Power Distribution Systems 1.0-1 April 2016 Sheet 01 001

Contents i Power Distribution Systems Suggested Ground System Design Fault Settings...... 1.4-6 ii Basic Principles...... 1.1-1 Grounding/Ground Fault Protection Modern Electric Power Grounding—Equipment, Technologies ...... 1.1-1 System, MV System, 1 Goals of System Design . . . 1.1-2 LV System ...... 1.4-9 Voltage Classifications; BILs— Ground Fault Protection. . . . 1.4-11 Basic Impulse Levels . . . . . 1.1-3 Lightning and Surge 2 Three-Phase Transformer Protection ...... 1.4-14 Winding Connections . . . . 1.1-5 Grounding Electrodes . . . . . 1.4-14 3 Types of Systems—Radial, MV Equipment Surge Loop, Selective, Two-Source, Protection Considerations . 1.4-14 Sparing Transformer, Spot Surge Protection ...... 1.4-14 4 Network, Distribution . . . . 1.1-6 Types of Surge Health Care Facility Protection Devices ...... 1.4-15 Design Considerations . . . 1.1-15 Power Quality 5 Generator Systems ...... 1.1-18 Terms, Technical Overview . . 1.4-18 Generator System Design SPD ...... 1.4-19 Types of Generators...... 1.2-1 Harmonics and 6 Generator Systems ...... 1.2-2 Nonlinear Loads ...... 1.4-21 Generator Grounding...... 1.2-3 UPS ...... 1.4-25 Generator Controls...... 1.2-4 Other Application Considerations 7 Generator Short-Circuit Secondary Voltage ...... 1.4-31 Characteristics ...... 1.2-4 Energy Conservation ...... 1.4-32 Systems 8 Generator Protection ...... 1.2-5 Building Control Systems . . 1.4-33 System Analysis Distributed Energy Systems Analysis ...... 1.3-1 Resources ...... 1.4-33 9 Short-Circuit Currents . . . . . 1.3-2 Cogeneration ...... 1.4-33 Fault Current Waveform PV System Design Relationships ...... 1.3-3 Considerations ...... 1.4-34 10 Fault Current Calculations Emergency Power...... 1.4-35 and Methods Index ...... 1.3-4 Peak Shaving...... 1.4-36 11 Determine X and R from Sound Levels...... 1.4-36 Transformer Loss Data . . . 1.3-19 Reference Data Voltage Drop IEEE Protective Relay Considerations ...... 1.3-20 12 Numbers ...... 1.5-1 System Application Considerations Codes and Standards ...... 1.5-6 Capacitors and Motor Protective 13 Power Factor ...... 1.4-1 Device Data...... 1.5-7 Overcurrent Protection Chart of Short-Circuit and Coordination ...... 1.4-3 Currents for Transformers . . 1.5-9 14 Protection of Conductors. . . 1.4-5 Transformer Full Load Circuit Breaker Cable Amperes ...... 1.5-10 15 Temperature Ratings . . . . . 1.4-5 Impedances Data ...... 1.5-11 Zone Selective Interlocking . 1.4-5 Transformer Losses ...... 1.5-12 Ground Fault Protection . . . 1.4-6 Power Equipment Losses . . . 1.5-13 16 NEMA Enclosure Definitions. . 1.5-13 Cable R, X, Z Data...... 1.5-15 Conductor Ampacities . . . . . 1.5-17 17 Conductor Temperature Ratings ...... 1.5-17 18 Formulas and Terms...... 1.5-20 Seismic Requirements . . . . . 1.5-21 19 Power Distribution Power 20

Designing a Distribution System 21

CA08104001E For more information, visit: www.eaton.com/consultants 1.0-2 Power Distribution Systems April 2016 Sheet 01 002

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For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.1-1 April 2016 System Design Sheet 01 003

Basic Principles The basic principles or factors requiring Modern Electric Power consideration during design of the i The best distribution system is one power distribution system include: Technologies that will, cost-effectively and safely, ■ Functions of structure, present Several new factors to consider in supply adequate electric service to ii and future modern power distribution systems both present and future probable result from two relatively recent loads—this section is included to aid ■ Life and flexibility of structure changes. The first recent change is in selecting, designing and installing ■ Locations of service entrance and 1 utility deregulation. The traditional such a system. distribution equipment, locations dependence on the utility for problem and characteristics of loads, analysis, energy conservation mea- The function of the electric power locations of unit substations 2 distribution system in a building or surements and techniques, and a ■ Demand and diversity factors an installation site is to receive power simplified cost structure for electricity of loads at one or more supply points and has changed. The second change is less 3 to deliver it to the individual lamps, ■ Sources of power; including obvious to the designer yet will have motors and all other electrically normal, standby and emergency an impact on the types of equipment operated devices. The importance (see Ta b 4 0 ) and systems being designed. It is the 4 of the distribution system to the ■ Continuity and quality of diminishing quantity of qualified build- function of a building makes it almost power available and required ing electrical operators, maintenance imperative that the best system be (see Ta b 3 3 ) departments and facility engineers. 5 designed and installed. ■ Energy efficiency and management Modern electric power technologies In order to design the best distribution ■ Distribution and utilization voltages may be of use to the designer and 6 system, the system design engineer ■ Bus and/or cable feeders building owner in addressing these must have information concerning the ■ Distribution equipment and new challenges. The advent of micro- loads and a knowledge of the various motor control processor devices (smart devices) into power distribution equipment has 7 types of distribution systems that are ■ Power and lighting panelboards expanded facility owners’ options and applicable. The various categories of and motor control centers buildings have many specific design capabilities, allowing for automated ■ 8 challenges, but certain basic principles Types of lighting systems communication of vital power system are common to all. Such principles, ■ Installation methods information (both energy data and if followed, will provide a soundly ■ Power monitoring systems system operation information) and 9 executed design. ■ Electric utility requirements electrical equipment control. These technologies may be grouped as: 10 ■ Power monitoring and control ■ Building management systems interfaces 11 ■ Lighting control ■ Automated energy management 12 ■ Predictive diagnostics Various sections of this guide cover the application and selection of such 13 systems and components that may be incorporated into the power equipment being designed. See Tabs 2, 3, 4, 23 14 and 41. 15

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CA08104001E For more information, visit: www.eaton.com/consultants 1.1-2 Power Distribution Systems System Design April 2016 Sheet 01 004

Goals of System Design 2. Minimum Initial Investment: 4. Maximum Flexibility and i The owner’s overall budget for Expendability: In many industrial When considering the design of an first cost purchase and installation manufacturing plants, electrical electrical distribution system for of the electrical distribution sys- utilization loads are periodically ii a given customer and facility, the tem and electrical utilization relocated or changed requiring electrical engineer must consider equipment will be a key factor changes in the electrical distribu- alternate design approaches that in determining which of various tion system. Consideration of 1 best fit the following overall goals. alternate system designs are to be the layout and design of the selected. When trying to minimize electrical distribution system to 1. Safety: The No. 1 goal is to design initial investment for electrical accommodate these changes must 2 a power system that will not equipment, consideration should be considered. For example, pro- present any electrical hazard to be given to the cost of installation, viding many smaller transformers the people who use the facility, floor space requirements and or loadcenters associated with a 3 and/or the utilization equipment possible extra cooling require- given area or specific groups of fed from the electrical system. ments as well as the initial machinery may lend more flexibility It is also important to design a purchase price. for future changes than one large 4 system that is inherently safe for transformer; the use of plug-in the people who are responsible for 3. Maximum Service Continuity: busways to feed selected equip- electrical equipment maintenance The degree of service continuity ment in lieu of conduit and wire 5 and upkeep. and reliability needed will vary may facilitate future revised depending on the type and use equipment layouts. The National Electrical Code® of the facility as well as the loads 6 (NEC®), NFPA® 70 and NFPA 70E, or processes being supplied by the In addition, consideration must be as well as local electrical codes, electrical distribution system. For given to future building expansion, provide minimum standards and example, for a smaller commercial and/or increased load require- 7 requirements in the area of wiring office building, a power outage ments due to added utilization design and protection, wiring of considerable time, say several equipment when designing the methods and materials, as well hours, may be acceptable, whereas electrical distribution system. 8 as equipment for general use with in a larger commercial building or In many cases considering trans- the overall goal of providing safe industrial plant only a few minutes formers with increased capacity electrical distribution systems may be acceptable. In other facilities or fan cooling to serve unexpected 9 and equipment. such as hospitals, many critical loads as well as including spare The NEC also covers minimum loads permit a maximum of additional protective devices and/ requirements for special 10 seconds outage and certain or provision for future addition of 10 occupancies including hazardous loads, such as real-time computers, these devices may be desirable. locations and special use type cannot tolerate a loss of power for Also to be considered is increasing facilities such as health care even a few cycles. appropriate circuit capacities or 11 quantities for future growth. facilities, places of assembly, Typically, service continuity and theaters and the like, and the reliability can be increased by: Power monitoring communication 12 equipment and systems located in systems connected to electronic these facilities. Special equipment A. Supplying multiple utility power metering can provide the trending and special conditions such as sources or services. and historical data necessary for emergency systems, standby B. Supplying multiple connection future capacity growth. 13 systems and communication paths to the loads served. systems are also covered in 14 the code. C. Using short-time rated power circuit breakers. It is the responsibility of the design engineer to be familiar with the D. Providing alternate customer- 15 NFPA and NEC code requirements owned power sources such as as well as the customer’s facility, generators or batteries supplying process and operating procedures; uninterruptable power supplies. 16 to design a system that protects personnel from live electrical E. Selecting the highest quality elec- conductors and uses adequate trical equipment and conductors. 17 circuit protective devices that will F. Using the best installation methods. selectively isolate overloaded or faulted circuits or equipment as G. Designing appropriate system 18 quickly as possible. alarms, monitoring and diagnostics. H. Selecting preventative mainte- 19 nance systems or equipment to alarm before an outage occurs. 20

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For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.1-3 April 2016 System Design Sheet 01 005

5. Maximum Electrical Efficiency 7. Maximum Power Quality: Coupled with this information, a (Minimum Operating Costs): The power input requirements knowledge of the major types of electric i Electrical efficiency can generally of all utilization equipment has power distribution systems equips the be maximized by designing to be considered including the engineers to arrive at the best system systems that minimize the losses acceptable operating range of design for the particular building. ii in conductors, transformers and the equipment and the electrical utilization equipment. Proper distribution system has to be It is beyond the scope of this guide to voltage level selection plays a designed to meet these needs. present a detailed discussion of loads 1 key factor in this area and will For example, what is the required that might be found in each of several be discussed later. Selecting input voltage, current, power types of buildings. Assuming that the equipment, such as transformers, factor requirement? Consider- design engineer has assembled the 2 with lower operating losses, ation to whether the loads are necessary load data, the following generally means higher first cost affected by harmonics (multiples pages discuss some of the various and increased floor space require- of the basic 60 Hz sine wave) or types of electrical distribution systems 3 ments; thus, there is a balance generate harmonics must be taken that can be used. The description of to be considered between the into account as well as transient types of systems, and the diagrams owner’s utility energy change voltage phenomena. used to explain the types of systems 4 for the losses in the transformer on the following pages omits the or other equipment versus the The above goals are interrelated location of utility revenue metering owner’s first cost budget and and in some ways contradictory. equipment for clarity. A discussion of 5 cost of money. As more redundancy is added to short-circuit calculations, coordination, the electrical system design along voltage selection, voltage drop, ground 6. Minimum Maintenance Cost: with the best quality equipment fault protection, motor protection and 6 Usually the simpler the electrical to maximize service continuity, other specific equipment protection system design and the simpler flexibility and expandability, and is also presented. the electrical equipment, the less power quality, the more initial 7 the associated maintenance costs investment and maintenance and operator errors. As electrical are increased. Thus, the designer Voltage Classifications systems and equipment become must weigh each factor based ANSI and IEEE® standards define 8 more complicated to provide on the type of facility, the loads various voltage classifications for greater service continuity or to be served, the owner’s past single-phase and three-phase systems. flexibility, the maintenance costs experience and criteria. The terminology used divides voltage 9 and chance for operator error classes into: increases. The systems should be Summary ■ designed with an alternate power It is to be expected that the engineer Low voltage 10 circuit to take electrical equipment will never have complete load infor- ■ Medium voltage (requiring periodic maintenance) mation available when the system is ■ High voltage out of service without dropping designed. The engineer will have to ■ 11 essential loads. Use of drawout Extra-high voltage expand the information made avail- ■ Ultra-high voltage type protective devices such as able to him on the basis of experience breakers and combination starters with similar problems. Of course, it Ta b l e 1. 1- 1 presents the nominal system 12 can also minimize maintenance is desirable that the engineer has as voltages for these classifications. cost and out-of-service time. much definite information as possible Utilizing sealed equipment in concerning the function, requirements, 13 lieu of ventilated equipment may and characteristics of the utilization minimize maintenance costs and devices. The engineer should know out-of-service time as well. whether certain loads function 14 separately or together as a unit, the magnitude of the demand of the loads viewed separately and as units, the rated 15 voltage and frequency of the devices, their physical location with respect to each other and with respect to the 16 source and the probability and possi- bility of the relocation of load devices and addition of loads in the future. 17 18

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CA08104001E For more information, visit: www.eaton.com/consultants 1.1-4 Power Distribution Systems System Design April 2016 Sheet 01 006

Table 1.1-1. Standard Nominal System Table 1.1-4. Pad Mounted and Overhead Table 1.1-6. Dry-Type Transformers Voltage i Voltages and Voltage Ranges Distribution Switchgear, Voltage and and Basic Lightning Impulse Insulation (From IEEE Standard 141-1993) Insulation Levels Levels (BIL)—From ANSI/IEEE C57.12.01-1998) 2 Voltage Nominal System Voltage Rated Maximum Impulse Nominal BIL (kV Crest) ii Class Three-Wire Four-Wire Voltage Level (kV rms) Withstand (kV) System Pad Mount Switchgear (per IEEE C37.74-2014) Voltage Low 240/120 208Y/120 (kV rms) 15.5 95 voltage 240 240/120 1 27 125 480 480Y/277 1.2 — 10 20 30 38 150 600 — 2.5 — 20 30 45 Overhead Switchgear (per IEEE C37.60-2012) 5.0 — 30 45 60 2 Medium 2400 4160Y/2400 8.7 — 45 60 95 voltage 4160 8320Y/4800 15 95 15.0 — 60 95 110 4800 12000Y/6930 15.5 110 3 25.0 95 110 125 150 6900 12470Y/7200 27 125 3 3 13,200 13200Y/7620 34.5 — 125 150 200 38 150 2 13,800 13800Y/7970 38 170 BIL values in bold typeface are listed as 23,000 20780Y/12000 standard. Others listed are in common use. 4 34,500 22860Y/13200 Optional higher levels used where exposure 46,000 24940Y/14400 Table 1.1-5. Liquid-Immersed to overvoltage occurs and higher protection 69,000 34500Y/19920 Transformers Voltage and Basic margins are required. 3 High 115, 0 0 0 — Lightning Impulse Insulation Levels (BIL) Lower levels where surge arrester 5 voltage 138,000 — (From ANSI/IEEE C57.12.00) protective devices can be applied with 161,000 — Applica- Nominal BIL lower spark-over levels. 1 230,000 — tion System (kV Crest) 6 Extra-high 345,000 — Voltage Voltage Recommendations by voltage 500,000 — (kV rms) Motor Horsepower 765,000 — Distribu- 1.2 30 — — — Some factors affecting the selection 7 Ultra-high 1,100,000 — tion 2.5 45 — — — voltage 5.0 60 — — — of motor operating voltage include: 8.7 75 — — — ■ Motor, motor starter and cable 8 BIL—Basic Impulse Levels 15.0 95 — — — first cost 25.0 150 125 — — ANSI standards define recommended ■ Motor, motor starter and cable and required BIL levels for: 34.5 200 150 125 — 9 46.0 250 200 — — installation cost ■ Metal-clad switchgear 69.0 350 250 — — ■ Motor and cable losses (typically vacuum breakers) Power 1.2 45 30 — — ■ Motor availability 10 ■ Metal-enclosed switchgear (typically 2.5 60 45 — — ■ Voltage drop 5.0 75 60 — — load interrupters, switches) ■ 8.7 95 75 — — Qualifications of the building 11 ■ Pad-mounted and overhead 15.0 110 95 — — operating staff; and many more distribution switchgear 25.0 150 — — — The following table is based in part ■ Liquid immersed transformers 34.5 200 — — — on the above factors and experience. 12 ■ Dry-type transformers 46.0 250 200 — — 69.0 350 250 — — Because all the factors affecting the selection are rarely known, it is only Ta b l e 1. 1- 2 through Ta b l e 1. 1- 6 contain 115 . 0 550 450 350 — those values. 138.0 650 550 450 — an approximate guideline. 13 161.0 750 650 550 — Table 1.1-2. Metal-Clad Switchgear Table 1.1-7. Selection of Motor Horsepower 230.0 900 825 750 650 Ratings as a Function of System Voltage Voltage and Insulation Levels 345.0 117 5 1050 900 — 14 (From IEEE Std. C37.20.2-2015) 500.0 1675 1550 1425 1300 Motor Voltage Motor System 765.0 2050 1925 1800 — (Volts) hp Range Voltage Rated Maximum Impulse 1 Voltage (kV rms) Withstand (kV) BIL values in bold typeface are listed as 460 up to 500 480 15 standard. Others listed are in common use. 2300 250 to 2000 2400 4.76 60 4000 250 to 3000 4160 8.25 95 15.0 95 4600 250 to 3000 4800 16 13,200 above 2000 13,800 27.0 125 38.0 150 17 Table 1.1-3. Metal-Enclosed Switchgear Voltage and Insulation Levels 18 (From IEEE Std. C37.20.3-2013) Rated Maximum Impulse Voltage (kV rms) Withstand (kV)

19 4.76 60 8.25 95 15.0 95 20 27.0 125 38.0 150 21

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.1-5 April 2016 System Design Sheet 01 007

Table 1.1-7. Three-Phase Transformer Winding Connections Phasor Notes i Diagram DELTA-DELTA Connection 1. Suitable for both ungrounded and effectively grounded sources. ii 2. Suitable for a three-wire service or a four-wire service with a mid-tap ground. Phasor H2 X2 Diagram: 1

