Power Distribution System Design

January 1999Cutler-Hammer A-1 Power Distribution System Design CAT.71.01.T.E A Index Description Page Basic Principles ......................................................................................................................... A-2 Modern Electric Power Technologies ......................................................................................A-2 Goals of System Design............................................................................................................A-3 Voltage Classifications ............................................................................................................. A-4 Types of Systems...................................................................................................................... A-5 1. Simple Radial....................................................................................................................A-5 2. Loop Primary System - Radial Secondary System........................................................A-6 3. Primary Selective System - Secondary Radial System.................................................A-7 4. Two Source Primary - Secondary Selective System.....................................................A-8 5. Simple Spot Network Systems .......................................................................................A-9 6. Medium-Voltage Distribution System Design..............................................................A-10 Systems Analysis.................................................................................................................... A-12 Short Circuit Currents - General ............................................................................................ A-13 Fault Current Wave Form Relationships............................................................................... A-14 Fault Current Calculations...................................................................................................... A-15 Fault Current Calculations for Specific Equipment .............................................................. A-16 1. Medium-Voltage VCP-W Metal-Clad Switchgear.........................................................A-16 2. Medium-Voltage Fuses ..................................................................................................A-21 3. Low-Voltage Power Circuit Breakers.............................................................................A-22 4. Molded Case Breakers ...................................................................................................A-22 Short Circuit Calculations - Short Cut Method..................................................................... A-23 How To Calculate Short Circuit Currents at Ends of Conductors ....................................... A-26 1. Method 1 (Adding Zs) ....................................................................................................A-26 2. Chart Approximate Method...........................................................................................A-27 Determine X and R From Transformer Loss Data................................................................ A-30 Voltage Drop ........................................................................................................................... A-31 Capacitor Switching Device Selections................................................................................. A-35 1. Medium-Voltage Capacitor Switching..........................................................................A-35 2. Low-Voltage Capacitor Switching.................................................................................A-35 Motor Power Factor Correction............................................................................................. A-36 Overcurrent Protection and Coordination ............................................................................ A-37 Grounding ............................................................................................................................... A-40 1. Equipment Grounding ...................................................................................................A-40 2. System Grounding.........................................................................................................A-40 3. Medium-Voltage System - Grounding..........................................................................A-40 4. Low-Voltage System - Grounding.................................................................................A-42 Ground Fault Protection......................................................................................................... A-43 Lightning and Surge Protection............................................................................................. A-45 Grounding Electrodes............................................................................................................. A-46 Terms, Technical Overview.................................................................................................... A-47 Harmonics and Nonlinear Loads........................................................................................... A-48 Secondary Voltages................................................................................................................ A-50 Energy Conservation.............................................................................................................. A-52 Building Control Systems ...................................................................................................... A-53 Cogeneration........................................................................................................................... A-53 Emergency Power................................................................................................................... A-53 Peak Shaving........................................................................................................................... A-54 Computer Power ..................................................................................................................... A-55 Sound Levels........................................................................................................................... A-56 Codes and Standards ............................................................................................................. A-57 Motor Protective Device Data ................................................................................................ A-58 Secondary Short Circuit Capacity of Typical Power Transformers .................................... A-59 Transformer Full Load Amperes and Impedances............................................................... A-60 Transformer Losses................................................................................................................ A-61 Power Equipment Losses....................................................................................................... A-62 NEMA Enclosure Definitions.................................................................................................. A-63 Cable R, X, Z Data ................................................................................................................... A-64 Conductor Ampacities............................................................................................................ A-65 Conduit Fill .............................................................................................................................. A-66 Formulas.................................................................................................................................. A-67 Seismic 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 A-3 Power Distribution System Design 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 Power Distribution System Design 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 240 480 600 208Y/120 240/120 480Y/277 Medium Voltage 2400 4160 4800 6900 13800 23000 34500 46000 69000 4160Y/2400 8320Y/4800 12000Y/6930 12470Y/7200 13200Y/7620 13800Y/7970 20780Y/12000 22860Y/13200 24940Y/14400 34500Y/19920 High Voltage 115000 138000 161000 230000 Extra-High Voltage Ultra-High Voltage 345000 500000 765000 1100000 January 1999 Cutler-Hammer A-5 Power Distribution System Design 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 Class Switchboard Distribution Dry-Type Transformer Lighting Panelboard Distribution Panel MCC Distribution Panel CAT.71.01.T.E Cutler-Hammer A-6 January 1999 Power Distribution System Design 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 NC NO Loop A Loop B Tie Breaker 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 NC NC NC NC 52 52 52 52 52 52 52 Fault Sensors Primary Main Breaker 1 Secondary Unit Substation Primary Main Breaker Primary Feeder Breakers Primary Cables 52 52 52 52 52 52 52 January 1999 Cutler-Hammer A-7 Power Distribution System Design 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 Loop Switching Loop A Loop A In cases where only one primary line is available, the use of a single primary breaker provides the loop connections to 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. Loop Feeder Loop Feeder Loadbreak Loop Switches Fused Disconnect Switch Loop Feeder Loop Feeder Loadbreak Loop Switches Loadbreak Drawout Fuses CAT.71.01.T.E Cutler-Hammer A-8 January 1999 Power Distribution System Design 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 Other Substations Typical Secondary Unit Substation Duplex Primary Switch/Fuses Transformer/600V Class Secondary Switchgear 52 52 52 52 52 52 52 NO NC NO NC NO NC Figure 3A. Duplex Fused Switch In Two Structures Figure 3. Basic Primary Selective - Radial Secondary System Primary Feeders Loadbreak Switches Fuses Figure 3B. Fused Selector Switch In One Structure Primary Feeders Interlock Non-loadbreak Selector Switch Loadbreak Disconnect 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 A-9 Power Distribution System Design 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 Substations To Other Substations Secondary Main Breaker Tie Breaker Primary Fused Switch Transformer Typical Double-Ended Unit Substation 52 52 52 52 52 52 52 CAT.71.01.T.E Cutler-Hammer A-10 January 1999 Power Distribution System Design 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 Customer Loads Customer Loads Customer Loads NC NC Tie Tie Typical Feeder To Other Networks Drawout Low Voltage Switchgear Fuses Primary Circuit Network Transformer Network Protector Optional Main, 50/51 Relaying and/or Network 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 #2 Utility #1 Normal Standby NC NO Loads 52 52 January 1999 Cutler-Hammer A-11 Power Distribution System Design 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 NO Typical Feeer 52 52 52 CAT.71.01.T.E Cutler-Hammer A-12 January 1999 Power Distribution System Design 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 A-13 Power Distribution System Design 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 Offset Asymmetrical Alternating Wave Rms Value of Total Current Alternating Component- A Symmetrical Wave Rms Value of Alternating Component Direct Component - The Axis of Asymmetrical Wave Time in Cycles of a 60 Cps Wave 1 2 3 4 S c a l e o f C u r e n t V a l u e s 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 Power Distribution System Design 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 1.4 1.5 1 2 2.5 3 4 5 6 7 8 9 10 15 20 25 30 40 50 60 70 80 90 100 1.8 1.7 1.6 1.5 1.4 1.3 1.2 1.1 P E A K M U L T I P L I C A T I O N F A C T O R R M S M U L T I P L I C A T I O N F A C T O R CIRCUIT X/R RATIO (TAN Ø) Based Upon: Rms Asym = Dc 2 + Rms Sym 2 with Dc Value Taken at Current Peak R M S M U L T I P L I C A T I O N F A C T O R = R M S M A X I M U M A S Y M M E T R I C A L R M S S Y M M E T R I C A L P E A K M U L T I P L I C A T I O N F A C T O R = P E A K M A X I M U M A S Y M M E T R I C A L R M S S Y M M E T R I C A L Fault Current Wave Form Relationships The following formulas and Table are reproduced from ANSI/IEEE C37.48. Table A2 describes the relationship between fault current peak values, rms symmetrical values and rms asymmetrical depending on the calculated X/R ratio. The formulas are: 1. I p 2 2∈ – wt X R ⁄ ------------ in per unit. + = For example, for X/R = 15, ∈ = 2.718 w = 2 π f for 60 hertz = 377 t = 1 ⁄ 2 cycle or 1 ⁄ 120 seconds then = 2.5612 2. I p 2 2 2.718 – × 377 15 ---------- 1 120 ---------- × + = I Rms Asymm = I 2 2 ∈ – wt X R ⁄ ------------ × 2 + 1 2 2.718 – 377 15 x 120 ----------------------- , ` 2 × . | + = 1.5217 = Table A2: Relation of X/R Ratio to Multiplication Factor January 1999 Cutler-Hammer A-15 Power 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 Calculations The 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 Cutler-Hammer A-16 January 1999 Power Distribution System Design A Fault 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 Voltage This 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 Factor The 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/V o 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-Circuit Duty Close and Latch (Momentary) % Reactance X/R Ratio 2-Pole Turbo Generator 4-Pole Turbo Generator Hydro Gen. with Damper Wdgs. and Syn. Condensers Hydro Gen. without Damper Windings All Synchronous Motors Ind. Motors Above 1000 Hp, 1800 Rpm and Above 250 Hp, 3600 Rpm All Other Induction Motors 50 Hp and Above Ind. Motors Below 50 Hp and All Single-Phase Motors Distribution System From Remote Transformers Current Limiting Reactors Transformers OA 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 Neglect X X X X X X X X X .75X 1.0X 1.0X 1.2X Neglect X X X X X X 9 7-14 14 12-17 20 13-32 30 20-50 24 13-35 25 15-25 25 15-25 As Specified or Calculated As Specified or Calculated 5.5 5-7 7.5 7-11 10 8-24 15 8-35 80 40-120 80 40-120 30 10-60 30 10-60 30 10-60 30 15-40 15 5-20 15 5-15 80 40-120 10 6-12 12 8-15 20 10-30 30 20-40 January 1999 Cutler-Hammer A-17 Power Distribution System Design CAT.71.01.T.E A 6 5 4 C O N T A C T P A R T I N G T I M E 3 5-CYCLE BREAKER 1.0 1.1 1.2 1.3 1.4 Multiplying Factors for E / X Amperes R a t i o X / R 130 120 110 100 90 80 70 60 50 40 30 20 10 7 8 5-CYCLE BREAKER 1.0 1.1 1.2 1.3 1.4 Multiplying Factors for E / X Amperes 3 4 5 R a t i o X / R 130 120 110 100 90 80 70 60 50 40 30 20 10 4 5-CYCLE BREAKER 1.0 1.1 1.2 1.3 1.4 Multiplying Factors for E / X Amperes 6 8 1 0 1 2 C O N T A C T P A R T I N G T I M E 3 R a t i o X / R 130 120 110 100 90 80 70 60 50 40 30 20 10 Fault Current Calculations for Specific Equipment 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 X I . Step 4–Set-up the same network for resis- tance values. Step 5–Reduce the resistance network to an equivalent resistance. Call this resistance R I . The above calculations of X I and R I may be calculated by several computer programs. Step 6–Calculate the E/X I 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/X I . X I R I ----- 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/X I 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 Cutler-Hammer A-18 January 1999 Power Distribution System Design A Fault Current Calculations for Specific Equipment 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 current V max = Rated maximum voltage of the breaker VD = Actual system voltage KI = Maximum symmetrical interrupting capacity c. E/X M 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 Duty ANSI 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. E X I ----- I V max V o --------------- KI < × ≤ Application Quick Check Table For 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. Œ Transformer impedance 6.5% or more, all other transformer impedances are 5.5% or more. Application Above 3300 Feet The 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) 5,000 10,000 1.00 0.99 0.96 1.00 0.95 0.80 Source Transformer MVA Rating Operating Voltage kV Motor Load 2.4 4.16 6.6 12 13.8 100% 0% 1 1.5 2 1.5 2 2.5 50 VCP-W 250 12 kA 50 VCP-W 250 10.1 kA 150 VCP-W 500 23 kA 150 VCP-W 500 22.5 kA 150 VCP-W 500 19.6 kA 2.5 3 3 3.75 3.75 5 5 7.5 50 VCP-W 250 36 kA 50 VCP-W 250 33.2 kA 7.5 10Œ 10 10 50 VCP-W 350 49 kA 10 12Œ 12 15 50 VCP-W 350 46.9 kA 75 VCP-W 500 41.3 kA 15 20 20Œ 20 Breaker Type and Sym. Interrupting Capacity at the Operating Voltage 150 VCP-W 750 35 kA 150 VCP-W 750 30.4 kA 25 30 50Œ 150 VCP-W 1000 46.3 kA 150 VCP-W 1000 40.2 kA January 1999 Cutler-Hammer A-19 Power Distribution System Design CAT.71.01.T.E A Application on Symmetrical Current Rating Basis Note: Interrupting capabilities I 1 and I 2 at operating voltage must not exceed max. sym. interrupting capability Kl. Example 1 — Fault Calculations Given a circuit breaker interrupting and momentary rating in the table below, verify the adequacy of the ratings for a system without motor loads, as shown. 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 I 1 58 kA I 3 LG Sym. Interrupting Capability 36 kA 1.15 (33.2) = 38.2 kA I 2 Fault Current Calculations for Specific Equipment Check capabilities I 1 , I 2 and I 3 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 Load 24,200 Watts Load Losses For 3-Phase Fault is the highest typical line-to-neutral operating voltage or I 3 ø = I B where X is per unit reactance X I B is base current 1.0 multiplying factor for short-circuit duty, therefore, short-circuit duty is 8.6 kA sym. for 3 ø fault I 1 and momentary duty is 8.6 x 1.6 = 13.7 kA I 3 . For Line-to-Ground Fault For this system, X 0 is the zero sequence reac- tance of the transformer which is equal to the transformer positive sequence reactance and X 1 is the positive sequence reactance of the system. Therefore, Using 1.0 multiplying factor, short-circuit duty = 9.1 kA Sym. LG (I 2 ) 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. (I 1, I 2 ) and momentary duty is 9.5 x 1.6 kA = 15.2 kA(I 3 ). I 3 ø E X ---- where X is ohms per phase and E = Base current I B 3.75 MVA 3 (4.16 kV) ------------------------------- .52 kA = = I 3 ø I 1 X ---- .52 .0604 ------------- 8.6 kA Sym. = = = System X R --- 9 (is less than 15) would use = I LG 3E 2X 1 X 0 + ----------------------- or 3I B 2X 1 X 0 + ----------------------- = = I LG 3(.52) 2(.0604) .0505 + --------------------------------------- 9.1 kA Sym. = = Then I 3 ø I B X ---- .52 .055 ---------- 9.5 kA Sym. = = = 13.8 kV 375 MVA Available 13.8 kV 3750 kVA 4.16 kV 50VPC-W250 = 15 X R On 13.8 kV System, 3.75 MVA Base Transformer Standard 5.5% Impedance has a ±7.5% Manufacturing Tolerance Transformer Z = 5.50 Standard Impedance –.41 (–7.5% Tolerance) 5.09% Z 3.75 MVA 375 MVA ------------------------ .01 pu or 1% = = Z 2 X 2 R 2 R 2 X 2 R 2 ------ 1 + . , | ` = + = R Z X 2 R 2 ------ 1 + -------------------- 1 226 ------------- 1 15.03 ------------- .066% = = = = X X R --- R ( ) 15 (.066) .99% = = = R 24.2 kW 3750 kVA ----------------------- .0065 pu or .65% = = X = 5.05% Transformer X Z 2 R 2 – (5.09) 2 (.65) 2 – 25.91 .42 – 25.48 = = = X R X/R 13.8 kV System Transformer .99% 5.05 .066% .65 15 8 System Total or 6.04% .0604 pu .716 .00716 pu 9 4.76 4.16 --------- [ ] CAT.71.01.T.E Cutler-Hammer A-20 January 1999 Power Distribution System Design 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 V Max. 3ø Sym. Interrupting Capability Close and Latch or Momentary @ V. Max. Max. KI @ 6.9 kV Oper. Voltage 75VCP-W500 8.25 kV 33 kA 41 kA 8.25 6.9 (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 Fault Current Calculations for Specific Equipment 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 I B 7.5 MVA 3 6.9 kV ------------------------ .628 kA = = X .628 21 ---------- (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 = = I 3 ø E X --- I B X ---- 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 = 15 X R X = 5.5% R = 0.55% X R X R = 25 X R = 35 3000 Hp 1.0 PF Syn. 2500 Hp Ind. 2 197A FL X'' = 20% d 173A FL X'' = 25% d 1 Source of Short Circuit Current Interrupting E/X Amperes Momentary E/X Amperes X R X (1) R (X) 1 R 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 1.6 17.0 kA Momentary Duty Total X I B I 3F ------- .628 10.1 ---------- .062 = = = System X R --- .062 (235) 14.5 is Mult. Factor 1.0 from Table 2. = = January 1999 Cutler-Hammer A-21 Power Distribution System Design CAT.71.01.T.E A Fault Current Calculations for Specific Equipment Example 3 — Fault Calculations Check breaker application or generator bus for the system of generators shown. Each generator is 7.5 MVA, 4.16 kV 1040 amperes full load, I B = 1.04 kA Sub transient reactance Xd” = 11% or, X = 0.11 pu Since generator neutral grounding reactors are used to limit the I LG to I 3 ø or below, we need only check the I 3 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 4.76 4.16 (29) = 33.2 kA Gen X R --- ratio is 30 1 X S ------- 1 X --- 1 X --- 1 X --- 3 X --- and = + + = 1 R S ------- 1 R --- 1 R --- 1 R --- 3 R --- = + + = or X S X 3 --- and R S R 3 --- Therefore, System X S R S ------- X R --- Gen X R --- 30 = = = = = I B ø I B X ---- I B X ---- I B X ---- 31 B X --------- 3 1.04 ( ) .11 ------------------ 28.4 kA Sym. E/X amperes = = + + + = Table 2 System X R --- 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 I 2 t 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/X I 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/X I is the fault current to be used in determining the required interrupting ca- pability of the fuse. CAT.71.01.T.E Cutler-Hammer A-22 January 1999 Power Distribution System Design A Fault Current Calculations for Specific Equipment Table A8: Standard Test Power Factors Type of Circuit Breaker Interrupting Rating in KA Power Factor Test Range X/R Test Range Molded Case Molded Case Molded Case Low-Voltage Power 10 or less over 10 to 20 over 20 All 0.45-0.50 0.25-0.30 0.15-0.20 0.15 max. 1.98 -1.73 3.87 -3.18 6.6 -4.9 6.6 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 All LV PCB 50 30 25 20 15 12 10 9 7 5 1.7321 3.1798 3.8730 4.8990 6.5912 8.2731 9.9499 11.7221 14.2507 19.9750 1.000 0.847 0.805 0.762 0.718 0.691 0.673 0.659 0.645 0.627 1.000 1.000 0.950 0.899 0.847 0.815 0.794 0.778 0.761 0.740 1.000 1.000 1.000 1.000 0.942 0.907 0.883 0.865 0.847 0.823 1.000 1.000 1.000 1.000 1.000 0.962 0.937 0.918 0.899 0.874 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. X 1 /R 1 = test X/R value. X 2 /R 2 = X/R at point where breaker is applied. MF 2 1 2.718 2π ( ) X R ⁄ ( ) ⁄ – + [ ] 2.29 -------------------------------------------------------------- - = MF 1 2 2.718 ( ) – 2π ( )/ X R ⁄ ( ) × + 1.25 ------------------------------------------------------------------- = MF 1 2.718 + -π X 2 R 2 ------ . , | ` ⁄ 1 2.718 + -π X 1 R 1 ------ . , | ` ⁄ --------------------------------------- = 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; X I = X I (+) + X I (-) + X I (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 I f E X I ----- 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 Cutler-Hammer A-23 Power Distribution System Design CAT.71.01.T.E A Short-Circuit Calculations Short-Circuit Calculations–Short Cut Method Determination of Short-Circuit Current Note 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 = I SC = (pu I SC ) (I Base 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 2 kVA base 1 ------------------------------- (pu impedance on kVA base 1) × = 2 kVA base 2 kVA base 1 ------------------------------- (% impedance on kVA base 1) × = Z percent impedance 100 ------------------------------------------------------ (ohms impedance) kV ( ) 2 ---------------------------------------------------- - (kVA base) 1000 ( ) ------------------------------ = = Z (ohms impedance) kV ( ) 2 ---------------------------------------------------- - (kVA base) 10 ( ) ------------------------------ = (% impedance) kV ( ) 2 (10) kVA base -------------------------------------------------------------------- Z kVA base in study power-source kVA fault capacity ------------------------------------------------------------------------------------------- = Z kVA base in study (short-circuit current) 3 ( )(kV of source) ---------------------------------------------------------------------------------------------------------------- = 3 ( ) 3-phase kVA 3 ( ) kV ( ) ----------------------------------- 1-phase kVA kV line-to-neutral ------------------------------------------------ I SC 1.0 puZ ----------- = 3-phase kVA base puZ ( ) 3 ( ) kV ( ) -------------------------------------------------- 1-phase kVA base puZ ( ) kV ( ) -------------------------------------------------- (3-phase kVA base) (100) (%Z) 3 ( ) kV ( ) --------------------------------------------------------------------- - 1-phase kVA base (100) (%Z) kV ( ) ----------------------------------------------------------------- - (kV) (1000) 3 (ohms Z) ---------------------------------- - kVA base puZ ( ) -------------------------- (kVA base) (100) %Z --------------------------------------------- - kV ( ) 2 1000 ( ) ohms Z --------------------------------- = = 3(line-to-neutral kV) 2 1000 ( ) (ohms Z) ----------------------------------------------------------------------------- CAT.71.01.T.E Cutler-Hammer A-24 January 1999 Power Distribution System Design A Utility Source 500 MVA 1,000 kVA 5.75% 480 Volts Switchboard Fault 100 Ft. 3-350 Kcmil Cable in Steel Conduit Mixed Load — Motors and Lighting Each Feeder — 100 Ft. of 3-350 Kcmil Cable in Steel Conduit Feeding Lighting and 250 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: Z TOTAL = Z 1 + Z 2 + ... +Z n Combining Parallel Impedances: Z TOTAL 1 = Z 1 1 + Z 2 1 + ... Z n 1 .0595 pu Short-Circuit Calculations 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 conductors Circuit length: 100 ft., in steel (magnetic) conduit Impedance Z = 0.00619 ohms/100 ft. Z TOT = 0.00619 ohms (100 circuit feet) D. Fault current calculations (combining impedances arithmetically, using approximate “short cut” method—see Note 4, page A-23) Equation Step (See page A-23) Calculation 1 – Select 1000 kVA as most convenient base, since all data except utility source is on secondary of 1000 kVA transformer. 2 4(a) Utility per unit impedance 3 3(a) Transformer per unit impedance = 4 4(a) and Motor contribution per unit impedance = 9(c) 5 3(a) Cable impedance in ohms (see above) = 0.00619 ohms Cable impedance per unit = 6 6(d) Total impedance to switchboard fault = 0.0507 pu (see diagram above) Symmetrical short-circuit current at switchboard fault = 7 6(d) Total impedance to cable fault = 0.0777 pu (see diagram above) Symmetrical short-circuit current at cable fault = Z pu kVA base utility fault kVA ------------------------------------------- 1000 500,000 --------------------- 0.002 pu = = = = Z pu %Z 100 ---------- 5.75 100 ----------- 0.0575 pu = = = Z pu kVA base 4 x motor kVA ---------------------------------------- 1000 4 x 250 -------------------- 1.00 pu = = = Z pu (ohms) (kVA base) kV ( ) 2 1000 ( ) --------------------------------------------------- - 0.00619 ( ) 1000 ( ) 0.480 ( ) 2 1000 ( ) --------------------------------------------- 0.027pu = = = 3-phase kVA base Z pu ( ) 3 ( ) kV ( ) -------------------------------------------------- 1000 0.0507 ( ) 3 ( ) 0.480 ( ) -------------------------------------------------------- 23,720 Amps rms = = 3-phase kVA base Z pu ( ) 3 ( ) kV ( ) -------------------------------------------------- 1000 0.0777 ( ) 3 ( ) 0.480 ( ) -------------------------------------------------------- 15 480 Amps rms , = = January 1999 Cutler-Hammer A-25 Power Distribution System Design CAT.71.01.T.E A R Syst = 0.00054 R Cond = 0.00677 R Tfmr = 0.0164 R Total = 0.02371 F 1 R Syst = 0.00356 R Cond = 0.00332 R Tfmr = 0.0227 R Total = 0.02958 F 1 R Syst = 0.00054 R Cond = 0.00677 R Tfmr = 0.0246 R Total = 0.03191 F 2 X Syst = 0.00356 X Cond = 0.00332 X Tfmr = 0.0272 X Total = 0.03408 F 2 240 Volts F1 120 Volts F2 Half-winding of Transformer Full-winding of Transformer { Multiply % R by 1.5 Multiply % 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 Ohms X = 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 Z X = 0.9887 Z Short-Circuit Calculations Deriving Transformer R and X: X = 6.6 R Z = R = R = 0.1498Z X = 6.6R X = 0.9887Z X R ---- 6.6 = X 2 R 2 + 6.6R ( ) 2 R 2 + 43.56R 2 R 2 + 44.56R 2 6.6753R = = = = Z 6.6753 ------------------ Example No. 2 Fault Calculation — Secondary Side of Single-Phase Transformer A. System Diagram R Syst = 2 (0.1498 x Z) = 0.00054 pu X Syst = 2 (0.9887 x Z) = 0.00356 pu R Cond = 2 = 0.00677 pu X Cond = 2 = 0.00332 pu R Tfmr = = 0.0164 pu X Tfmr = = 0.0277 pu R Tfmr = 1.5 = 0.0246 pu X Tfmr = 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 × -------------------------------------- . , | ` 1.64 100 ----------- 2.27 100 ----------- 1.64 100 ----------- . , | ` 2.27 100 ----------- . , | ` 0.02371 ( ) 2 0.02958 ( ) 2 + 0.03191 ( ) 2 0.03408 ( ) 2 + Z Syst = (From page A-23, Formula 4(b) ) 75 3 0.480 × 50,000 × ----------------------------------------------------- 0.0018 pu = D. Impedance and Fault Current Calculations—75 kVA Base Œ Z Cond = (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. Œ 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 Cutler-Hammer A-26 January 1999 Power Distribution System Design 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 I f = 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 Cutler-Hammer A-27 Power Distribution System Design CAT.71.01.T.E A How to Calculate Short-Circuit Currents at Ends of Conductors Method 2–Chart Approximate Method The chart method is based on the following: Motor Contribution For 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 Conductors The 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 Your Conductor is: Use Equivalent Arrangement 3 – No. 4/0 cables 4 – No. 2/0 cables 3 – 2000 kcmil cables 5 – 400 kcmil cables 6 – 300 kcmil cables 800 Amp busway 1000 Amp busway 1600 Amp busway 2 – 500 kcmil 2 – 500 kcmil 4 – 750 kcmil 4 – 750 kcmil 4 – 750 kcmil 2 – 500 kcmil 2 – 500 kcmil 4 – 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 One Obtain 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 Two Select 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 Three Select 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 Four Select 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 Five Enter 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 Six The 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 5000 0 2.5 5.0 7.5 10.0 12.5 15.0 F a u l t C u r r e n t i n T h o u s a n d s o f A m p e r e s ( S y m . ) Distance in Feet from Transformer to Breaker Location Chart 1 – 225 kVA Transformer/4.5% Impedance/208 Volts B F 4 – 750 kcmil 2 – 500 kcmil 250 kcmil #1/0 AWG #4 AWG 4 – 750 kcmil 2 – 500 kcmil 250 kcmil #1/0 AWG #4 AWG UTILITY KVA A INFINITE B 500,000 C 250,000 D 150,000 E 100,000 F 50,000 CAT.71.01.T.E Cutler-Hammer A-28 January 1999 Power Distribution System Design A 0 2 5 10 20 50 100 200 500 1000 2000 5000 0 20 40 60 80 100 120 F a u l t C u r r e n t i n T h o u s a n d s o f A m p e r e s ( S y m . ) Distance in Feet from Transformer to Breaker Location Chart 7 – 2000 kVA Transformer/5.5% Impedance/208 Volts B F 4 – 750 kcmil 2 – 500 kcmil 250 kcmil #1/0 AWG #4 AWG 4 – 750 kcmil 2 – 500 kcmil 250 kcmil #1/0 AWG #4 AWG UTILITY KVA A INFINITE B 500,000 C 250,000 D 150,000 E 100,000 F 50,000 0 2 5 10 20 50 100 200 500 1000 2000 5000 0 20 40 60 80 100 120 F a u l t C u r r e n t i n T h o u s a n d s o f A m p e r e s ( S y m . ) Distance in Feet from Transformer to Breaker Location Chart 6 – 1500 kVA Transformer/5.5% Impedance/208 Volts B F 4 – 750 kcmil 2 – 500 kcmil 250 kcmil #1/0 AWG #4 AWG 4 – 750 kcmil 2 – 500 kcmil 250 kcmil #1/0 AWG #4 AWG UTILITY KVA A INFINITE B 500,000 C 250,000 D 150,000 E 100,000 F 50,000 0 2 5 10 20 50 100 200 500 1000 2000 5000 0 10 20 30 40 50 60 F a u l t C u r r e n t i n T h o u s a n d s o f A m p e r e s ( S y m . ) Distance in Feet from Transformer to Breaker Location Chart 5 – 1000 kVA Transformer/5.5% Impedance/208 Volts B F 4 – 750 kcmil 2 – 500 kcmil 250 kcmil #1/0 AWG #4 AWG 4 – 750 kcmil 2 – 500 kcmil 250 kcmil #1/0 AWG #4 AWG UTILITY KVA A INFINITE B 500,000 C 250,000 D 150,000 E 100,000 F 50,000 0 2 5 10 20 50 100 200 500 1000 2000 5000 0 5 10 15 20 25 30 F a u l t C u r r e n t i n T h o u s a n d s o f A m p e r e s ( S y m . ) Distance in Feet from Transformer to Breaker Location Chart 2 – 300 kVA Transformer/4.5% Impedance/208 Volts B F 4 – 750 kcmil 2 – 500 kcmil 250 kcmil #1/0 AWG #4 AWG 4 – 750 kcmil 2 – 500 kcmil 250 kcmil #1/0 AWG #4 AWG UTILITY KVA A INFINITE B 500,000 C 250,000 D 150,000 E 100,000 F 50,000 0 2 5 10 20 50 100 200 500 1000 2000 5000 0 5 10 15 20 25 30 F a u l t C u r r e n t i n T h o u s a n d s o f A m p e r e s ( S y m . ) Distance in Feet from Transformer to Breaker Location Chart 3 – 500 kVA Transformer/4.5% Impedance/208 Volts B F 4 – 750 kcmil 2 – 500 kcmil 250 kcmil #1/0 AWG #4 AWG 4 – 750 kcmil 2 – 500 kcmil 250 kcmil #1/0 AWG #4 AWG UTILITY KVA A INFINITE B 500,000 C 250,000 D 150,000 E 100,000 F 50,000 0 2 5 10 20 50 100 200 500 1000 2000 5000 0 10 20 30 40 50 60 F a u l t C u r r e n t i n T h o u s a n d s o f A m p e r e s ( S y m . ) Distance in Feet from Transformer to Breaker Location Chart 4 – 750 kVA Transformer/5.5% Impedance/208 Volts B F 4 – 750 kcmil 2 – 500 kcmil 250 kcmil #1/0 AWG #4 AWG 4 – 750 kcmil 2 – 500 kcmil 250 kcmil #1/0 AWG #4 AWG UTILITY KVA A INFINITE B 500,000 C 250,000 D 150,000 E 100,000 F 50,000 How to Calculate Short-Circuit Currents at Ends of Conductors January 1999 Cutler-Hammer A-29 Power Distribution System Design CAT.71.01.T.E A 0 2 5 10 20 50 100 200 500 1000 2000 5000 0 5 10 15 20 25 30 F a u l t C u r r e n t i n T h o u s a n d s o f A m p e r e s ( S y m . ) Distance in Feet from Transformer to Breaker Location Chart 11 – 1000 kVA Transformer/5.5% Impedance/480 Volts B F UTILITY KVA A INFINITE B 500,000 C 250,000 D 150,000 E 100,000 F 50,000 4 – 750 kcmil 2 – 500 kcmil 250 kcmil #1/0 AWG #4 AWG 4 – 750 kcmil 2 – 500 kcmil 250 kcmil #1/0 AWG #4 AWG 0 2 5 10 20 50 100 200 500 1000 2000 5000 0 10 20 30 40 50 60 F a u l t C u r r e n t i n T h o u s a n d s o f A m p e r e s ( S y m . ) Distance in Feet from Transformer to Breaker Location Chart 13 – 2000 kVA Transformer/5.5% Impedance/480 Volts B F UTILITY KVA A INFINITE B 500,000 C 250,000 D 150,000 E 100,000 F 50,000 4 – 750 kcmil 2 – 500 kcmil 250 kcmil #1/0 AWG #4 AWG 4 – 750 kcmil 2 – 500 kcmil 250 kcmil #1/0 AWG #4 AWG 0 2 5 10 20 50 100 200 500 1000 2000 5000 0 10 20 30 40 50 60 F a u l t C u r r e n t i n T h o u s a n d s o f A m p e r e s ( S y m . ) Distance in Feet from Transformer to Breaker Location Chart 12 – 1500 kVA Transformer/5.5% Impedance/480 Volts B F UTILITY KVA A INFINITE B 500,000 C 250,000 D 150,000 E 100,000 F 50,000 4 – 750 kcmil 2 – 500 kcmil 250 kcmil #1/0 AWG #4 AWG 4 – 750 kcmil 2 – 500 kcmil 250 kcmil #1/0 AWG #4 AWG 0 2 5 10 20 50 100 200 500 1000 2000 5000 0 5 10 15 20 25 30 F a u l t C u r r e n t i n T h o u s a n d s o f A m p e r e s ( S y m . ) Distance in Feet from Transformer to Breaker Location Chart 10 – 750 kVA Transformer/5.5% Impedance/480 Volts B F UTILITY KVA A INFINITE B 500,000 C 250,000 D 150,000 E 100,000 F 50,000 4 – 750 kcmil 2 – 500 kcmil 250 kcmil #1/0 AWG #4 AWG 4 – 750 kcmil 2 – 500 kcmil 250 kcmil #1/0 AWG #4 AWG 0 2 5 10 20 50 100 200 500 1000 2000 5000 0 5 10 15 20 25 30 F a u l t C u r r e n t i n T h o u s a n d s o f A m p e r e s ( S y m . ) Distance in Feet from Transformer to Breaker Location Chart 9 – 500 kVA Transformer/4.5% Impedance/480 Volts B F UTILITY KVA A INFINITE B 500,000 C 250,000 D 150,000 E 100,000 F 50,000 4 – 750 kcmil 2 – 500 kcmil 250 kcmil #1/0 AWG #4 AWG 4 – 750 kcmil 2 – 500 kcmil 250 kcmil #1/0 AWG #4 AWG 0 2 5 10 20 50 100 200 500 1000 2000 5000 0 2 4 6 8 10 12 F a u l t C u r r e n t i n T h o u s a n d s o f A m p e r e s ( S y m . ) Distance in Feet from Transformer to Breaker Location Chart 8 – 300 kVA Transformer/4.5% Impedance/480 Volts B F 4 – 750 kcmil 2 – 500 kcmil 250 kcmil #1/0 AWG #4 AWG UTILITY KVA A INFINITE B 500,000 C 250,000 D 150,000 E 100,000 F 50,000 4 – 750 kcmil 2 – 500 kcmil 250 kcmil #1/0 AWG #4 AWG How to Calculate Short-Circuit Currents at Ends of Conductors CAT.71.01.T.E Cutler-Hammer A-30 January 1999 Power Distribution System Design 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 5.5 2 1.46 2 – 5.30% = = Method 2: Using same values above. See Tables A31, A32 and A33 on page A-61 for loss data on transformers. %R I R Losses 2 10 kVA × -------------------------- = 7300 10 500 × --------------------- 1.46 = %X 5.5 2 1.46 2 – 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. I sc I FLC 100 %Z -------- × = January 1999 Cutler-Hammer A-31 Power Distribution System Design CAT.71.01.T.E A Voltage Drop Voltage Drop Tables Œ 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 0.577 1-phase, 2-wire x 1.155 1-phase, 3-wire, phase-to-phase x 1.155 1-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 t 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. 4 No. 2 to 3/0 4/0 to 500 kcmil 600 to 1000 kcmil 5.0 5.0 5.0 5.0 4.7 4.2 3.1 2.6 4.7 3.7 2.6 2.1 4.6 3.5 2.3 1.5 4.6 3.2 1.9 1.3 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-feet 2. Divided by 100 = 186 3. Table: 2/0 copper, magnetic conduit, 80% pf = 0.0187 186 x 0.0187 = 3.48 volts drop 3.48 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 2 100 -------- 208 4.16 volts = × = 4.16 175 250 × ------------------------ 0.0000951 = 0.0000951 100 0.00951 = × Œ Busway voltage drop tables are shown in section H2 of this catalog. Voltage Drop CAT.71.01.T.E Cutler-Hammer A-32 January 1999 Power Distribution System Design A Table A12: Voltage Drop Volts 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 14 12 10 8 .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 6 4 2 1 .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 1/0 2/0 3/0 4/0 .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 250 300 350 500 .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 600 750 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 12 10 8 .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 6 4 2 1 .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 1/0 2/0 3/0 4/0 .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 250 300 350 500 .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 600 750 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 A-33 Power Distribution System Design 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 Œ Starting Torque Starting Current  How Started Starting Current % Full-Load Ž Starting Torque per Unit of Full Load Torque Full-Load Amps per kVA Generator Capacity for Each 1% Voltage Drop 1750 Rpm Motor 1150 Rpm Motor Ž 850 Rpm Motor Design B Normal Normal Across-the-Line Resistance Autotransformer 600-700 480-560  375-450  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 Resistance Autotransformer 500-600 400-480  320-400  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 Resistance Autotransformer 500-600 400-480  320-400  . . . . . . . . . . . . .2 to 2.5 1.28 to 1.6 1.28 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% current for 100% Torque . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .0655 Synchronous (for compressors) Synchronous (for centrifugal pumps) Low Low . . . . . . . . Across-the-Line Across-the-Line Autotransformer 300 450-550 288-350  40% Starting, 40% Pull-In 60% Starting, 110% Pull-In 38% Starting, 110% Pull-In .0218 .0145-.0118 .0228-.0197 Œ Consult NEMA MG-1 sections 1 and 12 for the exact definition of the design letter.  In each case, a solid-state reduced voltage starter can be adjusted and controlled to provide the re- quired inrush current and torque characteristics. Ž Where accuracy is important, request the code let- ter of the the motor and starting and breakdown torques from the motor vendor.  Using 80% taps. CAT.71.01.T.E Cutler-Hammer A-34 January 1999 Power Distribution System Design 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, volts E S = Source voltage, line-to-neutral, volts I = Line (Load) current, amps R = Circuit (branch, feeder) resistance, ohms X = 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 kV E S = Sending Line-Line voltage in kV MVA R = Receiving 3-phase mVA MVA S = Sending 3-phase mVA Z = Impedance between and receiving ends γ = The angle of impedance Z θ R = Receiving end PF θ S = Sending end PF, positive when lagging E VD IR cos θ IX SIN θ + = E VD E S IR COS θ + + = IXSINθ E S 2 IXcosθ IRSINθ – ( ) 2 – – E VD E R θ cos ( I R ) 2 E R θ sin I X ) 2 E – R + ( + + = E S 2 E R 2 ZMVA R 2 E R 2 ------------------- 2ZMVA R COS γ θ R – ( ) + + = E R 2 E S 2 ZMVA R 2 E S 2 ------------------- 2ZMVA S COS γ θ S – ( ) – + = 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. 158 1000 10 × ------------------------ 0.0158 amps per kVA per 1% voltage drop = January 1999 Cutler-Hammer A-35 Power Distribution System Design CAT.71.01.T.E A Capacitor Switching Device Selections Capacitor Switching Device Selections 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). Œ 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 DevicesŒ Capacitor Rating Amperes Capacitor Rating Amperes Volts kvar Capaci- tor Rated Current Safety Switch Fuse Rating Molded Case Breaker Trip Rating DSII Breaker Trip Rating Volts kvar Capaci- tor Rated Current Safety Switch Fuse Rating Molded Case Breaker Trip Rating DSII Breaker Trip Rating 240 2 1 ⁄2 5 7 1 ⁄2 10 15 20 25 30 45 50 60 75 90 100 120 125 135 150 180 200 225 240 250 270 300 360 375 6.0 12.0 18.0 24.1 36.1 48.1 60 72.2 108 120 144 180 217 240 289 301 325 361 433 480 541 578 602 650 720 866 903 15 20 30 40 60 80 100 125 200 200 250 300 400 400 500 500 600 600 800 800 900 1000 1000 1200 1200 1600 1500 15 20 30 40 70 90 100 125 175 200 225 275 350 400 500 500 500 600 700 800 900 900 900 100 0 . . . . . . . . . . . . 15 20 30 40 50 70 90 100 150 175 200 250 300 350 400 450 500 500 600 700 800 800 900 1000 1200 1200 1200 480 120 125 150 160 180 200 225 240 250 300 320 360 375 400 450 144 150 180 192 216 241 271 289 301 361 385 433 451 481 541 250 250 300 350 400 400 500 500 500 600 700 800 800 800 900 225 225 300 300 350 400 500 500 500 600 600 700 700 800 900 200 200 250 300 300 350 400 400 400 500 600 600 600 800 800 600 5 7 1 ⁄2 10 15 20 25 30 35 40 45 50 60 75 80 100 120 125 150 160 180 200 225 240 250 300 320 360 375 400 450 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 96.2 115 120 144 154 173 192 217 231 241 289 306 347 361 385 433 15 15 20 25 35 40 50 60 70 80 80 100 125 150 175 200 200 250 300 300 350 400 400 400 500 600 600 600 700 800 15 15 15 30 30 40 50 50 70 70 100 100 125 125 150 175 200 225 250 300 300 350 350 400 500 500 600 600 600 700 15 15 15 20 30 40 40 50 70 70 70 90 100 125 150 175 175 200 225 250 300 300 350 350 400 500 500 500 600 600 480 2 5 7 1 ⁄2 10 15 20 25 30 35 40 45 50 60 75 80 90 100 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 96.2 108 120 15 15 15 20 30 40 50 60 70 80 90 100 125 150 175 200 200 15 15 15 20 30 40 50 70 70 100 100 100 125 150 150 175 200 15 15 15 20 30 40 50 50 60 70 80 90 100 125 150 150 175 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 Cutler-Hammer A-36 January 1999 Power Distribution System Design 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. Definitions kvar—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 % AR Actual 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 φ 1 to COS φ 2 , the formula is: kVAC = KW (tan ø 1 - tan φ 2 ) Actual kvar = Nameplate kvar Applied 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- power Rating Nominal Motor Speed in Rpm and Number of Poles 3600 2 1800 4 1200 6 900 8 720 10 600 12 kvar % AR kvar % AR kvar % AR kvar % AR kvar % AR kvar % AR 5 7 1 ⁄2 10 15 20 2 2 1 ⁄2 3 5 6 13 13 12 11 10 2 3 3 5 6 17 16 14 14 13 3 3 4 5 7 1 ⁄2 23 19 18 17 16 3 4 5 7 1 ⁄2 7 1 ⁄2 28 25 24 21 20 4 6 6 7 1 ⁄2 10 36 33 30 27 25 5 7 1 ⁄2 10 10 15 49 46 39 34 31 25 30 40 50 60 7.5 7.5 7.5 10 10 10 10 10 10 9 6 7.5 10 15 15 13 12 11 11 11 7 1 ⁄2 10 15 20 25 16 16 15 15 14 10 10 15 20 20 19 18 18 18 17 10 15 15 20 25 23 21 20 19 19 20 20 25 30 35 31 28 28 28 27 75 100 125 150 200 15 20 25 25 35 9 9 9 9 9 20 25 30 30 40 10 10 9 9 9 25 30 30 35 50 13 11 11 11 10 25 30 40 45 60 14 13 13 12 12 30 35 40 50 70 16 15 14 13 13 40 45 50 60 80 19 17 17 17 17 250 300 350 400 450 40 45 50 70 75 9 9 9 8 7 50 60 70 70 80 8 8 7 7 7 60 70 80 80 100 10 10 10 10 9 70 80 100 110 120 12 12 12 12 11 80 90 100 125 125 12 12 12 12 12 100 110 125 150 150 17 17 16 16 16 500 90 7 90 7 120 9 125 11 140 12 175 16 Table A16: Design C–High Starting Torque, Normal Current Induction- Motor Horsepower Rating Nominal Motor Speed in Rpm and Number of Poles 1800 4 1200 6 900 8 720 10 kvar % AR kvar % AR kvar % AR kvar % AR 5 7 1 ⁄2 10 15 20 2 3 3 4 4 18 18 15 15 15 2 1 ⁄2 3 4 5 5 23 19 17 17 17 4 4 5 7 1 ⁄2 7 1 ⁄2 29 25 22 20 19 . . . . . . . . . . . . . . . . . . . . . . . . . 25 30 40 50 60 5 5 10 15 15 13 13 13 13 12 5 7 1 ⁄2 10 10 20 15 15 15 15 15 10 10 15 20 25 19 19 18 18 18 . . . 20 . . . 25 25 . . 23 . . 23 23 75 100 125 150 200 20 25 30 35 45 11 10 10 9 9 20 25 35 40 50 13 12 11 10 10 30 40 40 45 60 17 17 14 13 13 35 40 45 50 60 23 17 16 12 12 250 300 350 50 60 70 8 8 8 60 70 75 10 10 9 70 80 90 13 12 12 75 80 100 12 12 12 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 X S is the impedance of the circuit elements from the utility to the location of the capaci- tors. kVA B 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.” % VR kVAC X S kVA B --------------------- = January 1999 Cutler-Hammer A-37 Power Distribution System Design CAT.71.01.T.E A Overcurrent Protection and Coordination Time-Current Characteristic Curves for Typical Power Distribution System Protective Devices Coordination Analysis. Overcurrent Protection and 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. ർ —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 Ꭽ trip curve. Ꭽ —CB (175A) coordinates selectively with motor ർ on starting and running and with all upstream devices, except that CB Ꭾ will trip first on ground faults. Ꭾ —CB (600A) coordinates selectively with all upstream and downstream devices, except will trip before Ꭽ on limited ground faults, since Ꭽ has no ground fault trips. Ꭿ —Main CB (1600A) coordinates selectively with all downstream devices and with primary fuse ൳ , for all faults on load side of CB. ൳ —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, I P V S V P ------- I S × = 1000 10 9 7 6 .9 4 5 .5 .3 .2 100 90 30 20 500 300 200 1 0 ,0 0 0 8 0 0 0 6 0 0 0 9 0 0 0 7 0 0 0 5 0 0 0 4 0 0 0 3 0 0 0 2 0 0 0 1 0 0 0 8 0 0 6 0 0 9 0 0 7 0 0 5 0 0 4 0 0 3 0 0 2 0 0 1 0 0 8 0 60 9 0 7 0 50 40 30 20 10 9 8 7 5 6 4 3 1 2 .9 .8 .7 .5 .6 600 900 800 700 400 40 8 50 80 60 70 3 1 2 .8 .7 .6 .4 .1 .09 .08 .07 .06 .05 .04 .03 .02 .01 1 0 ,0 0 0 8 0 0 0 6 0 0 0 9 0 0 0 7 0 0 0 5 0 0 0 4 0 0 0 3 0 0 0 2 0 0 0 1 0 0 0 8 0 0 6 0 0 9 0 0 7 0 0 5 0 0 4 0 0 3 0 0 2 0 0 1 0 0 8 0 60 9 0 7 0 50 40 30 20 10 9 8 7 5 6 4 3 1 2 .9 .8 .7 .5 .6 1000 10 9 7 6 .9 4 5 .5 .3 .2 100 90 30 20 500 300 200 600 900 800 700 400 40 8 50 80 60 70 3 1 2 .8 .7 .6 .4 .1 .09 .08 .07 .06 .05 .04 .03 .02 .01 T I M E I N S E C O N D S SCALE X 100 = CURRENT IN AMPERES AT 480 VOLTS SCALE X 100 = CURRENT IN AMPERES AT 480 VOLTS T I M E I N S E C O N D S 250 MVA 4.16 kV 250 Amps 1000 kVA 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 current including motor contribution. D ANSI 3-Phase Thru Fault Protection Curve (More Than 10 in Lifetime) C B A C B A B C Transformer Inrush Ground Fault Trip M a x . 