertz ac, 3-phase, 4-wire distribution, in ohms per 100 feet of circuit length (not total conductor lengths).

➁ Based upon conductivity of 100% for copper, 61% for aluminum.

January 1999

Cutler-Hammer


CAT.71.01.T.E

A

Table 310-16: Allowable Ampacities of Insulated Conductors Rated 0-2000 Volts, 60

°

to 90

°

C (140

°

to 194

°

F)

Not More Than Three Conductors in Raceway or Cable or Earth (Directly Buried), Based on Ambient Temperature of 30

°

C (86

°

F)

Size Temperature Rating of Conductor. See Table 310-13. Size

AWGkcmil

60

°

C(140

°

F)75

°

C(167

°

F)90

°

C(194

°

F)60

°

C(140

°

F)75

°

C(167

°

F)90

°

C(194

°

F)AWGkcmil

TypesTW†,UF†

TypesFEPW†,RH†, RHW†,THHW†,THW†,THWN†,XHHW†,USE†, ZW†

TypesTBS, SA,SIS, FEP†,FEPB†, MI,RHH†, RHW-2,THHN†, THHW†,THW-2, THWN-2,USE-2, XHH,XHHW†,XHHW-2, ZW-2

TypesTW†,UF†

TypesRH†, RHW†,THHW†,THW†,THWN†,XHHW†,USE†

TypesTBS,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

1816141210

8

. . . .

. . . .20†25†3040

. . . .

. . . .20†25†35†50

141825†30†40†55

. . . .

. . . .

. . . .20†2530

. . . .

. . . .

. . . .20†30†40

. . . .

. . . .

. . . .25†35†45

. . . .

. . . .

. . . .1210

8

64321

55708595

110

6585

100115130

7595

110130150

4055657585

50657590

100

607585

100115

64321

1/02/03/04/0

125145165195

150175200230

170195225260

100115130150

120135155180

135150175205

1/02/03/04/0

250300350400500

215240260280320

255285310335380

290320350380430

170190210225260

205230250270310

230255280305350

250300350400500

600700750800900

355385400410435

420460475490520

475520535555585

285310320330355

340375385395425

385420435450480

600700750800900

10001250150017502000

455495520545560

545590625650665

615665705735750

375405435455470

445485520545560

500545585615630

10001250150017502000

Correction Factors

Ambient Temp.

°

CFor ambient temperatures other than 30

°

C (86

°

F), multiply the allowable ampacities shown above by the appropriate factor shown below.

Ambient Temp.

°

F

21-2526-3031-3536-4041-4546-5051-5556-6061-7071-80

1.081.00

.91

.82

.71

.58

.41. . . .. . . .. . . .

1.051.00

.94

.88

.82

.75

.67

.58

.33. . . .

1.041.00

.96

.91

.87

.82

.76

.71

.58

.41

1.081.00

.91

.82

.71

.58

.41. . . .. . . .. . . .

1.051.00

.94

.88

.82

.75

.67

.58

.33. . . .

1.041.00

.96

.91

.87

.82

.76

.71

.58

.41

70-7778-8687-9596-104

105-113114-122123-131132-140141-158159-176

†Unless otherwise specifically permitted elsewhere in this Code, the overcurrent protection for conductor types marked with an obelisk (†) shall not exceed 15 amperes for No. 14, 20 amperes for No. 12, and 30 amperes for No. 10 copper; or 15 amperes for No. 12 and 25 amperes for No. 10 aluminum and copper-clad aluminum after any correction factors for ambi-ent temperature and number of conductors have been applied.

Current Carrying Capacities of Copper and Aluminum and Copper-Clad Aluminum Conductors From National Electrical Code (NEC), 1996 Edition (NFPA70-1996)

Note:

For applications 2000 volts and below under conditions of use other than covered by the above table, and for applications over 2000 volts, see Article 310 and additional tables in NEC.

Where single conductors or multiconductor cables are stacked or bundled longer than 24 inches (610 mm) without maintaining spacing and are not installed in raceways, the allow-able ampacity of each conductor shall be reduced as shown in the above table.

Exception No. 1: Where conductors of differ-ent systems, as provided in Section 300-3, are installed in a common raceway or cable, the derating factors shown above shall apply to the number of power and lighting (Articles 210, 215, 220, and 230) conductors only.Exception No. 2: For conductors installed in cable trays, the provisions of Section 318-11 shall apply.Exception No. 3: Derating factors shall not apply to conductors in nipples having a length not exceeding 24 inches (610 mm).Exception No. 4: Derating factors shall not apply to underground conductors entering or leaving an outdoor trench if those conductors have physical protection in the form of rigid metal conduit, intermediate metal conduit, or rigid nonmetallic conduit having a length not exceeding 10 feet (3.05 m) and the number of conductors does not exceed four.Exception No. 5: For other loading conditions, adjustment factors and ampacities shall be permitted to be calculated under Section 310-15(b).