H1 H3 X1 X3 2

Angular Displacement (Degrees): 0

DELTA-WYE Connection 1. Suitable for both ungrounded and effectively grounded sources. 3 2. Suitable for a three-wire service or a four-wire grounded service with Phasor H2 X2 XO grounded. Diagram: 3. With XO grounded, the transformer acts as a ground source for the 4 secondary system. X1 X0 4. Fundamental and harmonic frequency zero-sequence currents in the secondary lines supplied by the transformer do not flow in the primary lines. Instead the 5 H1 H3 X3 zero sequence currents circulate in the closed delta primary windings. Angular Displacement (Degrees): 30 5. When supplied from an effectively grounded primary system does not see load unbalances and ground faults in the secondary system. 6 WYE-DELTA Connection 1. Suitable for both ungrounded and effectively grounded sources. 2. Suitable for a three-wire service or a four-wire delta service with a mid-tap ground. Phasor H2 X2 Diagram: 3. Grounding the primary neutral of this connection would create a ground source 7 for the primary system. This could subject the transformer to severe overloading during a primary system disturbance or load unbalance. X1 4. Frequently installed with mid-tap ground on one leg when supplying 8 combination three-phase and single-phase load where the three-phase H1 H3 X3 load is much larger than single-phase load. Angular Displacement (Degrees): 30 5. When used in 25 kV and 35 kV three-phase four-wire primary systems, ferroresonance can occur when energizing or de-energizing the transformer 9 using single-pole switches located at the primary terminals. With smaller kVA transformers the probability of ferroresonance is higher. WYE-WYE Connection 1. Suitable for both ungrounded and effectively grounded sources. 10 2. Suitable for a three-wire service only, even if XO is grounded. Phasor H2 X2 Diagram: 3. This connection is incapable of furnishing a stabilized neutral and its use may result in phase-to-neutral overvoltage (neutral shift) as a result of unbalanced 11 phase-to-neutral load. X0 4. If a three-phase unit is built on a three-legged core, the neutral point of the primary windings is practically locked at ground potential. 12 H1 H3 X1 X3 Angular Displacement (Degrees): 0 13 GROUNDED WYE-WYE Connection 1. Suitable for four-wire effectively grounded source only. 2. Suitable for a three-wire service or for four-wire grounded service with Phasor H2 X2 XO grounded. Diagram: 14 3. Three-phase transformers with this connection may experience stray flux tank heating during certain external system unbalances unless the core configuration H0 X0 (four or five legged) used provides a return path for the flux. 15 4. Fundamental and harmonic frequency zero-sequence currents in the secondary H1 H3 X1 X3 lines supplied by the transformer also flow in the primary lines (and primary neutral conductor). Angular Displacement (Degrees): 0 5. Ground relay for the primary system may see load unbalances and ground 16 faults in the secondary system. This must be considered when coordinating overcurrent protective devices. 6. Three-phase transformers with the neutral points of the high voltage and low 17 voltage windings connected together internally and brought out through an HOXO bushing should not be operated with the HOXO bushing ungrounded (floating). To do so can result in very high voltages in the secondary systems. 18 DELTA-DELTA Connection with Tap 1. Suitable for both ungrounded and effectively grounded sources. 2. Suitable for a three-wire service or a four-wire service with a mid-tap ground. Phasor H2 X2 Diagram: 3. When using the tap for single-phase circuits, the single-phase load kVA should 19 X4 not exceed 5% of the three-phase kVA rating of the transformer. The three-phase rating of the transformer is also substantially reduced. 20 H1 H3 X1 X3 Angular Displacement (Degrees): 0 21

CA08104001E For more information, visit: www.eaton.com/consultants 1.1-6 Power Distribution Systems System Design April 2016 Sheet 01 008

Types of Systems Low voltage feeder circuits run from A fault on the secondary low voltage i the switchgear or switchboard assem- bus or in the source transformer will In many cases, power is supplied by blies to panelboards that are located interrupt service to all loads. Service the utility to a building at the utilization closer to their respective loads as cannot be restored until the necessary ii voltage. In these cases, the distribution shown in Figure 1.1-1. repairs have been made. A low voltage of power within the building is achieved feeder circuit fault will interrupt service Each feeder is connected to the switch- through the use of a simple radial to all loads supplied over that feeder. gear or switchboard bus through a 1 distribution system. circuit breaker or other overcurrent A modern and improved form of the In cases where the utility service voltage protective device. A relatively small conventional simple radial system 2 is at some voltage higher than the number of circuits are used to distribute distributes power at a primary voltage. utilization voltage within the building, power to the loads from the switch- The voltage is stepped down to the system design engineer has a choice gear or switchboard assemblies and utilization level in the several load 3 of a number of types of systems that panelboards. areas within the building typically may be used. This discussion covers through secondary unit substation Because the entire load is served from several major types of distribution transformers. The transformers are a single source, full advantage can be systems and practical modifications usually connected to their associated 4 taken of the diversity among the loads. of them. load bus through a circuit breaker, as This makes it possible to minimize the shown in Figure 1.1-2. Each secondary 5 1. Simple radial installed transformer capacity. However, unit substation is an assembled unit the voltage regulation and efficiency consisting of a three-phase, liquid- 2. Loop-primary system— of this system may be poor because radial secondary system filled or air-cooled transformer, an inte- 6 of the low voltage feeders and single grally connected primary fused switch, 3. Primary selective system— source. The cost of the low voltage- and low voltage switchgear or switch- secondary radial system feeder circuits and their associated circuit board with circuit breakers or fused breakers are high when the feeders are switches. Circuits are run to 7 4. Two-source primary— long and the peak demand is above secondary selective system the loads from these low voltage 1000 kVA. protective devices. 8 5. Sparing transformer system 6. Simple spot network 9 7. Medium voltage distribution Primary Fused Switch system design Transformer

10 1. Simple Radial System 600V Class The conventional simple radial system Switchboard receives power at the utility supply 11 voltage at a single substation and steps the voltage down to the utilization level. Distribution In those cases where the customer Dry-Type 12 receives his supply from the primary Transformer system and owns the primary switch Distribution MCC Distribution Lighting and transformer along with the second- Panel Panel Panelboard 13 ary low voltage switchboard or switch- gear, the equipment may take the form of a separate primary switch, separate Figure 1.1-1. Simple Radial System 14 transformer, and separate low voltage switchgear or switchboard. This equip- ment may be combined in the form of 15 an outdoor pad-mounted transformer 52 Primary Main Breaker with internal primary fused switch and secondary main breaker feeding 16 an indoor switchboard. 52 52 52 52 52 52 Primary Feeder Breakers Another alternative would be a 17 secondary unit substation where the primary fused switch, transformer and secondary switchgear or switch- 18 board are designed and installed as a close-coupled single assembly. 19 In those cases where the utility owns the primary equipment and transformer, the supply to the customer is at the Secondary Unit Substation utilization voltage, and the service Primary 20 Cables equipment then becomes low voltage main distribution switchgear or 21 a switchboard. Figure 1.1-2. Primary and Secondary Simple Radial System

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.1-7 April 2016 System Design Sheet 01 009

Because each transformer is located In addition, if only one primary fuse on sectionalizing switches and primary within a specific load area, it must a circuit opens, the secondary loads are load break fused switch as shown i have sufficient capacity to carry the then single phased, causing damage to in Figure 1.1-4 or utilizing three peak load of that area. Consequently, low voltage motors. on-off switches or a four-position if any diversity exists among the load sectionalizing switch and vacuum ii area, this modified primary radial Another approach to reducing costs fault interrupter (VFI) internal to the system requires more transformer is to eliminate the primary feeder transformer saving cost and reducing capacity than the basic form of the breakers completely, and use a single footprint. 1 simple radial system. However, primary main breaker or fused switch because power is distributed to the for protection of a single primary When pad-mounted compartmental- load areas at a primary voltage, losses feeder circuit with all secondary unit ized transformers are used, they are 2 are reduced, voltage regulation is substations supplied from this circuit. furnished with loop-feed oil-immersed improved, feeder circuit costs are Although this system results in less ini- gang-operated load break sectionaliz- reduced substantially, and large tial equipment cost, system reliability is ing switches and Bay-O-Net expulsion 3 low voltage feeder circuit breakers reduced drastically because a single fuses in series with partial range back- are eliminated. In many cases the fault in any part of the primary conductor up current-limiting fuses. By operating interrupting duty imposed on the would cause an outage to all loads the appropriate sectionalizing switches, 4 load circuit breakers is reduced. within the facility. it is possible to disconnect any section of the loop conductors from the rest This modern form of the simple radial 2. Loop Primary System— of the system. In addition, it is possible 5 system will usually be lower in initial Radial Secondary System to disconnect any transformer from investment than most other types of the loop. primary distribution systems for build- This system consists of one or more 6 ings in which the peak load is above “PRIMARY LOOPS” with two or more A key interlocking scheme is normally 1000 kVA. A fault on a primary feeder transformers connected on the loop. recommended to prevent closing all circuit or in one transformer will cause This system is typically most effective sectionalizing devices in the loop. Each 7 an outage to only those secondary when two services are available from primary loop sectionalizing switch and loads served by that feeder or trans- the utility as shown in Figure 1.1-3. Each the feeder breakers to the loop are former. In the case of a primary main primary loop is operated such that one interlocked such that to be closed they 8 bus fault or a utility service outage, of the loop sectionalizing switches is require a key (which is held captive service is interrupted to all loads until kept open to prevent parallel operation until the switch or breaker is opened) the trouble is eliminated. of the sources. When secondary unit and one less key than the number of 9 substations are used, each transformer key interlock cylinders is furnished. Reducing the number of transformers may have its own duplex (2-load break An extra key is provided to defeat the per primary feeder by adding more switches with load side bus connection) interlock under qualified supervision. 10 primary feeder circuits will improve the flexibility and service continuity of this system; the ultimate being one 11 secondary unit substation per primary Primary Main Breaker 1 52 52 Primary Main Breaker 2 feeder circuit. This of course increases the investment in the system but 52 12 minimizes the extent of an outage Tie resulting from a transformer or 52 52 Breaker 52 52 Loop Feeder Breaker primary feeder fault. Loop A 13 Primary connections from one secondary Loop B unit substation to the next secondary unit substation can be made with NC NO NC NC 14 “double” lugs on the unit substation Fault Sensors primary switch as shown, or with separable connectors made in 15 manholes or other locations. Depending on the load kVA connected 16 to each primary circuit and if no ground fault protection is desired for either the primary feeder conductors and trans- 17 formers connected to that feeder or NC NC NO NC NC NC the main bus, the primary main and/or feeder breakers may be changed to 18 primary fused switches. This will sig- nificantly reduce the first cost, but also decrease the level of conductor and 19 equipment protection. Thus, should a fault or overload condition occur, downtime increases significantly and 20 Secondary Unit Substations Consisting of: higher costs associated with increased Duplex Primary Switches/Fused Primary Switches/ damage levels and the need for fuse Transformer and Secondary Main Feeder Breakers replacement is typically encountered. 21 Figure 1.1-3. Loop Primary—Radial Secondary System

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In addition, the two primary main cable has been faulted, the loop sec- i Loop Loop breakers, which are normally closed, tionalizing switches on each side of the Feeder Feeder and primary tie breaker, which is faulted conductor can be opened, the Load Break normally open, are either mechanically loop sectionalizing switch that had ii Loop Switches or electrically interlocked to prevent been previously left open then closed paralleling the incoming source lines. and service restored to all secondary For slightly added cost, an automatic unit substations while the faulted 1 throw-over scheme can be added conductor is replaced. If the fault between the two main breakers and should occur in a conductor directly Fused tie breaker. During the more common on the load side of one of the loop Disconnect 2 Switch event of a utility outage, the automatic feeder breakers, the loop feeder transfer scheme provides significantly breaker is kept open after tripping and reduced power outage time. the next load side loop sectionalizing 3 switch manually opened so that the The system in Figure 1.1-3 has higher faulted conductor can be sectionalized costs than in Figure 1.1-2, but offers and replaced. 4 increased reliability and quick restora- tion of service when 1) a utility outage Note: Under this condition, all secondary occurs, 2) a primary feeder conductor unit substations are supplied through the 5 Figure 1.1-4. Secondary Unit Substation fault occurs, or 3) a transformer fault other loop feeder circuit breaker, and thus or overload occurs. all conductors around the loop should be Loop Switching sized to carry the entire load connected to Should a utility outage occur on one of the loop. Increasing the number of primary 6 loops (two loops shown in Figure 1.1-8) Main Source Alternate Source the incoming lines, the associated pri- mary main breaker is opened and the will reduce the extent of the outage from a conductor fault, but will also increase the 3-Position tie breaker closed either manually or Selector Switch system investment. 7 through an automatic transfer scheme. Vacuum Fault When a transformer fault or overload Interrupter (VFI) When a primary feeder conductor fault 8 occurs, the associated loop feeder occurs, the transformer primary fuses breaker opens and interrupts service open, and the transformer primary to all loads up to the normally open switch manually opened, disconnecting 9 primary loop load break switch the transformer from the loop, and (typically half of the loads). Once it is leaving all other secondary unit substation loads unaffected. 10 determined which section of primary

11 Primary Metal-Clad Figure 1.1-5. VFI /Selector Switch Switchgear Lineup Combination 52 52 Primary Main Breaker

12 Bus A 52 Bus B

Loop Feeder Loop Feeder 13 52 52 52 52 Primary Feeder Breaker

Feeder A1 Feeder B1 Feeder B2 4-Position To Other Substations 14 Partial Range T-Blade Feeder A2 Current-Limiting Fuse Sectionalizing Load-Break NO Bay-O-Net Switch 15 Expulsion Fuse NC

16 NO Typical Secondary Unit Substation Duplex Primary Switch/Fuses NC Transformer/600V Class 17 Secondary Switchgear

NO 18 Figure 1.1-6. Pad-Mounted Transformer Loop Switching NC 19 Figure 1.1-7. Basic Primary Selective—Radial Secondary System 20

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This means limited cable space espe- Primary cially if double lugs are furnished for i Feeders each line as shown in Figure 1.1-7 and 52 should a faulted primary conductor Load Break have to be changed, both lines would ii Loop A Loop A Switches have to be de-energized for safe changing of the faulted conductors. A second alternative is utilizing a 1 In cases where only one primary line three-position selector switch internal is available, the use of a single primary Fuses to the transformer, allowing only one breaker provides the loop connections to the loads as shown here. primary feeder to be connected to 2 the transformer at a time without the Figure 1.1-8. Single Primary Feeder— need for any interlocking. The selector Loop System switch is rated for load-breaking. 3 If overcurrent protection is also A basic primary loop system that required, a vacuum fault interrupter uses a single primary feeder breaker (VFI), also internal to the transformer, 4 connected directly to two loop feeder may be utilized, reducing floor space. switches which in turn then feed the Figure 1.1-9. Duplex Fused Switch in loop is shown in Figure 1.1-8. In this Two Structures In Figure 1.1-7 when a primary feeder 5 basic system, the loop may be normally fault occurs, the associated feeder operated with one of the loop section- One alternate to the duplex switch breaker opens and the transformers alizing switches open as described arrangement, a non-load break selector normally supplied from the faulted 6 above or with all loop sectionalizing switch mechanically interlocked with feeder are out of service. Then manu- switches closed. If a fault occurs in the a load break fused switch can be used ally, each primary switch connected to basic primary loop system, the single as shown in Figure 1.1-10. The non- the faulted line must be opened and 7 loop feeder breaker trips, and secondary load break selector switch is physically then the alternate line primary switch loads are lost until the faulted conductor located in the rear of the load break can be closed connecting the trans- is found and eliminated from the loop fused switch, thus only requiring one former to the live feeder, thus restoring 8 by opening the appropriate loop structure and a lower cost and floor service to all loads. Note that each of the sectionalizing switches and then space savings over the duplex primary circuit conductors for Feeder reclosing the breaker. arrangement. The non-load break A1 and B1 must be sized to handle the 9 switch is mechanically interlocked to sum of the loads normally connected 3. Primary Selective System— prevent its operation unless the load to both A1 and B1. Similar sizing of Secondary Radial System break switch is opened. The main Feeders A2 and B2, etc., is required. 10 disadvantage of the selector switch is The primary selective—secondary that conductors from both circuits are If a fault occurs in one transformer, radial system, as shown in Figure 1.1-7, terminated in the same structure. the associated primary fuses blow 11 differs from those previously described and interrupt the service to just in that it employs at least two primary the load served by that transformer. feeder circuits in each load area. It is Service cannot be restored to the loads 12 Primary normally served by the faulted designed so that when one primary Feeders circuit is out of service, the remaining transformer until the transformer feeder or feeders have sufficient is repaired or replaced. 13 capacity to carry the total load. Half Non-Load Break Selector Switches Cost of the primary selective— of the transformers are normally Inter- secondary radial system is greater connected to each of the two feeders. lock Load Break than that of the simple primary radial 14 When a fault occurs on one of the Disconnect system of Figure 1.1-1 because of the primary feeders, only half of the additional primary main breakers, tie load in the building is dropped. Fuses breaker, two-sources, increased number 15 Duplex fused switches as shown in of feeder breakers, the use of primary- Figure 1.1-7 and detailed in Figure 1.1-9 duplex or selector switches, and the may be utilized for this type of system. greater amount of primary feeder 16 Each duplex fused switch consists of cable required. The benefits from the two (2) load break three-pole switches reduction in the amount of load lost 17 each in their own separate structure, when a primary feeder is faulted, plus connected together by busbars on the the quick restoration of service to all load side. Typically, the load break Figure 1.1-10. Fused Selector Switch in or most of the loads, may more than 18 switch closest to the transformer One Structure offset the greater cost. Having two includes a fuse assembly with fuses. sources allows for either manual or Mechanical and/or key interlocking automatic transfer of the two primary 19 is furnished such that both switches main breakers and tie breaker should cannot be closed at the same time one of the sources become unavailable. (to prevent parallel operation) and 20 interlocking such that access to either switch or fuse assembly cannot be obtained unless both 21 switches are opened.

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The primary selective-secondary radial Each transformer secondary is If the loss of voltage was due to a i system, however, may be less costly or arranged in a typical double-ended failure of one of the transformers in more costly than a primary loop— unit substation arrangement as shown the double-ended unit substation, then secondary radial system of Figure 1.1-3 in Figure 1.1-11. The two secondary the associated primary fuses would ii depending on the physical location main breakers and secondary tie open taking only the failed transformer of the transformers while offering breaker of each unit substation are out of service, and then only the sec- comparable downtime and reliability. again either mechanically or electrically ondary loads normally served by the 1 The cost of conductors for the two interlocked to prevent parallel operation. faulted transformer would have to be types of systems may vary greatly Upon loss of secondary source voltage transferred to the opposite transformer. depending on the location of the on one side, manual or automatic In either of the above emergency 2 transformers and loads within the transfer may be used to transfer the conditions, the in-service transformer facility and greatly override primary loads to the other side, thus restoring of a double-ended unit substation switching equipment cost differences power to all secondary loads. would have to have the capability of 3 between the two systems. serving the loads on both sides of the This arrangement permits quick tie breaker. For this reason, transform- 4. Two-Source Primary— restoration of service to all loads when ers used in this application have equal a primary feeder or transformer fault 4 Secondary Selective System kVA rating on each side of the double- occurs by opening the associated ended unit substation and the normal This system uses the same principle secondary main and closing the operating maximum load on each 5 of duplicate sources from the power secondary tie breaker. If the loss transformer is typically about 2/3 base supply point using two primary main of secondary voltage has occurred nameplate kVA rating. Typically these breakers and a primary tie breaker. because of a primary feeder fault with transformers are furnished with 6 The two primary main breakers and the associated primary feeder breaker fan-cooling and/or lower than normal primary tie breaker being either opening, then all secondary loads temperature rise such that under manually or electrically interlocked normally served by the faulted feeder emergency conditions they can carry 7 to prevent closing all three at the same would have to be transferred to the on a continuous basis the maximum time and paralleling the sources. Upon opposite primary feeder. This means load on both sides of the secondary tie loss of voltage on one source, a manual each primary feeder conductor must be breaker. Because of this spare trans- 8 or automatic transfer to the alternate sized to carry the load on both sides of former capacity, the voltage regulation source line may be used to restore all the secondary buses it is serving provided by the double-ended unit power to all primary loads. under secondary emergency transfer 9 substation system under normal . conditions is better than that of the systems previously discussed. 10 The double-ended unit substation arrangement can be used in conjunction 52 52 Primary Main Breakers with any of the previous systems 11 52 discussed, which involve two primary sources. Although not recommended, 52 52 52 52 Primary Feeder Breakers if allowed by the utility, momentary 12 re-transfer of loads to the restored source may be made closed transition To Other Substations To Other Substations (anti-parallel interlock schemes would 13 have to be defeated) for either the Typical primary or secondary systems. Under Double-Ended Unit this condition, all equipment interrupt- 14 Substation ing and momentary ratings should be suitable for the fault current available from both sources. 15 For double-ended unit substations equipped with ground fault systems 16 special consideration to transformer neutral grounding and equipment operation should be made—see 17 “Grounding” and “Ground Fault Primary Fused Switch Transformer Tie Breaker Secondary Main Breaker Protection” in Section 1.4. Where two single-ended unit substations are 18 Figure 1.1-11. Two-Source Primary—Secondary Selective System connected together by external tie conductors, it is recommended that a tie breaker be furnished at each end 19 of the tie conductors.