4 8 0 V F a u l t M a x . 3 Ø 4 . 1 6 k V F a u l t M CAT.71.01.T.E Cutler-Hammer A-38 January 1999 Power Distribution System Design 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- 1 0.866 ------------- or 1.1547 I 480V I 4160V 4160 480 ----------- × = 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 I 2 t or I 4 t feature for improved coordination with other devices having I 2 t or I 4 t (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 I FL 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 Cutler-Hammer A-39 Power Distribution System Design CAT.71.01.T.E A Overcurrent Protection and Coordinaton It is recommended that in solidly grounded 480/277-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 Settings For 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 (I p ) and heat energy (I 2 t) 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 I 2 t 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 I p and I 2 t 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 Power Distribution System Design A Grounding 3. Medium-Voltage System – Grounding Table A17: Features of Ungrounded and Grounded Systems (from ANSI C62.92) A Ungrounded B Solidly Grounded C Reactance Grounded D Resistance Grounded E Resonant Grounded (1) Apparatus Insulation Fully insulated Lowest Partially graded Partially graded Partially graded (2) Fault to Ground 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 A-41 Power Distribution System Design CAT.71.01.T.E A Grounding Table A17: Features of Ungrounded and Grounded Systems (Continued) A Ungrounded B Solidly Grounded C Reactance Grounded D Resistance Grounded E Resonant Grounded (9) Telephone Interference 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 Must be isolated for each fault 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 to Interconnection 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 fault conditions Interrupting capacity determined by three-phase fault conditions (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 Frequency Rms Line - Ground Voltage Rms Line - Line Voltage at Fault Location 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 Cutler-Hammer A-42 January 1999 Power Distribution System Design A Grounding Figure 2. Ungrounded Systems Figure 1. Solidly-Grounded Systems Table A18: Characteristics of Grounding Grounding Classes and Means Ratios of Symmetrical Component ParametersŒ Percent Fault Current Per Unit Transient LG Voltage A. Effectively  1. Effective 2. Very effective X 0 /X 1 0-3 0-1 R 0 /X 1 0-1 0-0.1 R 0 /X 0 -- --  >60 >95 Ž ≤2 <1.5 B. Noneffectively 1. Inductance a. Low inductance b. High inductance 2. Resistance a. Low resistance b. High resistance 3. Inductance and resistance 4. Resonant 5. Ungrounded/capacitance a. Range A b. Range B 3-10 >10 0-10 >10  -∞ to -40‘ -40 to 0 0-1 >100 -- -- -- -- <2 ≥2 ≤(-1) >2 -- -- >25 <25 <25 <1 <10 <1 <8 >8 <2.3 ≤2.73 <2.5 ≤2.73 ≤2.73 ≤2.73 ≤3 >3 ’ 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 Point The 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 ∅A Neutral Center-Tapped (High-Leg) Delta Grounded Wye • • • • • ∅C ∅A ∅B Neutral N • ∅A ∅B ∅C • • • Corner-Grounded Delta Œ 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.  Ground-fault current in percentage of the three- phase short-circuit value. Ž Transient line-to-ground voltage, following the sudden initiation of a fault in per unit of the crest of the prefault line-to-ground operating voltage for a simple, linear circuit.  In linear circuits, Class A1 limits the fundamental line-to-ground voltage on an unfaulted phase to 138% of the prefault voltage; Class A2 to less than 110%.  See ANSI 62.92 para. 7.3 and precautions given in application sections. ‘ Usual isolated neutral (ungrounded) system for which the zero-sequence reactance is capacitive (negative). ’ Same as NOTE (6) and refer to ANSI 62.92 para. 7.4. Each case should be treated on its own merit. Figure 3. Resistance-Grounded Systems • Resistance-Grounded Wye • • • ∅C ∅A ∅B R N • • ∅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 A-43 Power Distribution System Design 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 Cutler-Hammer A-44 January 1999 Power Distribution System Design 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 or a combination of the sensing methods de- pending upon the complexity of the system and the degree of service continuity and Zero Sequence Sensor Main Neutral Typical Feeder Alternate Sensor Location Typical 4W Load GFR GFR Typical 4W Load Sensor Polarity Marks Neutral Typical Feeder Main Residual Sensors Main GFR Neutral Typical Feeder Sensor Grounding Electrode Conductor Equipment Grounding Conductor Grounding Electrode Typical 4W Load Service Transformer Ground Fault Protection January 1999 Cutler-Hammer A-45 Power Distribution System Design CAT.71.01.T.E A system 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 Information AD 29-762 Type GFR Ground Fault Protection System DB 28-850 Systems Pow-R Breakers TD.44A.01.T.E Type DSII Metal-Enclosed Low-Voltage Switchgear IB 32-698A C-HRG “Safe Ground” Low- Voltage High Resistance Pulsing Ground System PRSC-4E System Neutral Grounding and Ground Fault Protection (ABB Publication) PB 2.2 NEMA Application Guide for Ground Fault Protective Devices for Equipment IEEE Grounding of Industrial and Standard 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 2 Tie M1 a T a Source 1 Source 2 Neutral Neutral Typical Feeder Typical Feeder Center Point Grounding Electrode Typical 4W Load Typical 4W Load M1 Sensor Tie Sensor GFR 1 GFR T GFR 2 M2 M2 Sensor a Figure 4. Dual Source System – Single Point Grounding Ground Fault Protection/Lighting and Surge Protection CAT.71.01.T.E Cutler-Hammer A-46 January 1999 Power Distribution System Design A Grounding 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 A-47 Power Distribution System Design 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 Terms Power 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, Power Monitoring, Analysis CAT.71.01.T.E Cutler-Hammer A-48 January 1999 Power Distribution System Design 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 A-49 Power Distribution System Design 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 h 2 (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 System Dedicated System 10 5 2 16,400 22,800 36,500 3% 5% 10% *Special system are those where the rate of change of voltage of the notch might misstriggen an event. A N is volt-microseconds, C is the impe- ance ratio of total impedance to impedance at common 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 Maximum Individual Harmonic 3.0% 1.5% 1.0% Total Harmonic Distortion 5.0% 2.5% 1.5% V h V 1 ------- V h 2 h 2 = h h max = ∑ ¹ ¹ ' ' ¹ ¹ 1 2 ⁄ V h = 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<50 50<100 100<1000 >1000 4.0 7.0 10.0 12.0 15.0 2.0 3.5 4.5 5.5 7.0 1.5 2.5 4.0 5.0 6.0 0.6 1.0 1.5 2.0 2.5 0.3 0.5 0.7 1.0 1.4 5.0 8.0 12.0 15.0 20.0 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 limited to 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 Power Distribution System Design 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 the 208-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- or 120-volt ballasts. However, in almost all cases, 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 for receptacle 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 A-51 Power Distribution System Design 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 Œ Œ Œ Œ Œ Œ Œ Œ Œ Spare Building and Miscellaneous Loads Include Ground Fault Trip. 4000A Main CB Automatic Transfer Switch Typical Gen. CB 4000A at 480Y/277V 100,000A Available Fault Current Utility Metering CTs PTs Utility Service HVAC Feeder Busway Riser Elevator Riser Elevator Panel (Typical Every Third Floor) 480Y/277V Panel 208Y/120V Panel Emergency Lighting Riser HVAC Panel Dry Type Transformer 480 -208Y/120V (Typical Every Floor) Emergency Lighting Panel Typical Typical Typical Typical Typical Typical Typical Emergency or Standby Generator CAT.71.01.T.E Cutler-Hammer A-52 January 1999 Power Distribution System Design 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 replaced by 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 A-53 Power Distribution System Design 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 Power Distribution System Design 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 A-55 Power Distribution System Design 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 Power Distribution System Design A Sound Levels Sound Levels of Electrical Equipment 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 Studios Theatres and Music Rooms Hospitals, Auditoriums and Churches Classrooms and Lecture Rooms Apartments and Hotels Private Offices and Conference Rooms Stores Residence (Radio, TV Off) and Small Offices Medium Office (3 to 10 Desks) Residence (Radio, TV On) Large Store (5 or More Clerks) Factory Office Large Office Average Factory Average Street 25-30 db 30-35 35-40 35-40 35-45 40-45 45-55 53 58 60 61 61 64 70 80 Table A23: Maximum Average Sound Levels - Decibels kVA Liquid-Filled Transformers Dry-Type Transformers Self- Cooled Rating (OA) Forced- Air Cooled Rating (FA) Self- Cooled Rating (AA) Forced- Air Cooled Rating (FA) 300 500 750 1000 1500 2000 2500 3000 3750 5000 6000 7500 10000 55 56 58 58 60 61 62 63 64 65 66 67 68 . . 67 67 67 67 67 67 67 67 67 68 69 70 58 60 64 64 65 66 68 68 70 71 72 73 . . 67 67 67 67 68 69 71 71 73 73 74 75 76 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 A-57 Power Distribution System Design 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 C37.100 Definitions for Power Switchgear Available (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 Institute 1430 Broadway New York, New York 10018 212-642-4900 Institute of Electrical and Electronics Engineers 445 Hoes Lane P.O. Box 1331 Piscataway, NJ 08855-9970 201-562-5522 International Association of Electrical Inspectors 930 Busse Highway Park Ridge, IL 60068-2398 708-696-1455 National Electrical Manufacturers Association 2101 L Street, N.W. Washington, DC 20037-1526 202-457-8474 National Fire Protection Association 1 Battery March Drive P.O. Box 9101 Quincy, MA 02269-9959 1-800-344-3555 Underwriters Laboratories, Inc. 333 Pfingsten Road Northbrook, IL 60062 Codes and Standards CAT.71.01.T.E Cutler-Hammer A-58 January 1999 Power Distribution System Design A Table A24: 60 Hz, Induction Motors Hp Full Load Amps (NEC) FLA Minimum Wire Size 75 ° C Copper Ampacity @125% FLA Minimum Conduit Size, In’s. Fuse Size NEC 430-152 Max. Amps  Recommended Cutler-Hammer Circuit Ž Breaker Motor Circuit Protector Type GMCP/HMCP THW THWN XHHN Time Delay Non- Time Delay Size Amps Amps Type Amps Adj. Range 230 Volts, 3-Phase 1 1 1 ⁄ 2 2 3 5 7 1 ⁄ 2 10 15 20 25 30 40 50 60 75 100 125 150 200 3.6 5.2 6.8 9.6 15.2 22 28 42 54 68 80 104 130 154 192 248 312 360 480 12 12 12 12 12 10 8 6 4 4 3 1 2/0 3/0 250 350 (2)3/0 (2)4/0 (2)350 20 20 20 20 20 30 50 65 85 85 100 130 175 200 255 310 400 460 620 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 3 ⁄ 4 1 1 1 1 1 ⁄ 4 1 1 ⁄ 4 1 1 ⁄ 2 2 2 1 ⁄ 2 2 1 ⁄ 2 (2)2 (2)2 (2)2 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 3 ⁄ 4 1 1 1 1 1 ⁄ 4 1 1 ⁄ 2 1 1 ⁄ 2 2 2 1 ⁄ 2 (2)1 1 ⁄ 2 (2)2 (2)2 1 ⁄ 2 10 10 15 20 30 40 50 80 100 125 150 200 250 300 350 450 600 700 1000 15 20 25 30 50 70 90 150 175 225 250 350 400 500 600 800 1000 1200 1600 15 15 15 20 30 50 60 90 100 125 150 150 200 225 300 400 500 600 700 ED ED ED ED ED ED ED ED ED ED ED ED ED ED KD KD LD LD MD 7 7 15 15 30 30 50 70 100 100 150 150 150 250 400 600 600 — — 21-70 21-70 45-150 45-150 90-300 90-300 150-500 210-700 300-1000 300-1000 450-1500 450-1500 750-2500 1250-2500 2000-4000 1800-6000 1800-6000 — — 460 Volts, 3-Phase 1 1 1 ⁄ 2 2 3 5 7 1 ⁄ 2 10 15 20 25 30 40 50 60 75 100 125 150 200 1.8 2.6 3.4 4.8 7.6 11 14 21 27 34 40 52 65 77 96 124 156 180 240 12 12 12 12 12 12 12 10 8 8 8 6 4 3 1 2/0 3/0 4/0 350 20 20 20 20 20 20 20 30 50 50 50 65 85 100 130 175 200 230 310 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 3 ⁄ 4 3 ⁄ 4 3 ⁄ 4 1 1 1 1 ⁄ 4 1 1 ⁄ 4 1 1 ⁄ 2 2 2 2 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 3 ⁄ 4 1 1 1 1 ⁄ 4 1 1 ⁄ 2 1 1 ⁄ 2 2 2 1 ⁄ 2 6 6 6 10 15 20 25 40 50 60 70 100 125 150 175 225 300 350 450 6 10 15 15 25 35 45 70 90 110 125 175 200 250 300 400 500 600 800 15 15 15 15 15 25 35 45 50 70 70 100 110 125 150 175 225 250 350 EHD EHD EHD EHD EHD EHD EHD EHD EHD EHD EHD EHD FDB FDB JD JD JD JD KD 3 7 7 7 15 15 30 30 50 50 70 100 100 150 150 150 250 250 400 9-30 21-70 21-70 21-70 45-150 45-150 90-300 90-300 150-500 150-500 210-700 300-1000 300-1000 450-1500 450-1500 750-2500 1250-2500 1250-2500 2000-4000 575 Volts, 3-Phase 1 1 1 ⁄ 2 2 3 5 7 1 ⁄ 2 10 15 20 25 30 40 50 60 75 100 125 150 200 1.4 2.1 2.7 3.9 6.1 9 11 17 22 27 32 41 52 62 77 99 125 144 192 12 12 12 12 12 12 12 12 10 8 8 6 6 4 3 1 2/0 3/0 250 20 20 20 20 20 20 20 20 30 50 50 65 65 85 100 130 175 200 255 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 3 ⁄ 4 1 1 1 1 1 ⁄ 4 1 1 ⁄ 4 1 1 ⁄ 2 2 2 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 3 ⁄ 4 3 ⁄ 4 1 1 1 1 ⁄ 4 1 1 ⁄ 2 1 1 ⁄ 2 2 3 6 6 10 15 20 20 30 40 50 60 80 100 110 150 175 225 300 350 6 10 10 15 20 30 35 60 70 90 100 125 175 200 250 300 400 450 600 15 15 15 15 15 20 25 40 50 60 60 80 100 125 150 175 200 225 300 HFD HFD HFD HFD HFD HFD HFD HFD HFD HFD HFD HFD HFD HFD HFD HJD HJD HJD HKD 3 3 7 7 15 15 15 30 50 50 50 70 100 100 150 150 250 250 400 9-30 9-30 21-70 21-70 45-150 45-150 45-150 90-300 150-500 150-500 150-500 210-700 300-1000 300-1000 450-1500 450-1500 875-1750 1250-2500 2000-4000 115 Volts, Single-Phase 3 ⁄ 4 1 1 1 ⁄ 2 2 3 5 7 1 ⁄ 2 13.8 16 20 24 34 56 80 12 12 10 10 8 4 3 20 20 30 30 50 85 100 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 3 ⁄ 4 1 1 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 3 ⁄ 4 1 25 30 35 45 60 100 150 45 50 60 80 110 175 250 30 35 40 50 70 100 150 ED ED ED ED ED ED ED Two-Pole Device Not Available 230 Volts, Single-Phase 3 ⁄ 4 1 1 1 ⁄ 2 2 3 5 7 1 ⁄ 2 6.9 8 10 12 17 28 40 12 12 12 12 10 8 8 20 20 20 20 30 50 50 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 3 ⁄ 4 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 1 ⁄ 2 15 15 20 25 30 50 70 25 25 30 40 60 90 125 15 20 25 30 40 60 80 ED ED ED ED ED ED ED Two-Pole Device Not Available Motor Protection Œ 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. Œ These recommendations are based on previous code interpretations. See the current NEC for exact up-to-date information.  Consult fuse manufacturer’s catalog for smaller fuse ratings. Ž Types are for minimum interrupting capacity breakers. Ensure that the fault duty does not exceed breakers I.C. Reference Data – Motor Protection January 1999 Cutler-Hammer A-59 Power Distribution System Design CAT.71.01.T.E A Table 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 Current RMS Symmetrical Amps Rated Load Contin- uous Current, Amps Short-Circuit Current RMS Symmetrical Amps Rated Load Contin- uous Current, Amps Short-Circuit Current RMS Symmetrical Amps Rated Load Contin- uous Current, Amps Short-Circuit Current RMS Symmetrical Amps Trans- former Alone Œ 50% Motor Load  Com- bined Trans- former Alone Œ 100% Motor Load  Com- bined Trans- former Alone Œ 100% Motor Load  Com- bined Trans- former Alone Œ 100% Motor Load  Com- bined 300 5% 50000 100000 150000 250000 500000 Unlimited 834 14900 15700 16000 16300 16500 16700 1700 16600 17400 17700 18000 18200 18400 722 12900 13600 13900 14100 14300 14400 2900 15800 16500 16800 17000 17200 17300 361 6400 6800 6900 7000 7100 7200 1400 7800 8200 8300 8400 8500 8600 289 5200 5500 5600 5600 5700 5800 1200 6400 6700 6800 6800 6900 7000 500 5% 50000 100000 150000 250000 500000 Unlimited 1388 21300 25200 26000 26700 27200 27800 2800 25900 28000 28800 29500 30000 30600 1203 20000 21900 22500 23100 23600 24100 4800 24800 26700 27300 27900 28400 28900 601 10000 10900 11300 11600 11800 12000 2400 12400 13300 13700 14000 14200 14400 481 8000 8700 9000 9300 9400 9600 1900 9900 10600 10900 11200 11300 11500 750 5.75% 50000 100000 150000 250000 500000 Unlimited 2080 28700 32000 33300 34400 35200 36200 4200 32900 36200 37500 38600 39400 40400 1804 24900 27800 28900 29800 30600 31400 7200 32100 35000 36100 37000 37800 38600 902 12400 13900 14400 14900 15300 15700 3600 16000 17500 18000 18500 18900 19300 722 10000 11100 11600 11900 12200 12600 2900 12900 14000 14500 14800 15100 15500 1000 5.75% 50000 100000 150000 250000 500000 Unlimited 2776 35900 41200 43300 45200 46700 48300 5600 41500 46800 48900 50800 52300 53900 2406 31000 35600 37500 39100 40400 41800 9600 40600 45200 47100 48700 50000 51400 1203 15500 17800 18700 19600 20200 20900 4800 20300 22600 23500 24400 25000 25700 962 12400 14300 15000 15600 16200 16700 3900 16300 18200 18900 19500 20100 20600 1500 5.75% 50000 100000 150000 250000 500000 Unlimited 4164 47600 57500 61800 65600 68800 72500 8300 55900 65800 70100 73900 77100 80800 3609 41200 49800 53500 56800 59600 62800 14400 55600 64200 57900 71200 74000 77200 1804 20600 24900 26700 28400 29800 31400 7200 27800 32100 33900 35600 37000 38600 1444 16500 20000 21400 22700 23900 25100 5800 22300 25800 27200 28500 29700 30900 2000 5.75% 50000 100000 150000 250000 500000 Unlimited 2406 24700 31000 34000 36700 39100 41800 9600 34300 40600 43600 46300 48700 51400 1924 19700 24800 27200 29400 31300 33500 7800 27500 32600 35000 37200 39100 41300 2500 5.75% 50000 100000 150000 250000 500000 Unlimited 3008 28000 36500 40500 44600 48100 52300 12000 40000 48500 52500 56600 60100 64300 2405 22400 29200 32400 35600 38500 41800 9600 32000 38800 42000 45200 48100 51400 Œ 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.  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 Power Distribution System Design 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 75 112.5 150 225 300 500 750 1000 7.93 3.70 3.42 5.20 5.60 4.50 4.90 5.90 6.20 6.40 7.10 5.50 6.30 6.50 6.60 3.28 1.94 4.83 4.67 3.56 3.47 3.91 4.07 3.51 3.13 1.46 1.27 1.08 4.40 1.71 2.81 1.92 3.10 2.76 3.46 4.42 4.68 5.35 6.37 5.30 6.17 6.41 0.67 0.52 1.45 0.40 0.66 0.78 1.00 1.13 1.15 1.52 2.03 3.63 4.87 5.93 115 ° C Rise kVA %Z %R %X X/R 15 30 45 75 112.5 150 225 300 500 750 5.20 4.60 3.70 4.60 6.50 6.20 7.20 6.30 5.50 4.10 3.67 4.33 3.11 2.53 2.31 3.53 2.36 1.93 1.02 1.00 3.69 1.54 2.00 3.84 6.08 5.09 6.80 6.00 5.40 3.98 1.01 0.36 0.64 1.52 2.63 1.44 2.89 3.10 5.30 3.98 80 ° C Rise kVA %Z %R %X X/R 15 30 45 75 112.5 150 225 300 500 2.30 2.90 2.90 3.70 4.30 4.10 5.30 3.30 4.50 2.00 2.25 1.78 2.07 2.49 1.70 1.42 1.00 0.62 1.14 1.83 2.29 3.07 3.51 3.73 5.11 3.14 4.46 0.57 0.81 1.29 1.49 1.41 2.19 3.59 3.14 7.19 Table A28: 15 kV Class Primary – Oil Liquid- Filled Substation Transformers 65 ° C Rise kVA %Z %R %X X/R 112.5 150 225 300 500 750 1000 1500 2000 2500 5.00 5.00 5.00 5.00 5.00 5.75 5.75 5.75 5.75 5.75 1.71 1.88 1.84 1.35 1.50 1.41 1.33 1.12 0.93 0.86 4.70 4.63 4.65 4.81 4.77 5.57 5.59 5.64 5.67 5.69 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 300 500 750 1000 1500 2000 2500 4.50 5.75 5.75 5.75 5.75 5.75 5.75 2.87 2.66 2.47 2.16 1.87 1.93 1.74 3.47 5.10 5.19 5.33 5.44 5.42 5.48 1.21 1.92 2.11 2.47 2.90 2.81 3.15 80 ° C Rise 300 500 750 1000 1500 2000 2500 4.50 5.75 5.75 5.75 5.75 5.75 5.75 1.93 1.44 1.28 0.93 0.87 0.66 0.56 4.06 5.57 5.61 5.67 5.68 5.71 5.72 2.10 3.87 4.38 6.10 6.51 8.72 10.22 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 30 45 75 112 1 / 2 83.3 125 208 312 72.2 108 180 271 36.1 54.1 90.2 135 28.9 43.3 72.2 108 7.22 10.8 18.0 27.1 4.16 6.25 10.4 15.6 2.41 3.61 6.01 9.02 1.44 2.17 3.61 5.41 1.39 2.08 3.47 5.21 1.31 1.97 3.28 4.92 1.26 1.88 3.14 4.71 0.75 1.13 1.89 2.84 0.50 0.76 1.26 1.89 150 225 300 500 416 625 833 1,388 361 541 722 1,203 180 271 361 601 144 217 289 481 36.1 54.1 72.2 120 20.8 31.2 41.6 69.4 12.0 18.0 24.1 40.1 7.22 10.8 14.4 24.1 6.94 10.4 13.9 23.1 6.56 9.84 13.1 21.9 6.28 9.41 12.6 20.9 3.78 5.67 7.56 12.6 2.52 3.78 5.04 8.39 750 1,000 1,500 2,000 2,082 2,776 4,164 . . . . 1,804 2,406 3,608 4,811 902 1,203 1,804 2,406 722 962 1,443 1,925 180 241 361 481 104 139 208 278 60.1 80.2 120 160 36.1 48.1 72.2 96.2 34.7 46.3 69.4 92.6 32.8 43.7 65.6 87.5 31.4 41.8 62.8 83.7 18.9 25.2 37.8 50.4 12.6 16.8 25.2 33.6 2,500 3,000 3,750 5,000 7,500 10,000 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,007 3,609 4,511 . . . . . . . . . . . . 2,406 2,887 3,608 4,811 . . . . . . . . 601 722 902 1,203 1,804 2,406 347 416 520 694 1,041 1,388 200 241 301 401 601 802 120 144 180 241 361 481 116 139 174 231 347 463 109 131 164 219 328 437 105 126 157 209 314 418 63.0 75.6 94.5 126 189 252 42.0 50.4 62.9 83.9 126 168 Œ 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 ቢ kVA Liquid-Filled Network Padmount 37.5 45 50 75 112.5 150 225 300 500 750 1000 1500 2000 2500 3000 3750 5000 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.00 5.00 5.00 5.00 7.00 7.00 7.00 . . . . . . . . . . . . . . . . . . . . . . . . 3.4 3.2 2.4 3.3 3.4 4.6 5.75 5.75 5.75 5.75 5.75 6.50 6.50 6.50 Approximate Impedance Data January 1999 Cutler-Hammer A-61 Power Distribution System Design 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 Load Watts Loss Full Load Watts Loss 3 6 9 15 30 45 75 112.5 150 225 300 500 750 1000 33 58 77 150 200 300 400 500 600 700 800 1700 2200 2800 231 255 252 875 1600 1900 3000 4900 6700 8600 10200 9000 11700 13600 115 ° C Rise kVA No Load Watts Loss Full Load Watts Loss 15 30 45 75 112.5 150 225 300 500 750 150 200 300 400 500 600 700 800 1700 1500 700 1500 1700 2300 3100 5900 6000 6600 6800 9000 80 ° C Rise kVA No Load Watts Loss Full Load Watts Loss 15 30 45 75 112.5 150 225 300 500 200 300 300 400 600 700 800 1300 2200 500 975 1100 1950 3400 3250 4000 4300 5300 Approximate Transformer Loss Data Table A31: 15 kV Class Primary – Oil Liquid- Filled Substation Transformers 65 ° C Rise kVA No Load Watts Loss Full Load Watts Loss 112.5 150 225 300 500 750 1000 1500 2000 2500 550 545 650 950 1200 1600 1800 3000 4000 4500 2470 3360 4800 5000 8700 12160 15100 19800 22600 26000 Table A32: 15 kV Class Primary – Dry-Type Substation Transformers 150 ° C Rise kVA No Load Watts Loss Full Load Watts Loss 300 500 750 1000 1500 2000 2500 1600 1900 2700 3400 4500 5700 7300 10200 15200 21200 25000 32600 44200 50800 80 ° C Rise 300 500 750 1000 1500 2000 2500 1800 2300 3400 4200 5900 6900 7200 7600 9500 13000 13500 19000 20000 21200 CAT.71.01.T.E Cutler-Hammer A-62 January 1999 Power Distribution System Design 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 2000 Ampere Breaker 1400 3000 Ampere Breaker 2000 Table A35: Medium Voltage Switchgear (Indoor, 5 and 15 kV) Equipment Watts Loss 600 Ampere Unfused Switch 500 1200 Ampere Unfused Switch 750 100 Ampere CL Fuses 840 Table A36: Medium Voltage Starters (Indoor, 5 kV) Equipment Watts Loss 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) Equipment Watts Loss 800 Ampere Breaker 400 1600 Ampere Breaker 1000 2000 Ampere Breaker 1500 3200 Ampere Breaker 2400 4000 Ampere Breaker 3000 5000 Ampere Breaker 4700 Fuse Limiters – 800 A CB 200 Fuse Limiters – 1600 A CB 500 Fuse Limiters – 2000 A CB 750 Fuse Truck – 3200 A CB 3600 Fuse Truck – 4000 A CB 4500 Structures – 3200 Ampere 4000 Structures – 4000 Ampere 5000 Structures – 5000 Ampere 7000 High Resistance Grounding 1200 Table A38: Motor Control Centers (Indoor, 480 volts) Equipment Watts Loss NEMA Size 1 Starter 39 NEMA Size 2 Starter 56 NEMA Size 3 Starter 92 NEMA Size 4 Starter 124 NEMA Size 5 Starter 244 Structures 200 Table A39: Panelboards (Indoor, 480 volts) Equipment Watts Loss 225 Ampere, 42 Circuit 300 Table A40: Low Voltage Busway (Indoor, Copper, 480 volts) Equipment Watts Loss 800 Ampere 44 per foot 1200 Ampere 60 per foot 1350 Ampere 66 per foot 1600 Ampere 72 per foot 2000 Ampere 91 per foot 2500 Ampere 103 per foot 3200 Ampere 144 per foot 4000 Ampere 182 per foot 5000 Ampere 203 per foot January 1999 Cutler-Hammer A-63 Power Distribution System Design CAT.71.01.T.E A Enclosures 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 the Following Environmental Conditions Type of Enclosures 1Œ 2Œ 4 4X 5 6 6P 12 12K 13 Incidental contact with the enclosed equipment Falling dirt Falling liquids and light splashing Circulating dust, lint, fibers, and flyings Settling airborne dust, lint, fibers, and flyings Hosedown and splashing water Oil and coolant seepage Oil or coolant spraying and splashing Corrosive agents Occasional temporary submersion Occasional prolonged submersion X X . . . . . . . . . . . . . . . . . . . . . . . . . . . X X X . . . . . . . . . . . . . . . . . . . . . . . . X X X X X X . . . . . . . . . . . . . . . X X X X X X . . . . . . X . . . . . . X X X . . . X . . . . . . . . . . . . . . . . . . X X X X X X . . . . . . . . . X . . . X X X X X X . . . . . . X X X X X X X X . . . X . . . . . . . . . . . . X X X X X . . . X . . . . . . . . . . . . X X X X X . . . X X . . . . . . . . . Table A42: Comparison of Specific Applications of Enclosures for Outdoor Nonhazardous Locations Provides a Degree of Protection Against the Following Environmental Conditions Type of Enclosures 3 3RŽ 3S 4 4X 6 6P Incidental contact with the enclosed equipment Rain, snow, and sleet Sleet Windblown dust Hosedown Corrosive agents Occasional temporary submersion Occasional prolonged submersion X X . . . X . . . . . . . . . . . . X X . . . . . . . . . . . . . . . . . . X X X X . . . . . . . . . . . . X X . . . X X . . . . . . . . . X X . . . X X X . . . . . . X X . . . X X . . . X . . . X X . . . X X X X X 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 Enclosure 7 and 8, Class I Groups‘ Type of Enclosure 9, Class II Groups‘ A B C D E F G 10 Acetylene Hydrogen, manufactured gas Diethel ether, ethylene, cyclopropane Gasoline, hexane, butane, naphtha, propane, acetone, toluene, isoprene Metal dust Carbon black, coal dust, coke dust Flour, starch, grain dust Fibers, flyings’ Methane with or without coal dust I I I I II II II III MSHA X . . . . . . . . . . . . . . . . . . . . . . . . . . . X . . . . . . . . . . . . . . . . . . . . . . . . . . . X . . . . . . . . . . . . . . . . . . . . . . . . . . . X . . . . . . . . . . . . . . . . . . . . . . . . . . . X . . . . . . . . . . . . . . . . . . . . . . . . . . . X . . . . . . . . . . . . . . . . . . . . . . . . . . . X X . . . . . . . . . . . . . . . . . . . . . . . . . . . X Table A44: Knockout Dimensions Conduit Trade Size, Inches Knockout Diameter, Inches Minimum Nominal Maximum 1 /2 3 /4 1 1 1 /4 1 1 /2 2 2 1 /2 3 3 1 /2 4 5 6 0.859 1.094 1.359 1.719 1.958 2.433 2.938 3.563 4.063 4.563 5.625 6.700 0.875 1.109 1.375 1.734 1.984 2.469 2.969 3.594 4.125 4.641 5.719 6.813 0.906 1.141 1.406 1.766 2.016 2.500 3.000 3.625 4.156 4.672 5.750 6.844 Œ 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.  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. Ž External operating mechanisms are not required to be operable when the enclosure is ice covered.  External operating mechanisms are operable when the enclosure is ice covered.  These enclosures may be ventilated. ‘ For Class III type ignitable fibers or combustible flyings see the National Electrical Code, Article 500. ’ Due to the characteristics of the gas, vapor, or dust, a product suitable for one Class or Group may not be suitable for another Class or Group unless so marked on the product. Reference Data – Enclosures CAT.71.01.T.E Cutler-Hammer A-64 January 1999 Power Distribution System Design A Ž 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.  For interlocked armored cable, use magnetic conduit data for steel armor and non-magnetic conduit data for aluminum armor.  ‘ For busway impedance data, see section H2 of this catalog. Z X 2 R 2 + = Reference Data – Conductor Resistance, Reactance, Impedance ‘ 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 14 12 10 8 6 4 2 1 1/0 2/0 3/0 4/0 250 300 350 400 450 500 600 700 750 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 14 12 10 8 6 4 2 1 1/0 2/0 3/0 4/0 250 300 350 400 450 500 600 700 750 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 Œ 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).  Based upon conductivity of 100% for copper, 61% for aluminum. January 1999 Cutler-Hammer A-65 Power Distribution System Design 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 AWG kcmil 60 ° C (140 ° F) 75 ° C (167 ° F) 90 ° C (194 ° F) 60 ° C (140 ° F) 75 ° C (167 ° F) 90 ° C (194 ° F) AWG kcmil Types TW†, UF† Types FEPW†, RH†, RHW†, THHW†, THW†, THWN†, XHHW†, USE†, ZW† Types TBS, SA, SIS, FEP†, FEPB†, MI, RHH†, RHW-2, THHN†, THHW†, THW-2, THWN-2, USE-2, XHH, XHHW†, XHHW-2, ZW-2 Types TW†, UF† Types RH†, RHW†, THHW†, THW†, THWN†, XHHW†, USE† Types TBS, SA, SIS, THHN†, THHW†, THW-2, THWN-2, RHH†, RHW-2, USE-2, XHH, XHHW, XHHW-2, ZW-2 Copper Aluminum or Copper-Clad Aluminum 18 16 14 12 10 8 . . . . . . . . 20† 25† 30 40 . . . . . . . . 20† 25† 35† 50 14 18 25† 30† 40† 55 . . . . . . . . . . . . 20† 25 30 . . . . . . . . . . . . 20† 30† 40 . . . . . . . . . . . . 25† 35† 45 . . . . . . . . . . . . 12 10 8 6 4 3 2 1 55 70 85 95 110 65 85 100 115 130 75 95 110 130 150 40 55 65 75 85 50 65 75 90 100 60 75 85 100 115 6 4 3 2 1 1/0 2/0 3/0 4/0 125 145 165 195 150 175 200 230 170 195 225 260 100 115 130 150 120 135 155 180 135 150 175 205 1/0 2/0 3/0 4/0 250 300 350 400 500 215 240 260 280 320 255 285 310 335 380 290 320 350 380 430 170 190 210 225 260 205 230 250 270 310 230 255 280 305 350 250 300 350 400 500 600 700 750 800 900 355 385 400 410 435 420 460 475 490 520 475 520 535 555 585 285 310 320 330 355 340 375 385 395 425 385 420 435 450 480 600 700 750 800 900 1000 1250 1500 1750 2000 455 495 520 545 560 545 590 625 650 665 615 665 705 735 750 375 405 435 455 470 445 485 520 545 560 500 545 585 615 630 1000 1250 1500 1750 2000 Correction Factors Ambient Temp. ° C For ambient temperatures other than 30 ° C (86 ° F), multiply the allowable ampacities shown above by the appropriate factor shown below. Ambient Temp. ° F 21-25 26-30 31-35 36-40 41-45 46-50 51-55 56-60 61-70 71-80 1.08 1.00 .91 .82 .71 .58 .41 . . . . . . . . . . . . 1.05 1.00 .94 .88 .82 .75 .67 .58 .33 . . . . 1.04 1.00 .96 .91 .87 .82 .76 .71 .58 .41 1.08 1.00 .91 .82 .71 .58 .41 . . . . . . . . . . . . 1.05 1.00 .94 .88 .82 .75 .67 .58 .33 . . . . 1.04 1.00 .96 .91 .87 .82 .76 .71 .58 .41 70-77 78-86 87-95 96-104 105-113 114-122 123-131 132-140 141-158 159-176 †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 or raceways 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 of Current-Carrying Conductors Percent of Values in Tables as Adjusted for Ambien Temperature if Necessary 4 through 6 7 through 9 10 through 20 21 through 30 31 through 40 41 and above 80 70 50 45 40 35 Œ For impedance data, see page A-64. Reference Data – Conductor Ampacities Œ CAT.71.01.T.E Cutler-Hammer A-66 January 1999 Power Distribution System Design 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 1 1 ⁄4 1 1⁄ 2 2 2 1 ⁄2 3 3 1 ⁄2 4 5 6 Type Letters Conductor Size AWG/kcmil TW, XHHW (14 through 8) RH (14 + 12) 14 12 10 8 9 7 5 2 15 12 9 4 25 19 15 7 44 35 26 12 60 47 36 17 99 78 60 28 142 111 85 40 171 131 62 176 84 108 RHW and RHH (without outer cover ing), RH (10 + 8) THW, THHW 14 12 10 8 6 4 4 1 10 8 6 3 16 13 11 5 29 24 19 10 40 32 26 13 65 53 43 22 93 76 61 32 143 117 95 49 192 157 127 66 163 85 133 TW, THW, FEPB (6 through 2), RHW and RHH (with- out outer covering) RH, THHW 6 4 1 1 2 1 4 3 7 5 10 7 16 12 23 17 36 27 48 36 62 47 97 73 141 106 3 2 1 1 1 1 1 1 2 2 1 4 4 3 6 5 4 10 9 6 15 13 9 23 20 14 31 27 19 40 34 25 63 54 39 91 78 57 1/0 2/0 3/0 4/0 1 1 1 1 1 1 1 2 1 1 1 3 3 2 1 5 5 4 3 8 7 6 5 12 10 9 7 16 14 12 10 21 18 15 13 33 29 24 20 49 41 35 29 250 300 350 400 500 1 1 1 1 1 1 1 1 1 1 1 1 2 2 1 1 1 4 3 3 2 1 6 5 4 4 3 8 7 6 5 4 10 9 8 7 6 16 14 12 11 9 23 20 18 16 14 600 700 750 1 1 1 1 1 1 1 1 1 3 2 2 4 3 3 5 4 4 7 7 6 11 10 9 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 1 1 ⁄4 1 1⁄ 2 2 2 1 ⁄2 3 3 1 ⁄2 4 5 6 Type Letters Conductor Size AWG/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) 14 12 10 8 13 10 6 3 24 18 11 5 39 29 18 9 69 51 32 16 94 70 44 22 154 114 73 36 164 104 51 160 79 106 136 6 4 3 2 1 1 1 1 1 4 2 1 1 1 6 4 3 3 1 11 7 6 5 3 15 9 8 7 5 26 16 13 11 8 37 22 19 16 12 57 35 29 25 18 76 47 39 33 25 98 60 51 43 32 154 94 80 67 50 137 116 97 72 1/0 2/0 3/0 4/0 1 1 1 1 1 1 1 1 3 2 1 1 4 3 3 2 7 6 5 4 10 8 7 6 15 13 11 9 21 17 14 12 27 22 18 15 42 35 29 24 61 51 42 35 250 300 350 400 1 1 1 1 1 1 1 1 1 1 1 3 3 2 1 4 4 3 3 7 6 5 5 10 8 7 6 12 11 9 8 20 17 15 13 28 24 21 19 500 600 700 750 1 1 1 1 1 1 1 1 1 1 2 1 1 1 4 3 3 2 5 4 4 3 7 5 5 4 11 9 8 7 16 13 11 11 XHHW 6 600 700 750 1 3 5 9 1 13 1 1 1 21 1 1 1 30 1 1 1 47 3 3 2 63 4 4 3 81 5 5 4 128 9 7 7 185 13 11 10 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 Conductor A 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 Cutler-Hammer A-67 Power Distribution System Design CAT.71.01.T.E A Common Electrical Terms Ampere (l) = unit of current or rate of flow of electricity Volt (E) = unit of electromotive force Ohm (R) = unit of resistance Ohms law: I = (DC or 100% pf) Megohm = 1,000,000 ohms Volt Amperes (VA) = unit of apparent power = (single-phase) = Kilovolt Amperes (kVA) = 1000 volt-amperes Watt (W) = unit of true power = = .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 kVAŒ To Find Direct Current Alternating Current Single-Phase Two-Phase — 4-Wire Three-Phase Amperes (l) When Horsepower is Known Amperes (l) When Kilowatts is Known Amperes (l) When kVA 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 ---------------------------------------------------------- E R --- E l × E l × 3 × VA pf × W VA ------- 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 by voltmeter. Amps = current measured in line wire (not neutral) by ammeter. 1 inch = 2.54 centimeters 1 kilogram = 2.20 lbs. 1 square inch = 1,273,200 circular mills 1 circular mill = .785 square mil 1 Btu = 778 ft. lbs. = 252 calories 1 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 20 F° 5 14 23 32 41 50 59 68 C° 25 30 35 40 45 50 55 60 F° 77 86 95 104 113 122 131 140 C° 65 70 75 80 85 90 95 100 F° 149 158 167 176 185 194 203 212 watts volts amperes × -------------------------------------------- disc 60 × Kh × Œ Units of measurement and definitions for E (volts), I (amperes), and other abbreviations are given below under Common Electrical Terms.  For 2-phase, 3-wire circuits the current in the common conductor is times that in either of the two other conductors. 2 Reference Data – Formulas and Terms CAT.71.01.T.E Cutler-Hammer A-68 January 1999 Power Distribution System Design 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 1 2B 2B 3 0 1 1 4 1 2B 3 3 ALEUTIAN ISLANDS ALASKA HAWAII PUERTO RICO 3 4 1 0 0 1 2A 2A 0 1 1 1 1 2A 2A 2A 2A 0 0 0 3 1 3 4 3 2 1 0 0 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) S p e c t r a l A c c e l e r a t i o n E f f e c t i v e P e a k G r o u n d A c c e l e r a t i o n 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. Seismic Requirements January 1999 Cutler-Hammer A-69 Power Distribution System Design 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) Response Acceleration (g) Cutler-Hammer Equipment Capability 50% of the Level Specified in ANSI C37.81 California Building Code Zone 4 Requirement Uniform Building Code Zone 4 Requirement Damping = 5% Z e r o P e r i o d A c c e l e r a t i o n Period (seconds) Seismic Requirements CAT.71.01.T.E Cutler-Hammer A-70 January 1999 Power Distribution System Design A This page intentionally left blank. A-2 Power Distribution System Design System Design Cutler-Hammer January 1999 Basic Principles A 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 system, the system design engineer must have information concerning the loads and a knowledge of the various types of distribution 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 distribution equipment, locations and characteristics 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 deregulation. The traditional dependence on the utility for problem analysis; energy conservation measurements and techniques; and a simplified cost structure for electricity will change to some degree in the next decade. The second change is less obvious to the designer yet will have an impact on the types of equipment and systems being designed. It is the diminishing quantity of qualified building electrical operators; maintenance departments; 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 capabilities, allowing for automated communication of vital power system information (both energy data and system operation information) 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 application and selection of such systems and components that may be incorporated into the power equipment being designed. CAT.71.01.T.E Cutler-Hammer January 1999 Power Distribution System Design System Design A-3 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 electrical equipment maintenance and upkeep. The National Electric Code (N.E.C.) as well as local electrical codes provide minimum standards 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 requirements 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. Special 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 protective 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 installation 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 commercial office building a power outage of considerable time, say several hours, may be acceptable, whereas in a larger commercial building or industrial plant only a few minutes 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 multiple connection paths to the loads served; C) providing alternate customer-owned power sources such as generators or batteries supplying uninterruptable power supplies; D) selecting highest quality electrical equipment and conductors; and E) using the best installation methods. 4. Maximum Flexibility and Expandability – In many industrial manufacturing plants, electrical utilization loads are periodically relocated or changed requiring changes in the electrical distribution system. Consideration of the layout and design of the electrical distribution 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 equipment 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 distribution 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 considered is increasing appropriate circuit capacities or quantities for future growth. 5. Maximum Electrical Efficiency (Minimum Operating Costs) – Electrical efficiency can generally be maximized by designing systems that minimize the losses in conductors, transformers and utilization equipment. Proper 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 between the owner’s utility energy change for the losses in the transformer or other equipment 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 maintenance costs and chance for operator error increases. The systems should be designed with an alternate power circuit to take electrical equipment (requiring periodic maintenance) out of service without dropping essential loads. Use of draw-out type protective devices such as breakers and combination starters can also minimize maintenance cost and out-of-service time. 7. Maximum Power Quality – The power input 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 designed 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 voltage 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 expandability, and power quality, the more initial investment 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, requirements, 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 probability 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 discuss some of the various types of electrical distribution systems being utilized today. A discussion of short circuit calculations, coordination, voltage selection, voltage drop, ground fault protection, motor protection, and other specific equipment protection is presented. A CAT.71.01.T.E 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 voltages for these classifications.E .T. Table A1 – Standard Nominal System Voltages and Voltage Ranges Voltage Class Low Voltage Nominal System Voltage 3-Wire 240 480 600 2400 4160 4800 6900 13800 23000 34500 46000 69000 115000 138000 161000 230000 345000 500000 765000 1100000 4-Wire 208Y/120 240/120 480Y/277 4160Y/2400 8320Y/4800 12000Y/6930 12470Y/7200 13200Y/7620 13800Y/7970 20780Y/12000 22860Y/13200 24940Y/14400 34500Y/19920 Medium Voltage High Voltage Extra-High Voltage Ultra-High Voltage CAT.71.A-4 Power Distribution System Design System Design Cutler-Hammer January 1999 Voltage Classifications A ANSI and IEEE standards define various voltage classifications for single-phase and three-phase systems.01. 1. Simple Spot Network 6. Primary Fused Switch Transformer 600V Class Switchboard Distribution Dry-Type Transformer Distribution Panel MCC Distribution Panel Lighting Panelboard Figure 1. 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. Two Source Primary . Reducing the number of transformers per primary feeder by adding more primary feeder circuits will improve the flexibility and service continuity of this system. In those cases where utility service is available at the building at some voltage higher than the utilization voltage to be used.Secondary Selective System 5. This of course increases the investment in the system but minimizes the extent of an outage resulting from a transformer or primary feeder fault. Since the entire load is served from a single source.E . Loop-Primary System . A modern and improved form of the conventional simple radial system distributes power at a primary voltage. In practically all of these cases. or with separable connectors made in manholes or other locations. because power is distributed to the load areas at a primary voltage. Simple Radial System CAT. In many cases the interrupting duty imposed on the load circuit breakers is reduced. and the service equipment then becomes a low voltage main distribution switchgear or switchboard. A relatively small number of circuits are used to distribute power to the loads from the switchgear or switchboard assemblies and panelboards. 1. However. The transformers are usually connected to their associated load bus through a circuit breaker.01. and large lowvoltage feeder circuit breakers are eliminated. the ultimate being one secondary unit substation per primary feeder circuit.Radial Secondary System 3. In those cases where the utility owns the primary equipment and transformer. 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. Since each transformer is located within a specific load area. voltage regulation is improved. 1A. losses are reduced.71. However. In the case of a primary main bus fault or an utility service outage. A fault on the secondary low voltage bus or in the source transformer will interrupt service to all loads. 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.T. A low-voltage feeder circuit fault will interrupt service to all loads supplied over that feeder. it must have sufficient capacity to carry the peak load of that area.Cutler-Hammer January 1999 Power Distribution System Design System Design A-5 Types of Systems In the great majority of cases. the voltage regulation and efficiency of this system may be poor because of the low-voltage feeders and single source. and separate low voltage switchgear or switchboard. This makes it possible to minimize the installed transformer capacity. service is interrupted to all loads until the trouble is eliminated. full advantage can be taken of the diversity among the loads. 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.Secondary Radial System 4. power is supplied by the utility to a building at the utilization voltage. Circuits are run to the loads from these low voltage protective devices. Consequently. A 1. The cost of the low voltage-feeder circuits and their associated circuit breakers are high when the feeders are long and the peak demand is above 1000 kVA. This system is the first type described on the following pages. the equipment may take the form of a separate primary switch. separate transformer. transformer and secondary switchgear or switchboard are designed and installed as a close coupled single assembly. this modified primary radial system requires more transformer capacity than the basic form of the simple radial system. if any diversity exists among the load area. liquid-filled or air-cooled transformer. Primary Selective System . the distribution of power within the building is achieved through the use of a simple radial distribution system. Simple Radial 2. an integrally connected primary fused switch. Service cannot be restored until the necessary repairs have been made. Medium-Voltage Distribution System Design Each feeder is connected to the switchgear or switchboard bus through a circuit breaker or other overcurrent protective device. Simple Radial System The conventional simple-radial system receives 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. Each secondary unit substation is an assembled unit consisting of a three-phase. This equipment may be combined in the form of an outdoor pad mounted transformer with internal primary fused switch and secondary main breaker feeding an indoor switchboard. The voltage is stepped down to utilization level in the several load areas within the building typically through secondary unit substation transformers. as shown in Fig. This discussion covers several major types of distribution systems and practical modifications of them. the system design engineer has a choice of a number of types of systems which the engineer may use. the supply to the customer is at the utilization voltage. feeder circuit costs are reduced substantially. Another alternative would be a secondary unit substation where the primary fused switch. and low-voltage switchgear or switchboard with circuit breakers or fused switches. should a fault or overload condition occur. A key interlocking scheme is normally recommended to prevent closing all sectionalizing devices in the loop.71. 2A. Although this system would result in less initial equipment cost. and just utilize a single primary main breaker or fused switch for protection of a single primary feeder circuit with all the secondary unit substations supplied from this circuit. should only one primary fuse on a circuit blow. Loop Primary System Radial Secondary System This system consists of one or more “PRIMARY LOOPS” with two or more transformers connected on the loop. This system is typically most effective when two services are available from the utility as shown in Fig.E . When pad mounted compartmentalized transformers are utilized. In addition. Loop Primary . In addition. 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. but also decrease the level of conductor and equipment protection. Each primary loop sectionalizing 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.A-6 Power Distribution System Design System Design Cutler-Hammer January 1999 A Depending on the load kVA connected to each primary circuit and if no ground fault protection is desired for either the primary feeder conductors and transformers connected to that feeder or the main bus. 2B. Primary Main Breaker 1 52 52 52 52 52 Primary Main Breaker 2 Tie Breaker 52 52 Loop Feeder Breaker Loop A Loop B NC NO NC NC Fault Sensors NC NC NO NC NC NC Secondary Unit Substations Consisting of: Duplex Primary Switches/Fused Primary Switches/ Transformer and Secondary Main Feeder Breakers Figure 2. By operating the appropriate sectionalizing switches. Each primary loop is operated such that one of the loop sectionalizing switches is kept open to prevent parallel operation of the sources. This will significantly reduce the first cost. Primary and Secondary Simple Radial System 2. causing damage to low voltage motors. the secondary loads could be single phased.01. it is possible to disconnect any section of the loop conductors from the rest of the system. Thus. Another approach to reducing costs would be to eliminate the primary feeder breakers completely. When secondary unit substations are utilized. 