(FPN): See Appendix B, Table B-310-11 for ad-justment factors for more than three current-carrying conductors in a raceway or cable with load diversity.b.

More Than One Conduit, Tube or Raceway.

Spacing between conduits, tubing orraceways shall be maintained.

9. Overcurrent Protection.

Where the standard ratings and settings of overcurrent devices do not correspond with the ratings and settings allowed for conduc-tors, the next higher standard rating and set-ting shall be permitted.

Exception: As limited in Section 240-3.

Note 9: Overcurrent protection.

Where the standard ratings and settings of overcurrent devices do not correspond with the ratings and settings allowed for conduc-tors, the next higher standard rating and set-ting shall be permitted, except as limited in Section 240-3 (not above a rating of 800A).

Note 10: Neutral Conductor

a. A neutral conductor which carries only the unbalanced current from other conduc-tors, as in the case of normally balanced circuits of three or more conductors, shall not be counted when applying the provi-sions of Note 8.

b. In a 3-wire circuit consisting of 2-phase wires and the neutral of a 4-wire, 3-phase wye-connected system, a common con-ductor carries approximately the same cur-rent as the line to neutral load currents of the other conductors and shall be counted when applying the provisions of Note 8.

c. On a 4-wire, 3-phase wye circuit where the major portion of the load consists of non linear loads, there are harmonic cur-rents present in the neutral conductor and the neutral shall be considered to be a current-carrying conductor.

See NEC for complete notes to Table 310-16. Some of the most important are summarized in part below.

8. Adjustment Factors

a.

More Than Three Current-Carrying Conductors in a Raceway or Cable.

Where the number of current-carrying conductors in a raceway or cable exceeds three, the allowable ampacities shall be reduced as shown in the following table:

Number ofCurrent-Carrying Conductors

Percent of Values in Tables as Adjusted for Ambien Temperature if Necessary

4 through 67 through 910 through 2021 through 3031 through 4041 and above

807050454035

➀

For impedance data, see page A-64.

Reference Data – Conductor Ampacities

➀

CAT.71.01.T.E



A

Reference Data – Conduit Fill

Note 1. This table is for concentric stranded conductors only. For cables with compact conductors, the dimensions in Table 5A shall be used.Note 2. Conduit fill for conductors with a -2 suffix is the same as for those types without the suffix.

Reproduced From 1993 NEC

Note 1. This table is for concentric stranded conductors only. For cables with compact conductors, the dimensions in Table 5A shall be used.Note 2. Conduit fill for conductors with a -2 suffix is the same as for those types without the suffix.

Table 3A: Maximum Number of Conductors in Trade Sizes of Conduit or Tubing (Based on Table 1, Chapter 9)

Conduit or Tubing Trade Size (Inches) 1⁄2 3⁄4 1 11⁄4 11⁄2 2 21⁄2 3 31⁄2 4 5 6

Type Letters Conductor SizeAWG/kcmil

TW, XHHW(14 through 8)RH (14 + 12)

1412108

9752

151294

2519157

44352612

60473617

99786028

1421118540

17113162

17684 108

RHW and RHH(without outer covering), RH (10 + 8)THW, THHW

1412108

6441

10863

1613115

29241910

40322613

65534322

93766132

1431179549

19215712766

16385 133

TW,

THW,

FEPB (6 through 2),RHW and RHH (with-out outer covering)

RH, THHW

64

11

21

43

75

107

1612

2317

3627

4836

6247

9773

141106

321

11

111

221

443

654

1096

15139

232014

312719

403425

635439

917857

1/02/03/04/0

111

1111

2111

3321

5543

8765

121097

16141210

21181513

33292420

49413529

250300350400500

11

11111

11111

22111

43321

65443

87654

109876

161412119

2320181614

600700750

111

111

111

322

433

544

776

11109

Table 3B: Maximum Number of Conductors in Trade Sizes of Conduit or Tubing (Based on Table 1, Chapter 9)

Conduit or Tubing Trade Size (Inches) 1⁄2 3⁄4 1 11⁄4 11⁄2 2 21⁄2 3 31⁄2 4 5 6

Type Letters Conductor SizeAWG/kcmil

THWN,

THHN,FEP (14 through 2),FEPB (14 through 8),PFA (14 through 4/0)PFAH (14 through 4/0)Z (14 through 4/0)XHHW (4 through

500 kcmil)

1412108

131063

2418115

3929189

69513216

94704422

1541147336

16410451

16079 106 136

64321

1111

42111

64331

117653

159875

261613118

3722191612

5735292518

7647393325

9860514332

15494806750

1371169772

1/02/03/04/0

1111

1111

3211

4332

7654

10876

1513119

21171412

27221815

42352924

61514235

250300350400

111

1111

1111

3321

4433

7655

10876

121198

20171513

28242119

500600700750

11

1111

1111

2111

4332

5443

7554

11987

16131111

XHHW 6600700750

1 3 5 91

13111

21111

30111

47332

63443

81554

128977

185131110

Conduit Fill

Reproduced From 1993 NEC. For estimate only – see 1996 NEC, Chapter 9, Tables 1-10 for exact code requirements.