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5. Sparing Transformer System Referring to Figure 1.1-12, it is apparent The sparing transformer system that the sparing concept backs up operates as follows: i The sparing transformer system concept primary switch and primary cable ■ came into use as an alternative to the failure as well. Restoration of lost or All main breakers, including capital cost intensive double-ended failed utility power is accomplished the sparing main breaker, are ii secondary unit substation distribution similarly to primary selective scheme normally closed; the tie breakers system (see Two-Source Primary— previously discussed. It is therefore are normally open Secondary Selective System). It essen- important to use an automatic thro- ■ Once a transformer (or primary 1 tially replaces double-ended substations wover system in a two source lineup cable or primary switch/fuse) fails, with single-ended substations and one of primary switchgear to restore utility the associated secondary main or more “sparing” transformer substa- power as discussed in the “Two-Source breaker is opened. The associated 2 tions all interconnected on a common Primary” scheme—see Figure 1.1-11. tie breaker is then closed, which secondary bus (see Figure 1.1-12). restores power to the single-ended A major advantage of the sparing substation bus Generally no more than three to five 3 transformer system is the typically ■ Schemes that require the main to single-ended substations are on a lower total base kVA of transformation. sparing loop. be opened before the tie is closed In a double-ended substation design, (“open transition”), and that allow 4 The essence of this design philosophy each transformer must be rated to any tie to be closed before the is that conservatively designed and carry the sum of the loads of two busses substation main is opened, loaded transformers are highly reliable and usually requires the addition of (“closed transition”) are possible 5 electrical devices and rarely fail. There- cooling fans to accomplish this rating. fore, this design provides a single com- In the “sparing” concept, each trans- With a closed transition scheme, it is mon backup transformer for a group of former carries only its own load, which common to add a timer function that 6 transformers in lieu of a backup trans- is typically not a fan-cooled rating. Major opens the tie breaker unless either space savings is also a benefit of this former for each and every transformer. main breaker is opened within a system in addition to first cost savings. This system design still maintains a time interval. 7 high degree of continuity of service. This closed transition allows power to be transferred to the sparing transformer without interruption, such 8 as for routine maintenance, and then back to the substation. This closed transition transfer has an advantage in 9 some facilities; however, appropriate K K K interrupting capacities and bus bracing must be specified suitable for the 10 momentary parallel operation. In facilities without qualified electrical 11 power operators, an open transition Sparing Transformer with key interlocking is often a prudent design. 12 Note: Each pair of “main breaker/tie breaker” K K key cylinders should be uniquely keyed to prevent any paralleled source operations. 13

Careful sizing of these transformers Typical Secondary Busway Loop as well as careful specification of the 14 transformers is required for reliability. Low temperature rise specified with continuous overload capacity or 15 upgraded types of transformers K K should be considered. Typical Single-Ended Substation 16 One disadvantage to this system is the external secondary tie system, see Figure 1.1-12. As shown, all single- 17 Figure 1.1-12. Sparing Transformer System ended substations are tied together on the secondary with a tie busway or cable system. Location of substations 18 is therefore limited because of voltage drop and cost considerations. 19

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Routing of busway, if used, must be The network relay is usually a solid- The optimum size and number of i carefully layed out. It should also be state microprocessor-based compo- primary feeders can be used in the noted, that a tie busway or cable fault nent integrated into the protector spot network system because the will essentially prevent the use of the enclosure that functions to automati- loss of any primary feeder and its ii sparing transformer until it is repaired. cally close the protector only when the associated transformers does not Commonly, the single-ended substa- voltage conditions are such that its result in the loss of any load even tions and the sparing transformer associated transformer will supply for an instant. In spite of the spare 1 must be clustered. This can also be power to the secondary network loads, capacity usually supplied in network an advantage, as more kVA can be and to automatically open the protec- systems, savings in primary switch- supported from a more compact tor when power flows from the sec- gear and secondary switchgear costs 2 space layout. ondary to the network transformer. often result when compared to a radial The purpose of the network protector system design with similar spare 6. Simple Spot Network Systems is to protect the integrity of the net- capacity. This occurs in many radial 3 The AC secondary network system work bus voltage and the loads served systems because more and smaller is the system that has been used for from it against transformer and pri- feeders are often used in order to mary feeder faults by quickly discon- minimize the extent of any outage 4 many years to distribute electric power in the high-density, downtown areas necting the defective feeder- when a primary fault event occurs. of cities, usually in the form of utility transformer pair from the network when backfeed occurs. In spot networks, when a fault occurs 5 grids. Modifications of this type of on a primary feeder or in a transformer, system make it applicable to serve The simple spot network system the fault is isolated from the system loads within buildings. resembles the secondary-selective through the automatic tripping of the 6 The major advantage of the secondary radial system in that each load area primary feeder circuit breaker and all network system is continuity of is supplied over two or more primary of the network protectors associated service. No single fault anywhere feeders through two or more trans- with that feeder circuit. This operation 7 on the primary system will interrupt formers. In network systems, the does not interrupt service to any loads. service to any of the system’s loads. transformers are connected through After the necessary repairs have been Most faults will be cleared without network protectors to a common made, the system can be restored to 8 interrupting service to any load. bus, as shown in Figure 1.1-13, from normal operating conditions by closing Another outstanding advantage that which loads are served. Because the the primary feeder breaker. All network the network system offers is its flexibil- transformers are connected in parallel, protectors associated with that feeder 9 ity to meet changing and growing load a primary feeder or transformer fault will close automatically. conditions at minimum cost and does not cause any service interrup- tion to the loads. The paralleled The chief purpose of the network bus minimum interruption in service to normally closed ties is to provide for 10 other loads on the network. In addition transformers supplying each load bus will normally carry equal load the sharing of loads and a balancing to flexibility and service reliability, the of load currents for each primary secondary network system provides currents, whereas equal loading of 11 the two separate transformers supply- service and transformer regardless of exceptionally uniform and good the condition of the primary services. voltage regulation, and its high ing a substation in the secondary- efficiency materially reduces the selective radial system is difficult to Also, the ties provide a means for 12 costs of system losses. obtain. The interrupting duty imposed isolating and sectionalizing ground on the outgoing feeder breakers in the fault events within the switchgear Three major differences between the network will be greater with the spot network bus, thereby saving a portion 13 network system and the simple radial network system. of the loads from service interruptions, system account for the outstanding yet isolating the faulted portion for advantages of the network. First, corrective action. 14 a network protector is connected in the secondary leads of each network transformer in place of, or in addition 15 to, the secondary main breaker, as Typical Feeder shown in Figure 1.1-13. Also, the Primary Circuit secondaries of each transformer in To Other Networks 16 a given location (spot) are connected Network Transformer together by a switchgear or ring bus from which the loads are served over Network Protector 17 short radial feeder circuits. Finally, the Fuses primary supply has sufficient capacity Optional Main, 50/51 to carry the entire building load with- Relaying and/or 18 out overloading when any one primary Network Disconnect Tie Tie Drawout feeder is out of service. Low Voltage LV Feeder NC NC Switchgear 19 A network protector is a specially designed heavy-duty air power breaker, spring close with electrical motor-charged Customer Customer Customer 20 mechanism, with a network relay to Loads Loads Loads control the status of the protector (tripped or closed). Figure 1.1-13. Three-Source Spot Network 21

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The use of spot network systems 7. Medium Voltage Distribution provides users with several important System Design i advantages. First, they save trans- Utility #1 Utility #2 former capacity. Spot networks permit A. Single Bus, Figure 1.1-14 equal loading of transformers under ii all conditions. Also, networks yield The sources (utility and/or generator(s)) Normal Standby lower system losses and greatly are connected to a single bus. All feeders improve voltage conditions. The are connected to the same bus. 1 voltage regulation on a network system is such that both lights and Utility power can be fed from the same 2 52 NC 52 NO load bus. Much larger motors can G be started across-the-line than on a simple radial system. This can result in 3 simplified motor control and permits the use of relatively large low voltage Loads motors with their less expensive 4 control. Finally, network systems Figure 1.1-15. Single Bus with Two-Sources 52 52 provide a greater degree of flexibility in adding future loads; they can be Retransfer to the “Normal” can be 5 connected to the closest spot Main Bus closed transition subject to the approval network bus. of the utility. Closed transition momen- tarily (5–10 cycles) parallels both 6 Spot network systems are economical utility sources. Caution: when both for buildings that have heavy concen- 52 sources are paralleled, the fault current trations of loads covering small areas, available on the load side of the main 7 with considerable distance between device is the sum of the available fault areas, and light loads within the One of Several Feeders current from each source plus the motor distances separating the concentrated fault contribution. It is recommended 8 loads. They are commonly used in Figure 1.1-14. Single Bus that the short-circuit ratings of the hospitals, high rise office buildings, bus, feeder breakers and all load side and institutional buildings where a This configuration is the simplest equipment are rated for the increased 9 high degree of service reliability is system; however, outage of the utility available fault current. If the utility required from the utility sources. results in total outage. requires open transfer, the disconnec- Spot network systems are especially tion of motors from the bus must be Normally the generator does not have 10 economical where three or more ensured by means of suitable time delay adequate capacity for the entire load. primary feeders are available. on reclosing as well as supervision A properly relayed system equipped of the bus voltage and its phase with with load shedding, automatic voltage/ 11 Principally, this is due to supplying respect to the incoming source voltage each load bus through three or frequency control may be able to more transformers and the reduction maintain partial system operation. This busing scheme does not preclude 12 in spare cable and transformer the use of cogeneration, but requires Any future addition of breaker sections capacity required. the use of sophisticated automatic syn- to the bus will require a shutdown of chronizing and synchronism checking the bus, because there is no tie breaker. 13 They are also economical when controls, in addition to the previously compared to two transformer double- B. Single Bus with Two Sources from the mentioned load shedding, automatic ended substations with normally frequency and voltage controls. opened tie breakers. Utility, Figure 1.1-15 14 Same as the single bus, except that This configuration is more expensive Emergency power should be connected two utility sources are available. than the scheme shown in Figure 1.1-14, to network loads downstream from This system is operated normally with but service restoration is quicker. Again, 15 the network, or upstream at primary the main breaker to one source open. a utility outage results in total outage to voltage, not at the network bus itself. Upon loss of the normal service, the the load until transfer occurs. Extension transfer to the standby normally of the bus or adding breakers requires 16 open (NO) breaker can be automatic a shutdown of the bus. or manual. Automatic transfer is preferred for rapid service restoration If paralleling sources, reverse current, 17 especially in unattended stations. reverse power and other appropriate relaying protection should be added as requested by the utility. 18

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C. Multiple Sources with Tie Breaker, In Figure 1.1-17, closing of the tie Summary i Figure 1.1-16 and Figure 1.1-17 breaker following the opening of a The medium voltage system configura- This configuration is similar to configu- main breaker can be manual or auto- tions shown are based on using metal- ration B. It differs significantly in that matic. However, because a bus can clad drawout switchgear. The service ii both utility sources normally carry the be fed through two tie breakers, the continuity required from electrical loads and also by the incorporation control scheme should be designed systems makes the use of single-source to make the selection. 1 of a normally open tie breaker. The systems impractical. outage to the system load for a utility The third tie breaker allows any bus outage is limited to half of the system. In the design of a modern medium to be fed from any utility source. voltage system, the engineer should: 2 Again, the closing of the tie breaker can be manual or automatic. The statements Caution for Figures 1.1-15, 1.1-16 and 1. Design a system as simple as made for the retransfer of scheme B 1.1-17: If continuous paralleling of possible. apply to this scheme also. sources is planned, reverse current, 3 2. Limit an outage to as small a reverse power and other appropriate portion of the system as possible. Utility #1 Utility #2 relaying protection should be added. 4 When both sources are paralleled for 3. Provide means for expanding the any amount of time, the fault current system without major shutdowns. available on the load side of the main 5 device is the sum of the available 4. Relay the system so that only the fault current from each source plus faulted part is removed from the motor fault contribution. It is service, and damage to it is mini- 6 52 NC 52 NC required that bus bracing, feeder mized consistent with selectivity. breakers and all load side equipment 5. Specify and apply all equipment NO is rated for the increased available Bus #1 Bus #2 within its published ratings and 7 52 fault current. national standards pertaining to the equipment and its installation.

8 52 52

9 Utility #1 Utility #2 Utility #3 Load Load 10 Figure 1.1-16. Two-Source Utility with Tie Breaker 11 If looped or primary selective distribu- tion system for the loads is used, the 52NC 52 NC 52 NC buses can be extended without a shut- down by closing the tie breaker and NO NO 12 transferring the loads to the other bus. Bus #1 Bus #2 Bus #3 52 52 This configuration is more expensive 13 than B. The system is not limited to two buses only. Another advantage is that 52 NO 52 Typical Feeder 52 52 52 NO the design may incorporate momentary 14 paralleling of buses on retransfer after Tie Busway the failed line has been restored to pre- vent another outage. See the Caution for Figure 1.1-17. Triple-Ended Arrangement 15 Figures 1.1-15, 1.1-16 and 1.1-17.

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Health Care Facilities ■ NFPA 101-2009—Life Safety Code The electrical system requirements for ■ NFPA 110-2010—Standard for Emer- the essential electrical system (EES) i Health care facilities are defined by gency and Standby Power Systems vary according to the type of health NFPA (National Fire Protection Agency) ■ NFPA 111-2010—Standard on Stored care facility. Health care facilities are as “Buildings or portions of buildings Electrical Energy Emergency and categorized by NFPA 99 as Type 1, ii in which medical, dental, psychiatric, Standby Power Systems Type 2 or Type 3 facilities. Some nursing, obstetrical, or surgical care example health care facilities, classified are provided.” Due to the critical nature These NFPA guidelines represent the by type, are summarized in the 1 of the care being provided at these most industry recognized standard following Ta b l e 1. 1- 8 . facilities and their increasing depen- requirements for health care electrical Table 1.1-8. Health Care Facilities dence on electrical equipment for pres- design. However, the electrical design 2 ervation of life, health care facilities engineer should consult with the Description Definition EES Type authorities having jurisdiction over have special requirements for the Hospitals NFPA 99 Chap. 13 Type 1 design of their electrical distribution the local region for specific electrical Nursing homes NFPA 99 Chap. 17 Type 2 3 systems. These requirements are distribution requirements. Limited care typically much more stringent than facilities NFPA 99 Chap. 18 Type 2 commercial or industrial facilities. Health Care Electrical System Ambulatory 4 The following section summarizes surgical Requirements 1 some of the unique requirements facilities NFPA 99 Chap. 14 Type 3 Other health of health care facility design. Health care electrical systems usually 1 5 consist of two parts: care facilities NFPA 99 Chap. 14 Type 3 1 There are several agencies and organi- If electrical life support or critical care areas zations that develop requirements 1. Non-essential or normal are present, then facility is classified as Type 1. 6 for health care electrical distribution electrical system. Type 1 Essential Electrical system design. The following is a 2. Essential electrical system. listing of some of the specific NFPA Systems (EES) 7 (National Fire Protection Agency) All electrical power in a health care standards that affect health care facility is important, though some Type 1 essential electrical systems facility design and implementation: loads are not critical to the safe opera- (EES) have the most stringent require- 8 tion of the facility. These “non-essential” ments for providing continuity of ■ NFPA 37-2010—Standard for or “normal” loads include things such electrical service and will, therefore, Stationary Combustion Engines as general lighting, general lab equip- be the focus of this section. Type 1 9 and Gas Turbines ment, non-critical service equipment, EES requirements meet or exceed ■ NFPA 70-2011—National patient care areas, etc. These loads are the requirements for Type 2 and Electrical Code not required to be fed from an alternate Type 3 facilities. 10 ■ NFPA 99-2005—Health Care Facilities source of power. 11 Normal Source Normal Source Normal Source Emergency Power Supply 12 G 13

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16 Non-Essential Loads Non-Essential Loads 17

Manual Transfer Switch 18 Equipment Life Safety Critical Delayed Automatic Transfer Switch System Branch Branch 19 Emergency System Automatic (Non-Delaying) Transfer Switch Essential Electrical System 20

Figure 1.1-18. Typical Large Hospital Electrical System—Type 1 Facility 21

CA08104001E For more information, visit: www.eaton.com/consultants 1.1-16 Power Distribution Systems System Design April 2016 Sheet 01 018

Sources: Type 1 systems are required Table 1.1-9. Type 1 EES Applicable Codes B. Critical branch—supplies power i to have a minimum of two independent Description Standard Section for task illumination, fixed equip- sources of electrical power—a normal ment, selected receptacles and source that generally supplies the Design NFPA 99 4.4.1.1.1 selected power circuits for areas ii entire facility and one or more alter- Sources NFPA 99 4.4.1.1.4 thru related to patient care. The 4.4.4.1.1.7.2 nate sources that supply power when Uses NFPA 99 4.4.1.1.8 (1-3) purpose of the critical branch the normal source is interrupted. The Emergency is to provide power to a limited 1 alternate source(s) must be an on-site Power Supply number of receptacles and loca- generator driven by a prime mover Classification NFPA 110 4 tions to reduce load and minimize unless a generator(s) exists as the Distribution NFPA 99 4.4.2 the chances of fault conditions. 2 normal power source. In the case NEC 517.30 The transfer switch(es) feeding the where a generator(s) is used as the critical branch must be automatic normal source, it is permissible for the Systems and Branches of Service: The type. They are permitted to have 3 alternate source to be a utility feed. Type 1 EES consists of two separate appropriate time delays that will Alternate source generators must be power systems capable of supplying follow the restoration of the life classified as Type 10, Class X, Level 1 power considered essential for life safety branch, but should have 4 gensets per NFPA 110 Tables 4.1(a) and safety and effective facility operation power restored within 10 seconds 4.2(b) that are capable of providing during an interruption of the normal of normal source power loss. power to the load in a maximum of power source. They are the emergency The critical branch provides power 5 10 seconds. Typically, the alternate system and the equipment system. to circuits serving the following sources of power are supplied to the areas and functions: 1. Emergency system—consists of loads through a series of automatic circuits essential to life safety and 6 and/or manual transfer switches (see 1. Critical care areas. critical patient care. Ta b 2 5 ). The transfer switches can 2. Isolated power systems in be non-delayed automatic, delayed The emergency system is an electrical special environments. 7 automatic or manual transfer depending sub-system that must be fed from an 3. Task illumination and selected on the requirements of the specific automatic transfer switch or series of receptacles in the following branch of the EES that they are feeding. automatic transfer switches. This patient care areas: infant 8 It is permissible to feed multiple emergency system consists of two nurseries, medication prep branches or systems of the EES from mandatory branches that provide power areas, pharmacy, selected 9 a single automatic transfer switch to systems and functions essential to acute nursing areas, psychiatric provided that the maximum demand life safety and critical patient care. bed areas, ward treatment on the EES does not exceed 150 kVA. rooms, nurses’ stations. This configuration is typically seen A. Life safety branch—supplies 10 in smaller health care facilities that power for lighting, receptacles 4. Specialized patient care task must meet Type 1 EES requirements and equipment to perform the illumination, where needed. following functions: 11 (see Figure 1.1-19). 5. Nurse call systems. 1. Illumination of means of egress. 6. Blood, bone and tissue banks. Normal Source 2. Exit signs and exit direction signs. 7. Telephone equipment rooms and closets. 12 3. Alarms and alerting systems. 8. Task illumination, selected Alternate 4. Emergency communications Source receptacles and selected power systems. 13 circuits for the following: general G 5. Task illumination, battery care beds (at least one duplex chargers for battery powered receptacle), angiographic labs, 14 lighting, and select receptacles cardiac catheterization labs, at the generator. coronary care units, hemodialysis 6. Elevator lighting control, com- rooms, selected emergency 15 munication and signal systems. room treatment areas, human 7. Automatic doors used for egress. physiology labs, intensive care units, selected postoperative 16 Non-Essential Loads These are the only functions recovery rooms. permitted to be on the life safety 9. Additional circuits and single- 17 Entire Essential branch. Life safety branch equip- phase fraction motors as needed Electric System ment and wiring must be entirely for effective facility operation. (150 kVA or Less) independent of all other loads and branches of service. This 18 Figure 1.1-19. Small Hospital Electrical includes separation of raceways, System—Single EES Transfer Switch boxes or cabinets. Power must be supplied to the life safety branch 19 from a non-delayed automatic transfer switch. 20