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. 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. down time could increase significantly and higher costs associated with increased damage levels and the need for fuse replacement would be typically encountered.T. the primary main and/or feeder breakers may be changed to primary fused switches. 52 Primary Main Breaker 52 52 52 52 52 52 Primary Feeder Breakers Secondary Unit Substation Primary Cables Figure 1A.Radial Secondary System CAT. they are furnished with loop feed oil immersed gang operated load break sectionalizing switches and drawout current limiting fuses in dry wells as shown in Fig. An extra key is provided to defeat the interlock under qualified supervision. thus restoring service to all loads. Note under this condition. or 3) a transformer fault or overload occurs. As an alternate to the duplex switch arrangement. connected together by bus bars on the load side. the transformer primary fuses would blow. Figure 2C. If a fault occurs in the basic primary loop system. This system of Fig. 2) will reduce the extent of the outage from a conductor fault. When a fault occurs on one of the primary feeders. 3A are the normal choice for this type of system. Should a utility outage occur on one of the incoming lines. In Fig. each primary switch connected to the faulted line must be opened and then the alternate line primary switch can be closed connecting the transformer to the live feeder. This means limited cable space especially if double lugs are furnished for each line as shown in Fig. 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.Secondary radial system. 2 provides for increased equipment costs over Fig. 2) a primary feeder conductor fault occurs. then the loop sectionalizing switches on each side of the faulted conductor can be opened. the loop sectionalizing switch which had been previously left open then closed and service restored to all secondary unit substations while the faulted conductor is replaced. as shown in Fig. but offers increased reliability and quick restoration of service when 1) a utility outage occurs. Pad Mounted Transformer Loop Switching 52 Loop A Loop A In cases where only one primary line is available. A Loop Feeder Loop Feeder Loadbreak Loop Switches Fused Disconnect Switch Figure 2A. 1. Typically the load break switch closest to the transformer includes a fuse assembly with fuses. Single Primary Feeder . the single loop feeder breaker trips. and thus all conductors around the loop should be sized to carry the entire load connected to the loop. the remaining feeder or feeders have sufficient capacity to carry the total load. only half of the load in the building is dropped. differs from those previously described in that it employs at least two primary feeder circuits in each load area. 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). If the fault should occur in a conductor directly on the load side of one of the loop feeder breakers. and leaving all other secondary unit substation loads unaffected. the associated primary main breaker can be opened and then the tie breaker closed either manually or through an automatic transfer scheme. etc. Duplex fused switches as shown in Fig. 3. Once it is determined which section of primary cable has been faulted. A basic primary loop system which utilizes a single primary feeder breaker connected directly to two loop feeder switches which in turn then feed the loop is shown in Fig. the use of a single primary breaker provides the loop connections to the loads as shown here. 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.T.01. It is designed so that when one primary circuit is out of service. Half of the transformers are normally connected to each of the two feeders. 3 and detailed in Fig. 2C. For slightly added cost. Each duplex fused switch consists of two (2) load break 3 pole switches each in their own separate structure.71. and the transformers normally supplied from the faulted feeder are out of service. Then manually. The non-load break switch is mechanically interlocked to prevent its operation unless the load break switch is opened. a non-load break selector switch mechanically interlocked with a load break fused switch can be utilized as shown in Fig. all secondary unit substations would be supplied through the other loop feeder circuit breaker. 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. is required. and secondary 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. and then the transformer primary switch manually opened.E . the automatic transfer scheme provides significantly reduced power outage time. thus only requiring one structure and a lower cost and floor space savings over the duplex arrangement. The main disadvantage of the selector switch is that conductors from both circuits are terminated in the same structure. Secondary Unit Substation Loop Switching Loop Feeder Loop Feeder Loadbreak Loop Switches Loadbreak Drawout Fuses Figure 2B. During the more common event of a utility outage. 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. 3 and should a faulted primary conductor have to be changed. Increasing the number of primary loops (two loops shown in Fig. an automatic throw-over scheme can be added between the two main breakers and tie breaker. When a transformer fault or overload occurs. Similar sizing of Feeders A2 and B2.Cutler-Hammer January 1999 Power Distribution System Design System Design A-7 In addition. but will also increase the system investment. the loop feeder breaker would be kept open after tripping and the next load side loop sectionalizing switch manually opened so that the faulted conductor could be sectionalized and replaced. Primary Selective System Secondary Radial System The primary selective . 3B. When a primary feeder conductor fault occurs. both lines would have to be deenergized for safe changing of the faulted conductors. The non-load break selector switch is physically located in the rear of the load break fused switch. disconnecting the transformer from the loop. 3.Loop System CAT. 3 when a primary feeder fault occurs the associated feeder breaker opens. tie breaker. Basic Primary Selective .E . The two secondary main breakers and secondary tie breaker of each unit substation are again either mechanically or electrically interlocked to prevent parallel operation. Fused Selector Switch In One Structure voltage has occurred because of a primary feeder fault with the associated primary feeder breaker opening. increased number of feeder breakers. a manual or automatic transfer to the alternate source line may be utilized to restore power to all primary loads. 1 because of the additional primary main breakers. manual or automatic transfer may be utilized to transfer the loads to the other side.secondary radial system of Fig. the in service transformer of a double-ended unit substation would have to have the capability of serving the loads on both sides of the tie breaker. however. and then only the secondary loads normally served by the faulted transformer would have to be transferred to the opposite transformer. Service cannot be restored to the loads normally served by the faulted transformer until the transformer is repaired or replaced. may more than offset the greater cost. Having two sources allows for either manual or automatic transfer of the two primary main breakers and tie breaker should one of the sources become unavailable. 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 maximum load on both sides of the secondary tie breaker. the associated primary fuses blows and interrupts the service to just the load served by that transformer. Because of this spare transformer capacity.71. Upon loss of secondary source voltage on one side. then all secondary loads normally served by the faulted feeder would have to be transferred to the opposite primary feeder. may be less costly or more costly than a primary loop . 4. 2 depending on the physical location of the transformers while offering comparable down-time and reliability. Cost of the primary selective . In either of the above emergency conditions. transformers utilized in this application have equal kVA rating on each side of the double-ended unit substation and the normal operating maximum load on each transformer is typically about 2/3 base nameplate kVA rating. For this reason. The two primary main breakers and primary tie breaker being either manually or electrically interlocked to prevent closing all three at the same time and paralleling the sources. Two Source Primary . 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 transfer. Duplex Fused Switch In Two Structures Figure 3B. then the associated primary fuses would blow taking only the failed transformer out of service.01. the use of primary-duplex or selector switches. Each transformer secondary is arranged in a typical double-ended unit substation arrangement as shown in Fig. If the loss of secondary Fuses Loadbreak Disconnect Fuses Figure 3A.A-8 Power Distribution System Design System Design Cutler-Hammer January 1999 A If a fault occurs in one transformer. The cost of conductors for the two types of systems may vary greatly depending on the location of the transformers and loads within the facility and greatly over-ride primary switching equipment cost differences between the two systems. plus the quick restoration of service to all or most of the loads. The benefits derived from the reduction in the amount of load dropped when a primary feeder is faulted. two sources.Secondary Selective System This system uses the same principle of duplicate sources from the power supply point utilizing two primary main breakers and a primary tie breaker. the voltage regulation provided by CAT. The primary selective-secondary radial system. and the greater amount of primary feeder cable required.secondary radial system is greater than that of the simple primary radial system of Fig. Primary Metal-Clad Switchgear Lineup Bus A 52 52 52 52 52 52 52 Primary Main Breaker Bus B Primary Feeder Breaker Feeder A1 Feeder B1 Feeder B2 Feeder A2 To Other Substations NO NC NO NC NO Typical Secondary Unit Substation Duplex Primary Switch/Fuses Transformer/600V Class Secondary Switchgear NC Figure 3.T. Upon loss of voltage on one source. If the loss of voltage was due to a failure of one of the transformers in the doubleended unit substation. 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.Radial Secondary System Primary Feeders Primary Feeders Loadbreak Switches Interlock Non-loadbreak Selector Switch 4. Secondary Selective System A network protector is a specially designed heavy duty air power breaker. Since the transformers are connected in parallel. if allowed by the utility. the transformers are connected through network protectors to a common bus. 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. The optimum size and number of primary feeders can be used in the spot network system because the loss of any primary feeder and its associated transformers does not result in the loss of any load even for an instant. when a fault occurs on a primary feeder or in a transformer. a primary feeder or transformer fault does not cause any service interruption to the loads.Cutler-Hammer January 1999 Power Distribution System Design System Design A-9 the double-ended unit substation system under normal conditions is better than that of the systems previously discussed. The purpose of the network protector is to protect the integrity of the network bus voltage and the loads served from it against transformer and primary feeder faults by quickly disconnecting the defective feeder-transformer pair from the network when backfeed occurs. and its high efficiency materially reduces the costs of system losses. Another outstanding 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. with a network relay to control the status of the protector (tripped or closed). Finally. No single fault anywhere on the primary system will interrupt service to any of the systems loads. as shown in Fig.” Where two single-ended unit substations are connected together by external tie conductors. momentary re-transfer of loads to the restored source may be made closed transition (anti-parallel interlock schemes would have to be defeated) for either the primary or secondary systems. The interrupting duty imposed on the outgoing feeder breakers in the network will be greater with the spot network system. The paralleled transformers supplying each load bus will normally carry equal load currents. from which loads are served. The double-ended unit substation arrangement can be utilized in conjunction with any of the previous systems discussed which involve two primary sources. 5. 52 52 52 52 52 52 52 A Primary Main Breakers Primary Feeder Breakers To Other Substations Typical Double-Ended Unit Substation To Other Substations 5. Three major differences between the network system and the simple radial system account for the outstanding advantages of the network. or motor operated mechanism. the secondaries of each transformer in a given location (spot) are connected together by a switchgear or ring bus from which the loads are served over short radial feeder circuits. the secondary network system provides exceptionally uniform and good voltage regulation. This operation does not interrupt service to any loads. After the necessary repairs have been made. as shown in Fig.see “grounding and ground fault protection. Under this condition. Two Source Primary . savings in primary switchgear and secondary switchgear costs often result when compared to a radial system design with similar spare capacity.01.E . The chief purpose of the network bus normally closed ties is to provide for the sharing of loads and a balancing of load currents for each primary service and transformer regardless of the condition of the primary services. Also. In network systems. the system can be restored to normal operating conditions by closing the primary feeder breaker. spring close with electrical motor-charged mechanism. In spot networks.T. All network protectors associated with that feeder will close automatically. Modifications of this type of system make it applicable to serve loads within buildings. or in addition to. The major advantage of the secondary network system is continuity of service. For double-ended unit substations equipped with ground fault systems special consideration to transformer neutral grounding and equipment operation should be made . usually in the form of utility grids. 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 primary fault event occurs. In addition to flexibility and service reliability. In spite of the spare capacity usually supplied in network systems. Most faults will be cleared without interrupting service to any load. 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 transformers. Primary Fused Switch Transformer Tie Breaker Secondary Main Breaker Figure 4. and to automatically open the protector when power flows from the secondary to the network transformer. Although not recommended. all equipment interrupting and momentary ratings should be suitable for the fault current available from both sources. downtown areas of cities.71. whereas equal loading of the two separate transformers supplying a substation in the secondaryselective radial system is difficult to obtain. First. 5. the primary supply has sufficient capacity to carry the entire building load without overloading when any one primary feeder is out of service. the fault is isolated from the system through the automatic tripping of the primary feeder circuit breaker and all of the network protectors associated with that feeder circuit. CAT. the secondary main breaker. Simple Spot Network Systems The ac secondary network system is the system that has been used for many years to distribute electric power in the high-density. a network protector is connected in the secondary leads of each network transformer in place of. it is recommended that a tie breaker be furnished at each end of the tie conductors. Fig. outage of the utility results in total outage. First. This busing scheme does not preclude the use of cogeneration. Medium-Voltage Distribution System Design a. This system is operated normally with the main breaker to one source open. thereby saving a portion of the loads from service interruptions. Single Bus Utility #1 Utility #2 6. Retransfer to the “Normal” can be closed transition subject to the approval of the utility. Cogeneration equipment is not recommended for use on networks unless the protectors are manually opened and the utility source completely disconnected and isolated from the temporary generator sources. This scheme is more expensive than scheme shown in Fig. The use of spot network systems provides users with several important advantages. Extension of the bus or adding breakers requires a shutdown of the bus. and institutional buildings where a high degree of service reliability is required from the utility sources. 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. Upon loss of the normal service the transfer to the standby Normally open (NO) breaker can be automatic or manual. in addition to the previously mentioned load shedding.71. reverse current. and light loads within the distances separating the concentrated loads. automatic frequency and voltage controls. This can result in simplified motor control and permits the use of relatively large low voltage motors with their less expensive control. Three Source Spot Network b. Caution – When both sources are paralleled. they save transformer capacity.01. however. This configuration is the simplest system. Much larger motors can be started across-the-line than on a simple radial system. 6A The sources (utility and/or generator(s)) are connected to a single bus. It is recommended that the short circuit ratings of the bus. Typical Feeder Primary Circuit Network Transformer Network Protector Fuses Optional Main. they can be connected to the closest spot network bus. network systems provide a greater degree of flexibility in adding future loads. Closed transition momentarily (5-10 cycles) parallels both utility sources. the ties provide a means for isolating and sectionalizing ground fault events within the switchgear network bus. Fig. Normally the generator does not have adequate capacity for the entire load. feeder breakers and all load side equipment are rated for the increased available fault current. A properly relayed system equipped with load shedding. Single Bus with Two Sources From the Utility. the disconnection of motors from the bus must be ensured by means of suitable time delay on reclosing as well as supervision of the bus voltage and its phase with respect to the incoming source voltage. Principally. If paralleling sources. except that two utility sources are available. Generators are used where cogeneration is employed. high rise office buildings. Single Bus with Two Sources CAT. 6B Same as the single bus. and other appropriate relaying protection should be added as requested by the utility. The voltage regulation on a network system is such that both lights and power can be fed from the same load bus. Finally. They are also economical when compared to two transformer double-ended substations with normally opened tie breakers. Again a utility outage results in total outage to the load until transfer occurs. They are commonly used in hospitals. automatic voltage/frequency control may be able to maintain partial system operation. Spot network systems are economical for buildings which have heavy concentrations of loads covering small areas. Automatic transfer is preferred for rapid service restoration especially in unattended stations. with considerable distance between areas. but service restoration is quicker. Note that the addition of breakers to the bus requires shutdown of the bus. this is due to supplying each load bus through three or more transformers and the reduction in spare cable and transformer capacity required. Utility G 52 Main Bus 52 52 One of Several Feeders Figure 6A. Spot network systems are especially economical where three or more primary feeders are available. 50/51 Relaying and/or Network Disconnect To Other Networks Tie NC Tie NC Drawout Low Voltage Switchgear LV Feeder Customer Loads Customer Loads Customer Loads Figure 5.A-10 Power Distribution System Design System Design Cutler-Hammer January 1999 A Also. yet isolating the faulted portion for corrective action. reverse power. Single Bus. 6A. Normal Standby 52 NC 52 NO Loads Figure 6B. Spot networks permit equal loading of transformers under all conditions. All feeders are connected to the same bus. Also.T. If the utility requires open transfer. networks yield lower system losses and greatly improve voltage conditions.E . but requires the use of sophisticated automatic synchronizing and synchronism checking controls. Specify and apply all equipment within its published ratings and national standards pertaining to the equipment and its installation.E . The outage to the system load for a utility outage is limited to half of the system. The service continuity required from electrical systems makes the use of single source systems impractical. Caution For Figures 6B. Relay the system so that only the faulted part is removed from service. 2. CAT. The statements made for the retransfer of scheme B apply to this scheme also. 6C and 6D: If continuous paralleling of sources is planned.Cutler-Hammer January 1999 Power Distribution System Design System Design A-11 c. 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. If looped or primary selective distribution system for the loads is used. In the design of modern medium-voltage system the engineer should: 1. 4. Provide means for expanding the system Utility #1 Utility #2 A 52 NC NO Bus #1 52 52 NC Bus #2 52 52 Load Load Figure 6C. Design a system as simple as possible. Triple Ended Arrangement without major shutdowns. It is required that bus bracing. 6D.01. Limit an outage to as small a portion of the system as possible. Another advantage is that if the paralleling of the buses is momentary. the buses can be extended without a shutdown by closing the tie breaker and transferring the loads to the other bus. Two Source Utility with Tie Breaker Utility #1 Utility #2 Utility #3 52 NC 52 NC 52 NC NO Bus #1 52 Bus #2 NO 52 Bus #3 52 NO 52 Typical Feeer 52 52 52 NO Tie Busway Figure 6D. 5. closing of the tie breaker following the opening of a main breaker can be manual or automatic. Figs. This system is more expensive than B.71. The system is not limited to two buses only. 3. 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. 6C and 6D This scheme is similar to scheme B. It differs significantly in that both utility sources normally carry the loads and also by the incorporation of a normally open tie breaker. Again the closing of the tie breaker can be manual or automatic.T. 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. reverse power and other appropriate relaying protection should be added. Summary The schemes shown are based on using metal-clad medium-voltage draw-out switchgear. feeder breakers and all load side equipment is rated for the increased available fault current. When both sources are paralleled. Multiple Sources with Tie Breaker. and damage to it is minimized consistent with selectivity. reverse current. Protective device coordination–determine characteristics and settings of mediumvoltage protective relays and fuses. A major consideration in the design of a distribution system is to ensure that it provides the required quality of service to the various loads. During this stage if system size or complexity warrant. or to it and every adjacent bus. load flow.T.E . several distribution systems should be analyzed and evaluated including both economic and technical factors.01. line and transformer loadings.71. The results of these calculations permit optimizing service to the loads while properly applying distribution apparatus within their intended limits. or to it and every bus which is one and two buses away. under abnormal conditions. the important technical factors include voltage profile. Circuit breaker duty–identify asymmetrical fault current based on X/R ratio. With the use of computer programs it is possible to identify the fault current at any bus. or currents in every line or source in the system. losses. in every line or source connected to the fault bus. fault isolation and service continuity. Load flow–simulate normal load conditions of system voltages. it may be appropriate to provide a thorough review of each system under both normal and abnormal conditions. Motor starting–identify system voltages and motor torques when starting large motors. Under normal conditions. The prime considerations under faulted conditions are apparatus protection. effects of motor starting. before selection of the distribution apparatus.A-12 Power Distribution System Design Systems Analysis Cutler-Hammer January 1999 Systems Analysis A 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. During the system preliminary planning stage. CAT. providing the desired protection to service and system apparatus so that interruptions of service are minimized consistent with good economic and mechanical design. and entire low-voltage circuit breaker and fuse coordination. 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. This includes serving each load under normal conditions and. power factor. service continuity and reliability. It is used in the breakers and fuses. medium. resistance may be neglected.0 Scale of Curent Values Rms Value of Total Current Alternating ComponentA Symmetrical Wave Rms Value of Alternating Component 1. Constituting 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.0 0.The Axis Time in Cycles of of Asymmetrical Wave a 60 Cps Wave Transformer Impedance. In an arcing fault. about 6 cycles this value increases to the tran.5 1 2 3 4 0 0.and high-voltage work. the short-circuit current is determined by Ohm’s Law except that the impedance is not constant since some reactance is included in the system. It is for this reason.Cutler-Hammer January 1999 Power Distribution System Design Short-Circuit Currents – General A-13 Short-Circuit Currents – General The amount of current available in a shortcircuit fault is determined by the capacity of the system voltage sources and the impedances of the system. which determines Transient Reactance ( fault current after about 6 cycles and this val.01. 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.71. The dc component depends maximum fault current from the transformer. Basically. which determines fault current after steady state condiFor low voltage circuit breakers and fuses.rated secondary current.0 2. is defined as that percent of rated primary voltage that must be applied to the transformer to produce rated current flowing in the secondary. tion is reached. xd’).0 Structure of an Asymmetrical Current Wave Direct Component . on the point on the voltage wave at which the fault is initiated.plus ease of manipulating the various impedsient reactance. In RMS symmetrical value. Limiting the power current component. machines are connected to the system beHowever. A fault may be either an arcing or bolted fault. The greater this ratio. Therefore.A Wholly Offset Asymmetrical Alternating Wave consists of an exponentially decreasing direct-current component superimposed upon a decaying alternating-current. hence it is called asymsource fault capacity will thereby reduce the metrical current. A CAT. The fault current Total Current . it is generally satisfactory to regard reactance as the enThe ac component is not constant if rotating tire impedance.5 -1.5 2. that computer equipment and/or system. and therefore is the value sought in the fault calculations. both the RMS symmetrisetting of the phase OC relays of generators. with secondary shorted through zero resistance. this is normally permissible only if cause the impedance of this apparatus is not the X/R ratio of the medium-voltage system is constant. fault at the device or the asymmetrical short circuit current.When evaluating the adequacy of short ue in 1⁄2 to 2 seconds increases to the value of circuit ratings of medium voltage circuit the synchronous reactance.5 1. assuming the primary voltage can be sustained (generally referred to as an infinite or unlimited supply). The electric network which determines the short-circuit current consists of an ac driving See Table A2 for multiplying factors that voltage equal to the pre-fault system voltage relate the RMS asymmetrical value of Total at the fault location and an impedance correCurrent to the RMS symmetrical value. and the sponding to that observed when looking back peak asymmetrical value of Total Current to the into the system from the fault location.T. and after dealing with impedance. Synchronous Reactance (xd).the RMS symmetrical value should be detercircuit calculations are concerned but is useful mined along with either: the X/R ratio of the in the determination of relay settings. studies are recommended before final selection of apparatus and system arrangements. It is used for the calculation of ances of cables and buses and transformers the momentary and interrupting duties of of the low-voltage circuits. including the fault. the maximum current a transformer can deliver to a fault condition is the quantity of (100 divided by The total fault current is not symmetrical with percent impedance) times the transformer respect to the time-axis because of the direct. in percent. it is usually worthwhile to attempt greater accuracy Subtransient Reactance (xd").5 -2. The rate of decay of both the dc and ac components depends upon the ratio of reactance to resistance (X/R) of the circuit. determines by including resistance with reactance in fault current during the first cycle. cal value and asymmetrical value of the short circuit current should be determined. 3. In low-voltage generator impedance is due to these factors: (1000 volts and below) calculations.E . The effect of reactance in an ac system is to cause the initial current to be high and then decay toward steadystate (the Ohm’s Law) value. It has no effect as far as short. The rapid variation of motor and equal to or more than 25.0 -1. the longer the current remains higher than the steady-state value which it would eventually reach. for X/R = 15. Ip = 2+ 2∈ wt – ----------X⁄R For example.4 2.4 1.718 1 – 377 × ----------------15 120 Ip = 2.5 C FA T OR PEAK MULTIPLICATION FACTOR = AT I O N 2.E RMS SYMMETRICAL Rms Asym = Dc2 + Rms Sym2 with Dc Value Taken at Current Peak RMS MAXIMUM ASYMMETRICAL .0 1.01.4 1.5 2 2.7 1.2 1.5 2.6 1.1 RM S IP LT MU L TI ICA ON 1 1. The formulas are: 1.3 2. 2 Asymm + 2×∈ wt – ----------X⁄R 2 = 1 +  2 × 2.5217 Table A2: Relation of X/R Ratio to Multiplication Factor 2.718 w = 2πf for 60 hertz = 377 t = 1⁄2 cycle or 1⁄120 seconds then 2 × 2.6 2.3 1.9 PE U LT I 1. 2+ = 2.1 IC 2.5 1.7 1.718   377 2 – --------------------- 15 x 120   = 1.2 FA C Based Upon: RMS SYMMETRICAL TO R 1. ∈ = 2. rms symmetrical values and rms asymmetrical depending on the calculated X/R ratio.8 1.T.6 1.48.8 1.A-14 Power Distribution System Design Fault Current Wave Form Relationships Cutler-Hammer January 1999 A Fault Current Wave Form Relationships The following formulas and Table are reproduced from ANSI/IEEE C37.5 3 4 5 6 7 8 9 10 15 20 25 30 40 50 60 70 80 90 100 CIRCUIT X/R RATIO (TAN Ø) RMS MULTIPLICATION FACTOR = AK M PL CAT.8 PEAK MAXIMUM ASYMMETRICAL 2.5612 = I I Rms in per unit. Table A2 describes the relationship between fault current peak values.71.7 2. or ● Assume motor feedback contribution of four times full load current of transformer. for low-voltage systems. It is common practice to calculate the rms symmetrical fault current.0 times motor full load current (impedance value of 25%). These values take into account that mediumvoltage breakers are rated on maximum asymmetry and low voltage breakers are rated average asymmetry. or ● For industrial plants.71. 480Y/277-volt systems in commercial buildings ● Assume 50% induction motor load.” For medium-voltage systems (defined by IEEE as greater than 1000 volts up to 69. When the motor load is not known. the multiplying factor is usually 1. Types of Calculations The following pages describe various methods of calculating short circuit currents for both medium and low voltage systems.17 (based on generally accepted use of X/R ratio of 6. and then apply a multiplying factor to obtain the first half-cycle rms asymmetrical current. the following assumptions generally are made: 208Y/120-volt systems ● Assume 50% lighting and 50% motor load.0 times motor full load current (impedance value of 20%). To determine the motor contribution to the first half-cycle fault current when the system motor load is known. make same assumptions as for 3-phase.000 volts) the multiplying factor is established by NEMA and ANSI standards depending upon the operating speed of the breaker. which is called the “momentary current.T. the following assumptions generally are made: Induction Motors – Use 4. with the assumption being made that the dc component has decayed to zero. Medium-Voltage Motors ● If known use actual values otherwise use the values indicated in the above for the same type of motor. 3-wire systems ● Assume 100% motor load.E .6 representing a source short-circuit power factor of 15%). Synchronous Motors – Use 5. or ● Assume motors 25% synchronous and 75% induction. 240-480-600-volt 3-phase. 600 volts and below. 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 A CAT. or ● Assume motor feedback contribution of two times full load current of transformer or source. 3-wire systems (above).Cutler-Hammer January 1999 Power Distribution System Design Fault Current Calculations A-15 Fault Current Calculations The calculation of asymmetrical currents is a laborious procedure since the degree of asymmetry is not the same on all three phases. or ● Assume motor feedback contribution of twice full load current of transformer.01. or 1. the breaker is acceptable.09 indicates 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 2 ) varies not more than ±2% from a ratio of 1.960 rounded to 36 kA.5X 1. Condensers Hydro Gen. Remote generation connected through transformer rated 10 MVA to 100 MVA for each three-phase bank.76 x 29. with Damper Wdgs.0X 9 7-14 14 12-17 20 13-32 30 20-50 24 13-35 25 15-25 25 15-25 80 40-120 80 40-120 30 10-60 30 10-60 30 10-60 30 15-40 15 5-20 Neglect X X Neglect X X 15 As Specified 5-15 or Calculated 80 As Specified 40-120 or Calculated 5. Motors Above 1000 Hp.E . For example.6 x 1. Test 1 for V/Vo x I or 15 kV/12. ANSI Standard C37.0X 1. Synchronous machines connected through transformers rated 25 to 100 MVA for each three-phase bank.000 amperes symmetrical available. distribution feeders. The following is a review of the meaning of the ratings. “Rated Voltage Range Factor” K = 1. Maximum Symmetrical Interrupting Capability–This is expressed in rms symmetrical amperes or kiloamperes and is K x I rated. without Damper Windings All Synchronous Motors Ind. 29. For example. which is the instantaneous value of the current at the crest.24 = 3.75X 1. 3600 Rpm All Other Induction Motors 50 Hp and Above Ind.01.000 = 239.092 kVA is less than the nominal 250. Therefore the close and latch current expressed in terms of the peak amperes is = 1. and Syn.000 kVA listed.2X Typical Values and Range on Component Base % Reactance X/R Ratio 2-Pole Turbo Generator 4-Pole Turbo Generator Hydro Gen. transmission lines.76/1. Synchronous machines connected through transformers rated 100 MVA and larger. Note: If the system available fault current were 22.000 amperes symmetrical. It should be noted that the product 3 x 4.5 5-7 7. When the devices to be used are ANSI-rated devices. For example 1. Table A3: Reactance X for E/X Amperes The close and latch capability is also a related quantity expressed in rms asymmetrical amperes by 1. the fault current must be calculated and the device selected as per ANSI standards. under column “Rated Short-Circuit Current” I = 18 kA.0X 1. fuse or other fault interrupting device in order to select a device adequate for the calculated fault current or to check the thermal and momentary ratings of non-interrupting devices.47 kV x 18 kA = 21.000 Amps) is also the base quantity that all the “related” capabilities are referred to. Voltage. Another way of expressing the close and latch rating is in terms of the peak current.65.75X 1.000 x 1.6 K x rated short circuit current.4 kA. Rated Short Circuit Current–This is the symmetrical rms value of current that the breaker can interrupt at rated maximum voltage.) The Rated Maximum Voltage This designates the upper limit of design and operation of a circuit breaker.3. From Table 1 in section C1 under column “Rated Maximum Voltage” V = 15 kV. above 69 kV FOA 12 to 30 MVA FOA 40 to 100 MVA X X X .A-16 Power Distribution System Design Fault Current Calculations for Specific Equipment Cutler-Hammer January 1999 A Fault 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. If this breaker is applied in a system rated at 2.06.5X 3. X/R Range 15 or less 15-40 30-50 30-50 40-60 40-120 CAT.T.6 x 36 = 57. Motors Below 50 Hp and All Single-Phase Motors Distribution System From Remote Transformers Current Limiting Reactors Transformers OA to 10 MVA.69. This is the rms symmetrical current that the breaker can interrupt down to a voltage = maximum rated voltage divided by K (for example. check the following: System Component Reactance X Used for Short-Circuit Duty Close and Latch (Momentary) X X X .6 x maximum symmetrical interrupting capability.24 = 35. This rating (29.000 since Test 1 calculation is not satisfied. this breaker could not be utilized even through the “Maximum Symmetrical Interrupting Capability” is greater than 22. 4. Since both of these numbers are greater than the available system fault current of 20. The calculation of available fault current and system X/R rating is utilized to verify adequate bus bar bracing and momentary withstand ratings of devices such as contactors. In order to determine if a Cutler-Hammer type 150 VCP-W 500 vacuum breaker is suitable for this application.6 or 58 kA.71. etc. consider the following case: Assume a 12. Synchronous machines connected directly to the bus or through reactors. (See section C1 of this catalog. also check K x I (which is shown in the column headed “Maximum Symmetrical Interrupting Capability”) or 1. 1800 Rpm and Above 250 Hp. 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.8 kV system. K-Rated Voltage Factor The rated voltage divided by this factor determines the system kV a breaker can be applied up to the short circuit kVA rating calculated by the formula 3 × Rated SC Current × Rated Max. Medium-Voltage VCP-W Metal-Clad Switchgear The applicable ANSI Standards C37.5 7-11 10 8-24 15 8-35 10 6-12 12 8-15 20 10-30 30 20-40 X X X X X X X X Table A4: Typical System X/R Ratio Range (for Estimating Purposes) Type of Circuit Remote generation through other types of circuits such as transformers rated 10 MVA or smaller for each three-phase bank. where the transformers provide 90 percent or more of the total equivalent impedance to the fault point. a circuit breaker with a 4.47 kV system with 20. 69 kV OA to 10 MVA.69 x K x rated shortcircuit current.4 kV the calculated fault current must be less than 36 kA.76 kV rated maximum voltage cannot be used in a 4.000 amperes. is the latest applicable edition.85).3 x 18 kA = 23. The steps in the calculation of fault currents and breaker selection are described hereinafter: Step 1–Collect the X and R data of the circuit elements.1 1.1 CO 1. Step 8–Go to the proper curve for the type of fault under consideration (3-phase. Typical values of impedances and their X/R ratios are given in Tables A3 and A4. Calculate E/X x 1.3 1. The R values are used to determine the X/R ratio.7 if the breaker close and latch capability is given in peak or crest amps.4 Multiplying Factors for E / X Amperes Multiplying Factors for E / X Amperes CAT.4.0 pu.2 1. The above calculations of XI and RI may be calculated by several computer programs. 130 120 110 6 4 3 12 5 10 8 6 4 100 3 90 80 Ratio X/R 70 60 50 40 30 Ratio X/R 100 90 80 70 60 50 40 30 20 10 4 70 60 50 40 30 TIME T P ART ING CO NT AC 5-CYCLE BREAKER 20 10 5-CYCLE BREAKER 20 10 5-CYCLE BREAKER 1.71. Step 4–Set-up the same network for resistance values. 5.3 1. Step 11–Reduce the network to an equivalent reactance. data from manufacturers is not available. type of breaker at the location (2. XI Step 7–Determine X/R = ---. The value of the impedances and their X/R ratios should be obtained from the equipment manufacturer.010 Article 5.2 1.4 Multiplying Factors for E / X Amperes 1.2 NT AC T PA RT ING 1.4 1. If the reactances and resistances are given either in ohms or per unit on a different voltage or kVA base. Also use Table A7 where the fault is supplied by a utility only. Call this resistance RI. negative and zero) networks properly connected for the type of fault under consideration.010 requires the use of the X values only in determining the E/X value of a fault current.0 1.Cutler-Hammer January 1999 Power Distribution System Design Fault Current Calculations for Specific Equipment A-17 In the calculation of faults for the purposes of breaker selection the rotating machine impedances specified in ANSI Standard C37. Step 3–Reduce the reactance network to an equivalent reactance. phase-tophase. The ANSI Standard C37. Step 5–Reduce the resistance network to an equivalent resistance. Call the reactance X. and decrement of the fault current. Table A5: Three-Phase Fault Multiplying Factors Which Include Effects of Ac and Dc Decrement.010 for the “interrupting” duty value of the short-circuit current. Step 10–Construct the sequence (positive.0 1. A6. A Table A7: Three-Phase and Line-to-Ground Fault Multiplying Factors Which Include Effects of Dc Decrement Only. Step 9–Interrupting duty short-circuit current = E/XI x MF. Use Table A7 if the short cricuit is fed predominantly from generators removed from the fault by two or more transformations or the per unit reactance external to the generation is 1. 130 120 110 100 90 80 Ratio X/R Step 2–Construct the sequence networks and connect properly for the type of fault under consideration. This caution does not apply where the base voltages are the same as the transformation ratio. Call this reactance XI. asymmetry. and contact parting time to determine the multiplier to the calculated E/XI. phase-to-ground).5 times or more than the subtransient reactance of the generation on a common base.as previously RI calculated.6 if the breaker close and latch capability is given in rms amperes or E/X x 2.1 1.0 1. and A7 for 5-cycle breaker multiplying factors. to account for the total fault clearing time. At initial short-circuit studies. Table A6: Line-to-Ground Fault Multiplying Factors Which Include Effects of Ac and Dc Decrement. Use the X values required by ANSI Standard C37. 130 120 8 7 110 5 See Tables A5.01. 3. or 8 cycles). Convert to a common kVA and voltage base. Use the X values required by ANSI Standard C37. in order to apply the proper multiplying factor.3 1.010 for the “Close and Latch” duty value of the short-circuit current.E TIME 3 .1 should be used. where E is the prefault value of the voltage at the point of fault nominally assumed 1. all should be changed to the same kVA and voltage base. Step 6–Calculate the E/XI value.T. A-18 Power Distribution System Design Fault Current Calculations for Specific Equipment Cutler-Hammer January 1999 A Application Quick Check Table For application of circuit breakers in a radial system supplied from a single source transa. maximum voltage rating exceeds the former. Short-circuit duty was determined operating voltage of the system; using E/X amperes and 1.0 multiplying factor for X/R ratio of 15 or less and 1.25 multiplying V max E b. ---- ≤ I × -------------- < KI See Table 1, Page C1-4. factor for X/R ratios in the range of 15 to 40. Vo XI Where: Source Operating Voltage I = Rated short circuit current Transformer kV Vmax = Rated maximum voltage of MVA Rating the breaker Motor Load 2.4 4.16 6.6 VD = Actual system voltage 100% 0% KI = Maximum symmetrical 1 1.5 interrupting capacity 1.5 2 50 VCP-W 250 c. E/XM x 1.6 ≤ closing and latch capability 2 2.5 12 kA 50 VCP-W 250 150 VCP-W 500 of the breaker. 10.1 kA 23 kA Step 12–Select a breaker whose: 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 capabilities of existing switchgears are investigated, the resistances should be included. For single line-to-ground faults the symmetrical interrupting capability is 1.15 x the symmetrical interrupting capability at any operating voltage but not to exceed the maximum 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 Duty ANSI Standard C37.010 indicates the reduction factors to use when circuit breakers are used as reclosers. Cutler-Hammer VCP-W breakers are listed at 100% rating factor for reclosing. 2.5 3 3 3.75 5 7.5 10 10 12Œ 15 20 20 25 30 50Œ Breaker Type and Sym. Interrupting Capacity at the Operating Voltage 50 VCP-W 350 46.9 kA 75 VCP-W 500 41.3 kA 3.75 5 7.5 10Œ 10 12 15 20Œ 50 VCP-W 250 36 kA 50 VCP-W 350 49 kA 12 13.8 150 VCP-W 500 22.5 kA 150 VCP-W 500 19.6 kA 50 VCP-W 250 33.2 kA 150 VCP-W 750 35 kA 150 VCP-W 750 30.4 kA 150 VCP-W 1000 150 VCP-W 1000 46.3 kA 40.2 kA Application Above 3300 Feet The rated one-minute power frequency withstand voltage, the impulse withstand voltage, the continuous current rating, and the maximum 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) 3,300 (and Below) 5,000 10,000 Correction Factor Current 1.00 0.99 0.96 Voltage 1.00 0.95 0.80 Œ Transformer impedance 6.5% or more, all other transformer impedances are 5.5% or more. CAT.71.01.T.E Cutler-Hammer January 1999 Power Distribution System Design Fault Current Calculations for Specific Equipment A-19 Application on Symmetrical Current Rating Basis Example 1 — Fault Calculations Given a circuit breaker interrupting and momentary rating in the table below, verify the adequacy of the ratings for a system without motor loads, as shown. Type Breaker 50VCP-W250 V Max. 4.76 kV 3ø Sym. Interrupting Capability @ V. Max. 29 kA Max. KI 36 kA @4.16 kV Oper. Voltage 4.76 [ -------- ] (29) = 33.2 kA I1 4.16 Close and Latch or Momentary 13.8 kV System Transformer System Total or X .99% 5.05 6.04% .0604 pu R .066% .65 .716 .00716 pu X/R 15 8 9 A For 3-Phase Fault 58 kA I3 LG Sym. Interrupting Capability 36 kA E I 3 ø = --- where X is ohms per phase and E X is the highest typical line-to-neutral operating voltage I or I3ø = B where X is per unit reactance X IB is base current 3.75 MVA Base current I B = ------------------------------ = .52 kA 3 (4.16 kV) I1 .52 I 3 ø = --- = ------------ = 8.6 kA Sym. X .0604 X System --- = 9 (is less than 15) would use R 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 3I B 3E I LG = ---------------------- or = ---------------------2X 1 + X 0 2X 1 + X 0 For this system, X0 is the zero sequence reactance of the transformer which is equal to the transformer positive sequence reactance and X1 is the positive sequence reactance of the system. Therefore, 3(.52) I LG = -------------------------------------- = 9.1 kA Sym. 2(.0604) + .0505 Using 1.0 multiplying factor, short-circuit duty = 9.1 kA Sym. LG (I2) 1.15 (33.2) = 38.2 kA I2 Note: Interrupting capabilities I1 and I2 at operating voltage must not exceed max. sym. interrupting capability Kl. Check capabilities I1, I2 and I3 on the following utility system where there is no motor contribution to short circuit. 