Note 11: Grounding or Bonding ConductorA grounding or bonding conductor shall not be counted when applying the provisions of Note 8.

Note: UL listed circuit breakers rated 125A or less shall be marked as being suitable for 60°C (140°F), 75°C (167°F) only or 60/75°C (140/167°F) wire. All Westinghouse listed breakers rated 125A or less are marked 60/75°C. All UL listed circuit breakers rated over 125A are suitable for 75°C conductors. Con-ductors rated for higher temperatures may be used, but must not be loaded to carry more

current than the 75°C ampacity of that size conductor for equipment marked or rated 75°C or the 65°C ampacity of that size conduc-tor for equipment marked or rated 65°C. How-ever, the full 90°C ampacity may be used when applying derated factors, so long as the actual load does not exceed the lower of the derated ampacity or the 75°C or 60°C ampac-ity that applies.

January 1999


CAT.71.01.T.E

A

Common Electrical TermsAmpere (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= = .00134 hp

Kilowatt (kW) = 1000 watts

Power Factor (pf) = ratio of true to apparent power

=

Watt-hour (Wh) = unit of electrical work= one watt for one hour= 3.413 Btu= 2,655 ft. lbs.

Kilowatt-hour (kWh) = 1000 watt-hours

Horsepower (hp) = measure of time rate of doing work= equivalent of raising 33,000 lbs. one ft. in one minute= 746 watts

Demand Factor = ratio of maximum demand to the total connected load

Diversity Factor = ratio of the sum of individual maximum demands of the various subdivisions of a system to the maximum demand of the whole system

Load Factor = ratio of the average load over a designated period of time to the peak load occurring in that period

Formulas for Determining Amperes, hp, kW, and kVA➀

To Find Direct Current Alternating Current

Single-Phase Two-Phase — 4-Wire➁ 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----------------------------------------------------------

ER---

E l×E l× 3×

VA pf×

WVA------- kW

kVA----------

How to Compute Power Factor

Determining watts: pf =

1. From watt-hour meter.Watts = rpm of

Where Kh is meter constant printed on face or nameplate of meter.

If metering transformers are used, above must be multiplied by the transformer ratios.

2. Directly from wattmeter reading.Where:

Volts = line-to-line voltage as measured byvoltmeter.

Amps = current measured in line wire (notneutral) by ammeter.

1 inch = 2.54 centimeters1 kilogram = 2.20 lbs.1 square inch = 1,273,200 circular mills1 circular mill = .785 square mil1 Btu = 778 ft. lbs.

= 252 calories1 year = 8,760 hours

Temperature Conversion

(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

C° 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

wattsvolts amperes×--------------------------------------------

disc 60× Kh×

➀ Units of measurement and definitions for E (volts), I (amperes), and other abbreviations are given below under Common Electrical Terms.

➁ For 2-phase, 3-wire circuits the current in thecommon conductor is times that in eitherof the two other conductors.

2

Reference Data – Formulas and Terms

CAT.71.01.T.E

Cutler-Hammer

A-68

January 1999


A

Seismic Requirements

Uniform Building Code (UBC)

The 1994 Uniform Building Code (UBC) includes Volume 2 for earthquake design requirements. Sections 1624-1633 of this ref-erence specifically require that structures and portions of structures shall be designed to withstand the seismic ground motion speci-fied in the code. The design engineer must evaluate the effect of lateral forces not only on the building structure but also on the equip-ment in determining whether the design will withstand those forces. In the code electrical equipment such as control panels, motors, switchgear, transformers, and associated con-duit are specifically identified.

The criteria for selecting the seismic require-ments are defined in Section 1627 of the code. Figure 16-2 of the code includes a seismic zone map of the United States. Figure 16-3 of the code includes the normalized response spec-tra shapes for different soil conditions. The damping value is 5% of the critical damping.

The seismic requirements in the UBC can be completely defined as the Zero Period Accel-eration (ZPA) and Spectrum Accelerations are computed. In a test program, these values are computed conservatively to envelop the requirements of all seismic zones. The lateral force on elements of structures and nonstruc-tural components are defined in Section 1630. The dynamic lateral forces are defined in Section 1629. These loads are converted to seismic accelerations according to the nor-malized response spectra shown in Figure 16-3 of the UBC.