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Table 1.1-10. Type 1—Emergency System The following equipment must be and must be shed in the event the Applicable Codes arranged for delayed automatic or generator enters an overload condition. i Description Standard Section manual transfer to the emergency power supply: Ground fault protection—per NFPA 70 General NFPA 99 4.4.2.2.2 NEC Article 230.95, ground fault ii NEC 517.31 1. Select heating equipment. protection is required on any feeder or Life safety NFPA 99 4.4.2.2.2.2 2. Select elevators. service disconnect 1000 A or larger on branch NEC 517.32 systems with line to ground voltages 3. Supply, return and exhaust 1 Critical branch NFPA 99 4.4.2.2.2.3 of 150 V or greater and phase-to-phase NEC 517.33 ventilating systems for surgical, voltages of 600 V or less. For health care obstetrical, intensive care, Wiring NFPA 99 4.4.2.2.4 facilities (of any type), a second level of 2 NEC 517.30(C) coronary care, nurseries and ground fault protection is required to emergency treatment areas. be on the next level of feeder down- 2. Equipment system—consists of 4. Supply, return and exhaust stream. This second level of ground 3 major electrical equipment necessary ventilating systems for airborne fault is only required for feeders that for patient care and Type 1 operation. infectious/isolation rooms, labs and serve patient care areas and equipment medical areas where hazardous intended to support life. 100% selective 4 The equipment system is a subsystem materials are used. coordination of the two levels of ground of the EES that consists of large electrical 5. Hyperbaric facilities. fault protection must be achieved with a equipment loads needed for patient minimum six-cycle separation between 5 care and basic hospital operation. 6. Hypobaric facilities. the upstream and downstream device. Loads on the equipment system that 7. Autoclaving equipment. are essential to generator operation are New in the 2011 NEC, ground fault required to be fed by a non-delayed 8. Controls for equipment listed above. protection is now allowed between 6 automatic transfer switch. 9. Other selected equipment in the generator(s) and the EES transfer kitchens, laundries, radiology switch(es). However, NEC 517.17(B) pro- The following equipment must be rooms and central refrigeration hibits the installation of ground fault 7 arranged for delayed automatic transfer as selected. protection on the load side of a transfer to the emergency power supply: switch feeding EES circuits (see Figure Table 1.1-11. Type 1—Equipment System 1.1-20—additional level of ground fault). 8 1. Central suction systems for medical Applicable Codes and surgical functions. Careful consideration should be used in Description Standard Section applying ground fault protection on the 2. Sump pumps and other equipment 9 essential electrical system to prevent required for the safe operation of General NFPA 99 4.4.2.2.3 a ground fault that causes a trip of the a major apparatus. NEC 517.34 Equipment NFPA 99 4.4.2.2.3 (3-5) normal source to also cause a trip on 10 3. Compressed air systems for NEC 517.34(A)-(B) the emergency source. Such an event medical and surgical functions. could result in complete power loss of 4. Smoke control and stair Any loads served by the generator that both normal and emergency power 11 pressurization systems. are not approved as outlined above as sources and could not be recovered until the source of the ground fault 5. Kitchen hood supply and exhaust part of the essential electrical system was located and isolated from the systems, if required to operate must be connected through a separate 12 system. To prevent this condition, during a fire. transfer switch. These transfer switches must be configured such that the loads NEC 700.26 removes the ground fault will not cause the generator to overload protection requirement for the 13

Normal Source Normal Source(s) G 14 Generator Breakers are Typically Supplied with 480/277V ¿ 480/277V 11480/277 V Ground Fault Alarm 15 1000 A Service 1000 A Service 1000 A Service Only. (NEC 700.26) GF GF GF or Larger Entrance or Larger Entrance or Larger Entrance Ground Fault 16 is Permitted Additional Level Between Generator GFGFGF GFGF of Ground Fault GFGFGF GFGFGF and EES Transfer 17 Protection Switches. (NEC 517.17(B))

Non-Essential Loads Non-Essential Loads 18

19 GF = Ground Fault Protection Required Additional Level of Ground Fault is not Permitted on Load Side of EES Essential Electrical System Transfer Switches. (NEC 517.17a(2)) 20 Figure 1.1-20. Additional Level of Ground Fault Protection 1 Ground fault protection is required for service disconnects 1000 A and larger or systems with less than 600 V phase-to-phase and greater than 150 V to 21 ground per NEC 230.95.

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emergency system source. Typically, Maintenance and Testing trained in development and execution i the emergency system generator(s) Regular maintenance and testing of of annual preventative maintenance are equipped with ground fault alarms the electrical distribution system in procedures of health care facility that do not automatically disconnect a health care facility is necessary to electrical distribution systems. ii power during a ground fault. ensure proper operation in an emer- Paralleling Emergency Generators Table 1.1-12. Ground Fault Protection gency and, in some cases, to maintain Applicable Codes government accreditation. Any health 1 care facility receiving Medicare or Without Utility Paralleling Description Standard Section Medicaid reimbursement from the In many health care facilities (and Services NEC 230.95 government must be accredited by other large facilities with critical 2 Feeders NEC 215.10 the Joint Commission on Accreditation loads), the demand for standby Additional level NEC 517.17 of Health Care Organizations (JCAHO). emergency power is large enough 3 NFPA 99 4.3.2.5 JCAHO has established a group of to require multiple generator sets to Alternate source NEC 700.26 standards called the Environment of power all of the required essential NEC 701.26 Care, which must be met for health electrical system (EES) loads. In many care facility accreditation. Included in cases, it becomes more flexible and 4 Wet procedure locations—A wet these standards is the regular testing easier to operate the required multiple procedure location in a health care of the emergency (alternate) power generators from a single location using facility is any patient care area that system(s). Diesel-powered EPS instal- generator paralleling switchgear. 5 is normally subject to wet conditions lations must be tested monthly in Figure 1.1-21 on Page 1.1-19 shows while patients are present. Typical wet accordance with NFPA 110 Standard an example of a typical one-line for a procedure locations can include oper- for Emergency and Standby Power paralleling switchgear lineup feeding 6 ating rooms, anesthetizing locations, Systems. Generators must be tested the EES. dialysis locations, etc. (Patient beds, for a minimum of 30 minutes under A typical abbreviated sequence of toilets and sinks are not considered the criteria defined in NFPA 110. operation for a multiple emergency 7 wet locations.) These wet procedure generator and ATS system follows. locations require special protection One method to automate the task of Note that other modes of operation to guard against electric shock. The monthly generator tests is through the ® such as generator demand priority and 8 ground fault current in these areas use of Power Xpert communications. automated testing modes are available must be limited to not exceed 6 mA. With the Power Xpert integrated meter- ing, monitoring and control system, a but are not included below. (Reference 9 In areas where the interruption of power facility maintenance director can initiate Ta b 4 1 for complete detailed is permissible, ground fault circuit a generator test, control/monitor sequences of operation.) interrupters (GFCI) can be employed. loads, meter/monitor generator test 1. Entering emergency mode 10 GFCIs will interrupt a circuit when points and create a JCAHO compliant ground fault current exceeds 5 mA report automatically from a central PC. a. Upon loss of normal source, (±1 mA). The report contains all metered values, automatic transfer switches 11 test results, date/time information, etc. send generator control system In areas where the interruption of necessary to satisfy JCAHO require- a run request. power cannot be tolerated, protection ments. This automated generator testing 12 from ground fault currents is accom- b. All available generators are procedure reduces the labor, training started. The first generator up plished through the use of an isolated and inaccuracies that occur during power system. Isolated power systems to voltage and frequency is manual emergency power system tests. closed to the bus. 13 provide power to an area that is iso- (See Power Monitoring Tab 2.) lated from ground (or ungrounded). c. Unsheddable loads and load This type of system limits the amount Table 1.1-14. Maintenance and Testing shed Priority 1 loads are pow- 14 of current that flows to ground in Applicable Codes ered in less than 10 seconds. the event of a single line-to-ground Description Standard Section d. The remaining generators are fault and maintains circuit continuity. synchronized and paralleled Electronic line isolation monitors (LIM) Grounding NFPA 99 4.3.3.1 15 to the bus as they come up to are used to monitor and display leakage Emergency power NFPA 99 4.4.4.1.1 voltage and frequency. currents to ground. When leakage system JCAHO EC.2.14(d) 16 current thresholds are exceeded, visible Generator NFPA 110 8.4 e. As additional generators are and/or audible alarms are initiated to Transfer switches NFPA 110 8.3.5, 8.4.6 paralleled to the emergency bus, load shed priority levels alert occupants of a possible hazardous Breakers NFPA 99 4.4.4.1.2 17 condition. This alarm occurs without NFPA 110 8.4.7 are added, powering their interrupting power to allow for the associated loads. safe conclusion of critical procedures. Routine maintenance should be f. The system is now in 18 performed on circuit breakers, transfer emergency mode.

Table 1.1-13. Wet Procedure Location switches, switchgear, generator equip- Applicable Codes 2. Exit from emergency mode ment, etc. by trained professionals 19 Description Standard Section to ensure the most reliable electrical a. Automatic transfer switches General NFPA 99 4.3.2.2.9 system possible. See Ta b 4 1 for Eaton’s sense the utility source is NEC 517.20 Electrical Services & Systems (EESS), within acceptable operational 20 Isolated power NFPA 99 4.3.2.6 which provides engineers, tolerances for a time duration systems NEC 517.160 set at the automatic transfer switch. 21

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b. As each automatic transfer With Utility Paralleling Many health care facilities are taking switch transfers back to utility Today, many utilities are offering their advantage of these utility incentives i power, it removes its run customers excellent financial incen- by adding generator capacity over request from the generator tives to use their on-site generation and above the NFPA requirements. plant. capacity to remove load from the utility Figure 1.1-22 on Page 1.1-20 shows ii c. When the last automatic trans- grid. These incentives are sometimes an example one-line of a health care fer switch has retransferred to referred to as limited interruptible facility with complete generator the utility and all run requests rates (LIP). Under these incentives, backup and utility interconnect. 1 have been removed from the utilities will greatly reduce or eliminate NFPA 110 requirements state that the generator plant, all generator kWhr or kW demand charges to their normal and emergency sources must 2 circuit breakers are opened. customers with on-site generation be separated by a fire-rated wall. d. The generators are allowed capabilities. In exchange, during times to run for their programmed of peak loading of the utility grid, the The intent of this requirement is so that 3 cool-down period. utility can ask their LIP rate customers a fire in one location cannot take out to drop load from the grid by using both sources of power. To meet this e. The system is now back in their on-site generation capabilities. requirement, the paralleling switchgear automatic/standby mode. must be split into separate sections 4 Health care facilities are ideally suited with a tie bus through a fire-rated wall. to take advantage of these programs For more information on generator because they already have significant paralleling switchgear, see Ta b 4 0 . 5 on-site generation capabilities due to the code requirements described. 6

Utility 7 Transformer Generators X = Number of Units 8 Utility G1 G2 Gx Metering 9 Typical Generator Breaker Service Main 10

Normal Bus Emergency Bus 11

Optional Optional Electrically Electrically Operated Stored 12 Operated Energy Breakers EF1 EF2 EFx Stored F1 F2 Fx Energy Breakers 13

14 Equipment Life Safety Critical Load Shed/Load ATS # 1 ATS # 2 ATS # X Add ATS Units Non-Essential 15 Loads

Optional Closed EP1 EP2 Typical EPX Tr ansition 16 Panelboards Paralleling of Generators and Utility 17 Figure 1.1-21. Typical One-Line for a Paralleling Switchgear Lineup Feeding the Essential Electrical System (EES) 18

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i Utility Fire-Rated Wall or Separation Barrier

Transformer ii Generators X = Number of Units

Utility G1 G2 Gx 1 Metering Utility Closed Protective Tr ansition Typical 2 Relay Paralleling of Generator Generators and Breaker Service Main Utility, Plus 3 Soft Loading/ Unloading Normal Bus Emergency Bus 4 TIE Optional TIE Optional Electrically Operated Electrically Stored Energy Field Installed Operated Breakers 5 Cable or Busway Stored F1 F2 Fx EF1 EF2 EFx Energy 6 Breakers

7 Equipment Life Safety Critical Load Shed/ ATS # 1 ATS # 2 ATS # X Load Add Non-Essential ATS Units 8 Loads

EP1 EP2 EPX Typical 9 Panelboards

10 Figure 1.1-22. Typical One-Line Health Care Facility with Complete Generator Backup and Utility Interconnect

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Generators and a supply-side bonding jumper to Types of Generators be installed from the source of a i Generator Systems separately derived system to the first Generators can be either synchronous disconnecting means in accordance or asynchronous. Asynchronous with 250.30(A)(2). Another new generators are also referred to as ii requirement, 250.30(C)—Outdoor induction generators. The construction Source—has been added, and requires is essentially the same as an induction a grounding electrode connection at motor. It has a squirrel-cage rotor and 1 the source location when the separately wound stator. An induction generator derived system is located outside is a motor driven above its designed of the building or the structure synchronous speed thus generating 2 being supplied. power. It will operate as a motor if it is running below synchronous speed. Typical Diesel Genset—Caterpillar Article 445.19—Generators Supplying The induction generator does not have 3 Multiple Loads—has been revised an exciter and must operate in parallel Introduction to require that the generator have with the utility or another source. The induction generator requires VARs from The selection and application overcurrent protection per 240.15(A) 4 an external source for it to generate of generators into the electrical when using individual enclosures power. The induction generator distribution system will depend on tapped from a single feeder. operates at a slip frequency so its the particular application. There are 5 Article 517.17(B)—Feeder GFP (Health output frequency is automatically many factors to consider, including Care Facilities)—now allows, but does locked in with the utility's frequency. code requirements, environmental not require, multiple levels of GFPE constraints, fuel sources, control upstream of the transfer switch when An induction generator is a popular 6 complexity, utility requirements and the choice is made to provide GFPE choice for use when designing load requirements. The health care on the alternate power source cogeneration systems, where it will requirements for legally required (i.e., generator). operate in parallel with the utility. 7 emergency standby generation This type of generator offers certain systems are described starting on Article 701.6(D)—Signals (Legally advantages over a synchronous Page 1.1-15. Systems described in Required Standby Systems)—now generator. For example, voltage and 8 this section are applicable to health requires ground fault indication for frequency are controlled by the utility; care requirements, as well as other legally required standby systems of thus voltage and frequency regulators facilities that may require a high more than 150 V to ground and OCPDs are not required. In addition, the 9 degree of reliability. The electrical rated 1000 A or more. generator construction offers high supply for data centers, financial reliability and little maintenance. institutions, telecommunications, Types of Engines Also, a minimum of protective relays 10 government and public utilities Many generator sets are relatively and controls are required. Its major also require high reliability. Threats small in size, typically ranging from disadvantages are that it requires 11 of disaster or terror attacks have several kilowatts to several megawatts. VARs from the system and it normally prompted many facilities to require These units are often required to come cannot operate as a standby/ complete self-sufficiency for online and operate quickly. They need emergency generator. 12 continuous operation. to have the capacity to run for an Synchronous generators, however, extended period of time. The internal are the most common. Their output is 2011 NEC Changes Related to combustion engine is an excellent determined by their field and governor 13 choice as the prime mover for the Generator Systems controls. Varying the current in the majority of these applications. Turbines Article 250.30—Grounding Separately DC field windings controls the voltage may also be used. Diesel-fueled Derived AC Systems—has been output. The frequency is controlled 14 engines are the most common, but completely rewritten for clarity and by the speed of rotation. The torque other fuels used include natural gas, for usability. Most notably, the term applied to the generator shaft by digester gas, landfill gas, propane, equipment bonding jumper was the driving engine controls the power 15 biodiesel, crude oil, steam and others. changed to supply-side bonding output. In this manner, the synchro- jumper (see 250.30(A)(2)). This was Some campuses and industrial nous generator offers precise control necessary to ensure proper identifica- facilities use and produce steam over the power it can generate. In 16 tion and installation of bonding for heating and other processes. cogeneration applications, it can be conductors within or on the supply These facilities may find it economically used to improve the power factor of side of service equipment and feasible to produce electricity as a the system. 17 between the source of a separately byproduct of the steam production. derived system and the first discon- These installations would typically necting means. The other require- be classified as a cogeneration facility 18 ments for grounded systems were producing a fairly constant power renumbered to accommodate the output and operating in parallel with 250.30(A)(2) change. 250.30(B)(3)— the electric utility system. 19 Ungrounded Systems—has been added, and this language requires 20

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Generator Systems Multiple Isolated Standby Generators Multiple generator systems have a i The second type of generator system more complex control and protection Emergency Standby Generator System is a multiple isolated set of standby requirement as the units have to be There are primarily three types of generators. Figure 1.2-2 shows synchronized and paralleled together. ii generator systems. The first and multiple generators connected to The generators are required to share simplest type is a single generator a paralleling bus feeding multiple the load proportionally without swings that operates independently from transfer switches. The utility is the or prolonged hunting in voltage or 1 the electric utility power grid. normal source for the transfer switches. frequency for load sharing. They may This is typically referred to as an The generators and the utility are never also require multiple levels of load emergency standby generator continuously connected together in this shedding and/or load restoration 2 system. Figure 1.2-1 shows a single scheme. Multiple generators may be schemes to match generation capacity. standby generator, utility source required to meet the load requirements Multiple Generators Operating in and a transfer switch. In this case, the (N system). Generators may be applied Parallel with Utility System 3 load is either supplied from the utility in an N+1 or a 2N system for improved or the generator. The generator and system reliability. The third type of system is either one the utility are never continuously with a single or multiple generators 4 connected together. This simple radial that operate in parallel with the utility system has few requirements for Utility system. Figure 1.2-3 shows two protection and control. It also has the G1 G2 generators and a utility source feeding 5 least impact on the complete electric a switchgear lineup feeding multiple loads. This system typically requires power distribution system. It should Switchgear be noted that this type of generator generator capacity sufficient to carry 6 system improves overall electrical the entire load or sophisticated load shedding schemes. This system will reliability but does not provide the ATS-1 ATS-2 redundancy that some facilities require require a complete and complex 7 if the generator fails to start or is out protection and control scheme. The for maintenance. electric utility may have very stringent Load 1 Load 2 and costly protection requirements 8 for the system. IEEE standard 1547 Utility describes the interconnection require- Figure 1.2-2. Multiple Isolated Set of ments for paralleling to the utility. 9 G1 Standby Generators In an N system, where N is the number Utility of generators required to carry the G1 G2 10 load; if a generator fails or is out for maintenance, then the load may be dropped. This is unacceptable for most Switchgear 11 critical 24/7 operations. In an N + 1 ATS system, N is the number of generators 12 needed to carry the load and 1 is an extra generator for redundancy. If one generator fails to start or is out for maintenance, it will not affect the 13 Load Load 1 Load 2 Load 3 load. In a 2N system, there is complete 100% redundancy in the standby 14 Figure 1.2-1. Emergency Standby generation system such that the failure Figure 1.2-3. Multiple Generators Operating Generator System of one complete set of generators in Parallel with Utility System will not affect the load. 15