13.8 kV X R 375 MVA Available On 13.8 kV System, 3.75 MVA Base 3.75 MVA Z = ----------------------- = .01 pu or 1% 375 MVA = 15 Z 2 2 2 2 X = X + R = R  ------ + 1  2  R 2 13.8 kV 3750 kVA 1 1 Z - -----------R = ------------------- = ------------ = 15.03 = .066% 2 226 X ----- + 1 2 R X X = --- ( R ) = 15 (.066) = .99% R Transformer Standard 5.5% Impedance has a ±7.5% Manufacturing Tolerance 4.16 kV 50VPC-W250 Transformer Z = 5.50 Standard Impedance –.41 (–7.5% Tolerance) 5.09% From transformer losses R is calculated 31,000 Watts Full Load –6,800 Watts No Load 24,200 Watts Load Losses Transformer X = Z –R 2 2 Answer 24.2 kW ---------------------R = 3750 kVA = .0065 pu or .65% 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 application. If we assume unlimited short circuit available at 13.8 kV and that Trans. Z = X IB .52 Then I 3 ø = ---- = --------- = 9.5 kA Sym. X .055 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). (5.09) – (.65) 2 2 = 25.91 – .42 = 25.48 X = 5.05% CAT.71.01.T.E A-20 Power Distribution System Design Fault Current Calculations for Specific Equipment Cutler-Hammer January 1999 A Example 2 — Fault Calculations Given the system shown with motor loads, calculate the fault currents and determine proper circuit breaker selection. 13.8 kV 13.8 kV System 21 kA Sym. Available X = 5.5% R = 0.55% X = 15 R X = 10 R All calculations on per unit basis. 7.5 MVA Base 7500 kVA Z = 5.53% Base Curent I B = ----------------------- = .628 kA 3 6.9 kV 7.5 MVA 6.9 kV 1 X 13.8 kV System .628 (6.9) X = --------- ------------- = .015 .015 21 (13.8) Transformer Total Source Transf. 3000 Hp Syn. Motor R X/R .001 15 2 .055 .0055 10 .070 pu .0065 pu 11 X = 25 R 197A FL X'' = 20% d 3 X = 35 R 173A FL X'' = 25% d (.628) X = .20 ------------- = .638 pu at 7.5 MVA base .197 2500 Hp Ind. Motor (.628) X = .25 ------------- = .908 pu at 7.5 MVA base (.173) IB E --I 3 ø = X = ---- where X on per unit base X Source of Short Circuit Current I3 Source Transf. I1 3000 Hp Syn. Motor I1 2500 Hp Syn. Motor Interrupting E/X Amperes .682 .070 = 8.971 3000 Hp 1.0 PF Syn. 2500 Hp Ind. Momentary E/X Amperes .682 .070 .628 .638 .628 .908 = 8.971 X R 11 X (1) R (X) 11 .070 25 .638 35 .908 1 R = 157 .628 = .656 (1.5) .638 .628 = .461 (1.5) .908 I3F = or 10.088 10.1 kA = .984 = .691 25 35 = 39 = 39 10.647 Total 1/R = 235 x 1.6 17.0 kA Momentary Duty IB .628 Total X = ------ = --------- = .062 I 3F 10.1 X System --- = .062 (235) = 14.5 is Mult. Factor 1.0 from Table 2. R Short Circuit Duty = 10.1 kA Type Breaker 75VCP-W500 150VCP-W500 V Max. 8.25 kV 15 kV 3ø Sym. Interrupting Capability @ V. Max. Max. KI @ 6.9 kV Oper. Voltage 33 kA 18 kA 41 kA 23 kA 8.25 (33) = 39.5 kA 6.9 15 (18) (39.1) = 23 kA 6.9 (But not to exceed KI) Close and Latch or Momentary 66 kA 37 kA Answer Either breaker could be properly applied, but price will make the type 150VCPW500 the more economical selection. CAT.71.01.T.E + -------.40).1 3 -----.E . Each generator is 7. The current limiting ability of a current limiting fuse is specified by its threshold ratio.and R S = -.= 28.16 kV CAT. factor 1. G1 G2 G3 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. extinguishes the arc.R or X S = --. A I I I X Table 2 System --.16 Type Breaker 50VCP-W250 V Max. Step 5–Calculate the E/XI value.-.4 kA Sym. Interrupting Ratings of Fuses Modern fuses are rated in amps rms symmetrical.-.. Expulsion Fuses A vented fuse in which the expulsion effect of gases produced by the arc and lining of the fuse holder.48 for fuse interrupting duty guidelines. E/X amperes X X X .11 X Medium-Voltage Fuses There are two basic types of medium-voltage fuses (the following definitions are taken from ANSI Standard C37. Current Limiting Fuses A fuse unit that when it is melted by a current within its specified current limiting range. For threephase faults E/XI is the fault current to be used in determining the required interrupting capability of the fuse. System -----.= --.= 30 R RS 3 3 Since generator neutral grounding reactors are used to limit the ILG to I3ø or below.Cutler-Hammer January 1999 Power Distribution System Design Fault Current Calculations for Specific Equipment A-21 Example 3 — Fault Calculations Check breaker application or generator bus for the system of generators shown. we need only check the I3 short-circuit duty.2 kA 4. Voltage 29 kA 36 kA 4.of 30 is Mult. 4.16 kV 1040 amperes full load. 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. Use the substransient X and R for all generators and motors.04) = 29.4 (1. B B B 31 B 3 ( 1.= Gen --.= --. Step 3–Construct the sequence networks using reactances and connect properly for the type of fault under consideration and reduce to a single equivalent reactance. abruptly introduces a high resistance to reduce the current magnitude and duration.71. They are distinguished from each other by the current ratings and minimum melting type characteristics. either alone or aided by a spring. 4.6 x the symmetrical rating. KI @ 4.= R X X R XS X X X R . IB = 1.X S = X + X + --.--.04 R Short-circuit duty is 28. peak let-through current and I2t characteristics. where E is the prefault value of the voltage at the point of fault normally assumed 1.ratio is 30 R 1 1 1 1 1 1 3 -----.04 kA Sub transient reactance Xd” = 11% or.76 kV Answer The 50VCP-W250 breaker could be applied. 4. Refer to ANSI/IEEE C37.0 in pu.04 ) I B ø = ---.= ----------------.T.and R S = R + R + -.01.16 kV Oper. There are two types of fuses. power and distribution.Therefore. Step 4–Same as above except using resistances (omit if a symmetrically rated fuse is to be selected). Max.5 MVA.76 (29) = 33.+ ---.+ ---. Interrrupting Capability @ V Max. X = 0.11 pu X Gen --.5 kA Symmetrical 3ø Sym. They also have a listed asymmetrical rms rating which is 1.1 -.--. This is because that the ratings established in the applicable standard are based on power factor values which amply cover most applications. Note: These are derating factors applied to the breaker.6 -4.1798 3.847 0.000 0. Table A2 should be used where older fuses asymmetrically rated are involved.805 0.7221 14.942 0. In low-voltage systems which contain generators the subtransient reactance should be used.9750 Interrupting Rating ≤ = 10kA 1.6. The X/R ratio is calculated in the same manner as that for medium-voltage circuit breakers. The lineto-ground fault may exceed the three-phase fault for fuses located in generating stations with solidly grounded neutral generators.627 >10 kA >20 kA ≤ = 20 kA 1.918 0.01.E .71. Current limiting fuses for threephase systems should be so applied that the fuse voltage rating is equal to or less than 1.15 max. CAT.73 3.8990 6. XI = XI(+) + XI(-) + XI(0) If the X/R to the point of fault is greater than 6. 480Y/277.718 ) MF = -----------------------------------------------------------------1.907 0. circuit breaker interrupting rating multiplying factors from the following table should be applied.2507 19. 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 motor loads the assumption is made that in 208Y/120-volt systems the contribution from motors is 2 times the full load current of stepdown transformer.794 0. E XI 10 or less over 10 to 20 over 20 All Low-Voltage Power Circuit Breakers Type Magnum DS.761 0.98 -1.25 If the X/R of the system feeding the breaker is not known use X/R = 20.659 0.718 X1/R1 = test X/R value.815 0.9 6.000 1.874 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.645 0.000 1.25-0.740 1.000 1.× 3 Step 6–Select a fuse whose published interrupting rating exceeds the calculated fault current. X2/R2 = X/R at point where breaker is applied.45-0.29 If the X/R of system feeding the breaker is not known use X/R = 15. a derating multiplying factor (MF) must be applied.762 0.962 0.000 1. or in delta-wye transformers with the wye solidly grounded.2731 9. This corresponds to an assumed 50% motor aggregate impedance on a kVA base equal to the transformer kVA rating or 50% motor load.41 x nominal system voltage.87 -3.000 1. Refer to Table A8 for the standard ranges of X/R and Power Factors used in testing and rating low-voltage breakers.718 0.823 All LV PCB 1.718 ] MF = -------------------------------------------------------------2. MF is always greater than 1.865 0. I f = ---.000 0. where the sum of the positive and negative sequence impedances on the high-voltage side (delta) is smaller than the impedance of the transformer.691 0. Again the calculated fault current x MF ≤ breaker interrupting capacity. Table A9: Circuit Breaker Interrupting Rating Multiplying Factors % X/R P. 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.673 0.937 0.6 min.000 1.20 0.718 1 + 2.50 0.883 0. 50 30 25 20 15 12 10 9 7 5 1.847 0. For single line-to-ground fault. Refer to Table A9 for the circuit breaker interrupting rating multiplying 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. X2 -π ⁄  ------  R 2 -π ⁄  ------  R 1 1 MF = --------------------------------------X 1 + 2. Established standard values include the following: Table A8: Standard Test Power Factors Type of Circuit Breaker Molded Case Molded Case Molded Case Low-Voltage Power Interrupting Rating in KA Power Factor Test Range 0. Because molded case breakers are tested at lower X/R ratios the MFs are different than those for low-voltage power circuit breakers. Calculated symmetrical Amps x MF ≤ breaker interrupting rating.000 1. For distribution systems where the calculated short-circuit current X/R ratio differs from the standard values given in the above table.15-0. The multiplying factor MF can be calculated by the formula: 2 [ 1 + 2.T.000 0.30 0.7321 3. For 480-.000 0.000 1.9499 11.5912 8. Normally the short circuit power factor or X/R ration of a distribution system need not be considered in applying low-voltage circuit breakers.18 6. This current is very nearly 3 /2 x three-phase fault. X/R Test Range 1.847 0.0.899 0. – ( 2π )/ ( X ⁄ R ) – ( 2π ) ⁄ ( X ⁄ R ) Refer to Table A8 for the standard ranges of X/R and power factors used in testing and rating low-voltage breakers.A-22 Power Distribution System Design Fault Current Calculations for Specific Equipment Cutler-Hammer January 1999 A Note: It is not necessary to calculate a single phase-to-phase fault current.899 0.F.778 0.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 transformer which corresponds to an assumed 25% aggregate motor impedance on a kVA base equal to the transformer kVA rating or 100% motor load. Refer to Table A9 for the circuit breaker interrupting rating multiplying 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.8730 4. For fused breakers by the formula: 1 + 2 × ( 2.950 0. kVA = (0. (c) 9. source. Change ohms. Determine line-to-line short-circuit current: (a) (3-phase kVA base) (100) 1-phase kVA base (100) = --------------------------------------------------------------------.g. Change per unit.Cutler-Hammer January 1999 Power Distribution System Design Short-Circuit Calculations A-23 Short-Circuit Calculations–Short Cut Method Determination of Short-Circuit Current Note 1. etc. Transformer impedance generally relates to self-ventilated rating (e. cables transformers.= --------------------------------------------.. 4-wire systems —In commercial buildings. (a) —synchronous motor—5 times motor full load current (impedance 20%) See IEEE Standard No. Determine motor contribution (or feedback) as source of fault current: —from single-phase transformer—see page A-25. 3 x 75 kVA = 225 kVA.0) (hp) 1-phase kVA or ----------------------------------------------kV line-to-neutral —if 0. Note 4. Determine symmetrical short-circuit current: (a) 3-phase kVA Base current = I Base = ---------------------------------( 3 ) ( kV ) 1.. Change power-source impedance to per-unit or percent impedance on kVA base as selected for this study: (a) (% impedance) ( kV )2 (10) Ohms impedance = -------------------------------------------------------------------kVA base —if utility fault capacity given in kVA kVA base in study Per-unit impedance = pu Z = -----------------------------------------------------------------------------------------power-source kVA fault capacity (b) —if utility fault capacity given in rms symmetrical short-circuit Amps kVA base in study Per-unit impedance = pu Z = --------------------------------------------------------------------------------------------------------------(short-circuit current) ( 3 )(kV of source) 5. proper combining of impedances (e.. Z = 2%) calculate same as one three-phase unit (i. arithmetic combining of impedances as “ohms Z”. Z = 2%).T.0) (hp) kVA = (1.0 times transformer full-load current —on 240-480-600-volt 3-phase.0 (b) Per unit I SC = ----------puZ (c) Rms Symmetrical current = ISC = (pu ISC) (IBase Amps) 3-phase kVA base 1-phase kVA base (d) Rms Symmetrical current = Amps = ------------------------------------------------. Note 2. or percent. or percent or per-unit.) should use individual R and X components. impedance from one kVA base to another: (a) kVA base 2 Per unit = pu impedance kVA base 2 = -----------------------------.= ---------------------------------------------------.E .0 times transformer full-load current (100% motor load) } CAT. kV refers to line-to-line voltage in kilovolts. Note 3.01. 3-wire systems—4.= -------------------------------( puZ ) %Z ohms Z 3(line-to-neutral kV) 2 ( 1000 ) = ----------------------------------------------------------------------------(ohms Z) —from three-phase transformer—approx. etc.0 times transformer full-load current —on 480Y/277-volt 3-phase. When totaling the components of system Z. 86% of three-phase current (b) —three single-phase transformers (e. is considered a short cut or approximate method.8) (hp) kVA = (1. Change motor rating to kVA: (a) (c) —motor kVA— ( 3 ) (kV) (I) where motor nameplate full-load Amps.g. conductors. Determine symmetrical short-circuit kVA: (a) (b) 8. 2..× (pu impedance on kVA base 1) kVA base 1 kVA base 2 (b) Percent = % impedance kVA base 2 = -----------------------------. A 1. 75 kVA.8 power factor synchronous motor (b) —if 1. Select convenient kVA base for system to be studied. use contribution from group of motors as follows: —on 208Y/120-volt systems—2. This Total Z = Total R + j Total X (See IEEE “Red Book” Standard No. 141). 4. “per unit Z”. 141 (b) —induction motor—4 times motor full-load current (impedance 25%) (c) —motor loads not individually identified.or ------------------------------------------------( puZ ) ( kV ) ( puZ ) ( 3 ) ( kV ) (e) (g) 7. etc. with OA/FA/FOA transformer use OA base). short circuit kVA = ------------------------..g. Z refers to line-to-neutral impedance of system to fault where R + jX = Z.e. 2.----------------------------( kV ) 2 ( 1000 ) 100 (ohms impedance) (kVA base) (b) Per unit impedance = % Z = ---------------------------------------------------.0 times transformers full-load current (50% motor load) —In industrial plants.or ----------------------------------------------------------------(%Z) ( kV ) (%Z) ( 3 ) ( kV ) (kV) (1000) = ---------------------------------3 (ohms Z) kVA base (kVA base) (100) ( kV )2 ( 1000 ) Sym.----------------------------( kV )2 ( 10 ) (c) 4.71.0 power factor synchronous motor (d) —if induction motor 6.: (a) (ohms impedance) (kVA base) percent impedance Per unit impedance = pu Z = ----------------------------------------------------.× (% impedance on kVA base 1) kVA base 1 3. using approximate “short cut” method—see Note 4. A Utility Major Contribution B C Transformer 1.00619 ohms (100 circuit feet) D.75% 480 Volts Cables Switchboard Fault Cables Cable Fault Switchboard Fault .0575 pu ..00619 ohms (ohms) (kVA base) ( 0.= ---------. 3-350 Kcmil Cable in Steel Conduit 1.002 pu 100 Ft.00 pu A B C .480 ) CAT..027 pu Cable Fault Combining Series Impedances: ZTOTAL = Z1 + Z2 + .00 pu 1. 1 Z1 Z2 Zn .01.0777 ) ( 3 ) ( 0.0575 pu 100 100 kVA base 1000 Motor contribution per unit impedance = Z pu = --------------------------------------.A-24 Power Distribution System Design Short-Circuit Calculations Cutler-Hammer January 1999 Example No.= 15.75 Transformer per unit impedance = Z pu = --------.= ------------------------------------------------------.0507 pu E . 480 Amps rms ( Z pu ) ( 3 ) ( kV ) ( 0.= 0.342 pu .480 ) ( 1000 ) 2 4(a) 3 3(a) 4 4(a) and 9(c) 3(a) 5 6 6(d) Total impedance to switchboard fault = 0.. single conductors Circuit length: 100 ft.00619 ) ( 1000 ) Cable impedance per unit = Z pu = --------------------------------------------------.00 pu 1.027 pu .= -------------------------------------------.0507 pu (see diagram above) 3-phase kVA base 1000 Symmetrical short-circuit current at switchboard fault = ------------------------------------------------.002 pu utility fault kVA 500.00 pu 4 x motor kVA 4 x 250 Cable impedance in ohms (see above) = 0.720 Amps rms ( Z pu ) ( 3 ) ( kV ) ( 0.000 %Z 5. Conductors: 3-350 kcmil copper.027 pu Switchboard Fault .027 pu .= 0.= 1. of 3-350 Kcmil Cable in Steel Conduit Feeding Lighting and 250 kVA of Motors Cable Fault . Fault current calculations (combining impedances arithmetically.0777 pu (see diagram above) 3-phase kVA base 1000 Symmetrical short-circuit current at cable fault = ------------------------------------------------. System Diagram Utility Source 500 MVA B. in steel (magnetic) conduit Impedance Z = 0.0595 pu ..027pu 2 2 ( kV ) ( 1000 ) ( 0. kVA base 1000 Utility per unit impedance = Z pu = -----------------------------------------.E . Impedance Diagram (Using “Short Cut” Method for Combining Impedances and Sources). page A-23) Equation (See page A-23) – .= 0.1 A A.00619 ohms/100 ft.480 ) 7 6(d) Total impedance to cable fault = 0.= ------------------. Conductor impedance from Tables A-45 and A-46. page A-64. +Zn Combining Parallel Impedances: 1 = ZTOTAL 1 + 1 + .000 kVA 5. ZTOT = 0.0777 pu C.0507 ) ( 3 ) ( 0.= ------------------------------------------------------..= -------------------.= 23. since all data except utility source is on secondary of 1000 kVA transformer.T.027 pu Mixed Load — Motors and Lighting Each Feeder — 100 Ft.027 pu Step 1 Calculation Select 1000 kVA as most convenient base.71. 03408 D.  100  = 0.386 Amp sym.000 (From page A-23.00332 pu 1.9887Z { X = 6.04669 pu Œ To account for the outgoing and return paths of single-phase circuits (conductors.1498 x Z) XSyst = 2 (0.T.= 6.64 RTfmr = ---------100 2.27 XTfmr = 1. X = 2.27% 120 Volts F2 240 Volts F1 Half-winding of Transformer Multiply % R by 1.27 XTfmr = ---------100 = 0.0104 Ohms X = 0. System Diagram R = 0. systems.03191 F2 F2 XSyst = 0. Z= Z= ( 0.00356 RCond = 0.2  ---------.00677 pu = 0.0018 pu 3 × 0.0051 Ohms (From tables page 30) R = 0.6R ) + R = 2 2 44.0164 RTotal = 0.48 )2 × 1000 0.243 Amp sym.1498 Z 480-Volt 3-Phase Switchboard Bus at 50. Impedance Diagram—Fault F1 RSyst = 0.02371 F1 F1 RSyst = 0.6 X = 0.  100  2.0272 XTotal = 0.01.104 × 75  --------------------------------------  ( 0.02958 C.E . etc.00356 pu = 0. 2 Fault Calculation — Secondary Side of Single-Phase Transformer A.0227 RTotal = 0. Short-circuit current F2 = 75 ÷ (0.02371 ) + ( 0.48 )2 × 1000 = 0.5 Reference: IEEE Standard No. 141 Multiply % X by 1.6 R 2 A 43.6753 100 Ft.0246 pu = 0.9887 Z Deriving Transformer R and X: X --.8%.= 0.03191 ) + ( 0. X/R = 6.120 kV) = 13. Formula 4(b) ) RSyst = 2 (0.6 R X = 6.2 { } Full-winding of Transformer B. R = 1.00356 XCond = 0.000 Amp Symmetrical.00054 RCond = 0.6R 75 kVA Single-Phase 480-120/240 Volts. Two #2/0 Copper Conductors. Z = 2. Impedance Diagram—Fault F2 RSyst = 0.) use twice the 3-phase values of R and X. Formula 3(a) ) XCond = 2 Full-winding of Tfmr (75 kVA Base) 0.00054 pu = 0.0272 pu 2 2 Impedance to Fault F1 — Full Winding Impedance to Fault F2 — Half Winding Short-circuit current F1 = 75 ÷ (0.Cutler-Hammer January 1999 Power Distribution System Design Short-Circuit Calculations A-25 Example No.0051 × 75  --------------------------------------  ( 0.56R = 6.480 × 50.0277 pu Half-winding of Tfmr (75 kVA Base) 1.1498Z X = 0.03408 ) 2 2 = 0.00677 RTfmr = 0.0246 RTotal = 0.00677 RTfmr = 0.04669 x 0.00332 XTfmr = 0.71.0164 pu = 0.9887 x Z) ohms × kVA Base ZCond = ------------------------------------------------2 ( kV ) × 1000 RCond = 2 (From page A-23.64%. Magnetic Conduit R = 0.5  ---------.00332 RTfmr = 0.64 RTfmr = 1.02958 ) ( 0.00054 RCond = 0. CAT.56R + R = 2 2 { Z= X +R = 2 ( 6.03791 x 0.6753R 2 Z R = ----------------6.240 kV) = 8.03791 pu = 0. Impedance and Fault Current Calculations—75 kVA Base Œ 75 ZSyst = ---------------------------------------------------. 00546 ohms per 100 ft. For Example: For a 480/277-volt system with 30.00273 = 0.00546/2 = 0.160 amperes CAT. and 2 conductors per phase we have: 0.01.00923 ohms (source impedance) Conductor ohms for 500 kcmil conductor from reference data in this section in magnetic conduit is 0.71.000 amperes = 0.T. the approximate fault current at the load side end of the conductors can be calculated as follows.00273 ohms (conductor impedance) Add source and conductor impedance or 0.E .01196 total ohms X 30. 2-500 kcmil per phase X Next.160 amperes rms at load side of conductors If = 23.A-26 Power Distribution System Design How to Calculate Short-Circuit Currents at Ends of Conductors Cutler-Hammer January 1999 Method 1 – Short Cut Methods A This method uses the approximation of adding Zs instead of the accurate method of Rs and Xs. 277 volts/0.00923 + 0.000 amperes symmetrical available at the line side of a conductor run of 100 feet of 2500 kcmil per phase and neutral. 277 volts/30.01196 ohms = 23. For 100 ft.000 amperes available 100 ft. but should eliminate the possibility of applying units which will not be safe for the possible fault duty.5 0 0 2 5 10 20 50 100 200 500 1000 2000 Distance in Feet from Transformer to Breaker Location 5000 CAT.000 F 50.000 Fault Current in Thousands of Amperes (Sym. Feeder Conductors The conductor sizes most commonly used for feeders from molded case circuit breakers are shown.000 kVA curves. it is reasonable to assume that the connected load consists of 50% motor load. Table A10: Conductor Conversion (Based on Using Copper Conductor) If Your Conductor is: 3 – No. The circuit breaker should have an interrupting capacity at least as large as this value. Chart 1 – 225 kVA Transformer/4. In some cases it may be necessary to interpolate for unusual feeder ratings.000 kVA.0 7.Cutler-Hammer January 1999 Power Distribution System Design How to Calculate Short-Circuit Currents at Ends of Conductors A-27 Method 2–Chart Approximate Method The chart method is based on the following: Motor Contribution For system voltages of 120/208 volts. the chart for the lowest kVA transformer is shown first.000 kVA it is appropriate to use the 500. and that the motors will contribute four times their full load current into a fault.0 2.000 E 100. You may interpolate between curves if necessary. see the formula method. System voltage 2. The charts are grouped by secondary system voltage which is listed with each transformer. Step Four Select the specific curve for the conductor size being used. For system voltages of 240 and 480 volts. Primary source fault energy available in kVA (from electric utility or distribution system engineers) Step Two Select the applicable chart from the following pages. lead to application of circuit breakers having interrupting ratings higher than necessary. Step Three Select the family of curves that is closest to the “available source kVA. it is reasonable to assume that the connected load consists of 100% motor load. Table A10 is based on using copper conductor.000 D 150. refer to the conductor conversion Table A10. A How to Use the Short-Circuit Charts Step One Obtain the following data: 1. Draw a vertical line up the chart to the point where it intersects the selected curve. The lower value line (in red) family of curves is for a source of 50. Transformer kVA rating (from transformer nameplate) 3.000 C 250.) 15. For a more exact determination. Step Five Enter the chart along the bottom horizontal scale with the distance (in feet) from the transformer to the fault point. Within each group. If your conductor size is something other than the sizes shown on the chart. Therefore. For conductor sizes not shown. It should be noted that even the most exact methods for calculating fault energy use some approximations and some assumptions. and that the motors will contribute four times their full load current into a fault.5 4 – 750 kcmil 2 – 500 kcmil 250 kcmil #1/0 AWG #4 AWG 5. the following table has been included for conversion to equivalent arrangements.T. in some cases. This may. 2/0 cables 3 – 2000 kcmil cables 5 – 400 kcmil cables 6 – 300 kcmil cables 800 Amp busway 1000 Amp busway 1600 Amp busway Use Equivalent Arrangement 2 – 500 kcmil 2 – 500 kcmil 4 – 750 kcmil 4 – 750 kcmil 4 – 750 kcmil 2 – 500 kcmil 2 – 500 kcmil 4 – 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.01.” The black line family of curves is for a source of 500. followed in ascending order to the highest rated transformer. but not more burdensome than is justified.5% Impedance/208 Volts 4 – 750 kcmil 2 – 500 kcmil 250 kcmil #1/0 AWG #4 AWG UTILITY KVA A INFINITE B 500. 4/0 cables 4 – No. The charts which follow make use of simplifications which are reasonable under most circumstances and will almost certainly yield answers which are on the safe side. but for values above 100. it is appropriate to select a method which is sufficiently accurate for the purpose. These motor contributions have been factored into each curve as if all motors were connected to the transformer terminals. Then draw a horizontal line to the left from this point to the scale along the left side of the chart.5 10.71.E . Transformer impedance (from transformer nameplate) 4. Step Six The value obtained from the left-hand vertical scale is the fault current (in thousands of amperes) available at the fault point.0 B F 12.000 kVA. 000 Fault Current in Thousands of Amperes (Sym.) Fault Current in Thousands of Amperes (Sym.000 250.) 60 4 – 750 kcmil 2 – 500 kcmil 250 kcmil #1/0 AWG #4 AWG B F 30 50 A INFINITE B 500.71.E .000 50.5% Impedance/208 Volts Chart 7 – 2000 kVA Transformer/5.000 D 150.000 20 40 30 10 5 4 – 750 kcmil 2 – 500 kcmil 250 kcmil #1/0 AWG #4 AWG 20 4 – 750 kcmil 2 – 500 kcmil 250 kcmil #1/0 AWG #4 AWG 10 0 0 2 5 10 20 50 100 200 500 1000 2000 Distance in Feet from Transformer to Breaker Location 5000 0 0 2 5 10 20 50 100 200 500 1000 2000 Distance in Feet from Transformer to Breaker Location 5000 Chart 3 – 500 kVA Transformer/4.000 UTILITY KVA 120 4 – 750 kcmil 2 – 500 kcmil 250 kcmil #1/0 AWG #4 AWG A INFINITE B 500.000 D 150.000 D 150.000 C 250.) 30 4 – 750 kcmil 2 – 500 kcmil 250 kcmil #1/0 AWG #4 AWG B F 15 25 A INFINITE B 500.) 120 B 100 4 – 750 kcmil 2 – 500 kcmil 250 kcmil #1/0 AWG #4 AWG A INFINITE B 500.000 C 250.000 F 50.000 40 80 F 60 20 4 – 750 kcmil 2 – 500 kcmil 250 kcmil #1/0 AWG #4 AWG 40 10 20 4 – 750 kcmil 2 – 500 kcmil 250 kcmil #1/0 AWG #4 AWG 0 0 2 5 10 20 50 100 200 500 1000 2000 Distance in Feet from Transformer to Breaker Location 5000 0 0 2 5 10 20 50 100 200 500 1000 2000 Distance in Feet from Transformer to Breaker Location 5000 CAT.000 F 50.) 30 F 25 4 – 750 kcmil 2 – 500 kcmil 250 kcmil #1/0 AWG #4 AWG UTILITY KVA A B C D E F INFINITE 500.000 E 100.000 F 50.000 E 100.000 150.T.000 C 250.A-28 Power Distribution System Design How to Calculate Short-Circuit Currents at Ends of Conductors Cutler-Hammer January 1999 Chart 2 – 300 kVA Transformer/4.000 D 150.) Chart 6 – 1500 kVA Transformer/5.000 E 100.5% Impedance/208 Volts Chart 5 – 1000 kVA Transformer/5.5% Impedance/208 Volts B Fault Current in Thousands of Amperes (Sym.5% Impedance/208 Volts UTILITY KVA UTILITY KVA Fault Current in Thousands of Amperes (Sym.5% Impedance/208 Volts Fault Current in Thousands of Amperes (Sym.000 E 100.000 F 50.01.000 D 150.5% Impedance/208 Volts A UTILITY KVA Fault Current in Thousands of Amperes (Sym.000 100.000 60 B 50 F 4 – 750 kcmil 2 – 500 kcmil 250 kcmil #1/0 AWG #4 AWG UTILITY KVA A INFINITE B 500.000 C 250.000 F 50.000 C 250.000 E 100.000 100 80 B 20 60 F 15 4 – 750 kcmil 2 – 500 kcmil 250 kcmil #1/0 AWG #4 AWG 40 10 20 4 – 750 kcmil 2 – 500 kcmil 250 kcmil #1/0 AWG #4 AWG 5 0 0 2 5 10 20 50 100 200 500 1000 Distance in Feet from Transformer to Breaker Location 2000 5000 0 0 2 5 10 20 50 100 200 500 1000 2000 Distance in Feet from Transformer to Breaker Location 5000 Chart 4 – 750 kVA Transformer/5. 000 50 20 4 – 750 kcmil 2 – 500 kcmil 250 kcmil #1/0 AWG #4 AWG 40 4 – 750 kcmil 2 – 500 kcmil 250 kcmil #1/0 AWG #4 AWG B 15 B F 30 F 10 4 – 750 kcmil 2 – 500 kcmil 250 kcmil #1/0 AWG #4 AWG 0 2 5 10 20 50 100 200 500 1000 2000 Distance in Feet from Transformer to Breaker Location 5000 20 5 10 4 – 750 kcmil 2 – 500 kcmil 250 kcmil #1/0 AWG #4 AWG 0 0 0 2 5 10 20 50 100 200 500 1000 2000 Distance in Feet from Transformer to Breaker Location 5000 Chart 10 – 750 kVA Transformer/5.000 C 250.000 D 150.000 D 150.) 30 25 A INFINITE B 500.E .5% Impedance/480 Volts A UTILITY KVA Fault Current in Thousands of Amperes (Sym.) UTILITY KVA 60 4 – 750 kcmil 2 – 500 kcmil 250 kcmil #1/0 AWG #4 AWG A INFINITE B 500.000 C 250.5% Impedance/480 Volts UTILITY KVA Fault Current in Thousands of Amperes (Sym.71.000 F 50.000 C 250.000 E 100.000 E 100.Cutler-Hammer January 1999 Power Distribution System Design How to Calculate Short-Circuit Currents at Ends of Conductors A-29 Chart 8 – 300 kVA Transformer/4.5% Impedance/480 Volts Chart 13 – 2000 kVA Transformer/5.000 D 150.000 F 50.) 30 25 4 – 750 kcmil 2 – 500 kcmil 250 kcmil #1/0 AWG #4 AWG B F A INFINITE B 500.000 C 250.) UTILITY KVA 60 A INFINITE B 500.5% Impedance/480 Volts UTILITY KVA Fault Current in Thousands of Amperes (Sym.000 D 150.) 12 10 B F 8 A INFINITE B 500.000 30 B 25 4 – 750 kcmil 2 – 500 kcmil 250 kcmil #1/0 AWG #4 AWG UTILITY KVA A INFINITE B 500.000 D 150.000 E 100.) Fault Current in Thousands of Amperes (Sym.000 D 150.000 50 B 20 40 F 30 15 10 4 – 750 kcmil 2 – 500 kcmil 250 kcmil #1/0 AWG #4 AWG 20 5 10 4 – 750 kcmil 2 – 500 kcmil 250 kcmil #1/0 AWG #4 AWG 0 0 0 2 5 10 20 50 100 200 500 1000 2000 Distance in Feet from Transformer to Breaker Location 5000 0 2 5 10 20 50 100 200 500 1000 2000 Distance in Feet from Transformer to Breaker Location 5000 CAT.000 C 250.000 Fault Current in Thousands of Amperes (Sym.000 20 F 6 4 4 – 750 kcmil 2 – 500 kcmil 250 kcmil #1/0 AWG #4 AWG 4 – 750 kcmil 2 – 500 kcmil 250 kcmil #1/0 AWG #4 AWG 0 2 5 10 20 50 100 200 500 1000 2000 Distance in Feet from Transformer to Breaker Location 5000 15 4 – 750 kcmil 2 – 500 kcmil 250 kcmil #1/0 AWG #4 AWG 10 2 5 0 0 0 2 5 10 20 50 100 200 500 1000 2000 Distance in Feet from Transformer to Breaker Location 5000 Chart 9 – 500 kVA Transformer/4.000 F 50.5% Impedance/480 Volts Chart 11 – 1000 kVA Transformer/5.5% Impedance/480 Volts Chart 12 – 1500 kVA Transformer/5.000 Fault Current in Thousands of Amperes (Sym.000 E 100.T.000 E 100.000 F 50.01.000 C 250.000 F 50.000 E 100.000 F 50. = 1.5 – 1..46 = 5. from Table A27.= 1. 100 %Z %X = 5. 1700W no-load loss.48 2 2 2 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.30% Method 2: Using same values above. I R Losses %R = -------------------------10 × kVA 7300 2 -------------------. assuming sustained primary voltage during fault.46 10 × 500 2 2 %X = 5.01.46% 2 10 × 0. i. CAT. Since the power source must always have some impedance this a conservative value. an infinite or unlimited primary power source (zero source impedance). 5. This will yield more accurate results and allow for including motor short circuit contribution.T.5% Z transformer with 9000W total loss.A-30 Power Distribution System Design Determining X and R Values From Transformer Loss Data Cutler-Hammer January 1999 A Determining X and R Values From Transformer Loss Data Method 1: Given a 500 kVA.30% See Tables A31.480 %R = .0067 ohms 0.0067 × 500 %R = -----------------------------. and use appropriate row of data based on transformer kVA and primary short circuit current available. 500 3 ×  ------------------------- × R = 7300 Watts -  3 × 0.71.46 = 5.E . page A-60. use the formula: I sc = I FLC × -------where %Z is the transformer impedance in percent.5 – 1. This is the maximum three-phase symmetrical bolted-fault current. A32 and A33 on page A-61 for loss data on transformers. actual fault current will be somewhat less. 7300W load loss and primary voltage of 480V. Method 2: Refer to Table A25 in the Reference section.e. Note: This will not include motor short circuit contribution. tables give voltage drop per ampere per 100 feet of circuit length (not conductor length). in correct column for type of conductor. 80% pf = 0.16 volts 100 4. The feeder length is 150 feet.2 3.T.) Œ Busway voltage drop tables are shown in section H2 of this catalog. 3. running at 80% pf.0 5. Three or four single conductors in a conduit.2 1. phase to neutral x 0.00951 A Tables for calculating voltage drop for copper 1.577 3.7 3. Where this results in an oversized cable.6 3. Divided by 100 = 186 3. It is desired to use aluminum conductors in aluminum conduit. the nearest lower value is 0. Tables are based on the following conditions: 1. 2-wire x 1.1 70% 60% 4. 100-hp motor. phase-to-neutral x 0. 2 to 3/0 4/0 to 500 kcmil 600 to 1000 kcmil 5.0 5. Divide voltage drop by (amperes x circuit feet). 3-wire. For conductor temperature of 60°C – SUBTRACT the percentage from Table A11.76% voltage drop is very acceptable 4. 14 to No. Determine maximum desired voltage drop. These 2.0 4. correction factors in the table below can be applied if desired. not conductor length). but the voltage drop would be excessive.3 Example: A 460-volt. 5. Voltage drops are for a conductor temperature of 75°C.7 2. In table.6 2.6 80% 4. 2. 4-wire. CAT. four-wire lighting feeder on a 208-volt circuit is 250 feet long. For conductor temperature of 90°C – ADD the percentage from Table A11. Find nearest lower voltage drop value in tables. Voltage drops are phase-to-phase. nonmagnetic conduit.01. They may be used for conductor temperatures between 60°C and 90°C with reasonable accuracy (within ± 5%). appear on page A-32. 3-wire. (Size 4/0 THW would have adequate ampacity. draws 124 amperes full-load current. 3. Where lug size available is exceeded.48 x 100 = 0.7 4. For three-conductor cable.9 1. 2. 90% pf. What size conductor is required to limit the voltage drop to 2% phase-to-phase? 1. What is the voltage drop in the feeder? What is the percentage voltage drop? 1. under Aluminum Conductors.0000951 175 × 250 0. Conductor required is 500 kcmil.1 2. conduit. Conclusion – . and power factor. 3-wire or 3-phase. Multiply current in amperes by the length of the circuit in feet to get ampere-feet and aluminum conductors.= 0.Cutler-Hammer January 1999 Power Distribution System Design Voltage Drop A-31 Voltage Drop Voltage Drop TablesŒ Calculations To calculate voltage drop: To select minimum conductor size: 1.600 ampere-feet 2. Table A11: Temperature Correction Factors for Voltage Drop Conductor Size Percent Correction Power Factors 100% 90% No.5 2. random lay. 3. Actual voltage drop will be from 10 to 15% lower for larger conductor sizes and lower power factors.48 volts drop 3. Result is voltage drop.6 3. 4 No. phase-to-phase x 1.76% drop — 460 4. (steel) or nonmagnetic (aluminum or nonmetallic) conduit. 124 amperes x 150 ft = 18. in volts.0 5.155 1-phase.5 4. go to next higher rating. magnetic conduit.3 1. 4. Multiply by 100. verify cable lug sizes for molded case breakers and fusible switches.155 1-phase. For other circuits. The values in the table are in percent of total voltage drop.71.0187 = 3. 4-wire 60 Hz circuits. Table: 2/0 copper.E . Read conductor size for that value. Divide by 100. Multiply by proper voltage drop value in tables. in either magnetic (circuit length. Example: A three-phase. 2 VD = -------. However.× 208 = 4. actual voltage drop will be approximately the same for small conductor sizes and high power factors. It is fed by three 2/0 copper conductors in steel conduit.0091.0187 186 x 0. 2.0000951 × 100 = 0. multiply voltage drop given in the tables by the following correction factors: 3-phase. The load is 175 amps at 90% pf. for 3-phase.577 1-phase.16 ----------------------. 0122 .0335 .0850 .0333 .0887 .4349 .0063 .0305 .0443 .4848 .0267 .0229 .1745 .0086 .0334 .0187 .0220 .0070 .0342 .0058 100 .0109 .0179 .0099 .0060 .0241 .2740 .0091 .0124 .0888 .1370 .0071 100 .0111 .0130 .0124 .0411 .0357 .0403 .0167 .0067 .2741 .3296 .2106 .0238 .0064 .T.0312 .0800 .0078 90 .0091 .1250 .0595 .0133 .1951 .0136 .0112 .0064 70 .3900 .0049 .2429 .1349 .0106 .0862 .0094 .0138 .0485 .0160 .0336 .1970 .0090 .0087 .0112 .0046 .0040 .0169 .0077 .A-32 Power Distribution System Design Voltage Drop Cutler-Hammer January 1999 A Table A12: Voltage Drop Volts per Ampere per 100 Feet. % 60 .0133 .0070 .0300 .0159 .1010 .2410 .0176 .1790 .0101 . % 60 .5331 .0134 .0081 .0099 .1150 .0533 .0158 .0099 .0423 .0144 .0122 .5410 . % 60 .0085 70 .0341 .0096 .0087 .0100 .0172 .0112 .0171 .0139 .0523 .1018 .0104 .0181 .3811 .0171 .0069 .0349 .0116 .0077 .E .0670 .0275 .0747 .0125 .4328 .0093 .0483 .0097 .0144 .0134 .0147 .2490 .1260 .0082 .0260 .0114 .4430 .0074 .0174 .0145 .0119 .0104 .0097 .0102 .2810 .0126 .0072 90 .0085 .0849 .0213 .0035 Nonmagnetic Conduit (Aluminum or Nonmetallic) Load Power Factor.0106 .3910 .5330 .0091 .0534 .2115 .0078 .3802 .0209 .0579 .71.0081 .1127 .0198 .0273 .0535 .0124 .0428 .0063 100 .0131 .0211 .0730 .1390 .0094 .0332 .0172 .0077 80 .0218 .0096 .0211 .0084 .0322 .0396 .0134 .0286 .0270 .0244 .0069 .0171 .0149 .1254 .0339 .0399 .0084 .0084 .3390 .0075 .0234 .0051 .2800 .1758 .0350 .2170 .0080 .0473 .0256 .0035 .3120 . % 60 .0072 .01.0124 .0654 .1030 .0246 .0042 .0251 .0069 .0154 .0443 .0064 .0905 .0742 .0155 .3370 .0043 Nonmagnetic Conduit (Aluminum or Nonmetallic) Load Power Factor.1361 .1590 .0287 .0179 .2150 .1011 .0162 .0088 .0111 .0100 .0222 .0183 .0180 .0809 .3410 .0076 .0222 .0120 .1140 .3180 .0123 .0279 .0898 .0081 .0077 .0148 .0111 .1980 .0264 .0190 .0080 .0138 .0078 .3312 .0544 .0233 .0029 Aluminum Conductors Conductor Size AWG or kcmil 12 10 8 6 4 2 1 1/0 2/0 3/0 4/0 250 300 350 500 600 750 1000 Magnetic Conduit (Steel) Load Power Factor.1305 .0158 .0090 .0583 .0218 .3363 .0323 .3363 .0211 .1350 .0284 .0428 .0122 . 3-Phase.0056 .0163 .0121 .0090 .0053 .1350 .0514 .0128 .5410 .0287 .2133 .0091 .0159 .0337 .0158 .0660 .0141 .0128 . Phase-to-Phase Copper Conductors Conductor Size AWG or kcmil 14 12 10 8 6 4 2 1 1/0 2/0 3/0 4/0 250 300 350 500 600 750 1000 Magnetic Conduit (Steel) Load Power Factor.1534 .0095 .0120 .0107 .0800 .0069 70 .0430 .2150 .2480 .0809 .0143 .0068 80 .0177 .0058 .0656 .0080 .0133 .0094 .3130 .0094 .0058 90 .1286 .0111 .0522 .4410 .0513 .0274 .0263 .0435 .1552 .0849 .0091 .0052 100 .1249 .0072 .0152 .0318 .0389 .0266 .0074 .0473 .0107 .0147 .0080 70 .0595 .4940 .3410 .2150 .0719 .0132 .0220 .0101 .4848 .0170 .0231 .0170 .0085 .0274 .1142 .0384 .1780 .0072 .0227 .0275 .0082 80 .0038 CAT.0137 .0391 .0198 .0217 .0233 .1580 .0065 90 .3052 .1933 .4930 .0066 .2090 .0110 .0062 80 .0136 .0267 .0156 .0130 . . The most common loads of this type are motor inrush currents during starting. usually 2 to 3%. Fine-print notes in the NEC recommend sizing feeders and branch circuits so that the maximum voltage drop in either does not exceed 3%.25 . steady load to the system until the instant the X-Ray tube is “fired.0136-. In some modern XRay equipment.. .35 . . and generators under the high current. . it will not restrike Table A13: Factors Governing Voltage Drop Type of MotorŒ Starting Torque Starting Current  Normal How Started Starting Current % Full-LoadŽ 600-700 480-560 375-450 500-600 400-480 320-400 500-600 400-480 320-400 800-1000 100% current for 100% Torque 300 450-550 288-350 Starting Torque per Unit of Full Load Torque 1750 Rpm Motor 1. The only standard that exists is that of NEMA.. allowing only a 15% dip.0164-. can be very annoying.80 .. That is..0170 A Recommended Limits of Voltage Variation General Illumination: Flicker in incandescent lighting from voltage dip can be severe.5 1. Lighting is often supplied from separate transformers. .0131-.87 ..25 .... This will require several minutes. . and unit substation transformers are relatively limited in size. and voltage at the source can be assumed to be constant during motor starting. ..Cutler-Hammer January 1999 Power Distribution System Design Voltage Drop A-33 Voltage Drop Considerations The first consideration for voltage drop is that under the steady-state conditions of normal load.00936 .. and reduce efficiency. to ensure proper X-Ray exposure...2 to 2..” This presents a brief but extremely high instantaneous momentary load. See section J4 for additional data on reduced voltage motor starting. Where the power is supplied by a utility network.87 .. For high-intensity discharge (HID) lamps such as mercury vapor.96 . such as CAT-scanners. until it has cooled.96 .  Using 80% taps. under these momentary loads. in many cases computers will require special powerconditioning equipment to operate properly.0146 . Voltage variation in such areas should be held to 2 or 3% under motor-starting or other transient conditions.. precision assembly plants. are extremely sensitive to low voltage. the sensitivity of computers to voltage has become an important consideration. short-time loads.28 to 1.0655 ..or microprocessor-controlled manufacturing. the firing is repeated rapidly to create multiple images.. voltage drop under transient conditions... (Fine print notes in the NEC are not mandatory.0218 .0117 .... In areas where close work is being done.. Voltage dip resulting from motor starting can be calculated on the basis of the voltage drop in the conductors between the power source and the motor resulting from the inrush current.. 1150 Rpm MotorŽ 1. Across-the-Line Across-the-Line Autotransformer 40% Starting.01. Design B Normal Across-the-Line Resistance Autotransformer Across-the-Line Resistance Autotransformer Across-the-Line Resistance Autotransformer Across-the-Line Secondary Controller Design C Normal Low Design D High Low Design E Wound Rotor Normal High High Low .0109-. and the inrush kVA or current of the motor being started is small compared to the full-rated kVA or current of the transformer. The voltage regulation must be maintained within the manufacturer’s limits. and to select generators of adequate size to limit voltage dip.0164-.0205-.... While most starters will tolerate considerably more voltage dip before dropping out. and other voltage transients caused by starting and stopping motors can cause data-processing errors. sometimes serious. transformers.0109 . high-pressure sodium.96 1. the transformer voltage dip will be small and may be ignored.5 . even a slight variation.96 . must be considered.80 .. Motor Starting: Motor inrush on starting must be limited to minimize voltage dips.. If the power source is a transformer. While voltage drops must be held to a minimum.. Severe dips of short duration can cause a computer to “crash” — shut down completely.71. X-Ray Equipment: Medical X-Ray and similar diagnostic equipment. The table below will help select the proper type of motor starter for various motors.0170 . lumen output drops about three times as much as the voltage dips. Computer Equipment: With the proliferation of data-processing and computer... limiting dip to 15% is the only way to ensure continuity of operation in all cases. which states that a starter must not drop out at 85% of its nominal coil voltage.01365 ..87 .0109 . These lighting flicker effects can be annoying. reduced-voltage starting of motors to reduce inrush current will be necessary.. This voltage dip can have numerous adverse effects on equipment in the system. . a 10% drop in voltage will result in a 30% drop in light output. CAT..) In addition to steady-state conditions. .0145-. the voltage at the utilization equipment must be adequate.0118 . .... .E .01365 . the utility will often specify the maximum permissible inrush current or the maximum hp motor they will permit to be started across-the-line.. While the lumen output drop in fluorescent lamps is roughly proportional to voltage drop. The actual dropout voltage varies considerably among starters of different manufacturers. Accurate voltage drop calculation would be Full-Load Amps per kVA Generator Capacity for Each 1% Voltage Drop . for efficiency of operation..6 . These loads cause a voltage dip on the system as a result of the voltage drop in conductors. with the total voltage drop for feeders and branch circuits not to exceed 5%.0197 Synchronous (for compressors) Synchronous (for centrifugal pumps) Low Low . Ž Where accuracy is important. with sudden high-current.0205-.. Where the utility system is limited. and equipment and conductors must be designed and sized to minimize these problems.. the motor inrush can be assumed to be small compared to the system capacity. As the motor inrush becomes a significant percentage of the transformer full-load rating.80 1. if the voltage dips about 25% the lamp will go out momentarily and then restrike.. it is usually best to limit dips to between 5 and 10% at most. if repeated. ..28 to 1. or metal halide.87 1.. an estimate of the transformer voltage drop must be added to the conductor voltage drop to obtain the total voltage drop to the motor. One critical consideration is that a large voltage dip can cause a dropout (opening) of magnetic motor contactors and control relays. . . Industrial Plants: Where large motors exist. 850 Rpm Motor 1. 110% Pull-In Œ Consult NEMA MG-1 sections 1 and 12 for the exact definition of the design letter. if they do not occur too frequently.35 . 110% Pull-In 38% Starting. such as drafting rooms..T.80 ..0170-. .... 40% Pull-In 60% Starting.0228-. However...5 . if the lamp goes out because of an excessive voltage dip.. .6 1.. voltage dips of as much as 20% may be permissible in some cases. They present a small. a solid-state reduced voltage starter can be adjusted and controlled to provide the required inrush current and torque characteristics. In many cases. and in the case HID lamps... and the like. ..0131-.  In each case. request the code letter of the the motor and starting and breakdown torques from the motor vendor.. and is minimally affected by voltage dips in the power systems.. CAT. the initial dip in voltage is caused by the inherent regulation of the generator and occurs too rapidly for the voltage regulator to respond. 220-volt. if a 480V transformer has an impedance of 5%. Consequently. 1750 rpm. Example: X Assuming a project having a 1000 kVA generator. 3-phase. amps Circuit (branch.+ 2ZMVA R COS ( γ – θ R ) E 2 R 2 2 158 ----------------------. the percent of initial voltage drop depends on the ratio of the starting kVA taken by the motor to the generator capacity. squirrel-cage motor is 19. 