The total design lateral force required is:

Force Fp = Z Ip Cp Wp

Dividing both sides by Wp, the acceleration requirement in g’s is equal to:

Acceleration = Fp/Wp = Z Ip Cp

Where:

Z:

is the seismic zone factor and is taken equal to 0.4. This is the maximum value provided in Table 16-I of the code.

Ip:

is the importance factor and is taken equal to 1.5. This is the maximum value provided in Table 16-K of the code.

Cp:

is the horizontal force factor and is taken equal to 0.75 for rigid equip-ment as defined in Table 16-O. For flexible equipment, this value is equal to twice the value for the rigid equip-ment: 2 x 0.75 = 1.5. This is the maxi-mum value provided in the code.

Wp:

is the weight of the equipment.

UBC Figure 16-2. Seismic Zone Map of the United States

UBC Figure 16-3. Normalized Response Spectra Shapes

2B

2B

2B

3

3

3

3

1

4

2B

2B

2B

3

3

3

4

4

4

1

1

1

12B

2B3

0

1

1

4

1

2B

3

3

ALEUTIANISLANDS

ALASKA

HAWAII

PUERTORICO

3 4

1

0

01

2A

2A

0

1

1

1

1

2A

2A

2A

2A

0

0

0

3

1

3

4

3

2

1

00 0.5 1.0 1.5 2.0 2.5 3.0

Soft to Medium Clays and Sands(Soil Type 3)

Deep Cohesionless or Stiff Clay Soils(Soil Type 2)

Rock and Stiff Soils(Soil Type 1)

Sp

ectr

al A

ccel

erat

ion

Eff

ecti

ve P

eak

Gro

un

d A

ccel

erat

ion

Period, T(Seconds)

Therefore, the maximum acceleration for rigid equipment is:

Acceleration = Fp/Wp= Z Ip Cp= 0.4 x 1.5 x 0.75= 0.45g

The maximum acceleration for flexible equipment is:

Acceleration = Fp/Wp= Z Ip Cp= 0.4 x 1.5 x 1.5= 0.9g

Flexible equipment is defined in the UBC as equipment with a period of vibration equal to or greater than 0.06 seconds. This period of vibration corresponds to a dominant frequency of vibration equal to 16.7 Hz. From actual tests,

the lowest natural frequency of Cutler-Hammer equipment is greater than 3 Hz. Therefore, the requirements for the flexible equipment ex-tend from 3 Hz. to 16.7 Hz. The rigid equipment requirements extend beyond 16.7 Hz. The resultant levels are shown in Figure 16-3.

Equipment must be designed and tested to the UBC requirements to determine that it will be functional following a seismic event. In addition, a structural or civil engineer must perform calculations based on data received from the equipment manufacturer specifying the size, weight, center of gravity, and mount-ing provisions of the equipment to determine its method of attachment so it will remain attached to its foundation during a seismic event. Finally, the contractor must properly install the equipment in accordance with the anchorage design.


January 1999

Cutler-Hammer


CAT.71.01.T.E

A

Figure 1. Tested Equipment Capability and Seismic Requirements

California Building Code

The 1992 California Building Code (CBC) requirements and the UBC requirements are similar except that the CBC specifies the coefficient Cp for flexible equipment is taken equal to 4 times the rigid value. The maxi-mum acceleration for rigid equipment is:

Acceleration = Fp/Wp= Z I Cp= 0.4 x 1.5 x 0.75= 0.45g

The maximum acceleration for flexible equipment is:

Acceleration = Fp/Wp= Z I Cp= 0.4 x 1.5 x 4 x 0.75= 1.8g

In addition, CBC State Requirements add under Note 12 in Table 23P, vertical accelera-tions are to be met along with the horizontal, equal to 1⁄3 of the horizontal accelerations. Because the 1⁄3 figure has been found to be inadequate for some applications, Cutler-Hammer recommends the vertical acceleration requirements to be equal to the horizontal seismic requirements. The result-ant levels are shown in Figure 1.

ANSI C37.81 - 1995

The seismic requirements for Class 1E Switchgear in nuclear power plants are defined in ANSI C37.81, Guide for Seismic Qualification of Class 1E Metal-Enclosed Power Switchgear Assemblies. Cutler-Hammer elected to test the equipment to 1⁄2 of the nuclear requirements. The 50% ANSI C37.81 seismic requirements are also plotted in Figure 1.

.31 .25 .20 .16 .13 .10 .08 .06 .05 .04 .03 0

2.0

1.5

1.0

0.5

0

3.2 4 5 6.4 8 10 13 17 20 26 32

Frequency (Hz)

ResponseAcceleration

(g)

Cutler-Hammer Equipment Capability50% of the Level Specified in ANSI C37.81

California Building Code Zone 4RequirementUniform Building Code Zone 4Requirement

Damping = 5%

Zer

o P

erio

d A

ccel

erat

ion

Period (seconds)


CAT.71.01.T.E



A

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