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Generator Fundamentals The application of generators requires derived system and a four-pole transfer special protection requirements. switch is required or ground fault relays i A generator consists of two primary The size, voltage class, importance could misoperate and unbalanced neu- components, a prime mover and an and dollar investment will influence tral current may be carried on ground alternator. The prime mover is the the protection scheme associated with conductors. ii energy source used to turn the rotor the generator(s). Mode of operation of the alternator. It is typically a An IEEE working group has studied the will influence the utility company’s practice of low resistance grounding diesel combustion engine for most interface protection requirements. 1 emergency or standby systems. of medium voltage generators within Paralleling with the electric utility is the general industry. This “working In cogeneration applications, the the most complicated of the utility prime mover may come from a steam group” found that, for internal generator inter-tie requirements. IEEE ANSI 1547 ground faults, the vast majority of the 2 driven turbine or other source. On provides recommended practices. diesel units, a governor and voltage damage is done after the generator regulator are used to control the speed Generator Grounding and Bonding breaker is tripped offline, and the field and power output. and turbine are tripped. This is due to 3 (Ref. NEC 2011, Article 250.30(A)(1) the stored energy in the generator flux The alternator is typically a synchro- and (2)) that takes several seconds to dissipate nous machine driven by the prime after the generator is tripped offline. 4 mover. A voltage regulator controls its Generator grounding methods need It is during this time that the low voltage output by adjusting the field. to be considered and may affect the resistance ground allows significant The output of a single generator or distribution equipment and ratings. amounts of fault current to flow into 5 multiple paralleled generator sets is Generators may be connected in delta the ground fault. Because the large fault controlled by these two inputs. The or wye, but wye is the most typical currents can damage the generator’s alternator is designed to operate at a connection. A wye-connected generator winding, application of an alternate 6 specified speed for the required output can be solidly grounded, low impedance protection method is desirable during frequency, typically 60 or 50 Hz. The grounded, high impedance grounded this time period. One of the solutions voltage regulator and engine governor or ungrounded. Section 1.4 discusses set forth by this “working group” is 7 along with other systems define the general grounding schemes, benefits a hybrid high resistance grounding generator’s response to dynamic of each and protection considerations. (HHRG) scheme as shown in load changes and motor starting A solidly grounded generator may have Figure 1.2-4. In the HHRG scheme, 8 characteristics. a lower zero sequence impedance than the low resistance ground (LRG) is quickly tripped offline when the Generators are rated in power and its positive sequence impedance. In this generator protection senses the 9 voltage output. Most generators are case, the equipment will need to be rated ground fault. The LRG is cleared designed to operate at a 0.8 power for the larger available ground fault at the same time that the generator factor. For example, a 2000 kW current. The generator’s neutral may breaker clears, leaving the high 10 generator at 277/480 V would have a be connected to the system-neutral; if resistance ground portion connected kVA rating of 2500 kVA (2000 kW/ it is, the generator is not a separately to control the transient overvoltages 08 pf) and a continuous current rating derived system and a three-pole transfer ··· during the coast-down phase of the 11 of 3007A2500 kVA 480V 3 . switch is used. If the generator’s neutral is bonded to ground separate from the generator, thereby all but eliminating Typical synchronous generators system-neutral, it is a separately generator damage. for industrial and commercial 12 power systems range in size from 100–3000 kVA and from 208 V–13,800 V. Other ratings are available and these HRG 13 discussions are applicable to those 51G ratings as well. Gen R 59G 86 14 Generators must be considered in the LRGR Phase 87GN short-circuit and coordination study Relays as they may greatly impact the rating 15 of the electrical distribution system. This is especially common on large installations with multiple generators 16 and systems that parallel with the utility source. Short-circuit current contribution from a generator 17 typically ranges from 8 to 12 times full load amperes. Figure 1.2-4. Hybrid High Resistance Grounding Scheme 18

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CA08104001E For more information, visit: www.eaton.com/consultants 1.2-4 Power Distribution Systems Generator System Design April 2016 Sheet 01 026

Generator Controls A synch-scope is typically supplied The subtransient reactance Xd” will i on paralleling gear. The synch-scope range from a minimum of approxi- The engine generator set has controls displays the relative relationship mately 9% for a two-pole, wound-rotor to maintain the output frequency between voltage phasors on the machine to approximately 32% for a ii (speed) and voltage. These controls generator to be paralleled and the low-speed, salient-pole, hydro-generator. consist of a governor and voltage bus. If the generator is running slower The initial symmetrical fault current regulator. As loads change on the than the bus (less than 60 Hz) then the can be as much as 12 times full 1 system, the frequency and voltage needle on the scope will spin in the load current. will change. The speed control will counterclockwise direction. If it is then adjust the governor to correct running faster, then it will rotate in Depending on the generator type, 2 for the load (kW) change. The the clockwise direction. The greater the zero sequence impedance may be voltage regulator will change the the frequency difference, the faster less than the subtransient reactance field current to adjust the voltage is the rotation. It is important that the and the ground fault current substan- 3 to the desired voltage value. These generators are in phase before they tially higher than the three-phase are the basic controls found on all are paralleled. Severe damage will short-circuit current. For example, a synchronous generators. occur if generators are paralleled 2500 kVA, 480/277 V, four-pole, 2/3 4 out-of-phase. pitch standby generator has a 0.1411 Multiple generator systems require per unit subtransient reactance Xd” more sophisticated controls. Generators and a 0.033 per unit zero sequence Xo are paralleled in a multi-generator Generator Short-Circuit reactance. The ground current is 5 system and they must share the load. Characteristics approximately a third larger than the These systems often have a load shed three-phase fault current. The ground scheme, which adds to the complexity. 6 If a short circuit is applied directly to fault current can be reduced to the Multiple generator schemes need a the output terminals of a synchronous three-phase level by simply adding a master controller to prevent units from generator, it will produce an extremely small reactance between the generator 7 being connected out-of-phase. The high current initially, gradually decaying neutral and ground while still being sequence of operation is to send a to a steady-state value. This change considered solidly grounded. start signal to all generators simulta- is represented by a varying reactive The electric power system analysis 8 neously. The first unit up to frequency impedance. Three specific reactances must be performed based on the worst- and voltage will be permitted to close are used for short-circuit fault currents. case operating conditions. Typically its respective breaker and energize the They are: this is when all sources are paralleled. 9 paralleling bus. Breakers for the other ■ If the system can operate with both generators are held open, not permit- Subtransient reactance Xd”, which is used to determine the fault the utility supply and generators in ted to close, until certain conditions parallel, then the equipment must be 10 are met. Once the paralleling bus is current during the first 1 to 5 cycles ■ Transient reactance Xd’, which is rated for the combined fault current energized, the remaining generators plus motor contribution. If the generator must be synchronized to it before used to determine the fault current 11 during the next 5 to 200 cycles and utility will not be paralleled, then the generators can be paralleled. both cases will need to be looked at ■ Synchronization compares the voltage Synchronous reactance Xd”, which is independently and the worst case used phasor’s angle and magnitude. Both used to determine the steady- state for selecting the equipment ratings. 12 generators must be operating at the fault current same frequency and phase-matched within typically 5 to 10 degrees with 13 each other. The voltage magnitude typically must be within 20 to 24%. 14

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For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.2-5 April 2016 Generator System Design Sheet 01 027

Generator Protection Generator Protection ANSI/IEEE i Generator protection will vary and Std 242-1986 depend on the size of the generator, type of system and importance of the ii generator. Generator sizes are defined 1 1 1 1 as: small—1000 kVA maximum up Alternate 51 51V 32 40 to 600 V (500 kVA maximum when Location 1 above 600 V); medium over 1000 kVA to 12,500 kVA maximum regardless of voltage; large—from 12,500– 2 50,000 kVA. The simplest is a single generator system used to feed emer- 1 3 gency and/or standby loads. In this 51G 3 case, the generator is the only source Gen 87 available when it is operating and 1 it must keep operating until the 51 Preferred 4 normal source returns. Location Gen Figure 1.2-5 Part (A) shows minimum 1 5 recommended protection for a single 51G generator used as an emergency or standby system. Phase and ground (A) (A) Single Isolated Generator on Low Voltage System (B) 6 time overcurrent protection (Device (B) Multiple Isolated Generator on Medium Voltage System 51 and 51G) will provide protection for external faults. For medium voltage generators, a voltage controlled time Figure 1.2-5. Typical Protective Relaying Scheme for Small Generators 7 overcurrent relay (Device 51V) is recommended for the phase protec- tion as it can be set more sensitive 8 than standard overcurrent relays and R is less likely to false operate on normal overloads. This scheme may not 9 provide adequate protection for internal generator faults when no 50/5A 87-1 other power source exists. Local 10 generator controllers may offer 50/5A 87-2 additional protection for voltage 11 and frequency conditions outside the generator’s capabilities. 50/5A 87-3 Figure 1.2-5 Part (B) shows the 12 recommended protection for multiple, isolated, medium voltage, small generators. Additional protection 13 may be desired and could include generator differential, reverse power, and loss of field protection. Differential Gen 14 protection (Device 87) can be accom- plished with either a self-balancing set of CTs as in Figure 1.2-6 or with 15 a percentage differential scheme as in Figure 1.2-7 on Page 1.2-6. The percentage differential scheme 16 offers the advantage of reducing the Figure 1.2-6. Self-Balancing Generator possibility for false tripping due to Differential Relay Scheme CT saturation. The self-balancing 17 scheme offers the advantages of increased sensitivity, needing three current transformers in lieu of six, 18 and the elimination of current transformer external wiring from the generator location to the generator 19 switchgear location. 20

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CA08104001E For more information, visit: www.eaton.com/consultants 1.2-6 Power Distribution Systems Generator System Design April 2016 Sheet 01 028

Reverse power protection (Device 32) i is used to prevent the generator from being motored. Motoring could Grounding Resistor damage (with other hazards) the prime ii mover. A steam turbine could overheat 51G and fail. A diesel or gas engine could either catch fire or explode. A steam 1 turbine can typically withstand approx- imately 3% reverse power where a diesel engine can withstand up to 25% 2 reverse power.

Loss of field protection (Device 40) is 87 3 needed when generators are operating in parallel with one another or the 01 R1 PC power grid. When a synchronous R1 generator loses its field, it will continue 4 02 R2 to generate power as an induction Gen R2 generator obtaining its excitation from OC 5 the other machines on the system. 03 R3 During this condition, the rotor will 87G R3 quickly overheat due to the slip 6 frequency currents induced in it. Loss of excitation in one machine could jeopardize the operation of the other 7 machines beyond their capability and 52 the entire system. 8

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To Main Bus OC = Operating coil PC = Permissive coil 10 Figure 1.2-7. Generator Percentage Differential Relay (Phase Scheme) and Ground Differential Scheme Using a Directional Relay 11

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For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.2-7 April 2016 Generator System Design Sheet 01 029

Typical protection for larger generators is shown in Figure 1.2-8. It adds i phase unbalance and field ground fault protection. Phase unbalance 3 (Device 46) or negative sequence ii 87B overcurrent protection prevents the 81U/O generator’s rotor from overheating damage. Unbalanced loads, fault 1 conditions or open phasing will produce a negative sequence current 27/59 to flow. The unbalanced currents 2 induce double system frequency currents in the rotor, which quickly causes rotor overheating. Serious 3 1 1 1 3 damage will occur to the generator if 51V 40 32 46 the unbalance is allowed to persist. 3 1 4 Other protection functions such as 87 87G under/overvoltage (Device 27/59) could 60 be applied to any size generator. The Voltage Regulator and 5 voltage regulator typically maintains Metering Circuits the output voltage within its desired 1 output range. This protection can 1 64 6 provide backup protection in case the 49 voltage regulator fails. Under/over frequency protection (Device 81U/81O) 7 could be used for backup protection Gen for the speed control. Sync check E relays (Device 25) are typically applied 8 as a breaker permissive close function where generators are paralleled. 9 Many modern protective relays are 51G microprocessor-based and provide a full complement of generator protection 10 functions in a single package. The cost per protection function has been drastically reduced such that it is 11 feasible to provide more complete Figure 1.2-8. Typical Protective Relaying Scheme for Large Generator protection even to smaller generators. IEEE ANSI 1547 provides recommended 12 practices for utility inter-tie protection. If the system has closed- transition or paralleling capability, additional pro- 13 tection may be required by the utility. Typically, no additional protection is required if the generator is paralleled 14 to the utility for a maximum of 100 msec or less. Systems that offer soft transfer, peak shaving or co-generation 15 will require additional utility inter-tie protection. The protection could include directional overcurrent and 16 power relays and even transfer trip schemes. Please consult your local utility for specific requirements. 17 18

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CA08104001E For more information, visit: www.eaton.com/consultants 1.2-8 Power Distribution Systems Generator System Design April 2016 Sheet 01 030

Generator Set Sizing Typical rating definitions for diesel Electrical rating definitions for natural i gensets are: standby, prime plus 10, gas powered gensets are typically and Ratings continuous and load management defined as standby or continuous with (paralleled with or isolated from definitions similar to those mentioned Many factors must be considered ii utility). Any diesel genset can have above for diesels. Natural gas gensets when determining the proper size or several electrical ratings depending recover more slowly than diesel gensets electrical rating of an electrical power on the number of hours of operation when subjected to block loads. Diesel generator set. The engine or prime 1 per year and the ratio of electrical engines have a much more direct path mover is sized to provide the actual load/genset rating when in operation. from the engine governor and fuel or real power in kW, as well as speed The same diesel genset can have a delivery system to the combustion (frequency) control through the use 2 standby rating of 2000 kW at 0.8 power chamber and this results in a very of an engine governor. The generator factor (pf) and a continuous rating of responsive engine-generator. A natural is sized to supply the kVA needed at 1825 kW at 0.8 pf. The lower continuous gas engine is challenged with air-fuel startup and during normal running 3 rating is due to the additional hours flow dynamics and a much more indi- operation and it also provides voltage of operation and higher load that the rect path from the engine governor control using a brushless exciter and continuous genset must carry. These (throttle actuator) and fuel delivery voltage regulator. Together the engine 4 additional requirements put more system (natural gas pressure regulator, and generator provide the energy stress on the engine and generator fuel valve and actuator, carburetor necessary to supply electrical loads and therefore the rating is decreased mixer, aftercooler, intake manifold) to 5 in many different applications to maintain longevity of the equipment. the combustion chamber and this results encountered in today’s society. in a less responsive engine-generator. Different generator set manufacturers The generator set must be able to Diesel gensets recover about twice as 6 use basically the same diesel genset fast as natural gas gensets. supply the starting and running electrical rating definitions and these electrical load. It must be able to are based on international diesel For the actual calculations involved 7 pick up and start all motor loads and fuel stop power standards from for sizing a genset, there are readily low power factor loads, and recover organizations like ISO, DIN and others. accessible computer software programs without excessive voltage dip or A standby diesel genset rating is that are available on the genset manu- 8 extended recovery time. Nonlinear typically defined as supplying varying facturer’s Internet sites or from the loads like variable frequency drives, electrical loads for the duration of a manufacturer’s dealers or distributors. uninterruptible power supply (UPS) power outage with the load normally These programs are used to quickly 9 systems and switching power supplies connected to utility, genset operating and accurately size generator sets for also require attention because the SCR <100 hours per year and no overload their application. The programs take switching causes voltage and current capability. A prime plus 10 rating is into consideration the many different 10 waveform distortion and harmonics. typically defined as supplying varying parameters discussed above, including The harmonics generate additional electrical loads for the duration of a the size and type of the electrical loads heat in the generator windings, and power outage with the load normally (resistive, inductive, SCR, etc.), reduced 11 the generator may need to be upsized connected to utility, genset operating voltage soft starting devices (RVSS), to accommodate this. The type of ð500 hours per year and overload motor types, voltage, fuel type, site fuel (diesel, natural gas, propane, etc.) capability of 10% above its rating for conditions, ambient conditions and 12 used is important as it is a factor in 1 hour out of 12. A continuous rating other variables. The software will determining generator set transient is typically defined as supplying optimize the starting sequences of the response. It is also necessary to unvarying electrical loads (i.e., base motors for the least amount of voltage 13 determine the load factor or average loaded) for an unlimited time. The load dip and determine the starting kVA power consumption of the generator management ratings apply to gensets needed from the genset. It also provides set. This is typically defined as the load in parallel operation with the utility transient response data, including 14 (kW) x time (hrs. while under that or isolated/islanded from utility and voltage dip magnitude and recovery particular load) / total running time. these ratings vary in usability from duration. If the transient response is When this load factor or average <200 hours per year to unlimited unacceptable, then design changes can 15 power is taken into consideration usage. Refer to generator set manufac- be considered, including oversizing with peak demand requirements turers for further definitions on load the generator to handle the additional and the other operating parameters management ratings, load factor or kvar load, adding RVSS devices to 16 mentioned above, the overall electrical average power consumption, peak reduce the inrush current, improving rating of the genset can be determined. demand and how these ratings are system power factor and other methods. Other items to consider include the typically applied. Even though there is The computer software programs are 17 unique installation, ambient, and site some standardization of these ratings quite flexible in that they allow changes requirements of the project. These across the manufacturers, there also to the many different variables and will help to determine the physical exists some uniqueness with regard to parameters to achieve an optimum 18 configuration of the overall system. how each manufacturer applies their design. The software allows, for generator sets. example, minimizing voltage dips or using paralleled gensets vs. a 19 single genset.