1750 rpm.0170-. Assume that a 100 kVA. volts Source voltage. and the motor inrush current is 25% of the transformer full-load current (FLC). A standard 80% power-factor engine-type generator (which would be used where power is to be supplied to motor loads) has an inherent regulation of approximately 40% from noload to full-load. 19. E VD = E S + IR COS θ + IX SIN θ – E S2 – ( IXcosθ – IR SIN θ ) 2 where: EVD = ES = I = R = Voltage drop.0 amperes.E .0 amperes.0. To convert to same basis as column 7. reactance. squirrel-cage motor be started without objectionable lamp flicker (or 10% voltage If the receiving end voltage.25 x 5%. ohms = Circuit (branch. ZMVA R 2 or ZMVA 2 --------------------------------------------------------------------------------------------------F.= 3. an approximation can be made on the basis of the low power-factor motor inrush current (30-40%) and impedance of the transformer. line-to-neutral. feeder) resistance.L. the type of starter that will limit the inrush depends on the characteristics of the generator. but the starting current would be higher. SINθ 3-phase. 220-volt. The engineer should request that the engine-generator vendor consider the proper generator size when closedtransition autotransformer reduced voltage starters. positive when lagging From the nameplate data on the motor the full-load amperes of a 71/2 hp.L.0158 falls within the . decimal Short-Cut Method Column 7 in Table A13 has been worked out to simplify checking.) = 10 × 100 × 1000 ------------------------------------------------------. and soft-start solid-state starter are used. This means that a 50% variation in load would cause approximately 20% variation in voltage (50% x 40% = 20%).25%. However. In other words.0158 amps per kVA per 1% 1000 × 10 = voltage drop Checking against the table. as well as motor inrush current and power factor. or 1. load current and drop)? power factor (pf) are known. where the voltage variation must not COSθ exceed 10%. decimal = Reactive factor of load.0146 range. E R 2 = E S 2 + ------------------. From tables in the circuit protective devices reference section the full-load amperes of this size and type of motor is 158. the inherent regulation of the generator. For example.45 or 345%. and impedance. a NEMA design C motor with an autotransformer would have a starting torque of approximately fullload (see Table A13) whereas the NEMA design D motor under the same conditions would have a starting torque of approximately 11/2 times full-load. 1750 rpm. kVA × 1000 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. the starting torque would be the same as that obtained with autotransformer type. Exact Method 2–If receiving or sending mVA and its power factor are known at a known sending or receiving voltage. so the most economical method of installation is obtained.” Exact Methods Voltage Drop Exact Method 1–If sending end voltage and load pf are known.A-34 Power Distribution System Design Voltage Drop Cutler-Hammer January 1999 A complex and depend upon transformer and conductor resistance. 3-phase. The engineer should provide to the engine-generator vendor the starting kVA of all motors that we will be connected to.71. feeder) reactance. Therefore: Starting current (%F. the power-factor of the load thrown on the generator. 0. and the percentage load carried by the generator. The allowable motor inrush current is determined by the total permissible voltage drop in transformer and conductors. This indicates that a general-purpose motor with autotransformer starting can be used.0 × 220 × 3 × 0.01. 158 Amps must be divided by the generator capacity and % voltage drop. volts Line (Load) current. The engineer should also specify the maximum allowable drop. Approximate Method Voltage Drop E VD = IR cos θ + IX SIN θ where Abbreviations are same as below “Exact Method. Can a 71/2 hp.– 2ZMVA S COS ( γ E S 2 R – θS ) where: ER = ES = MVAR = MVAS = Z = γ θR θS Receiving Line-Line voltage in kV Sending Line-Line voltage in kV Receiving 3-phase mVA Sending 3-phase mVA Impedance between and receiving ends = The angle of impedance Z = Receiving end PF = Sending end PF.40 From Table A13. as shown. The figures were obtained by using the formula above and assuming 1 kVA generator capacity and 1% voltage drop. then voltage drop will be 0. Although automatic voltage regulators are usually used with all ac engine-generators. The calculation results in conservative results. With an engine generator as the source of power.T. squirrelcage motor be started without exceeding this voltage drop? Starting ratio = Percent voltage drop × gen. It could also be obtained from a properly set solid-state adjustable reduced voltage starter. a NEMA design C or NEMA design D motor with an autotransformer starter gives approximately this starting ratio. ohms = Power factor of load. It will occur whether or not a regulator is installed. amps × volts × 3 × reg. 80% pf engine-type generator is supplying the power and that the voltage drop should not exceed 10%. Can a 75 hp. Note: If a resistance starter were used for the same motor terminal voltage. the generator and their starting sequence. E S 2 = E R 2 + ------------------. line-to-neutral. of gen. 220-volt. or: E VD = ( E R cos θ + I R ) +( E R sin θ + I X ) – E R ER is the receiving end voltage. E .2 24........ 7...8 7.......0 24.01 9. Rated transient overvoltage factor..... ANSI Standard C37.1 28.... 150% The NEC.04 Article 5.01.... 6.. when the alternating voltage on the source side of the breaker reaches its opposite maximum.41 6.. Rated back-to-back cable charging and back-to-back capacitor switching current. the voltage across the open contact is even higher..6 38...... Rated open wire line charging switching current........ .. 165% Molded case breaker or equivalent . For capacitor switching careful attention should be paid to the notes accompanying the table..1 48.....1 42 48.T... the switch rating should be selected based on the ultimate kvar capacity – not the initial installed capacity..2 115 120 144 154 173 192 217 231 241 289 306 347 361 385 433 Safety Switch Fuse Rating 250 250 300 350 400 400 500 500 500 600 700 800 800 800 900 15 15 20 25 35 40 50 60 70 80 80 100 125 150 175 200 200 250 300 300 350 400 400 400 500 600 600 600 700 800 Molded Case Breaker Trip Rating 225 225 300 300 350 400 500 500 500 600 600 700 700 800 900 15 15 15 30 30 40 50 50 70 70 100 100 125 125 150 175 200 225 250 300 300 350 350 400 500 500 600 600 600 700 DSII Breaker Trip Rating 200 200 250 300 300 350 400 400 400 500 600 600 600 800 800 15 15 15 20 30 40 40 50 70 70 70 90 100 125 150 175 175 200 225 250 300 300 350 350 400 500 500 500 600 600 240 21⁄2 5 71⁄2 10 15 20 25 30 45 50 60 75 90 100 120 125 135 150 180 200 225 240 250 270 300 360 375 2 5 71⁄2 10 15 20 25 30 35 40 45 50 60 75 80 90 100 480 120 125 150 160 180 200 225 240 250 300 320 360 375 400 450 5 71⁄2 10 15 20 25 30 35 40 45 50 60 75 80 100 120 125 150 160 180 200 225 240 250 300 320 360 375 400 450 600 480 Œ Switching device ratings are based on percentage of capacitor-rated current as indicated (above)..2 108 120 Safety Switch Fuse Rating 15 20 30 40 60 80 100 125 200 200 250 300 400 400 500 500 600 600 800 800 900 1000 1000 1200 1200 1600 1500 15 15 15 20 30 40 50 60 70 80 90 100 125 150 175 200 200 Molded Case Breaker Trip Rating 15 20 30 40 70 90 100 125 175 200 225 275 350 400 500 500 500 600 700 800 900 900 900 100 0 .2 9.. Loadbreak interrupter switches are permitted by ANSI/IEEE Standard C37..0 36.. The application guide ANSI/IEEE Standard C37..... Rated capacitive current switching life.... Rated interrupting time..3 48.. If a breakdown occurs across the open contact the arc is reestablished... The interrupting rating of the switch must be selected to match the system fault current available at the point of capacitor application... 135% Contactors: Open type.....012 covers the method of calculation of the quantities covered by C37.2 90..4 19.. A Low-Voltage Capacitor Switching Circuit breakers and switches for use with a capacitor must have a current rating in excess Table A14: Recommended Switching DevicesŒ Capacitor Rating Volts kvar Amperes Capacitor Rated Current 6. 1..2 77. 5.. 135% Magnum DS power circuit breaker.. Grounding of system and capacitor bank. A breaker specified for capacitor switching should include as applicable. ..1 36. Refer to Cutler-Hammer type WLI ratings... 8.. of rated capacitor current to provide for overcurrent from overvoltages at fundamental frequency and harmonic currents...06 (indoor oilless circuit breakers) Table 1A indicates the preferred ratings of Cutler-Hammer type VCP-W vacuum breaker.. 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...30 to switch capacitance but they must have tested ratings for the purpose... This classification requires a definite purpose circuit breaker (breakers specifically designed for capacitance switching).2 108 120 144 180 217 240 289 301 325 361 433 480 541 578 602 650 720 866 903 2.. We recommend that such application be referred to Cutler-Hammer. Rated frequency. 150% DSII power circuit breakers .1 57.. The following percent of the capacitor-rated current should be used: Fused and unfused switches . 3..0 24...13 (for the latest edition).Cutler-Hammer January 1999 Power Distribution System Design Capacitor Switching Device Selections A-35 Capacitor Switching Device Selections Medium-Voltage Capacitor Switching Capacitance switching constitutes severe operating duty for a circuit breaker.2 96...8 72...9 33.. Whenever a capacitor bank is purchased with less than the ultimate kvar capacity of the rack or enclosure. Rated isolated cable charging and shunt capacitor switching current. Note that the definitions in C37. CAT.0 12... 10... 2.1 60 72. At the time the breaker opens at near current zero the capacitor is fully charged...0 18.. After interruption........ 15 15 15 20 30 40 50 70 70 100 100 100 125 150 150 175 200 DSII Breaker Trip Rating 15 20 30 40 50 70 90 100 150 175 200 250 300 350 400 450 500 500 600 700 800 800 900 1000 1200 1200 1200 15 15 15 20 30 40 50 50 60 70 80 90 100 125 150 150 175 Capacitor Rating Volts kvar Amperes Capacitor Rated Current 144 150 180 192 216 241 271 289 301 361 385 433 451 481 541 4.. The definition of the terms are in ANSI Standard C37.1 72. Section 460-8(c)(4)..0 18. 9.........1 54 60....71. Rated maximum voltage... After it is interrupted and with subsequent alternation of the supply side voltage. 4. 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.5 43.0 96........04 make the switching of two capacitors banks in close proximity to the switchgear bus a back-toback mode of switching..6 14.0 12....06 Standard.. Rated transient inrush current and its frequency....0 30. 135% Enclosed type . requires the disconnecting means to be rated not less than 135% of the rated capacitor current (for 600V and below).. B.65 mult.4 – 1...8 – 1.. . The preferable means to select capacitor ratings is based on the “maximum recommended kvar” information available from the motor manufacturer.5 10 15 15 20 25 30 30 40 50 60 70 70 80 90 17 16 14 14 13 13 12 11 11 11 10 10 9 9 9 8 8 7 7 7 7 3 3 4 5 71⁄2 71⁄2 10 15 20 25 25 30 30 35 50 60 70 80 80 100 120 23 19 18 17 16 16 16 15 15 14 13 11 11 11 10 10 10 10 10 9 9 3 4 5 71⁄2 71⁄2 10 10 15 20 20 25 30 40 45 60 70 80 100 110 120 125 28 25 24 21 20 19 18 18 18 17 14 13 13 12 12 12 12 12 12 11 11 4 6 6 71⁄2 10 10 15 15 20 25 30 35 40 50 70 80 90 100 125 125 140 36 33 30 27 25 23 21 20 19 19 16 15 14 13 13 12 12 12 12 12 12 5 71⁄2 10 10 15 20 20 25 30 35 40 45 50 60 80 100 110 125 150 150 175 49 46 39 34 31 31 28 28 28 27 19 17 17 17 17 17 17 16 16 16 16 Table A16: Design C–High Starting Torque. The data is general in nature and representative of general purpose induction motors of standard design. use the following formula: Actual kvar = ( Applied Voltage ) 2 Nameplate kvar × -----------------------------------------------------( Nameplate Voltage ) 2 For the kVac required to correct the power factor from a given value of COS φ1 to COS φ2.4 of kVAR listed % AR = 1. For standard 60 Hz wound-rotor motors: Kvar = 1.5 7.A-36 Power Distribution System Design Motor Power Factor Correction Cutler-Hammer January 1999 Motor Power Factor Correction A Tables A15 and A16 contain suggested maximum capacitor ratings for induction motors switched with the capacitor. 23 23 23 17 16 12 12 12 12 12 kvar .05 of % AR listed Note: For A.... C.7 mult. Normal Current InductionMotor Horsepower Rating 5 71⁄2 10 15 20 25 30 40 50 60 75 100 125 150 200 250 300 350 Nominal Motor Speed in Rpm and Number of Poles 1800 1200 900 4 6 8 kvar % AR kvar % AR kvar % AR 2 18 21⁄2 23 4 29 3 18 3 19 4 25 3 15 4 17 5 22 4 15 5 17 71⁄2 20 1 ⁄2 4 15 5 17 7 19 5 13 5 15 10 19 5 13 71⁄2 15 10 19 10 13 10 15 15 18 15 13 10 15 20 18 15 12 20 15 25 18 20 11 20 13 30 17 25 10 25 12 40 17 30 10 35 11 40 14 35 9 40 10 45 13 45 9 50 10 60 13 50 8 60 10 70 13 60 8 70 10 80 12 70 8 75 9 90 12 720 10 % AR .e.01.. Induction-Motor/Capacitor Application Tables for Motors (Manufactured in 1956 or Later) 230-.tan φ2) Capacitors cause a voltage rise. With the introduction of variable speed drives and other harmonic current generating loads..1 of kvar listed % AR = 1. etc. An important point to remember is that if the capacitor used with the motor is too large. . The reduction in line current may be determined by measuring line current with and without the capacitor or by calculation as follows: (Original Pf) % AR = 100 – 100 × --------------------------------(Improved Pf) If a capacitor is used with a lower kVAR rating than listed in tables.5 10 10 15 20 25 25 35 40 45 50 70 75 90 13 13 12 11 10 10 10 10 10 9 9 9 9 9 9 9 9 9 8 7 7 2 3 3 5 6 6 7.1 of kvar listed % AR = 1. such as a 240-volt capacitor used on a 208-volt system. This matter is discussed further under the heading “Harmonics and Non-Linear Loads... . 3600 rpm = 1...T.35 of % AR listed B.71... .5 7. kVAB is the base kVA.Nominal Motor Speed in Rpm and Number of Poles Motor 3600 1800 1200 900 720 600 Horse2 4 6 8 10 12 power Rating kvar % AR kvar % AR kvar % AR kvar % AR kvar % AR kvar % AR 5 71⁄2 10 15 20 25 30 40 50 60 75 100 125 150 200 250 300 350 400 450 500 2 21⁄2 3 5 6 7. In addition. . If this is not possible or feasible. . .4 – 1. 460.7 – 1.. the % AR can be calculated as follows: Actual kvar % AR = Listed % AR × --------------------------------kvar in Table The tables can also be used for other motor ratings as follows: A.” CAT. 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. .. . the formula is: kVAC = KW (tan ø1 .. self-excitation may cause a motor-damaging overvoltage when the motor and capacitor combination is disconnected from the line. Therefore. For standard 60 Hz motors operating at 50 Hz: Kvar = 1. At light load periods the capacitive voltage rise can raise the voltage at the location of the capacitors to an unacceptable level.. 25 25 35 40 45 50 60 75 80 100 D. the larger multipliers apply for motors of higher speeds. For standard 50 Hz motors operating at 50 Hz: Kvar = 1.05 of % AR listed C.. Definitions kvar—rating of the capacitor in reactive kilovolt-amperes. This voltage rise can be calculated approximately by the formula kVAC X S % VR = --------------------kVA B XS is the impedance of the circuit elements from the utility to the location of the capacitors. . the capacitor impedance value determined must not be resonant with the inductive reactances of the system.E . This value is approximately equal to the motor no-load magnetizing kilovars.. 20 .and 575-Volt Motors Table A15: NEMA Design B–Normal Starting Torque and Current Induction. a different overload relay and/or setting may be necessary. 23 .. i. A capacitor located on the motor side of the overload relay reduces line current through the relay... % AR—percent reduction in line current due to the capacitor. To derate a capacitor used on a system voltage lower than the capacitor voltage rating. the tables can be used. 1800 rpm = 1.. 600 Amps 24.07 .4 .07 . showing all protective devices and the major or important distribution and utilization apparatus.8 .03 .2 . especially in industrial process plants.6 .600 Amps C 1. Therefore in close.) conditions.160 V ∆ 480/277 V 19. fire pumps. etc. except will trip before on limited ground faults. peak.160V) coordinates selectively with all secondary protective devices. Clears ANSI 3φ withstand curve.2 .09 . (e) understanding of operating characteristics and available adjustments of each protective device. 1000 900 800 700 600 500 400 300 .75% ANSI 3-Phase Thru Fault Protection Curve (More Than 10 in Lifetime) 4.9 1 2 3 4 5 6 7 8 9 10 20 30 40 50 60 4.16 kV Fault . economic loss from outages can be extremely high as a result of computer downtime.866 x I 3φ fault current.400 Amps 600 Amps TIME IN SECONDS 10 9 8 7 6 5 4 3 B M 6000 7000 8000 9000 10. Clears transformer inrush point (12 x FLC for 0.3 . (d) calculation of maximum short-circuit currents (and ground fault currents if ground fault protection is included) possible at each protective device location. etc. dependence on the continued supply of this power has also increased so that the direct costs of power outages have risen significantly. 3Ø 4.000 600 700 800 900 1000 2000 3000 4000 5000 70 80 90 100 200 300 400 500 . —Primary fuse (250A.01 . For line-to-line fault the secondary (low voltage) side fault current is 0.3 M 100 Hp – 124 Amps FLC 1 . to provide back-up and effect the isolation if the fault persists. Ground Fault Trip C . —Main CB (1600A) coordinates selectively with all downstream devices and with primary fuse .04 . and drop to 124A normal running current.6 .9 . line-to-line fault. Dashed line shows initial inrush current. 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. or. (b) identification of desired degrees of power continuity or criticality of loads throughout system.01 Max. To study and accomplish coordination requires a: (a) one-line diagram. except that CB will trip first on ground faults. Protective equipment must be adjusted and maintained in order to function properly when a current abnormality occurs. —CB (600A) coordinates selectively with all upstream and downstream devices. operation and application systems. ventilation.02 . 480V Fault A . starting) of each utilization circuit. transformer inrush.8 .7 . since has no ground fault trips.71. security systems. but coordination 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. Sensitivity of coordination is the degree to which the protective devices can minimize the damage to the faulted equipment. Delta-Wye secondary side short circuit is not reflected to the primary by the relation VS I P = -----.9 1 2 3 4 5 6 7 8 9 10 20 30 40 50 60 SCALE X 100 = CURRENT IN AMPERES AT 480 VOLTS Time-Current Characteristic Curves for Typical Power Distribution System Protective Devices Coordination Analysis.1 sec).5 .6 . Standard definitions have been established for overcurrent protective devices covering ratings.04 .01. for all faults on load side of CB.1 .1 . In either case.8 . to operate selectively to protect equipment. communications systems. indicating that fuse will not blow on inrush. Power outages can create dangerous and unsafe conditions as a result of failure of lighting. Curve converted to 480V basis.03 . —Motor (100 hp).7 . However the primary (high voltage) side fault is the same as if the secondary fault was a three-phase fault. In addition.05 .9 .06 . CAT.08 .8 .5 X = Available fault current including motor contribution. —CB (175A) coordinates selectively with motor on starting and running and with all upstream devices. (c) definition of operating-current characteristics (normal.5 . the fundamental purposes of current-sensing protective devices are to detect the abnormal overcurrent and with proper coordination.4 . starting current during 9-sec acceleration. but each preceding protective device upstream toward the power source should be capable. elevators.T. With the increase in electric power consumption over the past few decades. and the like.08 .06 . indicating fuse will protect transformer for full duration of faults up to ANSI rating.5 .16 kV 250 MVA B A C D D 200 100 90 80 70 60 50 40 30 20 250 Amps 1000 kVA 5.000 600 700 800 900 1000 2000 3000 4000 5000 Overcurrent Protection and Coordination SCALE X 100 = CURRENT IN AMPERES AT 480 VOLTS 1000 900 800 700 600 500 400 300 A 70 80 90 100 200 300 400 500 200 100 90 80 70 60 50 40 30 20 10 9 8 7 6 5 4 3 TIME IN SECONDS 20. property and personnel while minimizing the outage of the remainder of the system.Cutler-Hammer January 1999 Power Distribution System Design Overcurrent Protection and Coordination A-37 Overcurrents in a power distribution system can occur as a result of both normal (motor starting.09 .6 .000 Amps A 175 Amps 2 B C 2 1 . 4.) and abnormal (ground fault.05 .7 .E 6000 7000 8000 9000 10. interruption of production. all well below CB trip curve.× I S VP for L-L and L-G faults.02 B Transformer Inrush Max. within its designed settings of current and time.7 . the roadmap of the power distribution system. (f) any special overcurrent protection requirements including utility limitations. the time-trip characteristics of all devices in series should be plotted on a single sheet of standard log-log paper. 4000 Amps 30 sec. with solid-state trip units. In general for systems such as shown in the example: 1.12. the 30-sec. In practice the setting or rating of the utility’s protective device sets the upper limit. Even in cases where the customer owns the medium-voltage or higher distribution system. 1 second or less trip delay at currents of 3000 Amps or greater. If the breaker immediately downstream of the fault does not open. continuing power to the entire unfaulted part of the system. while all other breakers remain closed. Illustrative examples such as shown here start the coordination study from the lowest rated device proceeding upstream. 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 overcurrent device installed in a circuit breaker is rated or can be adjusted. The tripping characteristics of each overcurrent device should not overlap. based on ANSI standards.577 and replotted in order to determine the protection given by the primary for single line to ground fault in the secondary. trip curves include long. Where the utility is the sole source they should be consulted. with the feeder or branch breaker downstream furthest from the source. the setting or rating of the upstream device should be reviewed.. In the example shown. vide selectivity and coordination. The National Electric Code exempts fire pumps and continuous industrial processes from this requirement. Maximum 4160V 3φ fault indicated. then after timing out. and circuit breakers with integral fuses. Breakers equipped with ground fault trip elements should also be specified to include zone interlocking for the ground fault trip element.T. trip without intentional time delay unless a restraint signal is received from a protective device downstream. In the example shown the ANSI 3ø thru fault protection curve must be multiplied by 0. 2. The characteristics of the ground-fault trip elements create coordination problems with downstream devices not equipped with ground fault protection. Such a coordination plot is shown on page A-37. Transformer damage points. but not exceeding 600 volts phase-to-phase for each service disconnect rated 1000 amperes or more. Maximum 480V 3φ fault indicated.1547 0. A selective or fully coordinated system permits maximum service continuity. I 480V = I 4160V × ----------The ANSI protection curves are specified in ANSI C57.1547 = 4619 Amps. 5. not only are time-current characteristic curves available. the upstream breaker will trip. Application data is available for all protective equipment to permit systems to be designed for adequate overcurrent protection and coordination. The tripping 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. to the same voltage basis. 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.866 before it is compared to the minimum melting time of the fuse curve. Devices of different-voltage systems can be plotted on the same sheet by converting their current scales. If this procedure results in unacceptable settings. In this case there is adequate clearance to the fuse curve.E . If perfect coordination is not feasible. Generally. The settings or ratings of the primary side fuse and main breaker must not exceed the settings allowed by NEC Article 450.or 1. time-current curves permit selection of instantaneous and inverse-time trips. The maximum fault current must be indicated at the load side of each protective device. trip time should be compared to the MMT (minimum melt time) of the fuse curve at 4000 x 1. In this manner. 3.12. 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. In a fully rated system. the setting or rating of the lowest set protective device source determines the settings of the downstream devices and the coordination. but care must be used in interpreting their meaning. Therefore the coordination study should start at the present setting or rating of the upstream device and work towards the lowest rated device. but should maintain a minimum time interval for devices in series (to allow for normal operating tolerances) at all current values. Specify tripping elements with I2t or I4t feature for improved coordination with other devices having I2t or I4t (such as OPTIM trip units) characteristics. The correction factor for a single line-to-ground factor must be applied to the damage curve.71. and low-voltage cable heating limits can be plotted on this set of curves to assure that apparatus limitations are not exceeded. For currentlimiting circuit breakers. using the voltage ratios. 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. All breakers are equipped with long-time-delay (and possibly short delay) and instantaneous overcurrent trip devices. all circuit breakers must have an interrupting capacity adequate for the maximum available fault current at their point of application. and fuses. 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.1 second. A selective system is a fully-rated system with tripping devices chosen and adjusted to provide the desired selectivity.and short-time delays. Specify true rms sensing devices in order to avoid false trips due to rapid currents or spikes. as well as ground-fault tripping. Where the owner has its own medium or higher voltage distribution the settings or ratings of all upstream devices should be checked. Ground-fault curves may also be included in the coordination study if ground-fault protection is provided. with a wide range of settings and features to pro- 4160 480 CAT. The setting of a feeder protective device must comply with Article 240 and Article 430 of the NEC. then lack of coordination should be limited to the smallest part of the system. The setting of the short-time delay element must be checked against the fuse MMT after it is corrected for line-to-line faults. The primary fuse should be to the left of the transformer damage curve as much as possible. a maximum of four low-voltage circuit breakers can be operated selectively in series.01.” The maximum allowable settings are: 1200 Amps pickup. To assure complete coordination. 4. fuses. For circuit breakers of all types. All breakers must have an interrupting capacity not less than the maximum available shortcircuit current at their point of application. The upstream breaker upon receipt of the restraint signal will not trip until its time-delay setting times out. 6. but also data on current-limiting performance and protection for downstream devices. For more complex circuit breakers. At 12 x IFL the minimum melting time characteristic of the fuse should be higher than 0.109 for liquid-filled transformers and C57.59 for dry-type transformers. primary fuses and circuit breaker relays on the primary side of a substation transformer can be coordinated with the low-voltage breakers. converted to 480V basis.A-38 Power Distribution System Design Overcurrent Protection and Coordination Cutler-Hammer January 1999 A coordination studies the knee of the shorttime pick-up setting should be multiplied by 1 -----------. to minimize fuse blowing. 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. Application information is available for combinations which have been tested and UL-listed for safe operation downstream from DSLII. JDC. For the feeder ground fault setting.Cutler-Hammer January 1999 Power Distribution System Design Overcurrent Protection and Coordinaton A-39 It is recommended that in solidly grounded 480/277-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. periodic study of protectivedevice settings and ratings is as important for safety and preventing power outages as is periodic maintenance of the distribution system. Underwriters Laboratories tests and lists these series combinations. fused breakers. For fuse-breaker combinations. or current-limiting breakers – can not only clear these large faults safely. Current-limiting fuses can be used in fused switch assemblies. System changes and additions. Tri-Pac. common in urban areas and large industrial installations. KDC. To provide current limiting. LDC and NDC frames or type Current-Limit-R) have become available. or Series C breakers of various ratings. rule-of-thumb fuse ratios or more accurate I2t curves can be used to provide selectivity and coordination. Any of these current-limiting devices – fuses.T. several solutions are available.01. plus power source changes. sometimes causing loss of coordination and even increasing fault currents beyond the ratings of some devices. Protective devices in electrical distribution systems may be properly coordinated when the systems are designed and built. Without the current limitation of the upstream device. Suggested Ground Fault Settings For the main devices. extending their zone of protection. truly current-limiting circuit breakers with interrupting ratings adequate for the largest systems (type Series C. limiting the peak current (Ip) and heat energy (I2t) let-through to considerably less than what would have occurred without the fuse. but that is no guarantee that they will remain coordinated. For low-voltage systems with high-magnitude available short-circuit currents. and Current-Limit-R. unfused. 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). these fuses must clear the fault completely within the first half-cycle. approaching the interrupting capacity of the breaker. the design engineer should decide between coordination and damage limitation. the fault current could exceed the withstand capability of the downstream equipment. under high available fault currents.71. the fuse should be selected (coordinated) so as to permit the breaker to handle those overloads and faults within its capacity. 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. 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. Consequently. Recently. A CAT. but not to exceed 1 second. For a fully fusible system. FDC. but also will limit the Ip and I2t let through significantly to prevent damage to apparatus downstream. frequently modify the protection requirements. the fuse should operate before or with the breaker only on large faults.E . run with the circuit conductors. static and lightning protection. Where computers. Equipment Grounding Equipment grounding is essential to safety of personnel. If a separate equipment grounding conductor is used. if insulated.71. isolated grounding of this equipment. 2. A system can be solidly grounded (no intentional impedance to ground).01. To prevent the establishment of such unsafe potential difference requires that (1) the equipment grounding conductor provide a return path for ground fault currents of sufficiently low impedance to prevent unsafe voltage drop. the equipment grounding system must be designed to minimize interference with their proper operation. and that this is the zero reference potential of the earth. This will not cause problems with the safe operation of the electrical distribution system. 1. Conductors with green insulation may not be used for any purpose other than for equipment grounding. data processing. Medium-Voltage System – Grounding Table A17: Features of Ungrounded and Grounded Systems (from ANSI C62. from the utility. from transformer secondary windings. Grounding is required by both the National Electrical Code (Article 250) and the National Electrical Safety Code. or microprocessor-based industrial process control systems are installed.92) A Ungrounded (1) Apparatus Insulation (2) Fault to Ground Current Fully insulated Usually low B Solidly Grounded Lowest Maximum value rarely higher than three-phase short circuit current C Reactance Grounded Partially graded Cannot satisfactorily be reduced below one-half or one-third of values for solid grounding D Resistance Grounded Partially graded Low E Resonant Grounded Partially graded Negligible except when Petersen coil is short circuited for relay purposes when it may compare with solidlygrounded systems Is eliminated from consideration during single line-to-ground faults unless neutralizer is short circuited to isolate fault by relays Requires special provisions but can be made satisfactory Unlikely Effect of faults transmitted as excess voltage on sound phases to all parts of conductively connected network Seem to be more likely but conclusive information not available Ungrounded neutral service arresters must be applied at sacrifice in cost and efficiency (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 (4) Relaying Difficult Satisfactory Satisfactory Satisfactory (5) Arcing Grounds (6) Localizing Faults Likely Unlikely Possible if reactance is ex. 3. impedance grounded (through a resistance or reactance). 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. current flow from the accidental grounding of an energized part of the system could generate sufficient heat (often with arcing) to start a fire. system grounding. The equipment grounding conductor may be the metallic conduit or raceway of the wiring system. Accidental contact of an energized conductor of the system with an improperly grounded noncurrentcarry metallic part of the system (such as a motor frame or panelboard enclosure) would raise the potential of the metal object above ground potential. circuit breakers. it may be also connected to ground at many other points. System Grounding System grounding connects the electrical supply. and (2) the equipment grounding conductor be large enough to carry the maximum ground fault current. Among these are equipment grounding. for sufficient time to permit protective devices (ground fault relays. and connection to earth as a reference (zero) potential.Unlikely cessive Effect of faults localized to system or part of system where they occur unless reactance is quite high Unlikely unless reactance is quite high and insulation weak If resistance is very high arresters for ungrounded neutral service must be applied at sacrifice in cost and efficiency Effect of faults transmitted as excess voltage on sound phases to all parts of conductively connected network Unlikely unless resistance is quite high and insulation weak Arresters for ungrounded. as permitted by NEC.A-40 Power Distribution System Design Grounding Cutler-Hammer January 1999 Grounding A Grounding encompasses several different but interrelated aspects of electrical distribution system design and construction. the insulation must be green. or from a generator.E . without burning off. it may be bare or insulated. In addition. although grounded at the source. must not be used for equipment grounding. Often. fuses) to clear the fault. permitting protective devices to operate. all of which are essential to the safety and proper operation of the system and equipment supplied by it. 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. or a separate equipment grounding conductor. to ground. The equipment grounding system must be bonded to the grounding electrode at the source or service. or ungrounded (with no intentional connection to ground). Any person coming in contact with such an object while grounded could be seriously injured or killed. neutral service usually must be applied at sacrifice in cost and efficiency Effect of fault transmitted Effect of faults localized to as excess voltage on system or part of system sound phases to all parts where they occur of conductively connected network Likely Likely (7) Double Faults (8) Lightning Protection Ungrounded neutral service arresters must be applied at sacrifice in cost and efficiency Highest efficiency and lowest cost CAT. The grounded conductor of the system (usually the neutral conductor). however. Equipment grounding also provides a return path for ground fault currents.T. T.71. unless conditions are such that arc tends to extinguish itself. but duration may be great May be high during faults A (10) Ratio Interference (11) Line Availability Greater than for solidly grounded. With a properly sized resistor and relaying application. In effectively grounded system the line-to-ground fault current is high and there is no significant voltage rise in the unfaulted phases. Requires coordination between interconnected systems in neutralizer settings Interrupting capacity determined by three-phase fault conditions Taps on neutralizers must be changed when major system switching is performed and difficulty may arise in interconnected systems. Although this fact is not a problem except in small cables. when transmission circuits may be eliminated.01. in order to limit the line-to-ground fault to somewhat less than the three-phase fault at the generator terminals. selective fault isolation is feasible.E . If the reactor is so sized in all probability the system will remain effectively grounded. when faults occur Must be isolated for each fault Greater than for solidly grounded. Difficult to tell where faults are located Highest unless the are suppressing characteristic is relied on to eliminate transmission circuits when it may be lowest for the particular types of service (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 Simple Interrupting capacity determined by three-phase fault conditions Simple Interrupting capacity determined by three-phase fault conditions Simple (14) Operating Procedure Ordinarily simple but possibility of double faults introduces complication in times of trouble (15) Total Cost High. With selective ground fault isolation the fault current will be at 60% of the three-phase current at the point of fault. Resistance Grounded Medium-voltage systems in general are low resistance grounded.0 and R0/X1 ≤ 1. Damage to cable shields must be checked. The aforementioned definition is of significance in medium voltage distribution systems with long lines and with grounded sources removed during light load periods so that in some locations in the system the X0/ X1. The fault limit provided has a bearing on whether residually connected relays are used or ground sensor current transformers are used for ground fault relaying. The burdens on the current transformers must be checked also.0. Reactance Grounding It is generally used in the grounding of the neutrals of generators directly connected to the distribution system bus.Ground Voltage COG = ----------------------------------------------------------------------------------Rms Line . If ground sensor current transformers are used they must be of high burden capacity. reducing total cost Lowest Intermediate Intermediate Because the method of grounding affects the voltage rise of the unfaulted phases above ground. CAT. Any other grounding means that does not satisfy these conditions at any point in a system is not effectively grounded.8 such a system would have X0/X1 ≤ 3. Table A18 taken from ANSI-C62.92 classifies systems from the point of view of grounding in terms of a coefficient of grounding Highest Power Frequency Rms Line .Cutler-Hammer January 1999 Power Distribution System Design Grounding A-41 Table A17: Features of Ungrounded and Grounded Systems (Continued) A Ungrounded (9) Telephone Interference Will usually be low except in cases of double faults or electrostatic induction with neutral displaced but duration may be great May be quite high during faults or when neutral is displayed Will inherently clear themselves if total length of interconnected line is low and require isolation from system in increasing percentages as length becomes greater Cannot be interconnected unless interconnecting system is ungrounded or isolating transformers are used B Solidly Grounded Will be greatest in magnitude due to higher fault currents but can be quickly cleared particularly with high speed breakers Minimum C Reactance Grounded Will be reduced from solidly grounded values D Resistance Grounded Will be reduced from solidly grounded values E Resonant Grounded Will be low in magnitude except in cases of double faults or series resonance at harmonic frequencies.Line Voltage at Fault Location With the Fault Removed This same standard also defines systems as effectively grounded when COG ≤ .92 indicates the characteristics of the various methods of grounding. R0/X1 may exceed the defining limits. It is a good idea to supplement the cable shields as returns of ground fault current to prevent damage. Other standards (cable and lightning arrester) allow the use of 100% rated cables and arresters selected on the basis of an effectively grounded system only where the criteria in the above are met. The fault is limited from 25-20% of the three-phase fault value down to about 200A-400A. when faults occur Must be isolated for each fault 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 to Interconnection Satisfactory indefinitely with reactance-grounded systems Satisfactory indefinitely with solidly-grounded systems Satisfactory with solidlyor reactance-grounded systems with proper attention to relaying Cannot be interconnected unless interconnected system is resonant grounded or isolating transformers are used. where residually connected ground relays are used and the cts supply current to phase relays and meters. ANSI C62. fault clearance is recommended within one minute. Range A b. 3) are simplest with a wye connection. It must have at least a 10-second rating equal to the maximum future line-to-ground fault current and a continuous rating to accommodate the triple harmonics that may be present.A-42 Power Distribution System Design Grounding Cutler-Hammer January 1999 Table A18: Characteristics of Grounding 4.73 ≤2. the fault current at each grounded source should not be limited to less than the current transformers rating of the source. Class A2 to less than 110%. it is a good practice that all source neutrals be grounded with the same grounding impedance. Low-Voltage System – Grounding Percent Fault Per Unit Transient Current LG Voltage  >60 >95 Ž ≤2 <1.3 ≤2. High inductance 2. In general. Ž Transient line-to-ground voltage. This rule will provide sensitive differential protection for wye-connected generators and transformers against line-to-ground faults near the neutral. for 133% insulation. ’ Same as NOTE (6) and refer to ANSI 62. sensitive differential relaying in resistance grounded system with greater fault limitation is feasible.E . four-wire Corner-Grounded Delta Figure 1.73 ≤2. Range B Ratios of Symmetrical Component ParametersŒ X0/X1 0-3 0-1 3-10 >10 0-10 >10  -∞ to -40‘ -40 to 0 0-1 <2 ≥2 ≤(-1) >2 >25 <25 <25 <1 <10 <1 <2.92 Appendix figures. Ungrounded/capacitance a. with one phase grounded to stabilize all voltages to ground. although the ungrounded delta system is far more common. For 100% insulation. if the installation of ground fault differential protection is feasible. Resonant 5. increased insulation thickness is required. 7.T.3 and precautions given in application sections. Very effective B. for indefinite operation. Low resistance b. ground sensor current transformers do not have high burden capacity. A cornergrounded three-phase delta system is sometimes found. 7. If continued operation with one phase faulted to ground is desired.71. Effectively  1. Effective 2.01. Less common is the “redleg” or high-leg delta.92 para. Ungrounded systems (Fig. grounding the neutral point directly through the resistor.4. 1) are usually wye-connected.73 ≤3 >3 ’ >100 ----- Solidly-grounded three-phase systems (Fig.  Ground-fault current in percentage of the threephase short-circuit value. Where one of the mediumvoltage sources is the utility. On medium-voltage systems. one hour is acceptable. This method of grounding is not suitable for line-to-neutral connection of loads. with the neutral point grounded. or ground sensor current transformers are used. Resistance grounded systems limit the circulating currents of triple harmonics and limit the damage at the point of fault. linear circuit. 4-wire system is used where 120V lighting load is small compared to 240V power load. Solidly-Grounded Systems CAT. This 240V.5 ≤2. ‘ Usual isolated neutral (ungrounded) system for which the zero-sequence reactance is capacitive (negative).5 R0/X1 0-1 0-0. Coefficient of grounding affects the selection of arrester ratings. Inductance and resistance 4. Wye broken delta transformer banks may also be used.1 R0/X0 --- A Grounding Classes and Means A. a 240V system supplied by some utilities with one winding center-tapped to provide 120V to ground for lighting. following the sudden initiation of a fault in per unit of the crest of the prefault line-to-ground operating voltage for a simple.  In linear circuits.92 para. Resistance a. 3-phase. High resistance 3. Ungrounded Systems ∅A ∅B ∅C • • • N R • ∅A ∅B ∅C Resistance-Grounded Wye • • • • R ∅A Œ 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. The neutral impedance must have a voltage rating at least equal to the rated line-to-neutral voltage class of the system.  See ANSI 62. Better solutions are available for new installations. Grounding Point The 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. where residually connected relays are used. Class A1 limits the fundamental line-to-ground voltage on an unfaulted phase to 138% of the prefault voltage. Resistance-Grounded Systems Center-Tapped (High-Leg) Delta ∅A ∅B ∅C Resistance-grounded systems (Fig. as long as necessary. --- <8 >8 In general. which can be either solidly or impedance grounded. 100% cable insulation is rated for phase-to-neutral voltage. In general. Noneffectively 1. Low inductance b. Delta systems can be grounded by means of a zig-zag or other grounding transformer. Of course. If the grounding transformer has sufficient capacity. Inductance a. the neutral created can be solidly grounded and used as part of a three-phase. • • • Ungrounded Delta ∅A ∅B ∅C • • • N • Ungrounded Wye Figure 2. because the installation is low in cost to the utility. 173% insulation is required. their consent for impedance grounding must be obtained.73 <2. • • • • N • Grounded Wye ∅A ∅B ∅C Neutral • • • N • ∅B ∅C • • • • • • • • • • ∅B ∅C ∅A Neutral Delta With Derived Neutral ResistanceGrounded Using Zig-Zag Transformer Figure 3. Each case should be treated on its own merit. This derives a neutral point. 2) can be either wye or delta. In many instances. a feeder outage on first ground fault is seldom crucial—even in hospitals. In choosing among solidlygrounded. sputtering or arcing.71. the impedance of the ground return path is usually higher. even on a different. continuity of service. a solidly grounded wye distribution. lighting loads are often 50% or more of the total load. that can cause severe damage if at least one of the grounds is not cleared immediately. A solidlygrounded neutral circuit conductor is not imperative and. lighting is usually only a small fraction of the total industrial electrical load. In commercial and institutional installations. a second ground fault occurs on a different phase. When combined with sensitive ground-fault protection. such as office buildings. arcing ground faults on 208-volt systems tend to be self-extinguishing. risk of damage from a second ground fault. where loads will be connected line to neutral. such additional stages of ground fault protection must be provided. Therefore. Similar high voltages can occur as a result of resonance between system capacitance and the inductances of transformers and motors in the system. until the fault is cleared by a protective device. In industrial installations. the fault itself is usually arcing and the impedance of the arc further reduces the fault current. A high-resistance grounded wye distribution can continue in operation with a ground fault on the system. shopping centers. For these reasons. This is highly undesirable. often ruin the process equipment itself. which have emergency power in critical areas. primarily along the equipment grounding conductors. but not exceeding 600 volts phase-to-phase. lighting loads. the fault current returns to the source CAT. and the arc tends to be self-sustaining. ground fault currents would be high. caused by the distributed capacitance to ground of the system wiring and equipment. such as motor windings. If data for the charging current is not available use 40-50 ohm resistor in the neutral of the transformer. which is bonded to or part of the equipment grounding conductor. In a solidly grounded system. with the neutral used for lighting circuits. Selecting the Low-Voltage System Grounding Method There is no one “best” distribution system for all applications. This high transient phase-to-ground voltage can puncture insulation at weak points. or as a result of an insulation failure of an energized conductor. 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 voltage drop across the arc can be from 70 to 140V. In low-voltage systems. Practically. For these reasons. it will often open the service disconnect before the feeder or branch circuit overcurrent device can operate.Cutler-Hammer January 1999 Power Distribution System Design Grounding/Ground Fault Protection A-43 system. Under ground-fault conditions. can be obtained from inexpensive lighting transformers. and damage transient overvoltages. or ungrounded power distribution the characteristics of the system must be weighed against the requirements of power loads. since conductors are insulated for 600V. making it desirable where power outages cannot be tolerated. In addition. the high-resistance grounded distribution will be the most advantageous for industrial installations. with 277 volts to ground. Unless it is acceptable to disconnect the entire service on a ground fault almost anywhere in the system. damage from a second ground fault can be nearly eliminated.01. yet minimize the problems of the system. from the phase conductors to ground. many existing industrial plants use ungrounded delta distribution. or even branch circuits. Therefore. Sometimes. the energized conductor contacts normally noncurrent-carrying grounded metal. a high voltage—as much as 6 to 8 times phase voltage—can be built up across the system capacitance. remote feeder. will not develop transient overvoltages. On the other hand. is usually the most economical. each system behaves very differently. On a 208-volt system. However. the voltage to ground is 120 volts. In low-voltage systems this is not important. Most transformer-supplied systems are either solidly grounded or resistance grounded. When an insulation failure occurs. the arc goes out at current zero. be provided for each service disconnecting means rated 1000 amperes or more on solidly grounded wye services of more than 150 volts to ground.E . 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. schools. At least two stages of protection are mandatory in health care facilities (NEC Sec. safety. such as the difficulty of locating the first ground fault. If the ground return impedance were as low as that of the circuit conductors. and the faulted circuit must be cleared on first fault within a fraction of a second to minimize damage. and sometimes create extremely dangerous situations for operating personnel. and the normal phase overcurrent protection would clear them with little damage. on first ground fault an ungrounded system can continue in service. because the ground point is established. and is frequent cause of multiple motor failures on ungrounded systems. to limit groundfault (zero sequence) currents to values the generator can withstand. solidly grounded systems are used. the effect of a shutdown caused by a single ground fault could be disastrous. Ungrounded delta systems can be converted to high-resistance grounded systems. but not on 208Y/120volt services. Because of the ability to continue in operation with one ground fault on the system. If. this is rarely more than 1 or 2 amperes. the voltage to ground of the other two phases goes up 73%. resistance-grounded. the ground fault is below the trip setting of the protective device and it does not trip at all until the fault escalates and extensive damage is done. The NEC (Sec. and cost. effective. On a 480-volt system. doing severe and increasing damage. This protection works so fast that for ground faults on feeders. with a small part using parallel paths such as building steel or piping. Unfortunately. In general. Today.T. The phaseto-phase voltage is not affected. if the ground fault is intermittent. A Ground Fault Protection A ground fault normally occurs in one of two ways: By accidental contact of an energized conductor with normally grounded metal. The resulting ground fault current is rarely enough to cause the phase overcurrent protection device to open instantaneously and prevent damage. usually with arcing. and in the NEC (230-95) a Fine Print Note (FPN) states that additional ground fault protective equipment will be needed on feeders and branch circuits where maximum continuity of electric service is necessary. 517-17). A solidly grounded system produces high fault currents. set at no more than 1200 amperes. An ungrounded system will pass limited current into the first ground fault—only the charging current of the system. Generator neutrals are often grounded through a reactor. If a ground fault occurs. The NEC requires ground fault protection only on the service disconnecting means. and. to full phase-to-phase voltage. low level ground protection devices with minimum time delay settings are required to rapidly clear ground faults. Locating a first fault on an ungrounded system can be difficult. restrike usually takes place after current zero. it is a high-current phase-to-groundto-phase fault. 230-95) requires that ground fault protection. An interrupted process could cause the loss of all the materials involved. using a zig-zag or other grounding transformer to derive a neutral. In a 480Y/277-volt system. before the first fault is cleared. new installations can have all the advantages of service continuity of the ungrounded delta. this makes ground fault protection mandatory on 480Y/277-volt services. and convenient design. with similar benefits. and hospitals. locating a ground fault is less difficult than on an ungrounded system. when required. With one phase grounded. and the voltage to ground is often too low to cause it to restrike. usually arcing. High resistance grounded systems are used as substitutes for underground systems where high system availability is required. T. including balanced or unbalanced phase-to-phase and phase-toneutral normal or fault currents. The most simple and direct method is the ground return method as illustrated in Figure 1. not on the load side. This sensing method is based on the fact that all currents supplied by a transformer must return to that transformer. the fault current returns along the ground return path to the neutral of the source transformer. 4-wire distribution system. and harmonic currents. This method of sensing ground faults can be employed on the main disconnect where minimum protection per NEC (230-95) is desired. 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. Ground Return Sensing Method Neutral This is an inexpensive method of sensing ground faults where only minimum protection per NEC (230-95) is desired. Normal phase overcurrent protection devices provide no protection against low level ground faults. specially-designed sensor either of a torriodial or rectangular GFR Typical Feeder Typical 4W Load Figure 3. The third basic method of detecting ground faults involves the use of multiple current sensors connected in a residual sensing Sensor Polarity Marks Main Residual Sensors Figure 1.A-44 Power Distribution System Design Ground Fault Protection Cutler-Hammer January 1999 A Overcurrent protection is designed to protect conductors and equipment against currents that exceed their ampacity or rating under prescribed time values. For it to operate properly. short-circuit or (high level) ground fault condition. In a residual sensing scheme. the servicing utility grounds the neutral at the transformer and additional grounding is required in the service equipment per NEC (250-23a). The three-phase sensors are required for normal phase overcurrent protection. it is imperative that proper polarity connections are employed to reflect this condition. Normal neutral currents resulting from unbalanced loads will return along the neutral conductor and will not be detected by the ground return sensor. Should a ground fault occur. Since the vectorial sum of the currents in all the conductors will total zero under normal. When an energized conductor faults to grounded metal. nonground faulted conditions. This path includes the grounding electrode conductor–sometimes called the “ground strap”–as shown in Figure 1. This sensing method requires a single. the fault current will return along the ground path–not the normal circuit conductors–and the sensor will have an unbalanced magnetic flux condition and a sensor output will be generated to actuate the ground fault relay. interconnected neutral ground points.01. 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. A second method of detecting ground faults involves the use of a zero sequence sensing method as illustrated in Figure 2. 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. Zero Sequence Sensor Main Alternate Sensor Location method as illustrated in Figure 3. Additional grounding points may be employed upstream of the residual sensors but. This core balance current transformer surrounds all the phase and neutral conductors in a typical 3-phase. Additional grounding points may be employed upstream of the sensor but. This is a very common sensing method used with circuit breakers equipped with electronic trip units and integral ground fault protection. should any conductor become grounded. supplementary ground fault protection equipment will be required to sense low level ground fault currents and initiate the protection required. a ground fault tripping action will be initiated. In many installations. There are three basic means of sensing ground faults. Residual Sensing Method Both the zero sequence and residual sensing methods have been commonly referred to as “vectorial summation” methods. When currents flow outside the normal current path to ground. rather than on the other circuit conductors. and even with large rectangular windows to fit over bus bars or multiple large size conductors in parallel. An overcurrent can result from an overload. Neutral GFR Typical Feeder Typical 4W Load Main Figure 2. When the level of ground fault current exceeds the pre-set current and time delay settings. the current from the faulted conductor will return along the ground path. A current sensor on this conductor (which can be a conventional bar-type or window type CT) will respond to ground fault currents only. will result in zero sensor output. and others including multiple source with multiple. the relationship of the polarity markings–as noted by the “X” on each sensor–is critical. Some sensors have split cores for installation over existing conductors without disturbing the connections. This method of sensing ground faults can be economically applied on main service disconnects where circuit breakers with integral ground fault protection are provided. It can also be easily employed in multi-tier systems where additional levels of ground fault protection are desired for added service continuity. residual or zero sequence sensing methods should be employed.E . As with the zero sequence sensing method. In such cases. However. shaped configuration. 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 arranged for these modes of sensing. Zero Sequence Sensing Method Neutral Service Transformer Sensor GFR Typical Feeder Grounding Electrode Conductor Grounding Electrode Equipment Grounding Conductor Typical 4W Load Zero sequence sensors are available with various window openings for circuits with small or large conductors.71. not on the load side. Most distribution systems can utilize either of the three sensing methods exclusively or a combination of the sensing methods depending upon the complexity of the system and the degree of service continuity and CAT. Ground fault sensing is obtained with the addition of an identically rated sensor mounted on the neutral. and the residual sum of the sensor outputs will not be zero. the neutral must be grounded in only one place as indicated in Figure 1. Fusible switches so listed must be equipped with a shunt trip. Different methods will be required depending upon the number of supply sources and the number and location of system grounding points.E Type DSII Metal-Enclosed Low-Voltage Switchgear IB 32-698A C-HRG “Safe Ground” LowVoltage High Resistance Pulsing Ground System PRSC-4E System Neutral Grounding and Ground Fault Protection (ABB Publication) PB 2. In such cases a partial differential ground fault scheme should be used for the mains and tie breaker. time delay settings should be employed with the GFR furthest downstream having the minimum time delay. This operating mode permits all GFRs to operate instantaneously for a fault within their zone and still provide complete selectivity between zones. 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). are listed by UL as suitable for ground fault protection. this time delayed mode is only actuated when the GFR next upstream from the fault sends a restraining signal to the upstream GFRs. 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. Selective ground fault tripping coordination between the tie breaker and the two main circuit breakers is achieved by pre-set current pickup and time delay settings between devices GFR/1. 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. so that ground fault outages can be localized and service interruption minimized.Cutler-Hammer January 1999 Power Distribution System Design Ground Fault Protection/Lighting and Surge Protection A-45 selective coordination desired. To maintain maximum service continuity. analyzing the time-current characteristics. and CutlerHammer Type FDP fusible switches in ratings from 400A to 1200A. The advantages of increased service continuity offered by this system can only be effectively utilized if additional levels of ground fault protection are added on each downstream feeder. and the lightning protection ground must be bonded to the electrical equipment grounding system. more than two levels (zones) of ground fault protection will be required. Zone interlocking was developed for GFRs to overcome this problem. and be able to open safely on faults up to 12 times their rating. including ground fault currents. Power distribution systems differ widely from each other. As an example. GFR/2 and GFR/T. with the polarity arrangements of these two sensors along with the tie breaker auxiliary switch (T/a) and interconnections as shown. Requirements will vary with geographic location. Some users prefer individual grounding of the transformer neutrals. 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.T. one of the more frequently used systems where continuity of service to critical loads is a factor is the dual source system illustrated in Figure 4. to prevent tripping of the main service disconnect on a feeder ground fault. Depending upon the individual system configuration. GFRs (or circuit breakers with integral ground fault protection) with zone interlocking are coordinated in a system to operate in a time delayed mode for ground faults occurring most remote from the source. and many other factors. 250-23(a). However. building type and environment.01. and total system overcurrent protection. Many fused switches over 1200A. The absence of a restraining signal from a downstream GFR is an indication that any occurring ground fault is within the zone of the GFR next upstream from the fault and that device will operate instantaneously to clear the fault with minimum damage and maximum service continuity. the number of grounding points and system interconnections involved. safety for people and equipment. fault interrupting capacity. Experienced and knowledgeable engineers must consider the power sources (utility or on-site). Any lightning protection system must be grounded. this possibility is eliminated. However. the effects of outages and costs of downtime.71. and many other factors (see IEEE/ ANSI Standard 142-1982. initial and life-cycle costs. A two-wire connection is required to carry the restraining signal from the GFRs in one zone to the GFRs in the next zone. and selectivity and coordination methods to provide the most safe and cost-effective distribution system. Further Information AD 29-762 Type GFR Ground Fault Protection System DB 28-850 Systems Pow-R Breakers TD.2 NEMA Application Guide for Ground Fault Protective Devices for Equipment IEEE Grounding of Industrial and Standard 142 Commercial Power Systems (Green Book) A Main 1 Tie Main 2 Source 1 Neutral GFR 1 M1 a GFR T GFR 2 M2 a Source 2 Neutral Lightning and Surge Protection Physical protection of buildings from direct damage from lightning is beyond the scope of this section. ground fault protection must be provided on all the feeders. Dual Source System – Single Point Grounding CAT. in their application guide for ground fault protection. With several levels of protection.E . must be individually designed to meet these needs.44A. This scheme utilizes individual sensors connected in ground return fashion. that zone interlocking is necessary to minimize damage from ground faults. this will reduce the level of protection for faults within the upstream GFR zones. Grounding of Industrial and Commercial Power Systems).T. This will allow the GFR nearest the fault to operate first. Ta M1 Sensor Typical Feeder M2 Sensor Typical Feeder Tie Sensor Typical 4W Load Center Point Grounding Electrode Typical 4W Load Figure 4. They must apply protective devices. This system utilizes tie-point grounding as permitted under NEC Sec. To obtain selectivity between different levels of ground fault relays.01. An infinite number of ground fault protection schemes can be developed depending upon the number of alternate sources. depending upon the requirements of each user. The National Electrical Manufacturers Association (NEMA) states. either mode of sensing or a combination of all types may be employed to accomplish the desired end results. The electrical distribution system and equipment ground must be connected to this grounding electrode system by a grounding electrode conductor. The required grounding electrode system for a building is spelled out in the NEC. such as those for the lightning protection system. Further Information ● IEEE/ANSI Standard 142–Grounding Industrial and Commercial Power Systems (Green Book) ● IEEE Standard 241–Electric Power Systems in Commercial Buildings (Gray Book) ● IEEE Standard 141–Electric Power Distribution for Industrial Plants (Red Book) CAT. must be bonded to this grounding electrode system. The preferred grounding electrode is a metal underground water pipe in direct contact with the earth for at least 10 feet. the equipment and system grounds must be connected to the earth by means of a grounding electrode system. the telephone system. or at least 20 feet of bare copper conductor. Where any of these electrodes are present. Tests have shown this electrode to provide a low-resistance earth ground even in poor soil conditions.A-46 Power Distribution System Design Grounding Electrodes Cutler-Hammer January 1999 Grounding Electrodes A At some point. It consists of at least 20 feet of steel reinforcing bars or rods not less than 1/ 2 inch in diameter. It must be located within and near the bottom of a concrete foundation or footing that is in direct contact with the earth. Outdoor substations usually use a ground grid.71. such as the effectively grounded metal frame of the building.T. the NEC requires this electrode to be supplemented by and bonded to at least one other grounding electrode. One of the most effective grounding electrodes is the concrete-encased electrode. consisting of a number of ground rods driven into the earth and bonded together by buried copper conductors. size No. after the man who developed it. or may later be replaced by plastic piping. they must be bonded together into one grounding electrode system. and computer systems. However. television antenna and cable TV system grounds. encased in at least 2 inches of concrete. Sec. or a made electrode such as one or more driven ground rods or a buried plate. 4 AWG or larger. because underground water piping is often plastic outside the building.E .01. 250-H. sometimes called the Ufer ground. All other grounding electrodes. a concrete-encased electrode. a copper conductor ground ring encircling the building. Grounding 1.71.01. Interruption – The complete loss of voltage for a time period. expressed as a percentage of the fundamental. will provide the most cost effective approach (refer to figure below).Q. such as a loose connection or a reversed neutral and ground wire. Crest Factor – Ratio between the peak value (crest) and rms value of a periodic waveform. A The Power Quality Pyramid™ 6. can avoid a more expensive power conditioning solution. but not between the equipment grounding conductor or associated signal reference structure and the active circuit conductors. Power Quality Terms Power Disturbance – Any deviation from the nominal value (or from some selected thresholds based on load tolerance) of the input ac power characteristics. Power Quality is defined according to IEEE Standard 1100 as the concept of powering and grounding sensitive electronic equipment in a manner that is suitable to the operation of that equipment. Technical Overview Introduction Ever since the inception of the electric utility industry. Power quality starts with grounding (the base of the pyramid) and then moves upward to address the potential issues. Total Harmonic Distortion or Distortion Factor – The ratio of the root-mean-square of the harmonic content to the root-meansquare of the fundamental quantity. Surge or Impulse – See transient. the power quality problem can be defined. hardware.Cutler-Hammer January 1999 Power Distribution System Design Power Quality A-47 Power Quality – Terms. or by inserting some interface equipment (known as power conditioning equipment) between the electrical supply and the sensitive load(s) to improve the compatibility of the two. and optimal solution chosen. the problem must be clearly defined before it can be resolved. IEEE Standard 1159 notes that “within the industry. Thus unobserved or potential problems may not be considered in the solution. With this viewpoint. the exact sensitivities of the load equipment may be unknown and difficult to determine. Uninterruptible Power Supply (UPS. at the power frequency. For instance. and determining the load disruption and consequential effects (costs). etc. monitoring the power supply for power disturbances.E (power disturbances). Apparent (Total) Power Factor – The ratio of the total power input in watts to the total voltampere input. Voltage Regulation 3. power quality solutions are often implemented to solve potential or perceived problems on a preventive basis instead of a thorough on-site investigation. For electronic equipment. monitoring for power disturbances may be needed over an extended period of time to capture infrequent disturbances. the site should be checked for wiring and grounding problems. Analysis and Studies ● Power Monitoring ● Grounding Products & Services ● Surge Protection ● Voltage Regulation ● Harmonic Solutions ● Lightning Protection (ground rods. when planning a new facility. Not only do these types of equipment require quality power for proper operation. or in the design stages of a new building. An under-voltage would have a duration greater than several seconds. Survey. and finally. May be of either polarity and may be additive to or subtractive from the nominal waveform. The framework is also effective for specifying engineers who are creating a specification for a new facility. by improving the load equipment's tolerance to those variations. Common-Mode Noise – The noise voltage that appears equally and in phase from each current-carrying conductor to ground. Sensitive electronic loads deployed today by electrical energy users require strict requirements for the quality of power delivered to loads. Transient – A sub-cycle disturbance in the ac waveform that is evidenced by a sharp brief discontinuity of the waveform. the investigative approach tends to solve only observed problems. In this way. Sets. alternative solutions developed. Noise – Unwanted electrical signals that produce undesirable effects in the circuits of control systems in which they occur.” In addressing power quality problems at an existing site. variable frequency motor drives and other electronically controlled equipment is placing a greater demand on power producers for a disturbancefree source of power. these types of equipment are also the sources of power disturbances that corrupt the quality of power in a given facility.T. Surge Protection 2. The lowest cost and highest value solution is to selectively apply a combination of different products and services as follows: Key Services/Technologies in the “Power Quality” Industry ● Power Quality Surveys. Sometimes this approach is not practical because of limitations in the time and expense is not justified for smaller installations. if any. Harmonic Distortion 4. Sometimes. Another option is to buy power conditioning equipment to correct any and all perceived power quality problems without any on-site investigation. with shortened life expectancy. Methodology for Ensuring Effective Power Quality to Electronic Loads The Power Quality PyramidTM is an effective guide for addressing a power quality problem at an existing facility. Therefore. one option is a thorough on-site investigation which includes inspecting wiring and grounding for errors. For example. utilities have sought to provide their customers with reliable power maintaining a steady voltage and frequency. there is no site to investigate.) ● 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 required to reliably operate the load equipment. Before applying power-conditioning equipment to solve power quality problems. Practicality and cost usually determine the extent to which each option is used. for the duration from a half-cycle to a few seconds. Electronic systems may be damaged and disrupted.) 5. power disturbances are defined in terms of amplitude and duration by the electronic operating envelope. correcting a relatively inexpensive wiring error. As in all problem solving. Power Monitoring. Gen. power quality problems can be resolved in three ways: by reducing the variations in the power supply CAT. many times. Many methods are used to define power quality problems. alternate definitions or interpretations of power quality have been used. The proliferation of computers. Sag – An rms reduction in the ac voltage. yet proven methodology. reflecting different points of view. etc. Analysis . Normal-Mode Noise – Noise signals measurable between or among active circuit conductors feeding the subject load. P. This simple. investigating equipment sensitivity to power disturbances. engineers need to specify different services or mitigating technologies. e. 2. Suppressors are installed at the facility entrance and/or key substation locations. it is necessary to prevent ground loops from affecting the signal reference point. Nonlinear load currents vary widely from a sinusoidal wave shape. three-phase nonlinear loads contain small quantities of even and third harmonics although in an unbalanced three-phase system feeding threephase non-linear loads the unbalance may cause even harmonics to exist. The instantaneous current was directly proportional to the instantaneous voltage at any instant. SPDs are cost-effective compared to all other solutions (on a $/kVA basis).A-48 Power Distribution System Design Power Quality/Harmonics and Nonlinear Loads Cutler-Hammer January 1999 A 1. data processing and process controllers malfunctioning. In general as the order of a harmonic gets higher its amplitude becomes smaller as a percentage of the fundamental frequency. This can involve motor inrush currents or repeated starts per hour. and true rms measurements are necessary for metering and relaying to prevent improper operation of protective devices. such as many generator speed and synchronizing controls. 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.e. 3. isolation transformers in voltage regulating controls. Transformers. Some of the harmonic voltages are negative sequence (rotation is ACB instead of ABC). transfer schemes response times and power factor correction. auto-transfer switches and surge protection devices (SPD/TVSS). the technology is often applied at specific loads only. voltage flicker. They are also recommended on data lines. Engineers are often more concerned about the effects of increased neutral current on the electrical distribution system (i. transformers operating hot or loud. With the proliferation of electronic equipment such as computers. The transient voltage surge suppressors (also called TVSS) shunt short duration voltage disturbances to ground. In addition. signal lines or other non-isolated communication lines at the facility’s entrance. capacitor fuses blowing. generators. lights flickering. Grounding represents the foundation of a reliable power distribution system. and UPS systems will overheat and often fail at loads far below their ratings.T. thyristors. a common design error is to assume UPS systems solve all power quality problems. NFPA. Surge Protection Devices (SPDs) are recommended as the next stage power quality solutions. K-factor transformers. Harmonics seldom affect the operation of microprocessor-based loads. However. Power Quality Survey. breaker tripping or fuse blowing. Power Quality evaluations can identify deficiencies and corrective measures involving: harmonics and filtering. IEEE Emerald Book and equipment manufacturers recommend the use of surge protectors. UL96A. The above data is obtained both by on-site investigation and installation of high-speed temporary power measurement devices. Uninterruptible Power is often the last component to be selected in the design process. The rms value of current is not easy to determine. Triple harmonics are zero sequence harmonics and are in phase. the harmonic currents acting on the impedance of the source cause harmonics in the source voltage. causing them to overheat.01. most electrical loads were linear. neutral conductors. Readings from a power quality meter will determine the level of distortion and identify site-specific problems. motors tripping or overheating. neutral currents.. Devices that measure time on the basis of wave shape. The captured data will allow for the proper solution selection. While the proper selection and application of UPS is critical to reliable operation of mission critical equipment. loads that are switched or pulsed. sags or overvoltage) disturbances are generally siteor load-dependent. fault duration/magnitude and the specific problems encountered. transformers). the evaluation can identify problems. switching transients. Grounding and wiring problems can be the cause of up to 80% of all power quality problems. In addition to reviewing ac grounding/bonding practices. A power quality survey is a factfinding investigation which reviews total power outages. This means that they are extremely high in harmonic content. 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. A variety of mitigating solutions are available depending upon the load sensitivity. efficiency and maintenance costs) and the use of more decentralized network systems. programmable logic controllers.. Voltage Regulation (i. and switching power supplies. eighth. etc. Reference sections L and F1 for detailed information. lightning protection. 5. IEEE (Standard 1100) recommends surge protection ahead of UPS and associated bypass circuits. grounding issues. thereby preventing the surge from affecting electronic loads. It is important that with standby generators the harmonic content of the current of the loads that will be transferred to the standby generator be reviewed with the generator manufacturer to ensure that the voltage and frequency controls will operate satisfactorily. separation of feeders to critical loads and peak-reading circuit breaker trip systems versus updated rms sensing systems. because the harmonic currents cause greater heating than the same number of rms amperes of 60 Hz current. The second. The above survey and monitoring result in a power quality evaluation. 6. VFDs malfunctioning. Mitigating equipment is usually not required to prevent operating problems with electronic loads. and skin effect in the conductors of the windings. Computers will crash as their internal timing clocks fail. When installed as part of the facilitywide design. Effective distribution layout and other considerations can be addressed during the design stage to mitigating harmonic problems. The following grounding standards are useful references: ● IEEE Green Book (Standard 142) ● IEEE Emerald Book (Standard 1100) ● UL96A.. but are demonstrating power quality-like conditions. CAT. In addition to the above.71. high resistance ground units. though lagging by some time depending on the power factor. Given the high cost per kVA of UPS. fifth. variable speed drives. All other forms of power quality solutions are dependent upon good grounding procedures. (including capital. To prevent lightning or other surge related damage. which is then applied to other loads such as motors. Harmonics related problems can be investigated and solved once loads are up and running. nonlinear loads have become a significant part of many installations.E . Harmonics and Nonlinear Loads Until recently. therefore providing initial and long-term monitoring. will fail to maintain proper output frequency or to permit paralleling of generators. and the like. In addition. generators. This results from increased eddy current and hysteresis losses in the iron cores. which are not related to power quality issues. often they are discontinuous pulses. Many power quality instruments can not be permanently installed during the initial data collection effort. computer malfunctioning. and eleventh harmonics are negative sequence harmonics. It is recommended to install monitoring equipment on the ac powerlines to assess the degree and frequency of occurrences of voltage regulation problems. UPS systems. are nonlinear. 4. The harmonics create numerous problems in electrical systems and equipment. such as rectifiers. 23rd.5 5. triplens and their odd multiple harmonics are additive in the neutral. 4-wire system.5% 1. Even with the phase currents perfectly balanced.0% 1.0 11≤h<17 2.0 17≤h<23 1.0 5. Locate capacitors as far away (in terms of circuit impedance) from non-linear loads. or the method shown in C57. I L = maximum demand load current (fundamental frequency component) at PCC. The K-rated transformers calculate the sum of Ih2(pu) x h2 where Ih is the harmonic current of the hth harmonic as per unit of the fundamental and h is the order of the harmonic.0 12. 13th. 5.3 0. The winding eddy current loss under rated conditions should be obtained from the transformer manufacturer.5% >138 kV 1. are not allowed.0 20. C is the impeance ratio of total impedance to impedance at common point in system.0 7. 3-phase rectifiers produce 11th. 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 calculated. they lower the actual power factor. At the same time that harmonics create problems in the application of power factor correction capacitors. Use multipulse conversion (ac to dc) equipment (greater than 6 pulses) to reduce the amplitude of the harmonics.0 TDD= Total Demand Distortion. 4.. half-wave converters. 7th. Their effect is the same as that of multi-pulse equipment and should be considered with 6-pulse equipment only. AN is volt-microseconds. More recent electronic meters are capable of metering the true kVA kW hours taken by the circuit. When all the above do not produce the desired reduction. 2.110 covers the procedure of derating standard (non-K-rated) transformers. design the installation incorporating reactors as tuned filters to 5th.0 10. 11th.5 35≤h 0. regardless of actual ISC /I L .x 100 for each harmonic and V1 h = h max 1⁄ 2 Vh Vh =    ∑ h=2 2 Vh    Table A21 is taken from IEEE Standard 519 Table 10. This method is based on determining the 2 load loss due to I R loss including the harmonic current plus the increase in the eddy current losses due the harmonic currents. It is important for the customer to know the harmonic content of the utility’s supply voltage because it will affect the harmonic distortion on his premises.0 6. This has resulted in overheated neutrals.0 23≤h<35 0. oversize the system components as the last resort.harmonics. The Computer and Business Equipment Manufacturers 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 prevent problems.0 2. to compensate for harmonic heating effects. K is the factor that corrects the eddy current loss under rated conditions to reduce the effects of adverse heating due to harmonics. In spite of all the concerns they cause. 11th and 13th harmonics and high pass filters for higher harmonics. 7th. the harmonic currents in the neutral can total 173% of the phase current..0 15.0 1. Single-phase power supplies for computer and fixture ballasts are rich in third harmonics and their odd multiples.4 TDD 5. DF is distortion factor.800 36. where ISC = maximum short-circuit current at PCC.3-69 kV 69-138 kV 3.E . 3.0% 5.3.Cutler-Hammer January 1999 Power Distribution System Design Harmonics and Nonlinear Loads A-49 The harmonics also complicate the application of capacitors for power factor correction. 7. The standard also covers the harmonic limits of the supply voltage from the utility or cogenerators. nonlinear loads will continue to increase. Install reactors between the power supply and the conversion equipment.5 0. usually the point of connection to the utility or the main supply bus of the system. 25th. CAT. Rectifiers with diode front ends and large dc side capacitor banks have displacement power factor of 90% to 95%. Therefore 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.T.5 4. Table A21–“Current Distortion Limits For General Distribution Systems (120V Through 69000V)” Maximum Harmonic Current Distortion in Percent of IL Individual Harmonic Order (Odd Harmonics) ISC /I L <20* 20<50 50<100 100<1000 >1000 <11 4.0 1. 12-pulse.0 12. They reduce the harmonic components of the current drawn by diode type conversion equipment with large filter capacitors. Use ∆-∆ and ∆-Y transformers in pairs as supply to conversion equipment.5 7.g. 6. etc.0 8. Another benefit is that they protect the filter capacitors from switching surges produced by switched utility or mediumvoltage system capacitor. Table A20–Utility or Co-gen Supply Voltage Harmonic Limits Voltage Range Maximum Individual Harmonic Total Harmonic Distortion 2. the neutral current is zero. or derate the equipment. If at a harmonic frequency the capacitors capacitive impedance at the frequency equals the system’s reactive impedance at the same frequency. 13th.400 22. K-rated transformers have lower impedance than non-K-rated transformer which should be considered in the selection of the lowvoltage side breakers.5 2. loading them to no more than 50% to 70% of their nameplate kVA. *All power generation equipment is limited to these values of current distortion.71. Even harmonics are limited to 25% of the odd harmonic limits above.0 3. However.500 DF 3% 5% 10% A *Special system are those where the rate of change of voltage of the notch might misstriggen an event.110 should be used. if the 60 Hz phase currents are balanced (equal). CBEMA also recommends derating transformers. The rotating meters used by the utilities for watt-hour and varhour measurements do not detect the distortion component caused by the harmonics.7 1.5 4.. Use active filters that reduce the harmonics taken from the system by injecting harmonics equal to and opposite to those generated by the equipment. With a 3-phase. Where capacitors are required for a power factor correction. based on a rule-of-thumb calculation.5 2.0% 2.0 15. Current distortions that result in a dc offset. Three-phase.6 1. 6-pulse rectifiers produce 5th. e. Such measures are: 1. Table A19–Low-Voltage System Classification and Distortion Limits for 480V Systems Class Special Application* General System Dedicated System C 10 5 2 AN 16.01. ANSI Standard C57.5% Percents are -----. as viewed at the point of application of the capacitor the harmonic voltage and current can reach dangerous magnitudes. In addition. costly. at 277 volts. especially for large buildings or multiple-building installations such as shopping centers. Since most low-voltage distribution equipment available is rated for up to 600 volts. such as type of building. About 1950. secondary voltage drop high percentage of incandescent lighting would favor lower utilization voltages such as should not be a problem. more economical. and to serve increased lighting loads output of light per watt of power consumed. large motor ceptable limits on 480-volt circuits than on and fluorescent lighting loads. educational institutions. with a solidly 120 volts to ground tends to be self-extingrounded neutral. it is necessary to supply these loads through step-down transformers. The principal advantage of the use of higher secondary voltages in buildings is that for a and fewer branch circuits. Second. or hazardous than for 208-volt systems. CAT.T. small fractionalhorsepower motors. receptacle loads. 480Y/277V services).minaires do not have an integral manual switch and are mounted at least eight feet ment of 277-volt ballasts and 277-volt wall above the floor. for any neous developments changed this. and have less effect in reducing fault currents at Secondary Voltage the higher voltages. This permits a three-phase.or 120-volt ballasts. This system supplies 600-volt three-phase motors. and plug-and-cord connected appliances for receptacle loads require a 120-volt supply. However. schools. Since center unit substations close to the loads. and 346-volt ballasts for the fluorescent and HID lighting. (600 volts phase-tophase and 346 volts phase-to-neutral).E . centrally air-conditioned tends to be self-sustaining and likely to cause and electrically heated residential buildings. other HID lighting. such as bus or cable impedances. In general. while an arc of 277 volts to ground secondary voltage in industrial plants and even in some high-rise. to use 208-volt distribution and keep be used to transmit the power from the servoltage drops within acceptable limits.and high-intensity discharge (HID) lighting in ers became readily available to step down the a building at 277 volts. the 480-volt delta or wye systems (see section on arc is more difficult to interrupt than the ground fault protection). it would have been same voltage drop in volts. the small impedances in the system. The most important of these are size and types of loads (motors. 208-volt arc. The major difference is that an arc of ings today is 480Y/277 volts. with large motor Fault interruption by protective devices may loads. several simultacal purpose. fluorescent It is easier to keep voltage drops within aclighting. receptacles) and length of feeders. Utility Service Voltage Whether the utility service is at primary or secondary voltage will depend upon many factors. service disconnecting means rated 1000 amcentral air conditioning became standard peres or more. as well as motors at 480 volts. the utility will serve a single commercial or institutional building at secondary voltage only.cult.and 208-volt systems. this can influence the choice of supply voltage. tion of equipment on grounded wye services such as offices and stores.01. In most downtown metropolitan areas. al factors. Very large loads and long runs would indicate the volt supply conductors can be compensated use of medium-voltage distribution and load. voltage drop in the 480such as 480Y/277V. short runs. used 208Y/120-volt of more than 150 volts to ground but not exceeding 600 volts phase-to-phase (for practidistribution. If it is. A 277-volt wall switch and 277-volt ballast made the 480Y/277-volt system practical. First. When 120-volt loads are supplied from a 480-volt system through stepers. hospitals. the interrupting ratings of circuit breakers and fuses at 480 volts have increased considerably in recent years.A-50 Power Distribution System Design Secondary Voltages Cutler-Hammer January 1999 A conductors are insulated for 600 volts. or the relative cost of 480. With the increase in loads. such as high-pressure sodium or metal halide. and long feed. Three-phase motors and their controls can be obtained for either voltage. more than doubling the previous permits voltage up to 300 volts to ground on loads for similar non-air-conditioned buildings. using 600Y/ 346-volt distribution. the ability to serve is increasing in use. shopping centers.and a reduction in the number of lighting branch circuits is usually possible. will tend to make the higher voltages. are almost always 480V. and can be used to protect downstream equipment against these high fault currents. Incandescent lighting. down transformers. and for a given horsepower are less costly at 480 volts. and prohibitively expensupply voltage. resulting in full 120-volt output. For this reason. vice entrance point to the final distribution points. and hospitals. these transformers are usually located close Conversely.71. The higher secondary voltage system will usually be more economical in office buildings. In more open areas. If the amount of 120-volt load to be served is high. wall receptacles. as color rendition is imthe air-conditioning and other motor loads at proved. the National because of the large electrical loads. because of the economical high lumen 480 volts. the problems of excessive voltage drop from large given load. incandescent lighting. While mercury-vapor HID lighting is voltage for 120V incandescent lighting and becoming obsolescent. these considerations have been carried one step further. and the utility rate structure and standard practice. as well as in industrial plants. small loads. less current means smaller conloads on 208-volt systems was greatly reduced ductors and lower voltage drop. a given conductor size can supply a large load at the with 480-volt distribution. Finally. and similar commercial and institutional installations. Also. Fluorescent and HID lamps can be used with either 277. it is economically advantageous to minimize the amount of 120-volt load. First. the utility may offer a choice of primary or secondary service. total load. since they exceed 300 volts to ground. Smaller conductors can be used in The choice between 208Y/120V and 480Y/ many branch circuits supplying power loads. The National Electrical Code practice. These Canadian installations would violate the National Electrical Code in the United States. lighting levels were increased. Economic Factors Utilization equipment suitable for principal loads in most buildings is available for either 480-volt or 208-volt systems. class of user. provided the luwith fluorescent lighting replacing most of the incandescent lighting. the develop. switches made it possible to serve this fluofour-wire. Therefore. taps may be used to compensate by raising the voltage at 208Y/120V. economical mass-produced dry-type 480-volt to 208Y/120-volt transform. severe damage.for by the tap adjustments on the transformer. the installed equipment will have a lower total cost at the higher voltage. the transformer. Third. This prohibition does not exist in Canada. but a lower percentage voltage drop because of the higher nearly impossible. 