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For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.2-9 April 2016 Generator System Design Sheet 01 031

Genset Sizing Guidelines Generator Set Installation ■ Hazardous waste considerations for fuel, antifreeze, engine oil i Some conservative rules of thumb and Site Considerations ■ for genset sizing include: Meeting local building and There are many different installation electrical codes ii 1. Oversize genset 20–25% parameters and site conditions ■ Genset exposure (coastal for reserve capacity and for that must be considered to have a conditions, dust, chemicals, etc.) motor starting. successful generator set installation. ■ Properly sized starting systems 1 2. Oversize gensets for unbalanced The following is a partial list of areas (compressed air, batteries loading or low power factor to consider when conducting this and charger) running loads. design. Some of these installation ■ Allowing adequate space for 2 parameters include: installation of the genset and for 3. Use 1/2 hp per kW for motor loads. ■ Foundation type (crushed rock, maintenance (i.e., air filter removal, 4. For variable frequency drives, concrete, dirt, wood, separate oil changing, general genset 3 oversize the genset by at concrete inertia pad, etc.) inspection, etc…) ■ least 40%. ■ Foundation to genset vibration Flex connections on all systems that are attached to the genset and a 4 5. For UPS systems, oversize the dampening (spring type, cork and rubber, etc.) rigid structure (fuel piping, founda- genset by 40% for 6 pulse and tion vibration isolators, exhaust, air ■ 15% for 6 pulse with input filters or Noise attenuation (radiator fan intake, control wiring, power cables, 5 12 pulse. mechanical noise, exhaust noise, radiator flanges/duct work, etc.) air intake noise) 6. Always start the largest motor ■ Diesel fuel day tank systems ■ Combustion and cooling air 6 first when stepping loads. (pumps, return piping) requirements ■ Fuel storage tank (double walled, For basic sizing of a generator system, ■ Exhaust backpressure requirements fire codes) and other parameters the following example could be used: ■ Emissions permitting 7 ■ Delivery and rigging requirements Please see the generator set manufac- Step 1: Calculate Running Amperes turer’s application and installation ■ ■ Motor loads: Genset derating due to high guidelines for proper application 8 ❑ 200 hp motor...... 156 A altitudes or excessive ambient and operation of their equipment. temperatures ❑ 100 hp motor ...... 78 A 9 ❑ 60 hp motor...... 48 A ■ Lighting load ...... 68 A 10 ■ Miscellaneous loads ...... 95 A ■ Running amperes ...... 445 A Step 2: Calculating Starting Amperes 11 Using 1.25 Multiplier ■ Motor loads: 12 ❑ ...... 195 A ❑ ...... 98 A 13 ❑ ...... 60 A ■ Lighting load ...... 68 A ■ Miscellaneous loads ...... 95 A 14 ■ Starting amperes ...... 516 A Step 3: Selecting kVA of Generator 15 ■ Running kVA = (445 A x 480 V x 1.732)/ 1000 = 370 kVA 16 ■ Starting kVA = (516 A x 480 V x 1.732)/ 17 1000 = 428 kVA Solution Generator must have a minimum 18 starting capability of 428 kVA and Figure 1.2-9. Typical Genset Installation minimum running capability of 370 kVA. Note: Courtesy of Caterpillar, Inc. 19 Also, please see section “Factors Governing Voltage Drop” on Page 1.3-21 for further discussion 20 on generator loading and reduced volt- age starting techniques for motors. 21

CA08104001E For more information, visit: www.eaton.com/consultants 1.2-10 Power Distribution Systems April 2016 Sheet 01 032

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For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.3-1 April 2016 System Analysis Sheet 01 033

Systems Analysis The principal types of computer Short-circuit calculations define programs used to provide system momentary and steady-state fault i A major consideration in the studies include: currents for LV and MV breaker and design of a distribution system is to fuse duty and bus bracings at any ■ Short circuit—identify three-phase ensure that it provides the required selected location in the system, and also ii and line-to-ground fault currents quality of service to the various determine the effect on the system and system impedances loads. This includes serving each after removal of utility power due to load under normal conditions and, ■ Arc flash—calculates arc flash breaker operation or scheduled power 1 under abnormal conditions, providing energy levels, which leads to the outages. Computer software programs the desired protection to service selection of personal protective can identify the fault current at any and system apparatus so that equipment (PPE) bus, in every line or source connected 2 interruptions of service are minimized ■ Circuit breaker duty—identify to the faulted bus, or to it and every consistent with good economic and asymmetrical fault current based adjacent bus, or to it and every bus mechanical design. on X/R ratio that is one and two buses away, or 3 ■ Protective device coordination— currents in every line or source in the Under normal conditions, the impor- determine characteristics and set- system. The results of these calculations tant technical factors include voltage tings of medium voltage protective permit optimizing service to the loads 4 profile, losses, load flow, effects of relays and fuses, and entire low while properly applying distribution motor starting, service continuity and voltage circuit breaker and fuse apparatus within their intended limits. reliability. The prime considerations coordination 5 under faulted conditions are apparatus The following additional studies protection, fault isolation and service ■ Load flow—simulate normal should be considered depending continuity. During the system prelimi- load conditions of system upon the type and complexity of the 6 nary planning stage, before selection voltages, power factor, line distribution system, the type of facility of the distribution apparatus, several and transformer loadings and the type of loads to be connected distribution systems should be ana- ■ Motor starting—identify system to the system: 7 lyzed and evaluated, including both eco- voltages, motor terminal voltage, ■ Harmonic analysis nomic and technical factors. During this motor accelerating torque, and stage, if system size or complexity war- motor accelerating time when ■ Transient stability 8 rant, it may be appropriate to provide a starting large motors ■ Insulation coordination thorough review of each system under ■ Grounding study both normal and abnormal conditions. ■ Switching transient 9 Eaton’s Electrical Services & Systems division can provide the studies 10 enumerated above. 11

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CA08104001E For more information, visit: www.eaton.com/consultants 1.3-2 Power Distribution Systems System Analysis April 2016 Sheet 01 034

Short-Circuit Currents— The AC component is not constant secondary current. Limiting the power i if rotating machines are connected source fault capacity will thereby General to the system because the impedance reduce the maximum fault current from of this apparatus is not constant. The the transformer. The amount of current available in a ii rapid variation of motor and generator short-circuit fault is determined by the impedance is due to these factors: The electric network that determines capacity of the system voltage sources the short-circuit current consists of an 1 and the impedances of the system, Subtransient reactance (xd "), deter- AC driving voltage equal to the pre-fault including the fault. Voltage sources mines fault current during the first system voltage and an impedance include the power supply (utility or cycle, and after about 6 cycles this corresponding to that observed when 2 on-site generation) plus all rotating value increases to the transient reac- looking back into the system from the machines connected to the system at tance. It is used for the calculation fault location. In medium and high the time of the fault. A fault may be of the momentary interrupting and/or voltage work, it is generally satisfactory 3 either an arcing or bolted fault. In an momentary withstand duties of to regard reactance as the entire arcing fault, part of the circuit voltage is equipment and/or system. impedance; resistance may be consumed across the fault and the total neglected. However, this is normally 4 fault current is somewhat smaller than Transient reactance (xd ' ), which deter- permissible only if the X/R ratio of the for a bolted fault, so the latter is the mines fault current after about 6 cycles medium voltage system is equal to or worst condition, and therefore is the and this value in 1/2 to 2 seconds more than 25. In low voltage (1000 V 5 value sought in the fault calculations. increases to the value of the synchro- and below) calculations, it is usually nous reactance. It is used in the setting worthwhile to attempt greater accuracy Basically, the short-circuit current is of the phase OC relays of generators by including resistance with reactance 6 determined by applying Ohm’s Law and medium voltage circuit breakers. in dealing with impedance. It is for this to an equivalent circuit consisting of reason, plus ease of manipulating the Synchronous reactance (xd), which a constant voltage source and a time- various impedances of cables and varying impedance. A time-varying determines fault current after steady- 7 state condition is reached. It has no buses and transformers of the low impedance is used in order to account voltage circuits, that computer studies for the changes in the effective voltages effect as far as short-circuit calculations are concerned, but is useful in the are recommended before final selection of the rotating machines during the of apparatus and system arrangements. 8 fault. In an AC system, the resulting determination of relay settings. short-circuit current starts out higher in Transformer impedance, in percent, is When evaluating the adequacy 9 magnitude than the final steady-state defined as that percent of rated primary of short-circuit ratings of medium value and asymmetrical (due voltage that must be applied to the voltage circuit breakers and fuses, to the DC offset) about the X-axis. transformer to produce rated current both the rms symmetrical value and 10 The current then decays toward a flowing in the secondary, with second- asymmetrical value of the short-circuit lower symmetrical steady-state value. ary shorted through zero resistance. current should be determined. The time-varying characteristic of the Therefore, assuming the primary impedance accounts for the symmetri- For low voltage circuit breakers and 11 voltage can be sustained (generally fuses, the rms symmetrical value cal decay in current. The ratio of the referred to as an infinite or unlimited reactive and resistive components (X/R should be determined along with supply), the maximum current a trans- either: the X/R ratio of the fault 12 ratio) accounts for the DC decay, see former can deliver to a fault condition is Figure 1.3-1. The fault current consists at the device or the asymmetrical the quantity of (100 divided by percent short- circuit current. of an exponentially decreasing direct- impedance) times the transformer rated 13 current component superimposed upon a decaying alternating-current. The rate of decay of both the DC and Total Current—A Wholly Offset 14 AC components depends upon the Asymmetrical Alternating Wave ratio of reactance to resistance (X/R) 3.0 rms Value of Total Current of the circuit. The greater this ratio, 2.5 Alternating Component - 15 the longer the current remains higher Symmetrical Wave than the steady-state value that it 2.0 rms Value of would eventually reach. Alternating Component 16 The total fault current is not symmetrical 1.5 with respect to the time-axis because a lues of the direct-current component, hence 1.0 17 it is called asymmetrical current. The DC component depends on the point 0.5 on the voltage wave at which 1 2 34 18 the fault is initiated. 0

See Ta b l e 1. 3 - 2 for multiplying factors S ca le o f Curent V 0.5 19 that relate the rms asymmetrical value of total current to the rms symmetrical –1.0 value, and the peak asymmetrical Direct Component—The Axis value of total current to the rms –1.5 of Symmetrical Wave Time in Cycles of 20 a 60 Hz Wave symmetrical value. –2.0 21 Figure 1.3-1. Structure of an Asymmetrical Current Wave

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.3-3 April 2016 System Analysis Sheet 01 035

Fault Current Waveform Relationships i The following Figure 1.3-2 describes Based on a 60 Hz system and t = 1/2 cycle the relationship between fault (ANSI/IEEE C37.13.1990/10.1.4) 2 60 current peak values, rms symmetrical ------–  - ii 120 – values and rms asymmetrical values ------Ip XR XR depending on the calculated X/R ratio. Peak multiplication factor = ----- ==+ + 21e21 e The table is based on the following I  1 general formulas: –2 260 –t ------------120 –2 2 XR ------1. I = I21+ e Irms asym XR XR p  rms multiplication factor = ------==12e+ 12e+  I 3

–2t Example for X/R =15 ------XR 2. I I1+= 2e – 4 rms asym ------15 Peak mf== 2 1+ e 2.5612 Where:   5 I = Symmetrical rms current –2 ------Ip = Peak current 15 rms mf== 1+ 2e 1.5217 6 e = 2.718  = 2  f 7 f = Frequency in Hz t = Time in seconds 8

9 2.8

2.7 10 Based Upon: rms Asym = DC2 + rms Sym2 2.6 with DC Value Taken at Current Peak 11 2.5

2.4 12

2.3

RMS SYMMETRICAL 13

1.8 RMS SYMMETRICAL 2.2 R

PEAK MAXIMUM ASYMMETRICAL ACTO RMS MAXIMUM ASYMMETRICAL 14 2.1 F 1.7 N O TI 2.0 1.6 IPLICA 15 1.9 1.5 MULT 16 1.8 PEAK ACTOR 1.4

1.7 1.3 TIPLICATION F 17

1.6 1.2 RMS MUL 18

PEAK MULTIPLICATION FACTOR = FACTOR PEAK MULTIPLICATION 1.5 1.1 RMS MULTIPLICATION FACTOR = FACTOR RMS MULTIPLICATION

1.4 11.5 2 2.5 3 4 5 6 7 8 9 10 15 20 25 30 40 50 60 70 80 90 100 19 CIRCUIT X/R RATIO (TAN PHASE) 20 Figure 1.3-2. Relation of X/R Ratio to Multiplication Factor 21

CA08104001E For more information, visit: www.eaton.com/consultants 1.3-4 Power Distribution Systems System Analysis April 2016 Sheet 01 036

Fault Current Calculations Synchronous motors—use 5.0 times Medium Voltage Motors i motor full load current (impedance If known, use actual values otherwise The calculation of asymmetrical value of 20%). use the values indicated for the same currents is a laborious procedure since When the motor load is not known, type of motor. ii the degree of asymmetry is not the the following assumptions generally same on all three phases. It is common are made: practice for medium voltage systems, Calculation Methods 1 to calculate the rms symmetrical fault 208Y/120 V Systems The following pages describe various methods of calculating short-circuit current, with the assumption being ■ Assume 50% lighting and 50% currents for both medium and low made that the DC component has motor load 2 decayed to zero, and then apply voltage systems. A summary of a multiplying factor to obtain the first or the types of methods and types of half-cycle rms asymmetrical current, calculations is as follows: 3 which is called the “momentary ■ Assume motor feedback contribu- ■ Medium voltage current.” For medium voltage systems tion of twice full load current of switchgear—exact (defined by IEEE as greater than transformer 4 method...... Page 1.3-5 1000 V up to 69,000 V) the multiplying or factor is established by NEMA® and ■ Medium voltage ANSI standards depending upon the 240/480/600 V Three-Phase, Three-Wire or switchgear—quick 5 operating speed of the breaker. For Four-Wire Systems check table ...... Page 1.3-7 low voltage systems, short-circuit ■ Assume 100% motor load ■ Medium voltage study software usually calculates the switchgear 6 symmetrical fault current and the or Example 1—verify faulted system X/R ratio using ANSI ratings of breakers . . . . Page 1.3-8 ■ Assume motors 25% synchronous guidelines. If the X/R ratio is within the ■ and 75% induction Medium voltage 7 standard, and the breaker interrupting switchgear current is under the symmetrical fault or Example 2—verify value, the breaker is properly rated. ratings of breakers ■ 8 If the X/R ratio is higher than ANSI Assume motor feedback contribu- with rotating standards, the study applies a multi- tion of four times full load current loads...... Page 1.3-9 of transformer 9 plying factor to the symmetrical ■ Medium voltage calculated value (based on the 480Y/277 V Systems in Commercial Buildings switchgear Example 3 X/R value of the system fault) and ■ Assume 50% induction motor load —verify ratings of 10 compares that value to the breaker breakers with symmetrical value to assess if it is or generators ...... Page 1.3-10 properly rated. In the past, especially ■ using manual calculations, a multiply- ■ Assume motor feedback contribu- Medium voltage 11 ing factor of 1.17 (based on the use tion of two times full load current fuses—exact method . . Page 1.3-11 of an X/R ratio of 6.6 representing of transformer or source ■ Power breakers— a source short-circuit power factor asymmetry 12 of 15%) was used to calculate the derating factors ...... Page 1.3-11 asymmetrical current. These values ■ Molded-case take into account that medium voltage breakers—asymmetry 13 breakers are rated on maximum derating factors ...... Page 1.3-12 asymmetry and low voltage breakers ■ Short-circuit 14 are rated average asymmetry. calculations— To determine the motor contribution short cut method during the first half-cycle fault current, for a system ...... Page 1.3-13 15 when individual motor horsepower ■ Short-circuit load is known, the subtransient calculations—short reactances found in the IEEE Red Book cut method for 16 should be used in the calculations. end of cable ...... Page 1.3-15 When the system motor load is ■ Short-circuit unknown, the following assumptions calculations— 17 generally are made: short cut method for end of cable Induction motors—use 4.0 times chart method ...... Page 1.3-16 motor full load current (impedance 18 ■ value of 25%). Short-circuit currents— chart of transformers Note: For motors fed through adjustable 300–3750 kVA...... Page 1.5-9 19 frequency drives or solid-state soft starters, there is no contribution to fault current, unless 1) they have an internal run contactor or 20 2) they have a bypass contactor.

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For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.3-5 April 2016 System Analysis Sheet 01 037

Fault Current Calculations a voltage = maximum rated voltage greater than the available system fault divided by K (for example, 4.76/1.24 = current of 20,000 A, the breaker is i for Specific Equipment— 3.85). If this breaker is applied in a acceptable (assumes the breaker’s Exact Method system rated at 2.4 kV, the calculated momentary and fault close rating is fault current must be less than 36 kA. also acceptable). ii The purpose of the fault current calcu- For example, consider the following case: Note: If the system available fault current lations is to determine the fault current were 22,000 A symmetrical, this breaker at the location of a circuit breaker, fuse Assume a 12.47 kV system with could not be used even though the 1 or other fault interrupting device in 20,000 A symmetrical available. In “Maximum Symmetrical Interrupting order to select a device adequate for the order to determine if an Eaton Type Capability” is greater than 22,000 because calculated fault current or to check the 150 VCP-W 500 vacuum breaker is Test 1 calculation is not satisfied. 2 thermal and momentary ratings of non- suitable for this application, check interrupting devices. When the devices the following: For approximate calculations, Table 1.3-1 to be used are ANSI-rated devices, the provides typical values of % reactance 3 fault current must be calculated and the From Table 5.4-1B in Ta b 5 , S e c t i o n 5 . 4 (X) and X/R values for various rotating device selected as per ANSI standards. under column “Rated Maximum equipment and transformers. For sim- Voltage” V = 15 kV, under column plification purposes, the transformer 4 The calculation of available fault current “Rated short-circuit Current” I = 18 kA, impedance (Z) has been assumed to be and system X/R rating is also used to “Rated Voltage Range Factor” K = 1.3. primarily reactance (X). In addition, the verify adequate busbar bracing and Test 1 for V/V x I or 15 kV/12.47 kV x 18 resistance (R) for these simplified cal- 5 momentary withstand ratings of o culations has been ignored. For detailed devices such as contactors. kA = 21.65; also check K x I (which is shown in the column headed calculations, the values from the IEEE Medium Voltage VCP-W “Maximum Symmetrical Interrupting Red Book Standard 141, for rotating 6 Capability”) or 1.3 x 18 kA = 23.4 kA. machines, and ANSI C57 and/or C37 Metal-Clad Switchgear Because both of these numbers are for transformers should be used. The applicable ANSI Standards, C37 7 is the latest applicable edition. The Table 1.3-1. Reactance X following is a review of the meaning System Reactance X Used for Typical Values and Range of the ratings. (See Tab 5, Section 5.4.) Component Short-Circuit Close and Latch on Component Base 8 Duty (Momentary) % Reactance X/R Ratio The Rated Maximum Voltage This designates the upper limit of Two-pole turbo generator X X 9 (7–14) 80 (40–120) 9 design and operation of a circuit Four-pole turbo generator X X 15 (12–17) 80 (40–120) breaker. For example, a circuit breaker Hydro generator with damper wedges X X 20 (13–32) 30 (10–60) with a 4.76 kV rated maximum voltage and synchronous condensers 10 cannot be used in a 4.8 kV system. Hydro generator without damper windings 0.75X 0.75X 16 (16–50) 30 (10–60) All synchronous motors 1.5X 1.0X 20 (13–35) 30 (10–60) K-Rated Voltage Factor Induction motors above 1000 hp, 1800 rpm 1.5X 1.0X 17 (15–25) 30 (15–40) 11 The rated voltage divided by this factor and above 250 hp, 3600 rpm determines the system kV a breaker can All other induction motors 50 hp and above 3.0X 1.2X 17 (15–25) 15 (2–40) be applied up to the short-circuit kVA Induction motors below 50 hp and Neglect Neglect — — 12 rating calculated by the formula all single-phase motors Distribution system from remote XX As specified 15 (5–15) 3 Rated SC Current  Rated Max. Voltage transformers or calculated 13 Note: Interrupting capabilities of some of Current limiting reactors X X As specified 80 (40–120) today’s vacuum breakers may have K = 1, or calculated whereby the interrupting current is constant Transformers 14 across its entire operating range. OA to 10 MVA, 69 kV X X 8.0 18 (7–24) OA to 10 MVA, above 69 kV X X 8.0 to 10.5 18 (7–24) Rated Short-Circuit Current Depends on 15 FOA 12–30 MVA X X 20 (7–30) This is the symmetrical rms value of primary FOA 40–100 MVA X X windings BIL 38 (32–44) current that the breaker can interrupt rating at rated maximum voltage. It should 16 be noted that the product 3 x 4.76 x Table 1.3-2. Typical System X/R Ratio Range (for Estimating Purposes) 29,000 = 239,092 kVA is less than the nominal 250,000 kVA listed. This rating Type of Circuit X/R Range 17 (29,000 A) is also the base quantity Remote generation through other types of circuits such as transformers rated 10 MVA 15 or less that all the “related” capabilities are or smaller for each three-phase bank, transmission lines, distribution feeders, etc. 18 referred to. Remote generation connected through transformer rated 10 MVA to 100 MVA 15–40 for each three-phase bank, where the transformers provide 90% or more Maximum Symmetrical Interrupting of the total equivalent impedance to the fault point Capability Remote generation connected through transformers rated 100 MVA or larger 30–50 19 This is expressed in rms symmetrical for each three-phase bank where the transformers provide 90% or more amperes or kiloamperes and is K x I of the total equivalent impedance to the fault point rated; 29,000 x 1.24 = 35,960 rounded Synchronous machines connected through transformers rated 25–100 MVA 30–50 20 to 36 kA. for each three-phase bank Synchronous machines connected through transformers rated 100 MVA and larger 40–60 This is the rms symmetrical current 21 that the breaker can interrupt down to Synchronous machines connected directly to the bus or through reactors 40–120