277V secondary distribution for commercial and institutional buildings depends on sever. and protective devices are now available for any required fault duty at 480 volts. many of these protective devices are current limiting. It permitted Technical Factors smaller feeders or larger loads on each feeder. solidly grounded 480Y/277-volt rescent lighting load from a 480Y/277-volt system to supply directly all of the fluorescent system. It is also a very common guishing. using as little incandescent lighting as possible. the installation of 480-volt systems uses the same techniques and is essentially no more diffiThe most prevalent secondary distribution voltage in commercial and institutional build. and a to the 120-volt loads. Up until Electrical Code requires ground fault protecthe early 1950s.208-volt circuits. most commercial buildings. 480Y/277-volt systems became the most economical distribution. With a 480Y/277-volt service. Fewer or smaller circuits can sive. Practical Factors and upstream protective device impedances. Second. A 346-volt wall switch has been developed to control this fighting. Industrial installations. It is interesting to note that in some recent installations in Canada. However. often be more difficult at 480 volts than at 208 volts ungrounded delta or resistance grounded for two principal reasons. In addition. circuits supplying permanently installed electric discharge lamp fixtures. In some very tall high-rise office buildings. in almost all cases. to reduce the length of secondary feeder runs. the cost and availability of qualified maintenance for the primary distribution equipment and substations. There are exceptions.71. through spot networks for a high-rise office building. The fault current available at each service would be nearly 200. flexibility. Secondary distribution can be radial. the cost of an outage can be tremendous. with the required interrupting capacity. or with primary distribution to multiple load-center unit substa- tions for larger systems. continuity of service required. and redundant equipment can easily be justified. The utility would have one spot network in a utility vault under the sidewalk. depending upon the size of the institution. available room for electrical equipment. CB Emergency or Standby Generator CTs Utility Service 4000A at 480Y/277V 100. and another in a specially constructed fireproof utility vault on the 40th floor of the building. Utility rate structures provide higher cost for a given load served at secondary voltage than for the same load served at primary voltage. and using a secondary radial distribution system within the building. Where secondary service is delivered. supplying services in the basement. In industrial installations. ranging from a single pad-mounted transformer. The main and feeder circuit breakers in the switchboard must be able to interrupt the high fault currents available at their line terminals. High-Rise Office Buildings Over the past 30 years. Any of the primary and secondary distribution methods previously described may be used. The utility will supply the load in various ways.800 volts primary service by the utility and feeding 67 building-owned unit substations. or even secondary network. Œ 4000A Main CB Utility Metering PTs Automatic Transfer Switch Gen. most major cities have grown rapidly. It is also usual for com- mercial buildings to use secondary service. and similar factors. the design should provide that the switchboard breakers not A Elevator Panel Typical Typical HVAC Panel Emergency Lighting Panel (Typical Every Third Floor) 480Y/277V Panel 208Y/120V Panel Typical Dry Type Transformer 480 -208Y/120V (Typical Every Floor) HVAC Feeder Busway Riser Emergency Lighting Riser Elevator Riser Typical Building and Miscellaneous Loads Typical Typical Typical Spare Typical Œ Œ Œ Œ Œ Œ Œ Œ Include Ground Fault Trip. such as one major office building in Pittsburgh supplied at 13. especially in the process industries. A typical single-line riser diagram for such a building is shown. and well qualified maintenance. The choice will depend on the continuity of service required.01. Generally. Each vault might have six 2500-kVA network transformers. and their central areas have been the sites for construction of many highrise office buildings. along with the arrangement of a typical electrical closet on each floor. or high interrupting capacity breakers (Series C). and the initial andoperating costs must be weighed against the cost of downtime. most buildings will use simple radial distribution from the service. 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 of substation (mostly transformer) losses. the number and arrangement of buildings. For the customer. The smaller feeder circuit breakers in both normal and emergency sections can be of the current-limiting type (Current LimitR). or have multiple feeders or one or more loops. to single-ended or doubleended substations. since the utility must provide and maintain the substations and pay for the substation losses on a secondary service. served by a utility network system at 480Y/277 volts. secondary-selective. Many high-rise office buildings fall between these extremes. the distribution can be from a single substation for smaller installations. to take advantage of primary service. but they are not common.Cutler-Hammer January 1999 Power Distribution System Design Secondary Voltages A-51 Where a choice is available. the decision is essentially an economic one.E . Whatever type is chosen. the electric utility company serves these buildings at a secondary voltage of 480Y/277 volts from one or more spot networks.T. It is common for industrial plants. those systems that provide higher service reliability also have higher cost. The main circuit breaker and the large feeder circuit breaker supplying the riser busway can be of the encased type (Systems Pow-R).000 amperes. and quality of maintenance available. supplying four 4000-ampere 480Y/277-volt service takeoffs. The distribution system in this type of building is worthy of discussion.000A Available Fault Current Typical Power Distribution and Riser Diagram for a Commercial Office Building CAT. Where the service is at primary voltage. and the cost of the system. Institutional services vary. reliability of service. because it represents very large loads and often high available short-circuit fault currents. or several transformers for a multi-building installation. In most cases. and distribution systems with maximum reliability. integrally fused breakers (Tri-Pac). loop. supplying additional services. with large loads. Primary distribution can be radial. At the other extreme would be a typical block-square 60-story office building in New York City. on opposite sides of the building. similar to multifunction time clocks. and it rarely takes more than two years. because energy was inexpensive. often being designed for lowest first cost. designers must consider the efficiency of electrical distribution systems. Computers can not only control lighting and HVAC systems. at $. it is recommended to use the energy-efficient types. The lighting system must take advantage of the newest equipment and techniques. the additional initial cost could be repaid in energy saved within a few months. These range from simple devices. and the acceptable combinations are listed.5 watts per square foot have been given improved lighting.71. so the busway takeoff disconnect circuit breakers on each floor will have to be selected to withstand high fault currents and to protect the devices they supply. in some cases. but are driven by variable-speed drives. This is highly inefficient and wasteful of energy. up to full microprocessor-based. and larger windings. the busway riser will provide more diversity for feeding loads. HVAC systems have traditionally been very wasteful of energy. In recent years. Variable-speed drives can often be desirable on centrifugal compressor units as well. using as little as 1. Building security systems. in 400A. fully programmable devices. and that the variableair-volume fans do not use inlet vanes or outlet dampers. often very effective. Since. the throttling valves or inlet vanes or output dampers can be eliminated. to provide ground fault protection (Type FDP. and should be considered in all transformer specifications. as fuses must be replaced. reliable. New light sources. For example. they must be controlled to perform their functions most efficiently. too. such as closed-circuit television monitoring. savings from lower losses can be substantial. and often a lower installed cost for equal capacity. ft. Transformers. energy-saving devices. computers with specialized software can be used.01. at substantial cost. An additional benefit of both energy-efficient motors and variable-speed drives (when operated at less than full speed) is that the motors operate at reduced temperatures. in large installations.000 per year in energy costs. he can specify that all motors with continuous or long duty cycles are specified as energy efficient types. and special requirements. each with its own busway riser. and this results in increased initial cost. operating costs are so high that energyconserving designs can justify their higher initial cost with a rapid payback and continuing savings. and the cost of energy. incorrect replacement fuse types or sizes may be chosen resulting in loss of selectivity. design was for lowest first cost. They add up to providing the necessary amount of light. efficient luminaires. hours of use. and provide peak demand control. to minimize the cost of energy. The 2500-ampere circuit breaker supplying the busway will provide little current limitation. costs. The simplest of these energy-saving controls. computerized or programmed control. In the past. Where a motor drives a load with variable output requirements such as a centrifugal pump or a large fan. customary practice has been to run the motor at constant speed. Depending on loading. A busway riser might be replaced with cable risers to each floor. any motor with many hours of use should be of the energy-efficient type. Busway disconnects must be fusible. Fusible equipment will often have lower initial cost than circuit breakers. Using the best of techniques. However. Many commercial office buildings are constructed at minimum cost. and the like. power. There are four major sources of energy conservation in a commercial building – the lighting system. with the desired color rendition. Since the 480-volt to 208Y/120-volt stepdown transformers in an office building are usually energized 24 hours a day. Obviously. resulting in increased motor life. environmental design. based on actual loading cycles throughout the day. 10 hours per day. the transformers. solid-state variable-frequency. with no more than 80°C (or sometimes 115°C) average winding temperature rise at full load. However. which can also perform auxiliary functions such as elevator control and building communication in case of fire.A-52 Power Distribution System Design Secondary Voltages/Energy Conservation/Building Control Systems Cutler-Hammer January 1999 A only have adequate interrupting capacity. and. For any motor operating ten or more hours per day. where and when it is needed. this could mean a saving of 400 kW. Current limiting or integrally fused circuit breakers may be required for this duty. and consider the cost of losses as well as the initial cost of the transformers in purchasing. Current limiting and integrally fused circuit breakers have been tested by UL in series with lower-rated circuit breakers at high fault currents. such as those based on the NASA patents. and larger sizes). For complete control of all building systems. to provide sufficient current limiting to protect the circuit breakers in the 480-volt panelboards. reheat systems are being replaced by variable air volume systems. with less glare and higher visual comfort. etc. resulting in equal comfort with substantial increases in efficiency. even in the speculative office building. and relatively inexpensive. and the HVAC system. especially in commercial buildings. power factor control-type devices can rarely be justified unless the motor is loaded to less than 50% of its rating much of the time. intruder sensing.000 sq. door alarms.. can result in substantial savings.E . really small computers. Other variations of the typical design shown will be determined by building size. Energy Conservation Because of the greatly increased cost of electrical power. like motors. but downtime after a fault will be higher. Constant monitoring would be required for manual operation. energy efficient motor designs are available using more and better core steel. A better method would be to evaluate transformer losses. and not providing light where or when it is not necessary. a smaller switchboard. solid-state ballasts with dimming controls. are designed for lower losses by using more and better core materials. These motors have a premium cost of about 20% more than standard motors. CAT.T. it is important for the energy-conscious electrical engineer to work closely with the HVAC engineer at the design stage. use of daylight. and energy will be saved over the life of the system.05 per kWh.0 watts per square foot. and HVAC systems. office spaces that originally required as much as 3. This. Since some of these requirements will be in HVAC specifications. so some form of automatic control is required. but also that they limit the fault current letthrough to values that the devices they supply can withstand. One method of obtaining reduced losses is to specify transformers with 220°C insulation systems designed for 150°C average winding temperature rise. Today. over the life of a motor. and use fusible service equipment and distribution equipment with current limiting fuses. Fire detection and alarm systems can operate through the computer. could save $50. Motors and controls are another cause of wasted energy that can be reduced New. Transformers have inherent losses. For motors operating lightly loaded a high percentage of the time. 250 days per year. with Class L fuses. programmable controllers may be used. The branch switches should be able to be shunt tripped. Replacement current limiting fuses in all sizes and types used must be stocked. and design for energy conservation.. While the electrical engineer has little influence on the design of the HVAC system. saving their initial cost. and to throttle the pump output or use inlet vanes or outlet dampers on the fan. efficient lighting is a necessity. supplied from individual switches on a larger switchboard. variable-speed drives for ordinary induction motors have been available. especially when combined with solid-state starters. from the most efficient sources. If maintenance is not qualified. is changing. the motors and controls. Where flexible control is required. Using a variable-speed drive. are some of the methods that can increase the efficiency of lighting systems. familiar light sources with higher efficiencies. In an office building of 200. which. Building Control Systems In order to obtain the maximum benefit from these energy-saving lighting.0 to 2. but they can perform many other functions. reduced safety. larger conductors. the cost of energy to operate it is many times the cost of the motor itself. is a time clock to turn various systems on and off. The main switch and busway feeder switch could be the bolted pressure contact type. Buildings of larger size may have two electric closets per floor. and similar energy uses. it is necessary for the design engineer to make a thorough building and environmental study. Islanding is another reason why the utility insists on the disconnection of the cogenerator. It is considered preferable to risk arcing damage. A single pair of wires. Poor design can be wasteful. high-rise apartment buildings and even commercial office buildings. ground fault protection is not required. as in many industrial installations. but does have requirements for those systems when they are legally mandated and classed as emergency (Article 700) or standby (Article 701) by municipal. a part of the system may continue to be supplied by cogeneration. and to weigh the costs and advantages of many systems. Simpler and more economical in such a case is a separate emergency bus. 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. Sometimes. plus a federal law (Public Utility Regulatory Policies Act. when the normal supply fails. with a rechargeable battery. or by any governmental agency having jurisdiction. Major cogenerators are connected to the subtransmission or the transmission system of a utility. and steam or hot water the byproduct. and other equipment by means of hard wiring-separate wires to and from each piece of equipment. other than those classed as emergency systems. Major cogenerators have buy-sell agreements. is also permitted.Cutler-Hammer January 1999 Power Distribution System Design Building Control Systems/Cogeneration/Emergency Power A-53 can be performed by the same building computer system. as in most commercial installations. and complexity of functions to be performed. The National Electrical Code does not specifically call for any emergency or standby power. A Cogeneration Cogeneration is another outgrowth of the high cost of energy. In the more complex systems. On failure of the normal supply. and electric power a byproduct. Where a cogeneration system is being considered. The newest systems may use fiber-optic cables to carry tremendous quantities of data. number. Proper generator control and protection is necessary. in normal operation. Unit equipment for emergency illumination. steam. or other codes. supplied through an automatic transfer switch. NEC requirements are stringent. this would result in a tremendous number of control wires. Optional standby systems are those not legally required. on loss of normal power. programmable controllers. Because of the critical nature of emergency power. Reclosing in most cases will damage the cogenerator if it had remained connected to their system. It is preferable to isolate these systems as much as possible. but until recently it has not been economically feasible for most commercial installations. to feed all critical loads.71. The electric power can be the main product. motors. such as an engine generator or separate service. and sometimes steam absorption-type air conditioning. On return of the normal source. a charger to keep it at full capacity when normal power is on. efficient operation. except in transfer equipment enclosures and similar locations. hot water. practical commercial cogeneration systems have been built that provide some or all of the electric power required. cogeneration has been common practice for many years. less costly but equally effective. are also covered in the NEC (Article 702). electrically interlocked such that on failure of the normal supply the emergency supply is connected to the load. The interface with the Emergency Power Most areas have requirements for emergency and standby power systems. In many cases. as required by the governmental agency having jurisdiction. This has been changed by the high cost of purchased energy. engine-generator set. and extremely costly. so other methods are frequently used. and when it is up to speed the automatic switch transfers the emergency loads to this source. known as PURPA) that requires public utilities to purchase any excess power generated by the cogeneration plant. Such cogeneration systems are now operating successfully in hospitals. but loss of which could create hazards or hamper rescue or fire-fighting operations. Islanding is the event that after a fault in the utility’s system is cleared by the operation of the protective devices. except that wiring may occupy the same distribution and raceway system as the normal wiring if desired. utility company is critical. Where the emergency or standby source. plus hot water. not legally required. Cogeneration is the production of electric power concurrently with the production of steam.E .01. even though not required by code. state. manual or automatic retransfer of the emergency loads can take place. Some systems dispense with control wiring completely. On 480Y/277-volt emergency systems with protective devices rated 1000 amperes or more. free from electromagnetic interference. rather than to disconnect the emergency supply completely. and a relay to connect the battery to the lamps on loss of normal power. requiring careful relaying to protect both the utility and the cogeneration system. uninterruptible power supplies. or a connection to the service ahead of the normal service disconnecting means. coaxial cable is used with advanced signaling equipment. The time clocks. However. Because building design and control for maximum energy saving is important and complex. Optional systems can be treated as part of the normal building wiring system.T. NEC requirements are similar to those for emergency systems. as well. if the emergency or standby source does not have capacity for the full load. normal and emergency main circuit breakers. Many utilities have stringent requirements that must be incorporated into the system. the transfer scheme can be either a full-capacity automatic transfer switch. Utilities require that when the protective device at their substation opens that the device connecting a cogenerator to the utility open also. and frequently involves many functions and several systems. The most common power source for large emergency loads is an CAT. The result of good design can be economical. requiring periodic testing under load and automatic transfer to emergency power supply on loss of normal supply. but the entire design should be coordinated with the utility. the electrical distribution system becomes more complex. one or more lamps. One reason is that most cogenerators are connected to feeders serving other customers. In such cases utilities use a trip transfer scheme to trip the cogenerator breaker. with electronic digital multiplexing. or the steam or hot water can be the most required product. or. as is usually the case. federal. An on-site electrical generating plant tied to an electrical utility. Optional standby systems. are intended to supply power to selected loads. All wiring from emergency source to emergency loads must be kept separate from all other wiring and equipment. and are intended to protect private business or property where life safety does not depend on performance of the system. has capacity to supply the entire system. but the NEC also permits the emergency supply (subject to local code requirements) to be storage batteries. and computers can obtain data from external sensors and control the lighting. In some industries. in its own distribution and raceway system. sending and receiving digital signals over the power wiring. shopping centers. is a sophisticated engineering design. Legally required standby systems. such a scheme would require automatic disconnection of the nonessential loads before transfer. Such a condition is dangerous to the utility’s operation during restoration work. Utilities desire to reclose the feeder after a transient fault is cleared. a separate emergency service. Guidelines that are given in ANSI Guide Standard 1001 are a good starting point. The method used will depend on the type. the engine-generator is started. can control or obtain data from many different points. a ground fault alarm is required if ground fault protection is not provided. The transfer switch connects this bus to the normal supply. Emergency systems are intended to supply power and illumination essential for safety to human life. These are usually loads not essential to human safety. Obviously. Some utilities have a demand “ratchet clause” that will continue demand charges on a given peak demand for a full year. and utilities bill on the basis not only of power consumed. and even of partial utility company financing. These standby generating systems are critical when needed. The cost of electric energy has risen to new high levels in recent years. modern control systems (computers or programmable controllers) can monitor the peak demand. 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. They represent a large capital investment. they should be tested periodically under load.E . In the past. Some utilities have been able to delay large capital expenditures for additional generating capacity by such arrangements. Frequently. many costly and unfortunate experiences during utility blackouts in recent years have led to the more frequent installation of engine generators in commercial and institutional systems for safety and for supplying important loads. In some cases. coming on at a peak time. One large load. usually have some form of alternate power source to prevent extremely costly shutdowns. especially in process industries. For those installations with engine generators for emergency use. Industrial plants.T. utilities with little reserve capacity have helped finance the cost of some larger customer-owned generating equipment. the customer’s generator is paralleled with the utility to help supply the peak utility loads. More complex schemes operate the generator in parallel with the normal utility supply. As a result.71. reducing the peak demand can result in considerable savings in the cost of electrical energy. In some instances. The simplest of these schemes transfer specific loads to the generator. but not common in office buildings or shopping centers. 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. 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. but they are needed only infrequently. they were required for hospitals and similar locations. substantial savings in power costs can be realized for a small additional outlay in distribution and control equipment.01. However.A-54 Power Distribution System Design Peak Shaving Cutler-Hammer January 1999 Peak Shaving A Many installations now have emergency or standby generators. 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. CAT. The engine-generator must be selected to withstand the required duty cycle. In return. with the utility buying the supplied power. unless a higher peak results in even higher charges. can create higher electric demand charges for a year. but also on the basis of peak demand over a small interval. The savings in demand charges can reduce the cost of owning the emergency generator equipment. To be sure that their power will be available when required. and start the engine-generator to supply part of the demand as it approaches a preset peak value. with no transients superimposed. power distribution. Power enhancement takes the incoming power. and the grid itself bonded to the ground bus by a single short connection. harmonic filters. telephone or other communications systems. The power center consists of a shielded isolating transformer. and a constant-voltage transformer or voltage regulator may be used to eliminate voltage variations. and absolutely unnecessary.” and the like. Such “clean” power is not consistently available from utility sources. It can also be made of thin copper foil. The ground bus in a computer power center is excellent for this purpose. Since it is an equipment unit. familiar with the electronic needs of their equipment but not with power systems. communications systems. It combines power enhancement.71. either singly or as a damped oscillation. rapid rise (or dip) in voltage. isolating transformers (best with a Faraday shield). have recommended computer grounding schemes that separate the computer grounding system from the power grounding system. Power synthesis can be provided by a wide variety of rotating motorgenerator (MG) sets. Frequency deviations from 60 Hz are rarely a problem from the power company. so for most critical operations the UPS is further supplied by a standby generator. Least frequent. or “crashes. This is unsafe. making the frequent rearrangement or relocation of computer rooms easier and less costly. where outages cannot be tolerated. A single spike can be as brief as a few microseconds. Both MG sets and rectifier-inverters can be connected to a battery. Also very common are undervoltages. Typical battery time ranges from 5 minutes to 1 hour. and not interconnected with many grounds that form ground loops. This generated or synthesized output power is designed to meet computer requirements. not part of the permanently installed premises wiring system. 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. and minimizing noise input to the computers through the grounding systems. or blackouts. the grounded conductor (neutral) is connected to the grounding electrode. and must continue without interruption even if the normal power source fails. which is the most costly class of power conditioner. buried counterpoises. Transients can reach a peak several times the system voltage. The computer power center is an increasingly popular method of supplying power to computers. Battery supplies are costly. they must also be bonded to the power system grounding electrode. if they are present. This comprises the so-called uninterruptible power supply (UPS). and utility power is further degraded by disturbances from the building power distribution system. back to a common equipotential ground point at the power source to the computers. on loss of normal power. and supplies power to the generator or inverted. most noise is of much higher frequencies. only some form of static or rotary UPS can be used. regulating the voltage. cable TV. and similar schemes. and even sudden computer shutdowns. if they are bolted to the pedestals to form good electrical connections. such as used by banks. with connections brazed or welded at the intersections. It is possible to ground computer systems with maximum safety. and other familiar uses in commercial or industrial buildings. The computer units should be individually grounded to this point with radial connections. This supplies a distribution panelboard with circuits feeding flexible computer connection cables under the raised computer-room floor. up to about 30 MHz. with no sacrifice in safety. the cost of computer errors and interruptions. Then the improved power is delivered to the computer. Power synthesis uses the incoming power only as a source of energy. In general.E .T. with no interruption apparent to the computers. a violation of the National Electrical Code. the sensitivity of the computer installation. but provides less isolation and protection for the computers. are usually supplied from a UPS system. it can be depreciated rapidly (in 5 to 8 years). they must all be bonded to the power system grounding electrodes to make one grounding electrode system. The type and degree of conditioning depends on the types of power disturbances present. There are several categories of power disturbances.01. isolating power line “noise. In addition to the improvement in the quality of power. incorrect computations.Cutler-Hammer January 1999 Power Distribution System Design Computer Power A-55 Computer Power Computers require a source of steady. This will provide 60 Hz grounding for safety. Separate computer grounding electrodes. One of the most common is the transient. Power to the computers is conditioned to make it more satisfactory. In fact. they provide a separate grounding connection for plug-and-cord-connected computer equipment. and the like. Much less common are overvoltages of 10% or more. A CAT. which. The individual computer unit cabinets should be connected to this high-frequency grid by the shortest possible leads. and equipotential computer grounding in one unit. Critical computers. This signal reference grid can best be formed by the raised floor stringers. can in computers cause loss of data. However. are complete power outages. UPS systems are sometimes used to supply computer power centers. rather than keep it out. modifies and improves it by clipping spike peaks. for maximum flexibility. an additional high-frequency grounding system must supplement the 60 Hz system. regardless of the disturbances on the input power. Power that is entirely satisfactory for motors. or a combination of some or all of these. Where “isolated ground” plug-in receptacles are used. Ordinary conductors have a high impedance at noise frequencies. and there connected to the common ground bus. constant-voltage. The isolated grounds for these receptacles should be run with the supply conductors. from which it creates a new. back to the source. oscillatory transients may have a frequency of several hundred to several thousand kilohertz. which can be located right in or adjacent to the computer room. A transient suppressor is often included. Standard equipment grounding for exposed metal must also be provided. and the cost of power improvement equipment. To provide effective noise grounding. At the power source. Each separate unit of computer equipment must be grounded (usually by the equipment grounding conductor in the power cable). the computer power center has some financial advantages. voltage regulators. output errors. For these reasons. which comes on line before the battery supply runs down and keeps the computers operating as long as necessary. such as for a lightning protection system. If power must be of the highest quality. filtering transients and harmonics. reservation systems. placed under the raised floor. and the like. they may be a problem from on-site power generation. It can be moved to a new location like other computer equipment. lasting up to a full cycle. If any other grounding electrodes are present on the premises. power enhancement is less costly than power synthesis. heating. This will produce the radial equipotential grounding system that results in minimum ground-system noise to the computers. The technology to improve raw power falls into two broad categories. which “floats” when normal power is available. it may introduce electrical noise into the computers. may do more harm than good. with 15 to 30 minutes most common. Power enhancement can be provided by transient (spike) suppressors. or ferro-magnetic synthesizers. continues power to the computer while the batteries last. The computer units plug into these cables. on loss of normal power. computer grounding is extremely important. and only there. the building service or the separately derived system (the computer power center or MG set or UPS). and correction can be very time consuming. meeting all NEC requirements. The ground bus should be connected to the neutral at that point. power enhancement and power synthesis. Some computer suppliers.” These computer problems can be extremely costly. static semiconductor rectifier-inverters. a sudden. Computer Grounding Because computers are so sensitive to electrical “noise” input. completely isolated power output waveform to supply to the computer. often with 480-volt input and 208Y/ 120-volt output as required by the computers. constant-frequency power. raw incoming power is seldom used for critical computer installations. but most serious when they occur. for equipotential grounding. This requires conductors in a grid or mesh with sides of each square no more than two feet long. Iighting. E . The reduction in the transmitted vibration is approximately 98%. For example. what sound level in the equipment room and what type of associated acoustical treatment will give the most economical installation overall? A relatively high sound level in the equipment room does not indicate an abnormal condition within the apparatus. This problem begins in the designing stages of the equipment and the building. Transformer Sound Levels Transformers emit a continuous 120 Hertz hum with harmonics when connected to 60 Hertz circuits. blowers and transformers to a minimum. this rule applies only to equipment in large areas equivalent to an out-of-door installation. resulting in a build-up or apparent higher levels. it is important that consideration be given to the reduction of amplitude and to the absorption of energy at this frequency. if the level six feet from a transformer is 50 db. resonant conditions may exist near the equipment which will amplify their normal 120 Hertz hum. connections to an individually-mounted transformer should be in flexible conduit. especially if resonance occurs because of room dimensions or material characteristics. it is necessary to consider how the rooms are to be used and what levels may be objectionable to occupants of the building. added absorption material usually is desirable if there is a “build-up” of sound due to reflections. Table A23: Maximum Average Sound Levels Decibels kVA Liquid-Filled Transformers SelfCooled Rating (OA) 300 500 750 1000 1500 2000 2500 3000 3750 5000 6000 7500 10000 55 56 58 58 60 61 62 63 64 65 66 67 68 ForcedAir Cooled Rating (FA) . Since values given in Table A23 are in general higher than those given in Table A22. Dry-type power transformers are often built with an isolator mounted between the transformer support and case members.A-56 Power Distribution System Design Sound Levels Cutler-Hammer January 1999 Sound Levels Table A22: Typical Sound Levels Radio. Recording and TV Studios Theatres and Music Rooms Hospitals. 67 67 67 67 67 67 67 67 67 68 69 70 Dry-Type Transformers SelfCooled Rating (AA) 58 60 64 64 65 66 68 68 70 71 72 73 ... Area Consideration In determining permissible sound levels within a building. There are a number of different sound vibration isolating materials which may be used with good results. with no nearby reflecting surfaces. Schools and Similar Buildings Insurance underwriters and building owners desire and require that the electrical apparatus be installed for maximum safety and the least interference with the normal use of the property. Some reduction or attenuation takes place through building walls. TV Off) and Small Offices Medium Office (3 to 10 Desks) Residence (Radio. will reduce noise. the level at a distance of twelve feet would be 44 db and at 24 feet the level decreases to 38 db. Therefore. Decrease in sound level varies at an approximate rate of 6 decibels for each doubling of the distance from the source of sound to the listener. The natural period of the core and coil structure when mounted on vibration dampeners is about 10% of the fundamental frequency. However. The fundamental frequency is the “hum” which annoys people primarily because of its continuous nature. (Enclosure covers and ventilating louvers are often improperly tightened or gasketed and produce unnecessary noise. Two transformers of the same sound output in the same room increase the sound level in the room approximately 3 db. However. 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. There are two points worthy of consideration: 1) What sound levels are desired in the normally occupied rooms of this building? 2) To effect this. sound measuring instruments convert the different frequencies to 1000 Hertz and a 40 db level. Even though transformers are relatively quiet. etc. Transformer sound levels based on NEMA publication TR-1 are listed in Table A23. Often.T. Architects should take particular care with the designs for hospitals. etc. placing the transformer at an angle to the wall. and 3 transformers by about 5 db.01. schools and similar buildings to keep the sound perception of such equipment as motors. Furthermore. the isolator must be softer or have improved characteristics in order to keep the transmitted vibrations to a minimum. An observer may believe that a transformer is noisy because the level in the room where it is located is high.) The building structure will assist the dampeners if the transformer is mounted above heavy floor members or if mounted on a heavy floor slab. TV On) Large Store (5 or More Clerks) Factory Office Large Office Average Factory Average Street 25-30 db 30-35 35-40 35-40 35-45 40-45 45-55 53 58 60 61 61 64 70 80 A Sound Levels of Electrical Equipment for Offices. the remainder may be reflected in various directions. Positioning of the transformer in relation to walls and other reflecting surfaces has a great effect on reflected noise and resonances. the difference must be attenuated by distance and by proper use of materials in the design of the building. For purposes of reference. rather than parallel to it. absorption may be necessary if sound originating in an unoccupied equipment room is objectionable outside the room. If the floor or beams beneath the transformer are light and flexible. ForcedAir Cooled Rating (FA) 67 67 67 67 68 69 71 71 73 73 74 75 76 CAT. Sounds due to structure-transmitted vibrations originating from the transformer are lowered by mounting the transformers on vibration dampeners or isolators. Electrical connections to a substation transformer should be made with flexible braid or conductors. Auditoriums and Churches Classrooms and Lecture Rooms Apartments and Hotels Private Offices and Conference Rooms Stores Residence (Radio.71. Hospitals. but not necessarily efficient. usually more rigid. 70. When removable. some adopt it with variations. emergency power systems. (b)This Code contains provisions considered necessary to safety. DC 20037-1526 202-457-8474 National Fire Protection Association 1 Battery March Drive P. although they are not in any way mandatory. 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 under predetermined conditions. Ground Relay A relay that by its design or application is intended to respond primarily to system ground faults. (Note: It may be designed to close and carry abnormal or short-circuit currents as specified).O. Switchboard A type of switchgear assembly that consists of one or more panels with electric devices mounted thereon. and a number of other testing laboratories have been recognized and accepted. protective and regulating devices. (4) instruments. Most jurisdictions adopt the NEC in its entirety. or adequate for good service or expansion of electrical use. The Occupational Safety and Health Act (OSHA) of 1970 sets uniform national requirements for safety in the workplace — anywhere that people are employed. has no legal standing of its own. (c) This Code is not intended as a design specification nor an instruction manual for untrained persons. county. and require equipment to be listed by UL or another recognized testing laboratory wherever possible. Introduction. OSHA was amended to adopt this code. IL 60062 A CAT. long-lasting. Also assemblies of these devices with associated interconnections. which is now federal law. to suit local conditions and requirements. 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.100 Definitions for Power Switchgear Available (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. Inc. accessories. enclosures and supporting structures. 333 Pfingsten Road Northbrook.01. Box 1331 Piscataway. is the most prevalent electrical code in the United States. such as New York and Chicago. the involved process for modifying a federal law such as OSHA made it impossible for the act to adopt each new code revision. As the NEC was amended every three years. until it is adopted as law by a jurisdiction. The NEC. convenient. based on NFPA Standard 70E. Most of these IEEE standards have been adopted as ANSI standards. N. The NEC is a minimum safety standard. They are excellent guides. The lowvoltage power circuit breakers are contained in individual grounded metal compartments and controlled remotely or from the front of the panels. transmission. meters. MA 02269-9959 1-800-344-3555 Underwriters Laboratories. is connected to ground at one or more points. and (5) control wiring and accessory devices. Washington. Professional Organizations American National Standards Institute 1430 Broadway New York. (a) The purpose of this Code is the practical safeguarding of persons and property from hazards arising from the use of electricity. The tops may or may not be covered. Excerpts From ANSI/IEEE C37. (3) instrument and control power transformers. Part 1.Cutler-Hammer January 1999 Power Distribution System Design Codes and Standards A-57 Codes and Standards The National Electrical Code (NEC). Direct-Current Component (of a Total Current) That portion of the total current which constitutes the asymmetry. The circuit breakers may be stationary or removable. and associated framework. Box 9101 Quincy. NFPA Standard No.O. A design engineer should conform to all applicable codes. (2) bare bus and connections. Enclosed Switchboard A dead-front switchboard that has an overall sheet metal enclosure (not grille) covering back and ends of the entire assembly.71. used primarily in connection with the generation. or state. Compliance therewith and proper maintenance will result in an installation essentially free from hazard.T. The NEC. IL 60068-2398 708-696-1455 National Electrical Manufacturers Association 2101 L Street. New York 10018 212-642-4900 Institute of Electrical and Electronics Engineers 445 Hoes Lane P. Underwriters Laboratory (UL) has standards that equipment must meet before UL will list or label it. Molded-Case Circuit Breaker One that is assembled as an integral unit in a supporting and enclosing housing of molded insulating material. which is revised every three years. 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 unfused). NJ 08855-9970 201-562-5522 International Association of Electrical Inspectors 930 Busse Highway Park Ridge. reads: 90-1. Most jurisdictions and OSHA require that where equipment listed as safe by a recognized laboratory is available. metering. The design goal should be a safe. distribution and conversion of electric power. efficient. Originally OSHA adopted the 1971 NEC as rules for electrical safety. commercial buildings.E . mechanical interlocks are provided to ensure a proper. Efficient and adequate design usually requires not just meeting. The designer must determine which code applies in the area of a specific project. Many equipment standards have been established by the National Electrical Manufacturers Association (NEMA) and the American National Standards Institute (ANSI). which may be a city. safe operating sequence. 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. Interrupting (Breaking) Current The current in a pole of a switching device at the instant of initiation of the arc. although Factory Mutual Insurance Company lists some equipment. and to meet ANSI or NEMA standards. (Note: Access to the enclosure is usually provided by doors or removable covers. To avoid this problem. in turn. the OSHA administration in 1981 adopted its own code. and economical electrical distribution system. grounding.) Ground Bus A bus to which the grounds from individual pieces of equipment are connected and that. and the like. but often exceeding NEC requirements to provide an effective. UL is by far the most widely accepted national laboratory. unlisted equipment may not be used. economical electrical system. Zone of Protection The part of an installation guarded by a certain protection. standards should be exceeded to get a system of the quality required. flexible. have their own electrical codes. A few large cities. basically similar to the NEC. reliable. Ground Protection A method of protection in which faults to ground within the protected equipment are detected. Switchgear A general term covering switching and interrupting devices and their combination with associated control. In many cases. ANSI/IEEE recommended practices should be followed to a great extent. Article 90.W. a condensed version of the NEC containing only those provisions considered related to occupational safety. Load-Interrupter Switch An interrupter switch designed to interrupt currents not in excess of the continuouscurrent rating of the switch. and relays. T.2 22 28 42 54 68 80 104 130 154 192 248 312 360 480 12 12 12 12 12 10 8 6 4 4 3 1 2/0 3/0 250 350 (2)3/0 (2)4/0 (2)350 20 20 20 20 20 30 50 65 85 85 100 130 175 200 255 310 400 460 620 1⁄2 1⁄2 12 1⁄2 1⁄2 12 ⁄ ⁄ 1⁄2 1⁄2 12 1⁄2 1⁄2 12 ⁄ ⁄ 3⁄4 1⁄2 3⁄4 1 1 1 11⁄4 11⁄4 11⁄2 2 21⁄2 21⁄2 (2)2 (2)2 (2)21⁄2 1 1 1 11⁄4 11⁄2 11⁄2 2 21⁄2 (2)11⁄2 (2)2 (2)21⁄2 10 10 15 20 30 40 50 80 100 125 150 200 250 300 350 450 600 700 1000 15 20 25 30 50 70 90 150 175 225 250 350 400 500 600 800 1000 1200 1600 15 15 15 20 30 50 60 90 100 125 150 150 200 225 300 400 500 600 700 ED ED ED ED ED ED ED ED ED ED ED ED ED ED KD KD LD LD MD 7 7 15 15 30 30 50 70 100 100 150 150 150 250 400 600 600 — — 21-70 21-70 45-150 45-150 90-300 90-300 150-500 210-700 300-1000 300-1000 450-1500 450-1500 750-2500 1250-2500 2000-4000 1800-6000 1800-6000 — — 460 Volts. Higher interrupting rating types may be required to satisfy specific system application requirements. Motor accelerating time – 10 seconds or less. 2. Single-Phase 3⁄4 1 12 1⁄ 2 3 5 71⁄2 13. Type HMCP motor circuit protector may not be set at more than 1300% of the motor full-load current.8 2. Motors built special for low speeds. Conduits with internal equipment grounding conductors or conductors with different insulation will require further considerations. 5.9 8 10 12 17 28 40 12 12 12 12 10 8 8 20 20 20 20 30 50 50 12 ⁄ 12 ⁄ ⁄ 1⁄2 1⁄2 12 1⁄2 1⁄2 12 1⁄2 1⁄2 12 ⁄ ⁄ 1⁄2 1⁄2 34 ⁄ 15 15 20 25 30 50 70 25 25 30 40 60 90 125 15 20 25 30 40 60 80 ED ED ED ED ED ED ED Two-Pole Device Not Available Œ These recommendations are based on previous code interpretations.1 2. 3-Phase 1 11⁄2 2 3 5 71⁄2 10 15 20 25 30 40 50 60 75 100 125 150 200 1. In’s.6 3. (Except for new E rated motor which can be set up to 1700%. See the current NEC for exact up-to-date information.) Circuit breaker selections are based on types with standard interrupting ratings.A-58 Power Distribution System Design Reference Data – Motor Protection Cutler-Hammer January 1999 A Motor ProtectionŒ In line with NEC 430-6(a). Ensure that the fault duty does not exceed breakers I.8 9. increase the corresponding 230-volt motor values by 10 and 15 percent respectively. stopping or reversing. Amps Time Delay NonTime Delay Recommended Cutler-Hammer CircuitŽ Breaker Amps Type Motor Circuit Protector Type GMCP/HMCP Amps Adj. Single-Phase 34 ⁄ 1 11⁄2 2 3 5 71⁄2 6. high torque characteristics.01.4 4. circuit breaker. Ambient – Outside enclosure not more than 40°C (104°F).2 6. 3-Phase 1 11⁄2 2 3 5 71⁄2 10 15 20 25 30 40 50 60 75 100 125 150 200 3.71. to comply with the NEC. 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 (singlephase) and 430-150 (3-phase). THW THWN XHHN Fuse Size NEC 430-152 Max. Circuit breaker. CAT. For motor full load currents of 208 and 200 volts. special starting conditions and applications will require other considerations as defined in the application section of the NEC. Induction Motors Hp Full Load Amps (NEC) FLA Minimum Wire Size 75°C Copper Ampacity @125% FLA Size Amps Minimum Conduit Size.C.8 7. Cutler-Hammer type circuit breakers rated less than 125 amperes are marked for application with 60/75°C wire. Based on known characteristics of Cutler-Hammer type breakers. Motors with lower code letters will require further considerations.1 9 11 17 22 27 32 41 52 62 77 99 125 144 192 12 12 12 12 12 12 12 12 10 8 8 6 6 4 3 1 2/0 3/0 250 20 20 20 20 20 20 20 20 30 50 50 65 65 85 100 130 175 200 255 1⁄2 1⁄2 1 ⁄2 1⁄2 1⁄2 12 ⁄ 1⁄ 2 1⁄2 12 ⁄ 1⁄2 1⁄ 2 34 ⁄ 1 1 1 11⁄4 11⁄4 11⁄2 2 21⁄2 1 ⁄2 1⁄2 1⁄2 12 ⁄ ⁄ 1⁄ 2 1⁄2 12 1⁄2 1⁄ 2 12 ⁄ 3⁄4 3⁄4 1 1 11⁄4 11⁄2 11⁄2 2 3 6 6 10 15 20 20 30 40 50 60 80 100 110 150 175 225 300 350 6 10 10 15 20 30 35 60 70 90 100 125 175 200 250 300 400 450 600 15 15 15 15 15 20 25 40 50 60 60 80 100 125 150 175 200 225 300 HFD HFD HFD HFD HFD HFD HFD HFD HFD HFD HFD HFD HFD HFD HFD HJD HJD HJD HKD 3 3 7 7 15 15 15 30 50 50 50 70 100 100 150 150 250 250 400 9-30 9-30 21-70 21-70 45-150 45-150 45-150 90-300 150-500 150-500 150-500 210-700 300-1000 300-1000 450-1500 450-1500 875-1750 1250-2500 2000-4000 115 Volts.6 5. Ž Types are for minimum interrupting capacity breakers. In general. Wire and conduit sizes as well as equipment ratings will vary accordingly. Actual motor nameplate ratings shall be used for selecting motor running overload protection.7 3.6 15. The current ratings are no more than the maximum limits set by the NEC rules for motors with code letters F to V or without code letters.4 2. 4. Range 230 Volts. 430-52.E .6 11 14 21 27 34 40 52 65 77 96 124 156 180 240 12 12 12 12 12 12 12 10 8 8 8 6 4 3 1 2/0 3/0 4/0 350 20 20 20 20 20 20 20 30 50 50 50 65 85 100 130 175 200 230 310 12 ⁄ 1⁄2 1⁄2 1 12 ⁄ 1⁄2 1⁄2 1 ⁄2 1⁄2 1⁄2 12 ⁄2 1⁄2 1⁄2 12 ⁄ ⁄ 1⁄ 2 1⁄ 3⁄4 34 34 2 1⁄2 12 12 3⁄ 4 ⁄ ⁄ ⁄ ⁄ 1 1 11⁄4 11⁄4 11⁄2 2 2 21⁄2 1 1 11⁄4 11⁄2 11⁄2 2 21⁄2 6 6 6 10 15 20 25 40 50 60 70 100 125 150 175 225 300 350 450 6 10 15 15 25 35 45 70 90 110 125 175 200 250 300 400 500 600 800 15 15 15 15 15 25 35 45 50 70 70 100 110 125 150 175 225 250 350 EHD EHD EHD EHD EHD EHD EHD EHD EHD EHD EHD EHD FDB FDB JD JD JD JD KD 3 7 7 7 15 15 30 30 50 50 70 100 100 150 150 150 250 250 400 9-30 21-70 21-70 21-70 45-150 45-150 90-300 90-300 150-500 150-500 210-700 300-1000 300-1000 450-1500 450-1500 750-2500 1250-2500 1250-2500 2000-4000 575 Volts. specific units are recommended. these selections were based on: 1.  Consult fuse manufacturer’s catalog for smaller fuse ratings. Wire size selections shown are minimum sizes based on the use of 75°C copper wire per NEC table 310-16. Table A24: 60 Hz.8 16 20 24 34 56 80 12 12 10 10 8 4 3 20 20 30 30 50 85 100 1⁄2 1⁄2 12 1⁄2 1⁄2 12 ⁄ 1⁄2 3⁄4 1 1 1 ⁄ 1⁄2 1⁄2 34 ⁄ 25 30 35 45 60 100 150 45 50 60 80 110 175 250 30 35 40 50 70 100 150 ED ED ED ED ED ED ED Two-Pole Device Not Available 230 Volts. Motor starting – Infrequent starting. Sec. 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.9 6. HMCP and fuse ampere rating selections are in line with maximum rules given in NEC 430-52 and table 430-152. 3-Phase 1 11⁄2 2 3 5 71⁄2 10 15 20 25 30 40 50 60 75 100 125 150 200 1. 3. Locked rotor – Maximum 6 times motor FLA. For other percentages. 50% motor load is assumed while for other voltages 100% motor load is assumed. Amps 834 Short-Circuit Current RMS Symmetrical Amps Transformer Alone 50% Motor Load Combined 240 Volts.75% 3008 12000 2405 9600 Œ Short-circuit capacity values shown correspond to kVA and impedances shown in this table. short-circuit currents are inversely proportional to impedance. CAT. the motor short-circuit current will be in direct proportion. For impedances other than these. 3-Phase Rated Load Continuous Current.  The motor’s short-circuit current contributions are computed on the basis of motor characteristics that will give four times normal current. For 208 volts.01. 3-Phase Rated Load Continuous Current. Amps 289 Short-Circuit Current RMS Symmetrical Amps Transformer Alone 100% Motor Load Combined A Œ 14900 15700 16000 16300 16500 16700 21300 25200 26000 26700 27200 27800 28700 32000 33300 34400 35200 36200 35900 41200 43300 45200 46700 48300 47600 57500 61800 65600 68800 72500  1700 16600 17400 17700 18000 18200 18400 25900 28000 28800 29500 30000 30600 32900 36200 37500 38600 39400 40400 41500 46800 48900 50800 52300 53900 55900 65800 70100 73900 77100 80800 Œ 12900 13600 13900 14100 14300 14400 20000 21900 22500 23100 23600 24100 24900 27800 28900 29800 30600 31400 31000 35600 37500 39100 40400 41800 41200 49800 53500 56800 59600 62800  2900 15800 16500 16800 17000 17200 17300 24800 26700 27300 27900 28400 28900 32100 35000 36100 37000 37800 38600 40600 45200 47100 48700 50000 51400 55600 64200 57900 71200 74000 77200 Œ 6400 6800 6900 7000 7100 7200 10000 10900 11300 11600 11800 12000 12400 13900 14400 14900 15300 15700 15500 17800 18700 19600 20200 20900 20600 24900 26700 28400 29800 31400 24700 31000 34000 36700 39100 41800 28000 36500 40500 44600 48100 52300  1400 7800 8200 8300 8400 8500 8600 12400 13300 13700 14000 14200 14400 16000 17500 18000 18500 18900 19300 20300 22600 23500 24400 25000 25700 27800 32100 33900 35600 37000 38600 34300 40600 43600 46300 48700 51400 40000 48500 52500 56600 60100 64300 Œ 5200 5500 5600 5600 5700 5800 8000 8700 9000 9300 9400 9600 10000 11100 11600 11900 12200 12600 12400 14300 15000 15600 16200 16700 16500 20000 21400 22700 23900 25100 19700 24800 27200 29400 31300 33500 22400 29200 32400 35600 38500 41800  1200 6400 6700 6800 6800 6900 7000 9900 10600 10900 11200 11300 11500 12900 14000 14500 14800 15100 15500 16300 18200 18900 19500 20100 20600 22300 25800 27200 28500 29700 30900 27500 32600 35000 37200 39100 41300 32000 38800 42000 45200 48100 51400 500 5% 1388 2800 1203 4800 601 2400 481 1900 750 5.75% 4164 8300 3609 14400 1804 7200 1444 5800 2000 5. 3-Phase Rated Load Continuous Current.71.E . 3-Phase Rated Load Continuous Current.T.Cutler-Hammer January 1999 Power Distribution System Design Reference Data – Secondary.75% 2406 9600 1924 7800 2500 5. Amps 361 Short-Circuit Current RMS Symmetrical Amps Transformer Alone 100% Motor Load Combined 600 Volts.75% 2776 5600 2406 9600 1203 4800 962 3900 1500 5. Short Circuit Capacity of Typical Power Transformers A-59 Table A25: Secondary Short Circuit Capacity of Typical Power Transformers TransFormer Rating 3-Phase kVA and Impedance Percent 300 5% Maximum Short Circuit kVA Available From Primary System 50000 100000 150000 250000 500000 Unlimited 50000 100000 150000 250000 500000 Unlimited 50000 100000 150000 250000 500000 Unlimited 50000 100000 150000 250000 500000 Unlimited 50000 100000 150000 250000 500000 Unlimited 50000 100000 150000 250000 500000 Unlimited 50000 100000 150000 250000 500000 Unlimited 208 Volts.75% 2080 4200 1804 7200 902 3600 722 2900 1000 5. Amps 722 Short-Circuit Current RMS Symmetrical Amps Transformer Alone 100% Motor Load Combined 480 Volts. 000 3.4 63.35 1..1 72.00 5.01 9.87 4.6 116 139 174 231 347 463 13.90 2.3 72.92 2.64 5.7 65.93 1.804 2. . CAT.400 0.00 5. .93 0..2 120 180 241 361 481 601 722 902 1.30 6.164 .500 2.11 3.6 94.11 2.26 1.90 5......81 1.30 3.800 1.000 1... .25 1.4 13...75 2.84 6.40 3.21 5.10 2.10 6.20 5.0 50.33 1.78 5.38 6.1 40.49 1.13 1..00 0.7 105 126 157 209 314 418 22.5 150 225 300 500 750 1000 1500 2000 2500 3000 3750 5000 Liquid-Filled Network .1 48.35 6.20 6.0 75..00 7.60 3.11 2.2 120 160 200 241 301 401 601 802 12.1 21.21 6.44 2.46 X/R 0...41 X/R 0.. 5.75 5.203 1.44 5..06 5.56 4..90 3..14 7..93 Table A29: 15 kV Class Primary – Dry-Type Substation Transformers 150°C Rise kVA 300 500 750 1000 1500 2000 2500 80°C Rise 300 500 750 1000 1500 2000 2500 4. .47 5.67 5.81 3.811 .4 62.9 25..925 2.56 3..56 9..5 150 225 300 500 750 80°C Rise kVA 15 30 45 75 112.30 5..93 1...75 6.53 2.60 3.54 2.71 6.31 1.500 10.70 3.07 3.406 2.45 0. .52 2.007 3.75 5.28 0.10 %R 3.776 4.50 4.15 Œ Values are typical.66 0..87 2.41 2.10 5.50 1.59 3.46 4. Note: K factor rated distribution dry type transformers may have significantly lower impedances. .608 4..01.30 4.47 2.66 0.75 5.90 6.6 20.51 3.10 6.00 5.75 5. .94 10.81 1.00 7. .511 .84 13.49 1..39 12..17 6.2 33. . .6 20.00 5.75 5.000 1.76 1.71.03 3.2 135 180 271 361 601 902 1.406 3.400 7.6 69.42 1.887 3. .8 83..2 2.4 3.5 109 131 164 219 328 437 13.63 4..75 %R 2..406 4.20 6.T.40 1.10 3.89 2.50 6.28 4.59 5.388 2.66 2.16 6..67 0.47 3. .75 5.8 62.75 5.00 5. .29 1.3 69.73 5...200 2.36 1.30 6.50 %R 2.47 5.83 2.02 12.804 2.203 1.57 5.0 24.61 5.93 1.9 31.78 1.57 0..4 104 139 208 278 347 416 520 694 1.00 5.87 1..48 X/R 1.78 5.53 2.. Self-cooled Ratings A Voltage.07 3.16 1.19 5...87 5..1 72.22 %Z 4.92 3.04 6.75 5.30 3.1 36.75 1.22 10.00 7.5 45 50 75 112..8 50..6 87. ...470 1.26 1.500 3.406 3.44 1.4 4.50 5.50 %R 6..88 3...50 4.04 8.75 5.75 5..72 2.70 4.67 5. .00 1.28 1.6 16..75 1.91 4.71 1.63 1..00 2.00 .57 5.9 43.41 1.41 3.50 5.388 7.98 %Z 7.47 2.75 5.5 150 225 300 500 750 1000 1500 2000 2500 %Z 5.68 5...15 1..33 5. 600 28. .0 27.8 43..52 3.160 4. 240 72.42 5.64 1.36 0.84 1.60 4.750 5.200 1.93 3.75 5.50 Table A28: 15 kV Class Primary – Oil LiquidFilled Substation Transformers 65°C Rise kVA 112.28 9..4 92.2 120 144 180 241 361 481 12.1 90.00 5. Three-Phase..1 60.1 54.9 83..1 80.94 4.00 5.443 1.27 1.6 18.50 6.5 150 225 300 500 %Z 2.51 3.93 0.1 36. Line-to-Line kVA 30 45 75 1121/2 150 225 300 500 750 1.75 5.18 3.. .90 2. 480 36.14 4.84 3.2 96.46 1.13 1.08 3.29 3..39 2. Padmount ..E .47 2.02 1..76 3.01 0.67 3.608 4. 2.8 18..3 125 208 312 416 625 833 1.33 3.08 %X 4.30 2. refer to transformer manufacturer.A-60 Power Distribution System Design Reference Data – Transformer Full Load Amperes and Impedances Cutler-Hammer January 1999 Table A26: Transformer Full-load Current.41 7.70 1.00 %X 3.8 25.08 5.75 %R 1. For guaranteed values...30 4.98 X/R 1.88 1...65 4.09 6.8 31.10 5.83 4.67 4..50 6. .203 1.804 2...92 6.75 5.. .6 5.4 41..52 2.75 5.69 1.56 12.20 4.71 5.609 4.67 7.41 12.000 2.082 2..72 10.000 208 83.21 1.22 10..07 2.1 54.19 3..97 3.17 3.7 46.10 5.9 23.4 15...57 3.52 3.8 14.3 3.041 1..31 3....61 6.13 1.42 5.62 %X 1.75 5.61 5.14 4.900 0..0 18.51 8.77 5.50 6.25 10.10 5.44 2.00 5.2 108 180 271 361 541 722 1.9 126 168 Approximate Impedance Data Table A27: Typical Impedances – Three-Phase Transformers kVA 37..37 5.12 0.68 5.40 7. .4 24.2 41.86 %X 4.14 1.50 0.811 .40 0..74 %X 3.4 3. .71 2.89 3.80 6.42 4.60 6.70 4..000 7.5 126 189 252 34.2 37.78 2.89 2..1 34.75 5. .61 Table A30: 600-Volt Primary Class Dry-Type Distribution Transformers 150°C Rise kVA 3 6 9 15 30 45 75 112.69 X/R 2..00 3.19 %Z 5..81 4. .9 32.52 1.70 4.20 7.87 0..75 5.2 108 144 217 289 481 722 962 1.5 150 225 300 500 750 1000 115°C Rise kVA 15 30 45 75 112.6 42. . 3.63 4....96 4. 5 150 225 300 500 750 1000 1500 2000 2500 No Load Watts Loss 550 545 650 950 1200 1600 1800 3000 4000 4500 Full Load Watts Loss 2470 3360 4800 5000 8700 12160 15100 19800 22600 26000 Table A33: 600-Volt Primary Class Dry-Type Distribution Transformers 150°C Rise kVA 3 6 9 15 30 45 75 112.T.E .5 150 225 300 500 No Load Watts Loss 200 300 300 400 600 700 800 1300 2200 Full Load Watts Loss 500 975 1100 1950 3400 3250 4000 4300 5300 No Load Watts Loss 150 200 300 400 500 600 700 800 1700 1500 Full Load Watts Loss 700 1500 1700 2300 3100 5900 6000 6600 6800 9000 No Load Watts Loss 33 58 77 150 200 300 400 500 600 700 800 1700 2200 2800 Full Load Watts Loss 231 255 252 875 1600 1900 3000 4900 6700 8600 10200 9000 11700 13600 A Table A32: 15 kV Class Primary – Dry-Type Substation Transformers 150°C Rise kVA 300 500 750 1000 1500 2000 2500 80°C Rise 300 500 750 1000 1500 2000 2500 1800 2300 3400 4200 5900 6900 7200 7600 9500 13000 13500 19000 20000 21200 No Load Watts Loss 1600 1900 2700 3400 4500 5700 7300 Full Load Watts Loss 10200 15200 21200 25000 32600 44200 50800 Note: 1 watt hour = 3.5 150 225 300 500 750 80°C Rise kVA 15 30 45 75 112.Cutler-Hammer January 1999 Power Distribution System Design Reference Data – Transformer Losses A-61 Approximate Transformer Loss Data Table A31: 15 kV Class Primary – Oil LiquidFilled Substation Transformers 65°C Rise kVA 112.5 150 225 300 500 750 1000 115°C Rise kVA 15 30 45 75 112.71.01.413 Btu CAT. 480 volts) Equipment 225 Ampere.01. 480 volts) Equipment 800 Ampere 1200 Ampere 1350 Ampere 1600 Ampere 2000 Ampere 2500 Ampere 3200 Ampere 4000 Ampere 5000 Ampere Watts Loss 44 per foot 60 per foot 66 per foot 72 per foot 91 per foot 103 per foot 144 per foot 182 per foot 203 per foot Table A35: Medium Voltage Switchgear (Indoor.A-62 Power Distribution System Design Reference Data – Power Equipment Losses Cutler-Hammer January 1999 Power Equipment Losses Table A39: Panelboards (Indoor. 480 volts) Equipment NEMA Size 1 Starter NEMA Size 2 Starter NEMA Size 3 Starter NEMA Size 4 Starter NEMA Size 5 Starter Structures Watts Loss 39 56 92 124 244 200 CAT. Copper. 5 kV) Equipment 400 Ampere Starter FVNR 800 Ampere Starter FVNR 600 Ampere Fused Switch 1200 Ampere Fused Switch Watts Loss 600 1000 500 800 Table A37: Low Voltage Switchgear (Indoor. 5 and 15 kV) Equipment 600 Ampere Unfused Switch 1200 Ampere Unfused Switch 100 Ampere CL Fuses Watts Loss 500 750 840 Table A36: Medium Voltage Starters (Indoor.71. 480 volts) Equipment 800 Ampere Breaker 1600 Ampere Breaker 2000 Ampere Breaker 3200 Ampere Breaker 4000 Ampere Breaker 5000 Ampere Breaker Fuse Limiters – 800 A CB Fuse Limiters – 1600 A CB Fuse Limiters – 2000 A CB Fuse Truck – 3200 A CB Fuse Truck – 4000 A CB Structures – 3200 Ampere Structures – 4000 Ampere Structures – 5000 Ampere High Resistance Grounding Watts Loss 400 1000 1500 2400 3000 4700 200 500 750 3600 4500 4000 5000 7000 1200 Table A38: Motor Control Centers (Indoor. 42 Circuit Watts Loss 300 A Table A34: Medium Voltage Switchgear (Indoor. 5 and 15 kV) Equipment 1200 Ampere Breaker 2000 Ampere Breaker 3000 Ampere Breaker Watts Loss 600 1400 2000 Table A40: Low Voltage Busway (Indoor.E .T. Type 1 may not provide protection against small particles of falling dirt when ventilation is provided in the enclosure top..359 1... Vapors and Dusts for Electrical Equipment in Hazardous (Classified) Locations) Acetylene Hydrogen. X X ...... ... 6P X X X X X X . .... . cyclopropane Gasoline.71.. ... or dust.. . .. Ž External operating mechanisms are not required to be operable when the enclosure is ice covered.000 3.. 12K X X X X X .. ..... Type of Enclosure 9. .. 4X X X X X X X .. X . Inches Minimum 0... and flyings Settling airborne dust. X . .  These fibers and flying are nonhazardous materials and are not considered the Class III type ignitable fibers or combustible flyings. . ... . F ..... ....... . . 6P X X . fibers. .. propane.. .... . G .719 6...... X X . X ... ... X . X X .625 4... isoprene Metal dust Carbon black.. and flyings Hosedown and splashing water Oil and coolant seepage Oil or coolant spraying and splashing Corrosive agents Occasional temporary submersion Occasional prolonged submersion Type of Enclosures 1Œ X X ... ..... X X .. . fibers.. For Class III type ignitable fibers or combustible flyings see the National Electrical Code. . 4X X X ..406 1..625 6... . ..700 Nominal 0..... Class II Groups‘ E . . ........109 1.....750 6. . ’ Due to the characteristics of the gas...... X X X 12 X X X X X ..844 2 21/2 3 31/2 4 5 6 Œ These enclosures may be ventilated. D ... ........ See NFPA 497M-1986.E . X .. .. 4 X X X X X X .. .. lint... X ... ..156 4. Article 500.766 2.. .6) (If the installation is outdoors and/or additional protection is required by Tables A41 and A42..T..875 1. hexane.719 1. 2Œ X X X ..984 2... butane.  External operating mechanisms are operable when the enclosure is ice covered... coke dust Flour.. . .. ...... ...125 4.. .... . ... . Class I Groups‘ Class I I I I II II II III MSHA A X . coal dust..... X ... .. ... ..... 13 X X X X X . and sleet Sleet Windblown dust Hosedown Corrosive agents Occasional temporary submersion Occasional prolonged submersion Type of Enclosures 3 X X . .. B .. . .. .813 Maximum 0... Provides a Degree of Protection Against Atmospheres Typically Containing (For Complete Listing. . a product suitable for one Class or Group may not be suitable for another Class or Group unless so marked on the product. .... .. X X X . X ..375 1. .. X ..859 1.. . . . acetone.. .. . 5 X X X .... .. grain dust Fibers... .. .063 4.01. A Table A42: Comparison of Specific Applications of Enclosures for Outdoor Nonhazardous Locations Provides a Degree of Protection Against the Following Environmental Conditions Incidental contact with the enclosed equipment Rain.. 3RŽ X X .. X .. . Classification of Gases. .. .. 6 X X . .469 2.958 2.. Table A41: Comparison of Specific Applications of Enclosures for Indoor Nonhazardous Locations Provides a Degree of Protection Against the Following Environmental Conditions Incidental contact with the enclosed equipment Falling dirt Falling liquids and light splashing Circulating dust. .. ...  These enclosures may be ventilated. .. ... ... Consult the manufacturer. ..641 5. vapor... .. 3S X X X X . ... ‘ For Class III type ignitable fibers or combustible flyings see the National Electrical Code. ..016 2.. ... X . ... .. toluene.672 5. ... .. .... ..433 2... X Table A44: Knockout Dimensions Conduit Trade Size.. snow.......906 1..500 3.........563 5. X X X X X Table A43: Comparison of Specific Applications of Enclosures for Indoor Hazardous Locations (See Paragraph 3.594 4. . . Article 500.. . 4 X X ........ ..... .094 1.938 3.. .734 1. ....969 3. .. . . a combination-type enclosure is required.. . ... C ..... .... 6 X X X X X X .... ......Cutler-Hammer January 1999 Power Distribution System Design Reference Data – Enclosures A-63 Enclosures The following are reproduced from NEMA 250-1991.... starch. manufactured gas Diethel ether... .... naphtha... 10 . CAT......... . .... . lint.. Inches 1/2 3/4 1 11/4 11/2 Knockout Diameter. .... However....141 1.. . flyings’ Methane with or without coal dust Type of Enclosure 7 and 8. X .. .563 4. ethylene. 3130 .01340 .00484 .01.00309 .00364 .00487 .00408 .00578 .0210 .00632 .00810 .00480 .00346 .00346 .00250 X – – – – .00350 .00843 .00227 . Reactance.00330 .00414 Nonmagnetic Conduit R – – – – .00330 .00980 .00457 .01414 .00803 .00335 .00696 .00467 .00713 .00328 .00412 .00265 .00470 .A-64 Power Distribution System Design Reference Data – Conductor Resistance.0321 .00272 .00610 .00926 . Average Characteristics of 600-Volt Conductors (Ohms per 100 Feet) Table A45: Two or Three Single Conductors Wire Size.00366 .0530 .00303 .00936 .00409 .00326 . wire stranding.00899 .0267 .00512 .00539 .00350 Table A46: Three-conductor Cables (and Interlocked Armored Cable) Wire Size.00898 .0170 .00633 .00713 .0493 .00591 .00323 .00264 Z – – – – .00763 .00280 .0212 .00705 .0167 .0490 .00293 .00317 . 3-phase.3130 .00312 .00288 .00261 .0318 .0530 .0338 .0321 .00420 .00440 .00501 .00509 . AWG or kcmil 14 12 10 8 6 4 2 1 1/0 2/0 3/0 4/0 250 300 350 400 450 500 600 700 750 1000 Copper Conductors Magnetic Conduit R .00241 .0170 .00694 . jacketing.00485 .0337 .00300 .0129 .0789 .00300 .01380 .01414 .00525 .00426 .00584 .00503 .00933 .00666 .00381 .00473 .00395 .00318 .00325 .0494 .00288 .0267 .00548 .00602 .0490 .0530 .00410 .1230 .00330 Z – – – – . Impedance ‘ Cutler-Hammer January 1999 A The tables below are average characteristics based on data from several manufacturers of copper and aluminum conductors and cable.00546 .00350 .00370 .0129 .0143 .00355 .00548 .0208 .1231 .00294 – Z .00277 .00536 .00360 .00396 .00803 .00374 .0104 .3130 .1969 .00548 .0834 .00441 – Z .00791 .0130 .00386 .0792 . random lay of multiple conductors in conduit.0833 .00272 .00694 .0789 .00284 .00414 Nonmagnetic Conduit R – – – – .00391 . Reactance values will have negligible variation with temperature.00851 .3130 .00354 – Aluminum Conductors Magnetic Conduit R – – – – .0492 .0215 .1230 .00458 .0212 .0175 .00427 .0532 .0170 .00529 .00691 .0173 .00533 .00558 .00360 .00696 .00536 .T.00605 . see section H2 of this catalog.00250 X – – – – .00381 .00782 . Ž Based on conductor temperatures of 75°C.00297 .00278 .00298 .00330 .01097 .00328 .00730 .01380 .00384 .00410 .00356 .0490 .00369 .00936 .00596 .0103 .00673 .00502 .00375 .00373 .00330 .0162 .00405 – Aluminum Conductors Magnetic Conduit R – – – – .00650 .00666 . at an average temperature of 75°C.0790 .0216 .00870 .00981 .0335 .00772 .00346 .0789 . insulation materials and thicknesses.00663 .00264 Z – – – – .1230 .01006 .00392 .01008 .00352 .0834 .0490 .00889 .0203 .00355 . conductor spacing.00428 .00366 .0162 .0335 .  Z = X +R ‘ For busway impedance data.0216 . based on 60 Hertz ac.00387 .00358 .00640 .0166 .0531 .00595 . differences among manufacturers are considerably greater because of the wider variations in insulation materials and thicknesses. in ohms per 100 feet of circuit length (not total conductor lengths).00350 Œ Resistance and reactance are phase-to-neutral values.0203 . 4-wire distribution.00696 .00415 .00521 .00284 .00437 .00330 Z – – – – .01108 .00742 . These tables are for 600-volt conductors.00331 .00230 X – – – – .00411 .00933 .00512 .1231 .0835 .00457 .00624 .00452 .00198 – X .00486 .00305 .00490 .00317 .0269 .00366 .00486 .0117 .00619 .00293 .0833 .0320 .00261 .00247 .00440 .0335 .00305 .00705 .00366 .00384 .0212 .0267 .00486 .00369 .00398 .00375 .00546 .0834 .00491 .1232 .0136 .0833 .0789 . and other divergences in materials.00578 .00366 .00746 .00395 .00435 . overall diameters.00428 .00241 .00384 .00588 . use magnetic conduit data for steel armor and non-magnetic conduit data for aluminum armor. 2 2 CAT.00476 .1969 .00391 .00387 .00448 .00384 .00455 .00980 .00588 .00310 .00553 .0531 .00351 .00688 .00391 – Nonmagnetic Conduit R .00438 .00356 .00782 .00346 .00391 .0173 .0104 .00564 .00366 .0338 .0206 .  Based upon conductivity of 100% for copper.00355 .0143 .00810 .00297 .00516 .00392 .00650 .00452 .00535 .00275 .00470 .00390 .00277 .00355 .01103 .00618 .00278 .00797 .00381 .00407 . Values from different sources vary because of operating temperatures.0271 .0108 .00308 .00309 .00409 .0492 . overall diameters.E .00310 .00341 .00280 .00490 .00365 .00688 .3131 .01097 .00198 – X .00375 .0337 .00308 .00340 .00352 . For medium-voltage cables.0833 .  For interlocked armored cable.00375 .00593 .1968 .0791 .00546 .00355 .0170 .00230 X – – – – .00486 .00511 .00470 .71.0318 .0271 .0318 .00402 .00220 – X .0203 .00493 – Nonmagnetic Conduit R .00360 .3131 .00346 .1968 . Therefore.0162 .00843 .00394 .00380 .00331 .00458 .1231 . Data shown in tables may be used without significant error between 60°C and 90°C.00284 . Other parameters are listed in the notes.00605 .0318 .00452 .00482 . Resistance of both copper and aluminum conductors will be approximately 5% lower at 60°C or 5% higher at 90°C. and also NEC Table 9.1968 .00360 .01380 .00780 .0103 .00409 .01159 .00275 .01103 .00610 .0212 .00542 .00482 .01360 .00501 .0532 .00337 .00323 – Z .00247 . AWG or kcmil 14 12 10 8 6 4 2 1 1/0 2/0 3/0 4/0 250 300 350 400 450 500 600 700 750 1000 Copper Conductors Magnetic Conduit R .0175 .3130 .1969 .00597 .00542 .00487 .00512 .0267 . data for medium-voltage cables should be obtained from the manufacturer of the cable to be used.00521 .00343 .00849 .0130 .0215 .1968 .00220 – X .00426 . 61% for aluminum.00341 .00618 . and the like.00489 .1969 .00461 .00540 .0323 .3131 .00320 .0203 .00593 .01380 .01139 .00477 .0171 .0134 .0269 .0335 .00697 .00407 .00454 .00519 .0790 .00797 .00305 . shielding.0117 .00390 .0168 .00497 .0530 .00353 – Z .0111 .00380 .00247 .1230 .00284 .0207 . test conditions and calculation methods.00849 .00673 .00512 .00509 .00440 .00746 .00396 .00389 .01139 .00265 .0162 . 58 .. . Some of the most important are summarized in part below. USE† RHH†. MI. SIS.....08 1. .91 .Cutler-Hammer January 1999 Power Distribution System Design Reference Data – Conductor Ampacities Œ A-65 Current Carrying Capacities of Copper and Aluminum and Copper-Clad Aluminum Conductors From National Electrical Code (NEC). THWN-2. On a 4-wire. USE-2. as in the case of normally balanced circuits of three or more conductors. ... Exception: As limited in Section 240-3.05 m) and the number of 1 110 130 150 85 100 115 1 conductors does not exceed four.. Tube or Raceway.76 .71 . 1. SIS.05 1... except as limited in Section 240-3 (not above a rating of 800A). as provided in Section 300-3.76 . RHH†.. see page A-64... .71 . See Table 310-13.. 12. RHW†.41 1.88 ... THW-2. XHHW†.05 1. .. 12 and 25 amperes for No. c. THW†. 10 copper.67 . Adjustment Factors a.. RH†.. Based on Ambient Temperature of 30°C (86°F) Exception No.. or 4 70 85 95 55 65 75 4 rigid nonmetallic conduit having a length not 3 85 100 110 65 75 85 3 2 95 115 130 75 90 100 2 exceeding 10 feet (3..91 . XHH. Note 9: Overcurrent protection.94 . 9. the next higher standard rating and setting shall be permitted.. b.82 .. RHW-2. the provisions of Section 318-11 XHHW†. shall apply. TBS.. Where the standard ratings and settings of overcurrent devices do not correspond with the ratings and settings allowed for conductors.. 5: For other loading conditions. Size ent systems. Exception No. Note: For applications 2000 volts and below under conditions of use other than covered by the above table. . ..96 . . 3-phase wye circuit where the major portion of the load consists of non linear loads. XHHW†. and for applications over 2000 volts. the overcurrent protection for conductor types marked with an obelisk (†) shall not exceed 15 amperes for No. 20 amperes for No..04 1. 800 410 490 555 330 395 450 800 Spacing between conduits.58 ...75 .. Note 10: Neutral Conductor a.71 . 18 . ZW-2 XHHW-2.41 . More Than Three Current-Carrying Conductors in a Raceway or Cable. Overcurrent Protection. .00 . . 220.. USE†. RHW†. ZW-2 apply to conductors in nipples having a Copper Aluminum or Copper-Clad Aluminum length not exceeding 24 inches (610 mm). In a 3-wire circuit consisting of 2-phase wires and the neutral of a 4-wire.82 .. FEP†. and 30 amperes for No. °F 70-77 78-86 87-95 96-104 105-113 114-122 123-131 132-140 141-158 159-176 A Correction Factors For ambient temperatures other than 30 °C (86°F). there are harmonic currents present in the neutral conductor and the neutral shall be considered to be a current-carrying conductor.67 . FEPB†. FEPW†. 1. Exception No.96 . SA.E . CAT. 1: Where conductors of differSize Temperature Rating of Conductor..T.00 . 18 . 1996 Edition (NFPA70-1996) Table 310-16: Allowable Ampacities of Insulated Conductors Rated 0-2000 Volts. ZW† USE-2.. Where the standard ratings and settings of overcurrent devices do not correspond with the ratings and settings allowed for conductors. Œ For impedance data. 14 . 1000 455 545 615 375 445 500 1000 1250 1500 1750 2000 Ambient Temp... 4: Derating factors shall not 14 20† 20† 25† . 60° to 90°C (140° to 194°F) Not More Than Three Conductors in Raceway or Cable or Earth (Directly Buried). 3-phase wye-connected system.87 ... °C 21-25 26-30 31-35 36-40 41-45 46-50 51-55 56-60 61-70 71-80 495 520 545 560 590 625 650 665 665 705 735 750 405 435 455 470 485 520 545 560 545 585 615 630 1250 1500 1750 2000 Ambient Temp.. shall not be counted when applying the provisions of Note 8..58 . 1.. 215. or 15 amperes for No. . THHW†.71. More Than One Conduit. 2: For conductors installed in THWN†. .. .41 . cable trays.41 †Unless otherwise specifically permitted elsewhere in this Code. apply to underground conductors entering or 12 25† 25† 30† 20† 20† 25† 12 10 30 35† 40† 25 30† 35† 10 leaving an outdoor trench if those conductors 8 40 50 55 30 40 45 8 have physical protection in the form of rigid 6 55 65 75 40 50 60 6 metal conduit. 2/0 145 175 195 115 135 150 2/0 3/0 165 200 225 130 155 175 3/0 adjustment factors and ampacities shall be 4/0 195 230 260 150 180 205 4/0 permitted to be calculated under Section 215 255 290 170 205 230 250 250 310-15(b).91 . THHN†..82 . XHH.. and 230) conductors only.. Table B-310-11 for ad400 280 335 380 225 270 305 400 justment factors for more than three current500 320 380 430 260 310 350 500 carrying conductors in a raceway or cable 600 355 420 475 285 340 385 600 with load diversity. THHN†..87 . the next higher standard rating and setting shall be permitted. 1. the number of power and lighting (Articles UF† RH†. .00 . RHW-2. .94 .. THWN†.00 . 300 240 285 320 190 230 255 300 350 260 310 350 210 250 280 350 (FPN): See Appendix B.. 14....01.75 . the derating factors shown above shall apply to Types Types Types Types Types Types TW†.. 8. SA. the allowable ampacities shall be reduced as shown in the following table: Number of Current-Carrying Conductors 4 through 6 7 through 9 10 through 20 21 through 30 31 through 40 41 and above Percent of Values in Tables as Adjusted for Ambien Temperature if Necessary 80 70 50 45 40 35 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... THW†. THWN-2.. THHW†..08 1.82 . UF† THHW†.82 . THW-2.33 . TBS...82 .00 .....04 1.33 .71 .88 . Exception No.. the allowable ampacity of each conductor shall be reduced as shown in the above table... Where the number of current-carrying conductors in a raceway or cable exceeds three.00 . 3: Derating factors shall not XHHW-2. TW†. intermediate metal conduit. 1. multiply the allowable ampacities shown above by the appropriate factor shown below. a common conductor carries approximately the same current as the line to neutral load currents of the other conductors and shall be counted when applying the provisions of Note 8.. 700 385 460 520 310 375 420 700 750 400 475 535 320 385 435 750 b. see Article 310 and additional tables in NEC.91 .. tubing or 900 435 520 585 355 425 480 900 raceways shall be maintained. 10 aluminum and copper-clad aluminum after any correction factors for ambient temperature and number of conductors have been applied. 1/0 125 150 170 100 120 135 1/0 Exception No.58 .. A neutral conductor which carries only the unbalanced current from other conductors.. XHHW. are AWG 60°C 75°C 90°C 60°C 75°C 90°C AWG kcmil (140°F) (167°F) (194°F) (140°F) (167°F) (194°F) kcmil installed in a common raceway or cable..58 .58 . THHW†. See NEC for complete notes to Table 310-16. 16 .. 210.. For cables with compact conductors. This table is for concentric stranded conductors only.71. Chapter 9. Note 2. the dimensions in Table 5A shall be used. CAT. FEP (14 through 2). THHW TW. All UL listed circuit breakers rated over 125A are suitable for 75°C conductors. Reproduced From 1993 NEC Table 3B: Maximum Number of Conductors in Trade Sizes of Conduit or Tubing (Based on Table 1. the dimensions in Table 5A shall be used. the full 90°C ampacity may be used when applying derated factors. For cables with compact conductors.A-66 Power Distribution System Design Reference Data – Conduit Fill Cutler-Hammer January 1999 A Note 11: Grounding or Bonding Conductor A grounding or bonding conductor shall not be counted when applying the provisions of Note 8. Conductors rated for higher temperatures may be used. RHW and RHH (without outer covering) Note 1. All Westinghouse listed breakers rated 125A or less are marked 60/ 75°C. Conductor Size AWG/kcmil 14 12 10 8 14 12 10 8 6 4 3 2 1 1/0 2/0 3/0 4/0 250 300 350 400 500 RH. Conductor Size AWG/kcmil 14 12 10 8 6 4 3 2 1 1/0 2/0 3/0 4/0 250 300 350 400 500 600 700 750 XHHW 6 600 700 750 1 3 5 13 10 6 3 1 1 1 1 24 18 11 5 4 2 1 1 1 1 1 1 1 39 29 18 9 6 4 3 3 1 1 1 1 1 1 1 1 69 51 32 16 11 7 6 5 3 3 2 1 1 1 1 1 1 1 1 94 70 44 22 15 9 8 7 5 4 3 3 2 1 1 1 1 1 1 1 1 13 1 1 1 154 114 73 36 26 16 13 11 8 7 6 5 4 3 3 2 1 1 1 1 1 21 1 1 1 164 104 51 37 22 19 16 12 10 8 7 6 4 4 3 3 2 1 1 1 30 1 1 1 1⁄2 3⁄4 1 11⁄4 11⁄2 2 21⁄2 3 31⁄2 4 5 6 160 79 57 35 29 25 18 15 13 11 9 7 6 5 5 4 3 3 2 47 3 3 2 106 76 47 39 33 25 21 17 14 12 10 8 7 6 5 4 4 3 63 4 4 3 136 98 60 51 43 32 27 22 18 15 12 11 9 8 7 5 5 4 81 5 5 4 154 94 80 67 50 42 35 29 24 20 17 15 13 11 9 8 7 128 9 7 7 137 116 97 72 61 51 42 35 28 24 21 19 16 13 11 11 185 13 11 10 THHN. Chapter 9) Conduit or Tubing Trade Size (Inches) Type Letters THWN. Table 3A: Maximum Number of Conductors in Trade Sizes of Conduit or Tubing (Based on Table 1. PFA (14 through 4/0) PFAH (14 through 4/0) Z (14 through 4/0) XHHW (4 through 500 kcmil) 9 1 Note 1.T. THW. This table is for concentric stranded conductors only. 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 conductor for equipment marked or rated 65°C. FEPB (14 through 8). Tables 1-10 for exact code requirements. so long as the actual load does not exceed the lower of the derated ampacity or the 75°C or 60°C ampacity that applies.01. Conduit fill for conductors with a -2 suffix is the same as for those types without the suffix. For estimate only – see 1996 NEC. THHW 600 700 750 9 7 5 2 6 4 4 1 1 1 1 1 15 12 9 4 10 8 6 3 2 1 1 1 1 1 1 1 25 19 15 7 16 13 11 5 4 3 2 2 1 1 1 1 1 1 1 44 35 26 12 29 24 19 10 7 5 4 4 3 2 1 1 1 1 1 1 1 1 60 47 36 17 40 32 26 13 10 7 6 5 4 3 3 2 1 1 1 1 1 1 1 1 1 99 78 60 28 65 53 43 22 16 12 10 9 6 5 5 4 3 2 2 1 1 1 1 1 1 142 111 85 40 93 76 61 32 23 17 15 13 9 8 7 6 5 4 3 3 2 1 1 1 1 171 131 62 143 117 95 49 36 27 23 20 14 12 10 9 7 6 5 4 4 3 3 2 2 1⁄2 3⁄4 1 11⁄4 11⁄2 2 21⁄2 3 31⁄2 4 5 6 176 84 192 157 127 66 48 36 31 27 19 16 14 12 10 8 7 6 5 4 4 3 3 108 163 85 62 47 40 34 25 21 18 15 13 10 9 8 7 6 5 4 4 133 97 73 63 54 39 33 29 24 20 16 14 12 11 9 7 7 6 141 106 91 78 57 49 41 35 29 23 20 18 16 14 11 10 9 FEPB (6 through 2). Conduit fill for conductors with a -2 suffix is the same as for those types without the suffix. XHHW (14 through 8) RH (14 + 12) RHW and RHH (without outer cover ing). Conduit Fill Note: UL listed circuit breakers rated 125A or less shall be marked as being suitable for 60°C (140°F). However. Note 2. 75°C (167°F) only or 60/75°C (140/167°F) wire.E . Reproduced From 1993 NEC. Chapter 9) Conduit or Tubing Trade Size (Inches) Type Letters TW. RH (10 + 8) THW. T.54 centimeters = 2. kW. If metering transformers are used. lbs. 2.(DC or 100% pf) R Megohm Volt Amperes (VA) = 1.01. Directly from wattmeter reading. hp. and kVAŒ To Find Direct Current hp × 746 ------------------------E × % eff kW × 1000 ---------------------------E Alternating Current Single-Phase Amperes (l) When Horsepower is Known Amperes (l) When Kilowatts is Known Amperes (l) When kVA is Known Kilowatts kVA Horsepower (Output) I × E × % eff ------------------------------746 I×E -----------1000 hp × 746 ------------------------------------E × % eff × pf kW × 1000 ---------------------------E × pf kVA × 1000 ------------------------------E l × E × pf ----------------------1000 I×E -----------1000 I × E × % eff × pf ------------------------------------------746 Two-Phase — 4-Wire hp × 746 ----------------------------------------------2 × E × % eff × pf kW × 1000 ---------------------------2 × E × pf kVA × 1000 ------------------------------2×E l × E × 2 × pf -------------------------------1000 I×E×2 -------------------1000 I × E × 2 × % eff × pf ----------------------------------------------------746 Three-Phase hp × 746 --------------------------------------------------3 × E × % eff × pf kW × 1000 ------------------------------------3 × E × % pf kVA × 1000 ------------------------------3×E l × E × 3 × pf ------------------------------------1000 I×E× 3 -----------------------1000 I × E × 3 × % eff × pf --------------------------------------------------------746 A Common Electrical Terms Ampere (l) Volt (E) Ohm (R) = unit of current or rate of flow of electricity = unit of electromotive force = unit of resistance E Ohms law: I = -.273. = 1000 watt-hours = measure of time rate of doing work = equivalent of raising 33. Watts = rpm of disc × 60 × Kh Where Kh is meter constant printed on face or nameplate of meter. Where: Volts = line-to-line voltage as measured by voltmeter. = 1.000 ohms = unit of apparent power = E × l (single-phase) = E×l× 3 How to Compute Power Factor watts Determining watts: pf = ------------------------------------------volts × amperes 1.000. above must be multiplied by the transformer ratios.785 square mil = 778 ft. one ft. 3-wire circuits the current in the common conductor is 2 times that in either of the two other conductors.200 circular mills = . From watt-hour meter.Cutler-Hammer January 1999 Power Distribution System Design Reference Data – Formulas and Terms A-67 Formulas for Determining Amperes.E . Amps = current measured in line wire (not neutral) by ammeter. I (amperes).71. CAT.413 Btu = 2. = 252 calories = 8. lbs.  For 2-phase.655 ft.760 hours Load Factor Œ Units of measurement and definitions for E (volts). and other abbreviations are given below under Common Electrical Terms.000 lbs.20 lbs.00134 hp = 1000 watts = ratio of true to apparent power W = ------VA Watt-hour (Wh) Kilowatt (kW) Power Factor (pf) ---------- kW kVA = unit of electrical work = one watt for one hour = 3. Temperature Conversion (F° to C°) (C° to F°) C° F° C° F° -15 5 25 77 -10 14 30 86 70 158 -5 23 35 95 75 167 0 32 40 104 80 176 C°=5/9 (F°-32°) F°=9/5(C°)+32° 5 41 10 50 15 59 55 131 95 203 20 68 60 140 100 212 Kilovolt Amperes (kVA) = 1000 volt-amperes Watt (W) = unit of true power = VA × pf = . in one minute = 746 watts = ratio of maximum demand to the total connected load = ratio of the sum of individual maximum demands of the various subdivisions of a system to the maximum demand of the whole system = ratio of the average load over a designated period of time to the peak load occurring in that period 45 50 113 122 85 90 185 194 Kilowatt-hour (kWh) Horsepower (hp) C° 65 F° 149 Demand Factor Diversity Factor 1 inch 1 kilogram 1 square inch 1 circular mill 1 Btu 1 year = 2. Figure 16-2 of the code includes a seismic zone map of the United States.5 x 0. Wp: is the weight of the equipment. The damping value is 5% of the critical damping.5.5 1. The resultant levels are shown in Figure 16-3. these values are computed conservatively to envelop the requirements of all seismic zones. The total design lateral force required is: Force Fp = Z Ip Cp Wp 3 2A 2B 3 1 2B 3 4 2B 3 2B 4 4 3 3 1 2A 2A 1 3 4 ALASKA 0 1 2B 1 1 3 4 2B 1 HAWAII 2B 3 3 PUERTO RICO 4 0 0 3 ALEUTIAN ISLANDS 1 2B 2A 2B 1 1 0 3 1 2A 1 3 0 1 1 0 2A 0 1 UBC Figure 16-2.06 seconds. Equipment must be designed and tested to the UBC requirements to determine that it will be functional following a seismic event. and associated conduit are specifically identified. transformers. Normalized Response Spectra Shapes Therefore. The rigid equipment requirements extend beyond 16. switchgear.5 = 0.75 for rigid equipment as defined in Table 16-O. the lowest natural frequency of Cutler-Hammer equipment is greater than 3 Hz.71. this value is equal to twice the value for the rigid equipment: 2 x 0.75 = 1. From actual tests. In addition. Figure 16-3 of the code includes the normalized response spectra shapes for different soil conditions.0 1.5 3. The dynamic lateral forces are defined in Section 1629. This is the maximum value provided in Table 16-I of the code. Therefore. 0 0.5.9g Flexible equipment is defined in the UBC as equipment with a period of vibration equal to or greater than 0. is the importance factor and is taken equal to 1. The design engineer must evaluate the effect of lateral forces not only on the building structure but also on the equipment in determining whether the design will withstand those forces. This is the maximum value provided in Table 16-K of the code. Ip: Cp: is the horizontal force factor and is taken equal to 0. In the code electrical equipment such as control panels. For flexible equipment. T (Seconds) 2. 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. This is the maximum value provided in the code.T.45g The maximum acceleration for flexible equipment is: Acceleration = Fp/Wp = Z Ip Cp = 0.0 2.75 = 0.5 x 1. The criteria for selecting the seismic requirements are defined in Section 1627 of the code.4.4 x 1.01.7 Hz. weight. to 16. CAT. These loads are converted to seismic accelerations according to the normalized response spectra shown in Figure 16-3 of the UBC.E . The seismic requirements in the UBC can be completely defined as the Zero Period Acceleration (ZPA) and Spectrum Accelerations are computed. Sections 1624-1633 of this reference specifically require that structures and portions of structures shall be designed to withstand the seismic ground motion specified in the code. Finally. center of gravity. The lateral force on elements of structures and nonstructural components are defined in Section 1630. the requirements for the flexible equipment extend from 3 Hz.0 UBC Figure 16-3.7 Hz.5 Period. and mounting provisions of the equipment to determine its method of attachment so it will remain attached to its foundation during a seismic event. In a test program. motors. the maximum acceleration for rigid equipment is: Acceleration = Fp/Wp = Z Ip Cp = 0.A-68 Power Distribution System Design Seismic Requirements Cutler-Hammer January 1999 Seismic Requirements A Uniform Building Code (UBC) The 1994 Uniform Building Code (UBC) includes Volume 2 for earthquake design requirements. the contractor must properly install the equipment in accordance with the anchorage design. a structural or civil engineer must perform calculations based on data received from the equipment manufacturer specifying the size.4 x 1.7 Hz. This period of vibration corresponds to a dominant frequency of vibration equal to 16. Seismic Zone Map of the United States 4 Soft to Medium Clays and Sands (Soil Type 3) 3 Deep Cohesionless or Stiff Clay Soils (Soil Type 2) 2 Rock and Stiff Soils (Soil Type 1) Spectral Acceleration Effective Peak Ground Acceleration 1 0 Dividing both sides by Wp. 71.75 = 0.E .4 x 1.05 .81 0.20 . Tested Equipment Capability and Seismic Requirements CAT.5 x 0.2 4 5 6. CutlerHammer elected to test the equipment to 1⁄2 of the nuclear requirements.75 = 1.16 . equal to 1⁄3 of the horizontal accelerations. The 50% ANSI C37.81 .T.8g In addition.4 x 1.4 8 10 13 Frequency (Hz) Figure 1. Guide for Seismic Qualification of Class 1E Metal-Enclosed Power Switchgear Assemblies.45g Period (seconds) .03 0 A 2.0 Damping = 5% 1.06 .10 .Cutler-Hammer January 1999 Power Distribution System Design Seismic Requirements A-69 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.5 The maximum acceleration for flexible equipment is: Acceleration = Fp/Wp = Z I Cp = 0. The resultant levels are shown in Figure 1.0 (g) Zero Period Acceleration 17 20 26 32 Cutler-Hammer Equipment Capability 50% of the Level Specified in ANSI C37.81.25 .5 x 4 x 0. The maximum acceleration for rigid equipment is: Acceleration = Fp/Wp = Z I Cp = 0. Because the 1⁄3 figure has been found to be inadequate for some applications.1995 The seismic requirements for Class 1E Switchgear in nuclear power plants are defined in ANSI C37. Response Acceleration 1.04 . vertical accelerations are to be met along with the horizontal. Cutler-Hammer recommends the vertical acceleration requirements to be equal to the horizontal seismic requirements.08 . CBC State Requirements add under Note 12 in Table 23P. ANSI C37.5 California Building Code Zone 4 Requirement Uniform Building Code Zone 4 Requirement 0 3.13 .01.81 seismic requirements are also plotted in Figure 1.31 . E . CAT.T.A-70 Power Distribution System Design Cutler-Hammer January 1999 A This page intentionally left blank.71.01.