CA08104001E For more information, visit: www.eaton.com/consultants 1.3-6 Power Distribution Systems System Analysis April 2016 Sheet 01 038

The Close and Latch Capability The ANSI Standard C37.010 allows the Step 3: Reduce the reactance network i This is also a related quantity use of the X values only in determin- to an equivalent reactance. Call this expressed in rms asymmetrical ing the E/X value of a fault current. The reactance XI. amperes by 1.6 x maximum R values are used to determine the X/R ii ratio, in order to apply the proper Step 4: Set up the same network for symmetrical interrupting capability. resistance values. For example, 1.6 x 36 = 57.6 or 58 kA, or multiplying factor, to account for the 1.6 K x rated short-circuit current. total fault clearing time, asymmetry, Step 5: Reduce the resistance network 1 and decrement of the fault current. to an equivalent resistance. Call this Another way of expressing the close resistance R . The above calculations and latch rating is in terms of the peak The steps in the calculation of fault I currents and breaker selection are of XI and RI may be calculated by 2 current, which is the instantaneous several computer programs. value of the current at the crest. ANSI described hereinafter: Standard C37.09 indicates that the ratio Step 1: Collect the X and R data of the Step 6: Calculate the E/XI value, where 3 of the peak to rms asymmetrical value circuit elements. Convert to a common E is the prefault value of the voltage at for any asymmetry of 100% to 20% kVA and voltage base. If the reactances the point of fault nominally assumed (percent asymmetry is defined as the and resistances are given either in 1.0 pu. 4 ratio of DC component of the fault in ohms or per unit on a different voltage XI per unit to 2 ) varies not more than Step 7: Determine X/R = ------as or kVA base, all should be changed previously calculated. RI ±2% from a ratio of 1.69. Therefore, the to the same kVA and voltage base. This 5 close and latch current expressed in caution does not apply where Step 8: Go to the proper curve for terms of the peak amperes is = 1.6 x the base voltages are the same as the type of fault under consideration 1.69 x K x rated short-circuit current. the transformation ratio. (three-phase, phase-to-phase, phase- 6 to-ground), type of breaker at the loca- In the calculation of faults for the pur- Step 2: Construct the sequence poses of breaker selection, the rotating tion (2, 3, 5 or 8 cycles), and contact networks and connect properly for parting time to determine the multi- 7 machine impedances specified in ANSI the type of fault under consideration. plier to the calculated E/XI. Standard C37.010 Article 5.4.1 should Use the X values required by ANSI be used. The value of the impedances Standard C37.010 for the “interrupting” See Figures 1.3-3, 1.3-4 and 1.3-5 for 8 and their X/R ratios should be obtained duty value of the short-circuit current. 5-cycle breaker multiplying factors. from the equipment manufacturer. At Use Figure 1.3-5 if the short circuit is initial short-circuit studies, data from fed predominantly from generators 9 manufacturers is not available. Typical removed from the fault by two or more values of impedances and their X/R ratios are given in Table 1.3-1. 10 130 130 130

11 120 120 120 8 7 5

110 110 4 110 6 12 3 12

5 10 8 100 100 100 6 4

4

13 3 90 90 90

3 14 80 80 80 E

70 70 70 TIM G 15 TIME G 60 60 R a t i o X/R 60 R a t i o X/R R a t i o X/R

PARTIN 50 16 50 PARTIN 50 ACT

40 40 40 CONT 17 CONTACT 30 30 30 5-CYCLE 5-CYCLE 5-CYCLE BREAKER BREAKER BREAKER 18 20 20 20

19 10 10 10

1.0 1.1 1.2 1.3 1.4 1.0 1.1 1.2 1.3 1.4 1.0 1.1 1.2 1.3 1.4 20 Multiplying Factors for E / X Amperes Multiplying Factors for E / X Amperes Multiplying Factors for E / X Amperes Figure 1.3-3. Three-phase Fault Multiplying Figure 1.3-4. Line-to-Ground Fault Multiplying Figure 1.3-5. Three-phase and Line-to-Ground 21 Factors that Include Effects of AC and Factors that Include Effects of AC and Fault Multiplying Factors that Include Effects DC Decrement DC Decrement of DC Decrement Only

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.3-7 April 2016 System Analysis Sheet 01 039 transformations or the per unit reac- The ANSI standards do not require the Application Quick Check Table tance external to the generation is 1.5 inclusion of resistances in the calcula- i times or more than the subtransient tion of the required interrupting and For application of circuit breakers in a reactance of the generation on a com- close and latch capabilities. Thus the radial system supplied from a single mon base. Also use Figure 1.3-5 where calculated values are conservative. source transformer. Short-circuit duty ii the fault is supplied by a utility only. However, when the capabilities of was determined using E/X amperes existing switchgears are investigated, and 1.0 multiplying factor for X/R ratio Step 9: Interrupting duty short-circuit the resistances should be included. of 15 or less and 1.25 multiplying 1 current = E/X x MF = E/X . I x 2 factor for X/R ratios in the range of For single line-to-ground faults, the 15 to 40. Step 10: Construct the sequence symmetrical interrupting capability (positive, negative and zero) networks 2 is 1.15 x the symmetrical interrupting Application Above 3,300 ft (1,000 m) properly connected for the type of fault capability at any operating voltage, under consideration. Use the The rated one-minute power frequency but not to exceed the maximum withstand voltage, the impulse with- 3 X values required by ANSI Standard symmetrical capability of the breaker. C37.010 for the “Close and Latch” stand voltage, the continuous current duty value of the short-circuit current. Section 5 of ANSI C37 provides rating, and the maximum voltage rating further guidance for medium voltage must be multiplied by the appropriate 4 Step 11: Reduce the network to an breaker application. correction factors below to obtain equivalent reactance. Call the reac- modified ratings that must equal or tance X. Calculate E/X x 1.6 if the Reclosing Duty exceed the application requirements. 5 breaker close and latch capability is ANSI Standard C37.010 indicates the given in rms amperes or E/X x 2.7 if Note: Intermediate values may be obtained reduction factors to use when circuit by interpolation. the breaker close and latch capability breakers are used as reclosers. Eaton 6 is given in peak or crest amperes. VCP-W breakers are listed at 100% Table 1.3-3. Altitude Derating rating factor for reclosing. Step 12: Select a breaker whose: Altitude in Correction Factor 7 Feet (Meters) a. Maximum voltage rating exceeds Current Voltage the operating voltage of the system: 3300 (1006) (and below) 1.0 0 1.0 0 5000 (1524) 0.99 0.95 8 E Vmax 10,000 (3048) 0.96 0.80 b. ------I ------ KI X2 Vo Table 1.3-4. Application Quick Check Table 9 See Table 6.0-1, Ta b 6 . Source Operating Voltage Transformer kV Where: MVA Rating 10 I = Rated short-circuit current Motor Load 2.4 4.16 6.6 12 13.8 100% 0% Vmax = Rated maximum voltage 11 of the breaker 1 1.5 1.5 2 50 VCP-W 250 VD = Actual system voltage 2 2.5 12 kA 50 VCP-W 250 150 VCP-W 500 150 VCP-W 500 150 VCP-W 500 12 2.5 3 10.1 kA 23 kA 22.5 kA 19.6 kA KI = Maximum symmetrical 3 3.75 interrupting capacity 3.75 5 50 VCP-W 250 13 c. E/X x 1.6 m rms closing and 5 7. 5 36 kA 50 VCP-W 250 7. 5 10 50 VCP-W 350 33.2 kA latching capability of the breaker 1 10 10 49 kA 14 1 and/or 10 12 E/X x 2.7 m Crest closing and 12 15 50 VCP-W 350 75 VCP-W 500 latching capability of the breaker. 46.9 kA 41.3 kA 15 15 20 1 20 20 Breaker Type and 150 VCP-W 750 150 VCP-W 750 16 25 symmetrical interrupting capacity 35 kA 30.4 kA 30 at the operating voltage 1 50 150 VCP-W 1000 150 VCP-W 1000 46.3 kA 40.2 kA 17 1 Transformer impedance 6.5% or more, all other transformer impedances are 5.5% or more. 18

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CA08104001E For more information, visit: www.eaton.com/consultants 1.3-8 Power Distribution Systems System Analysis April 2016 Sheet 01 040

Application on Symmetrical Current Rating Basis For Three-Phase Fault i E I  ----- Example 1—Fault Calculations 3-Phase X ii Given a circuit breaker interrupting and momentary rating in the table below, where X is ohms per phase and E is verify the adequacy of the ratings for a system without motor loads, as shown. the highest typical line-to-neutral Table 1.3-5. Short-Circuit Duty operating voltage or 1 Ty p e V Max. Three-Phase Symmetrical Interrupting Capability Close and Latch or IB Breaker at V Max. Max. KI at 4.16 kV Oper. Voltage Momentary I  ------3-Phase X 50VCP–W250 4.76 kV 29 kA 36 kA 4.76 58 kA I 2 ------(29) = 33.2 kA I 3 4.16 1 where X is per unit reactance LG symmetrical interrupting capability IB is base current 3 — 36 kA 1.15 (33.2) = 38.2 kA I2 3.75 MVA Base current IB== 0.52kA Note: Interrupting capabilities I1 and I2 at operating voltage must not exceed maximum 3 4.16 kV 4 symmetrical interrupting capability Kl. I1 0.52 I ------8.6 kA Sym. Check capabilities I1, I2 and I3 on the following utility system where there is no 3-Phase X 0.0604 5 motor contribution to short circuit. X System   9 (is less than 15) On 13.8 kV System, 3.75 MVA Base R 6 13.8 kV 3.75 MVA would use 1.0 multiplying factor for Z ==------0.01 pu or 1% 375 MVA short-circuit duty, therefore, short- X 7 = 15 circuit duty is 8.6 kA sym. for three- R 2 phase fault I and momentary duty is 2 2 2 2X 1 Z X R =+= R ------+ 1 8.6 x 1.6 = 13.7 kA I . 375 MVA 2 3 R 8 Available For Line-to-Ground Fault Z 1 1 ------R 0.066% 3IB 2 266 15.03 3E ------9 X ILG  ------ ------+ 1 2X + X 2X + X 2 1 0 1 0 13.8 kV R For this system, X0 is the zero sequence 10 reactance of the transformer, which 3750 kVA X X ==-----R 15 (0.066) = .99% is equal to the transformer positive R 11 sequence reactance and X1 is the posi- Transformer Standard 5.5% Impedance tive sequence reactance of the system. has a ±7.5% Manufacturing Tolerance Therefore, 12 4.16 kV 5.50 Standard Impedance 3(0.52) –0.41 (–7.5% Tolerance) ILG 9.1 kA Sym. Transformer Z = 2(0.0604)+ 0.0505 13 50VPC-W250 5.09% Using 1.0 multiplying factor (see Table 1.3-6), short-circuit duty = 9.1 kA 14 Sym. LG (I2) Answer

15 Figure 1.3-6. Example 1—One-Line Diagram The 50VCP-W250 breaker capabilities exceed the duty requirements and From transformer losses per unit or may be applied. 16 percent R is calculated With this application, shortcuts could 31,000 Watts Full Load 24.2 kW have been taken for a quicker check of –6,800Watts No Load R ------0.0065 pu or 0.65% 17 3750 kVA the application. If we assume unlimited 24,200 Watts Load Losses short circuit available at 13.8 kV and that Trans. Z = X 2 2 2 2 18 Transformer X=== Z – R (5.09) – (0.65) 25.91– 0.42 25.48 IB 0.52 ------Then I3-Phase  9.5 kA Sym. X = 5.05% X 0.055 19 X/R ratio 15 or less multiplying factor X R X/R is 1.0 for short-circuit duty. 20 13.8 kV System 0.99% 0.066% 15 Transformer 5.05% 0.65% 8 The short-circuit duty is then 9.5 kA System Total 6.04% 0.716% 9 Sym. (I1, I2) and momentary duty is 21 or 0.0604 pu 0.00716 pu 9.5 x 1.6 kA = 15.2 kA (I3).

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.3-9 April 2016 System Analysis Sheet 01 041

Example 2—Fault Calculations Given the system shown with motor 13.8 kV System i loads, calculate the fault currents 21 kA Sym. Available X = 15 and determine proper circuit breaker 13.8 kV R selection. ii X = 5.5% X All calculations on per unit basis. 7500 kVA Z = 5.53% = 10 R = 0.55% R 7. 5 M V A b a s e 1 7.5 MVA Base Current IB ==------0.628 kA 6.9 kV 36.9 kV 1 2

XR X/R 13.8 kV System 3 0.628 (6.9) X = = 0.015 0.015 0.001 15 X X 21 (13.8) = 25 = 35 R R Transformer 0.055 0.0055 10 2 3 4 197A FL 173A FL Total Source Transformer 0.070 pu 0.0065 pu 11 X''d = 20% X''d = 25% 3000 hp Synchronous Motor 5 (0.628) 3000 hp X = 0.20 = 0.638 pu at 7.5 MVA Base 2500 hp 0.197 1.0 PF 6 Syn. Ind. 2500 hp Ind. Motor 7 X = 0.25 (0.628) = 0.908 pu at 7.5 MVA Base 0.173 Figure 1.3-7. Example 2—One-Line Diagram

Source of Interrupting Momentary X X (1) 1 E IB 8 I ------where X on per unit base Short-Circuit Current E/X Amperes E/X Amperes R R (X) R 3-Ph X X 0.628 0.628 11 I3 Source Transformer = 8.971 = 8.971 11 = 157 Table 1.3-6. Multiplying Factor for E/X 0.070 0.070 0.070 9 Amperes (ANSI C37.010, 1979, Figures 1.1-8, 0.628 0.628 25 I1 3000 hp Syn. Motor = 0.656 = 0.984 25 = 39 1.1-9 and 1.1-10) (1.5) 0.638 0.638 0.638 0.628 0.628 35 10 System Type VCP-W Vacuum I1 2500 hp Syn. Motor = 0.461 = 0.691 35 = 39 X/R Circuit Breaker (1.5) 0.908 0.908 0.908 Rated Interrupting Time, 5-Cycle I3F = 10.088 10.647 Total 1/R = 235 Ty p e o f Fa u l t or 10.1 kA x 1.6 11 17.0 kA Momentary Duty Ratio Three- LG Three-Phase Phase and LG IB 0.628 12 Source of Short Circuit Total X ==------=0.062 Local Remote I3F 10.1

1 1.0 0 1.0 0 1.0 0 X 13 1 System ----- = 0.062 (235) = 14.5 is a Multiplying Factor of 1.0 from Table 1.3-6 15 1.0 0 1.0 0 1.0 0 R 20 1.0 0 1.02 1.05 25 1.0 0 1.06 1.10 Table 1.3-7. Short-Circuit Duty = 10.1 kA 14 30 1.04 1.10 1.13 36 1.06 1.14 1.17 Breaker V Three-Phase Symmetrical Interrupting Capability Close and Latch 40 1.08 1.16 1.22 Ty p e Max. at V Max. Max. KI at 6.9 kV Oper. Voltage or Momentary 45 1.12 1.19 1.25 15 50 1.13 1.22 1.27 75VCP-W500 8.25 kV 33 kA 41 kA 8.25 (33) = 39.5 kA 66 kA 55 1.14 1.25 1.30 6.9 60 1.16 1.26 1.32 150VCP-W500 15 kV 18 kA 23 kA 15 (18) (39.1) = 23 kA 37 kA 16 65 1.17 1.28 1.33 6.9 70 1.19 1.29 1.35 (But not to exceed KI) 75 1.20 1.30 1.36 17 80 1.21 1.31 1.37 Answer 85 — — 1.38 Either breaker could be properly 90 1.22 1.32 1.39 18 95 — — 1.40 applied, but price will make the type 100 1.23 1.33 1.41 150VCP-W500 the more economical 100 1.24 1.34 1.42 selection. 120 1.24 1.35 1.43 19 130 1.24 1.35 1.43 1 Where system X/R ratio is 15 or less, the multiplying factor is 1.0. 20 21

CA08104001E For more information, visit: www.eaton.com/consultants 1.3-10 Power Distribution Systems System Analysis April 2016 Sheet 01 042

Example 3—Fault Calculations Answer i Check breaker application or generator bus for the system of generators shown. The 50VCP-W250 breaker could be Each generator is 7.5 MVA, 4.16 kV 1040 A full load, I = 1.04 kA applied. ii B Sub transient reactance Xd” = 11% or, X = 0.11 pu

X Gen ----- ratio is 30 1 R

1 1 1 1 3 1 1 1 1 3 2        and       XS X X X X RS R R R R

3 G1 G2 G3 X X R XS ----- X or XS ----- and RS ---- Therefore, System ------Gen ----- 30 3 3 R R R 4 S Since generator neutral grounding reactors are used to limit the ILG to I3-phase or below, we need only check the I3 short-circuit duty. 5 I I I 31B 3(1.04) 4.16 kV B B B ------IBPhase  ------+++------28.4 kA Symmetrical E/X amperes 6 X X X X 0.11 X System ----- of 30 is a Multiplying Factor of 1.04 from Table 1.3-6. 7 R Short-circuit duty is 28.4 (1.04) = 29.5 kA Symmetrical

8 Three-Phase Symmetrical Interrupting Capability Figure 1.3-8. Example 3—One-Line Diagram Breaker Type V Max. at V Max. Max. KI at 4.16 kV Oper. Voltage 50VCP-W250 4.76 kV 29 kA 36 kA 4.76 (29) = 33.2 kA 9 4.16

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For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.3-11 April 2016 System Analysis Sheet 01 043

Medium Voltage Fuses— Step 3—Construct the sequence Low Voltage Power Circuit networks using reactances and connect i Fault Calculations properly for the type of fault under Breakers—Fault Calculations consideration and reduce to a single There are two basic types of medium equivalent reactance. The steps for calculating the fault cur- ii voltage fuses. The following definitions rent for the selection of a low voltage are taken from ANSI Standard C37.40. Step 4—Construct the sequence power circuit breaker are the same as networks using resistances and those used for medium voltage circuit 1 Expulsion Fuse (Unit) connect properly for the type of breakers except that where the con- A vented fuse (unit) in which the fault under consideration and reduce nected loads to the low voltage bus expulsion effect of the gases produced to a single equivalent resistance. 2 by internal arcing, either alone or aided includes induction and synchronous by other mechanisms, results in current Step 5—Calculate the E/XI value, motor loads. The assumption is made interruption. where E is the prefault value of the that in 208Y/120 V systems the contri- voltage at the point of fault normally bution from motors is two times the full 3 Current-Limiting Fuse (Unit) assumed 1.0 in pu. For three-phase load current of step-down transformer. This corresponds to an assumed 50% A fuse unit that, when its current- faults E/XI is the fault current to be responsive element is melted by a used in determining the required motor aggregate impedance on a kVA 4 current within the fuse’s specified interrupting capability of the fuse. base equal to the transformer kVA current-limiting range, abruptly rating or 50% motor load. For 480 V, Note: It is not necessary to calculate a 480Y/277 V and 600 V systems, the 5 introduces a high resistance to single phase-to-phase fault current. This reduce current magnitude and assumption is made that the contribution current is very nearly3 /2 x three-phase from the motors is four times the full duration, resulting in subsequent fault. The line-to-ground fault may exceed 6 current interruption. the three-phase fault for fuses located in load current of the step-down trans- generating stations with solidly grounded former, which corresponds to an assumed There are two classes of fuses; neutral generators, or in delta-wye trans- 25% aggregate motor impedance on a power and distribution. They are formers with the wye solidly grounded, kVA base equal to the transformer kVA 7 distinguished from each other by where the sum of the positive and negative rating or 100% motor load. the current ratings and minimum sequence impedances on the high voltage melting type characteristics. side (delta) is smaller than the impedance of In low voltage systems that contain 8 the transformer. generators, the subtransient reactance The current-limiting ability of a should be used. current-limiting fuse is specified by For single line-to-ground fault: 9 its threshold ratio, peak let-through If the X/R to the point of fault is greater XI  XI(+) ++XI(–) XI(0) than 6.6, a derating multiplying factor current and I2t characteristics. (MF) must be applied. The X/R ratio is 10 Interrupting Ratings of Fuses E calculated in the same manner as that If  ------ 3 for medium voltage circuit breakers. Modern fuses are rated in amperes XI rms symmetrical. They also have a Calculated symmetrical amperes x 11 listed asymmetrical rms rating that Step 6—Select a fuse whose MF ð breaker interrupting rating. is 1.6 x the symmetrical rating. published interrupting rating The multiplying factor MF can be exceeds the calculated fault current. Refer to ANSI/IEEE C37.48 for fuse calculated by the formula: 12 interrupting duty guidelines. Figure 1.3-2 should be used where older fuses asymmetrically rated are –  X/R Calculation of the Fuse Required 2 1 2.718 13 involved. MF   Interrupting Rating: 2.29 Step 1—Convert the fault from The voltage rating of power fuses used If the X/R of system feeding the the utility to percent or per unit on on three-phase systems should equal breaker is not known, use X/R = 15. 14 a convenient voltage and kVA base. or exceed the maximum line-to-line voltage rating of the system. Current For fused breakers by the formula: Step 2—Collect the X and R data of all limiting fuses for three-phase systems 15 the other circuit elements and convert should be so applied that the fuse 12  2.718–2  X/R MF   to a percent or per unit on a conve- voltage rating is equal to or less than 1.25 nient kVA and voltage base same as 1.41 x nominal system voltage. 16 that used in Step 1. Use the substran- If the X/R of the system feeding the sient X and R for all generators and breaker is not known, use X/R = 20. motors. 17 Refer to Table 1.3-8 for the standard ranges of X/R and power factors used in testing and rating low voltage breakers. 18 Refer to Table 1.3-9 for the circuit breaker interrupting rating multiplying factors to be used when the calculated 19 X/R ratio or power factor at the point the breaker is to be applied in the power distribution system falls outside 20 of the Table 1.3-8 X/R or power factors used in testing and rating the circuit breakers. MF is always greater than 1.0. 21

CA08104001E For more information, visit: www.eaton.com/consultants 1.3-12 Power Distribution Systems System Analysis April 2016 Sheet 01 044

i Molded-Case Breakers and Low Voltage Circuit Breaker Insulated Case Circuit Interrupting Derating Factors ii Breakers—Fault Calculations Refer to Table 1.3-8 for the standard Established standard values include ranges of X/R and power factors the following: The method of fault calculation is the used in testing and rating low voltage same as that for low voltage power breakers. Refer to Table 1.3-9 for Table 1.3-8. Standard Test Power Factors 1 circuit breakers. Again, the calculated the circuit breaker interrupting rating Interrupting Power Factor X/R Test fault current x MF ð breaker interrupting de-rating factors to be used when the Rating in kA Te s t R a n ge Range capacity. Because molded case breakers calculated X/R ratio or power factor Molded Case Circuit Breaker 2 are tested at lower X/R ratios, the MFs at the point the breaker is to be applied are different than those for low voltage 10 or Less 0.45–0.50 1.98–1.73 in the power distribution system falls Over 10 to 20 0.25–0.030 3.87–3.18 power circuit breakers. 3 outside of the Table 1.3-8 X/R or power Over 20 0.15–0.20 6.6–4.9 factors used in testing and rating the Low Voltage Power Circuit Breaker X2 –    circuit breakers. All 0.15 Maximum 6.6 Minimum 1+ 2.718 R2 4 MF  ------X1 Normally the short-circuit power factor –    For distribution systems where the R or X/R ratio of a distribution system 1+ 2.718 1 calculated short-circuit current X/R need not be considered in applying ratio differs from the standard values 5 low voltage circuit breakers. This is X1 •R1 = test X/R value given in the above table, circuit breaker because the ratings established in interrupting rating derating factors from X/R at point where breaker the applicable standard are based X •R = Table 1.3-9 table should be applied. 6 2 2 is applied on power factor values that amply cover most applications. 7 Table 1.3-9. Circuit Breaker Interrupting Rating Derating Factors % P.F. X/R Interrupting Rating 8 Molded Case or Insulated Case Power Circuit Breaker >10 kA m m L 9 / = 10 kA / = 20 kA 20 kA Unfused Fused 50 1.73 1.000 1.000 1.0 0 0 1.0 0 0 1.0 0 0 30 3.18 0.847 1.000 1.0 0 0 1.0 0 0 1.0 0 0 10 25 3.87 0.805 0.950 1.0 0 0 1.0 0 0 1.0 0 0 20 4.90 0.762 0.899 1.0 0 0 1.0 0 0 1.0 0 0 15 6.59 0.718 0.847 0.942 1.0 0 0 0.939 11 12 8.27 0.691 0.815 0.907 0.962 0.898 10 9.95 0.673 0.794 0.883 0.937 0.870 8.5 11. 72 0.659 0.778 0.865 0.918 0.849 12 7 14.25 0.645 0.761 0.847 0.899 0.827 5 19.97 0.627 0.740 0.823 0.874 0.797 13 Note: These are derating factors applied to the breaker and are the inverse of MF.

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For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.3-13 April 2016 System Analysis Sheet 01 045

Short-Circuit Calculations—Shortcut Method i 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). ii 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 1 shortcut 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 2 be studied. kVA base 2 (a) Per unit = pu impedance kVA base 2 =   (pu impedance on kVA base 1) 2. Change per unit, or percent, impedance from kVA base 1 one kVA base to another: 3 kVA base 2 (b) Percent = % impedance kVA base 2 =   (% impedance on kVA base 1) kVA base 1 4 percent impedance (ohms impedance) (kVA base) 3. Change ohms, or percent or per unit, etc.: (a) Per unit impedance = pu Z ==  100 kV 2 1000 (ohms impedance)(kVA base) (b) % impedance = % Z =  5 kV 2 10 (% impedance)kV 2 (10) (c) Ohms impedance =  kVA base 6

4. Change power-source impedance to per unit (a) —if utility fault capacity given in kVA or percent impedance on kVA base as selected 7 for this study: 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 amperes 8

kVA base in study Per-unit impedance = pu Z = ------(short-circuit current) 3 (kV of source) 9

5. Change motor rating to kVA: (a) —motor kVA —3 (kV) (I) where I = motor nameplate full-load amperes (b) —if 1.0 power factor synchronous motorkVA = (0.8) (hp) 10 (c) —if 0.8 power factor synchronous motorkVA = (1.0) (hp) (d) —if induction motor kVA = (1.0) (hp) 11 Three-phase kVA Single-phase kVA (a) Base current = I Base =  or  6. Determine symmetrical short-circuit current: 3 kV kV line-to-neutral 1.0 (b) Per unit ISC =  12 puZ

(c) rms Symmetrical current = ISC = (pu ISC) (IBase Amperes) 13 Three-phase KVA base Single-phase kVA base (d) rms Symmetrical current = Amperes = ------or ------puZ 3 kV puZ kV 14 (Three-phase kVA base) (100) Single-phase kVA base (100) (e) = ------or ------(%Z)3 kV (%Z) kV (kV) (1000) (g) = ------15 3 (ohms Z) kVA base (kVA base) (100) kV 2 1000 7. Determine symmetrical short-circuit kVA: (a) Symmetrical short-circuit kVA = ------==------puZ %Z ohms Z 16 3(line-to-neutral kV)21000 (b) = ------(ohms Z) 17 8. Determine line-to-line short-circuit current: (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%). 18 (c) —from single-phase transformer—see Page 1.3-15.

(a) —synchronous motor—5 times motor full load current (impedance 20%) 19 9. Determine motor contribution (or feedback) as jSee IEEE source of fault current: (b) —induction motor—4 times motor full-load current (impedance 25%) Standard No. 141 (c) —motor loads not individually identified, use contribution from group of motors as follows: —on 208Y/120 V systems—2.0 times transformer full-load current 20 —on 240-480-600 V three-phase, three-wire systems—4.0 times transformer full-load current —on 480Y/277 V three-phase, four-wire systems —In commercial buildings, 2.0 times transformers full-load current (50% motor load) —In industrial plants, 4.0 times transformer full-load current (100% motor load) 21

CA08104001E For more information, visit: www.eaton.com/consultants 1.3-14 Power Distribution Systems System Analysis April 2016 Sheet 01 046

Example Number 1 i How to Calculate Short-Circuit Currents at Ends of Conductors ii A. System Diagram B. Impedance Diagram (Using “Short Cut” Method for Combining Impedances and Sources). 1 AB C Utility Source 500 MVA Major Contribution Utility 2 Cables Transformer Switchboard Fault 3 1000 kV A 5.75% 480V Cables 4 Cable Fault Switchboard Fault

5 0.002 pu 1.00 pu 1.00 pu 1.00 pu 100 ft (30m) 3–350 kcmil Cable in Steel Conduit 6 ABC 0.0575 pu 0.027 pu 0.027 pu 0.027 pu Switchboard Fault Mixed Load—Motors and Lighting 7 Each Feeder—100 ft (30m) of 3–350 kcmil Cable in Steel Conduit Feeding Lighting and 0.027 pu 250 kVA of Motors Cable Fault

8 Cable Fault Combining Series Impedances: ZTOTAL = Z1 + Z2 + ... +Zn 1 1 1 1 9 C. Conductor impedance from Ta b l e 1. 5 - 17 , Combining Parallel Impedances: = + + ... Z Z Z Z Page 1.5-15. Conductors: 3–350 kcmil copper, TOTAL 1 2 n single conductors Circuit length: 100 ft 10 (30 m), in steel (magnetic) conduit Impedance 0.0595 pu Z = 0.00619 ohms/100 ft (30 m). 0.342 pu 0.0507 pu E 0.0777 pu 11 ZTOT = 0.00619 ohms (100 circuit feet) D. Fault current calculations (combining imped- 0.027 pu 0.027 pu ances arithmetically, using approximate 12 “Short Cut” method—see Note 4, Page 1.3-13)

13 Equation Step (See) Calculation 1 – Select 1000 kVA as most convenient base, since all data except utility source is on 14 secondary of 1000 kVA transformer. kVA base 1000 2 4(a) Utility per unit impedance Z == ------==------0.002 pu pu utility fault kVA 500.000 15 %Z 5.75 3 3(a) Transformer per unit impedance = Z ==------=0.0575 pu pu 100 100

16 4 4(a) and Motor contribution per unit impedance = Z = kVA base ==1000 1.00 pu pu ------9(c) 4 x motor kVA 4 x 250 17 5 3(a) Cable impedance in ohms (see above) = 0.00619 ohms (ohms)(kVA base) (0.00619)(1000) Cable impedance per unit = Z ===------0.027pu pu 2 2 18 (kV) (1000) (0.480) (1000) 6 6(d) Total impedance to switchboard fault = 0.0507 pu (see diagram above)

3-phase kVA base 1000 19 Symmetrical short circuit current at switchboard fault =  == 23,720 amperes rms Z 3 kV 0.0507 3 0.480 pu 20 7 6(d) Total impedance to cable fault = 0.0777 pu (see diagram above) 3-phase kVA base 1000 Symmetrical short circuit current at cable fault =  == 15, 480 amperes rms Z 3 kV 0.0777 3 0.480 21 pu Figure 1.3-9. Example Number 1

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.3-15 April 2016 System Analysis Sheet 01 047

Example Number 2 i Fault Calculation—Secondary Side of Single-Phase Transformer

A. System Diagram Deriving Transformer R and X: ii R = 0.1498 Z X 480V Three-Phase Switchboard Bus at 50,000A Symmetrical, X/R = 6.6 {X = 0.9887 Z   6.6 X = 6.6 R R 1 2 2 2 2 2 2 2 Z = X + R ==6.6R + R 43.56R + R ==44.56R 6.6753R 100 Ft. Two #2/0 Copper Conductors, Magnetic Conduit R = 0.0104 Ohms X = 0.0051 Ohms { Z 2 R =  R = 0.1498Z 6.6753 75 kVA Single-Phase 480-120/240V; Z = 2.8%, R = 1.64%, X = 2.27% X = 6.6R X = 0.9887Z 3

120V Half-winding of Transformer Multiply % R by 1.5 F2 {Multiply % X by 1.2 } Reference: IEEE Standard No. 141 4 240V F1 Full-winding of Transformer B. Impedance Diagram—Fault F1 C. Impedance Diagram—Fault F2 5

R = 0.00054 R = 0.00356 R = 0.00054 X = 0.00356 Syst Syst Syst Syst 6

RCond = 0.00677 RCond = 0.00332 RCond = 0.00677 XCond = 0.00332

RTfmr = 0.0164 RTfmr = 0.0227 RTfmr = 0.0246 XTfmr = 0.0272 7

RTotal = 0.02371 RTotal = 0.02958 RTotal = 0.03191 XTotal = 0.03408 F F F F 1 1 2 2 8 D. Impedance and Fault Current Calculations—75 kVA Base Note: To account for the outgoing and return paths of single-phase circuits (conductors, systems, etc.) use twice the three-phase values of R and X. 9 75 Z 0.0018 (From Page 1.3-13 R = 2 (0.1498 x Z) = 0.00054 pu Syst    pu Syst 3 0.480  50,000 Formula 4(b) ) 10 XSyst = 2 (0.9887 x Z) = 0.00356 pu ohms kVA Base 0.0104 75 Z =  (From Page 1.3-13 R = 2  = 0.00677 pu Cond 2 Cond 2 kV  1000 Formula 3(a) ) 0.48  1000 11 0.0051 75 X = 2  = 0.00332 pu Cond 2 0.48  1000 1.64 Full-winding of Transformer (75 kVA Base) R =  = 0.0164 pu 12 Tfmr 100 2.27 X =  = 0.0277 pu Tfmr 100 13 1.64 Half-winding of Transformer (75 kVA Base) R = 1.5  = 0.0246 pu Tfmr 100 2.27 14 X = 1.2  = 0.0272 pu Tfmr 100

2 2 Impedance to Fault F1—Full Winding Z = 0.02371 + 0.02958 = 0.03791 pu 15 Impedance to Fault F2—Half Winding 2 2 Short circuit current F1 = 75 ÷ (0.03791 x 0.240 kV) = 8,243 A Symmetrical Z = 0.03191 + 0.03408 = 0.04669 pu Short circuit current F2 = 75 ÷ (0.04669 x 0.120 kV) = 13,386 A Symmetrical 16 Figure 1.3-10. Example Number 2 17 Method 1: Shortcut Methods— at the load side end of the conductors Add source and conductor impedance or End of Cable can be calculated as follows. 0.00923 + 0.00273 = 0.01196 total ohms This method uses the approximation 277 V/30,000 A = 0.00923 ohms Next, 277 V/0.01196 ohms = 23,160 A 18 of adding Zs instead of the accurate (source impedance) rms at load side of conductors method of Rs and Xs. Conductor ohms for 500 kcmil conduc- X 30,000 A available 19 For Example: For a 480/277 V system tor from reference data in this section with 30,000 A symmetrical available in magnetic conduit is 0.00551 ohms 100 ft (30 m) at the line side of a conductor run of per 100 ft (30 m). For 100 ft (30 m) and 2–500 kcmil per phase 20 100 ft (30 m) of 2–500 kcmil per phase two conductors per phase we have: XIf = 23,160 A and neutral, the approximate fault current 0.00551/2 = 0.00273 ohms (conductor 21 impedance) Figure 1.3-11. Short-Circuit Diagram

CA08104001E For more information, visit: www.eaton.com/consultants 1.3-16 Power Distribution Systems System Analysis April 2016 Sheet 01 048

Method 2: Chart Approximate Method Step Five i The chart method is based on the following: Enter the chart along the bottom horizontal scale with the distance (in feet) from the transformer to the fault point. Motor Contribution Draw a vertical line up the chart to the point where it inter- ii For system voltages of 120/208 V, it is reasonable to assume sects the selected curve. Then draw a horizontal line to the that the connected load consists of 50% motor load, and that left from this point to the scale along the left side of the chart. the motors will contribute four times their full load current 1 into a fault. For system voltages of 240 and 480 V, it is rea- Step Six sonable to assume that the connected load consists of 100% The value obtained from the left-hand vertical scale is the fault motor load, and that the motors will contribute four times current (in thousands of amperes) available at the fault point. 2 their full load current into a fault. These motor contributions have been factored into each curve as if all motors were For a more exact determination, see the formula method. connected to the transformer terminals. It should be noted that even the most exact methods for 3 calculating fault energy use some approximations and some Feeder Conductors assumptions. Therefore, it is appropriate to select a method The conductor sizes most commonly used for feeders which is sufficiently accurate for the purpose, but not more 4 from molded case circuit breakers are shown. For conductor burdensome than is justified. The charts that follow make sizes not shown, the following table has been included for use of simplifications that are reasonable under most cir- conversion to equivalent arrangements. In some cases it cumstances and will almost certainly yield answers that are 5 may be necessary to interpolate for unusual feeder ratings. on the safe side. This may, in some cases, lead to application Table 1.3-10 is based on using copper conductor. of circuit breakers having interrupting ratings higher than necessary, but should eliminate the possibility of applying Table 1.3-10. Conductor Conversion (Based on Using Copper Conductor) 6 units which will not be safe for the possible fault duty. If Your Conductor is: Use Equivalent Arrangement

3–No. 4/0 cables 2–500 kcmil 7 4–No. 2/0 cables 2–500 kcmil 4 – 750 kcmil 2 – 500 kcmil UTILITY KVA 3–2000 kcmil cables 4–750 kcmil 15.0 B 250 kcmil 5–400 kcmil cables 4–750 kcmil #1/0 AWG A INFINITE F #4 AWG B 500,000 8 6–300 kcmil cables 4–750 kcmil C 250,000 D 150,000 800 A busway 2–500 kcmil 12.5 E 100,000 1000 A busway 2–500 kcmil F 50,000 1600 A busway 4–750 kcmil 9 10.0 4 – 750 kcmil 2 – 500 kcmil 250 kcmil Short-Circuit Current Readout #1/0 AWG 7. 5 #4 AWG 10 The readout obtained from the charts is the rms symmetrical amperes available at the given distance from the trans- former. The circuit breaker should have an interrupting 5.0 11 capacity at least as large as this value. ult Current i n Thous a nds o f Amperes a ult Current (Sym.)

F 2.5 12 How to Use the Short-Circuit Charts 0 Step One 0 2 5 10 20 50 100 200 500 1000 2000 5000 Distance in Feet from Transformer to Breaker Location 13 Obtain the following data: 1. System voltage Figure 1.3-12. 225 kVA Transformer/4.5% Impedance/208 V 2. Transformer kVA rating (from transformer nameplate) 14 3. Transformer impedance (from transformer nameplate) 4. Primary source fault energy available in kVA (from electric utility or distribution system engineers) UTILITY KV 15 30 A INFINITE Step Two 4 – 750 kcmil B 500,000 2 – 500 kcmil C 250,000 D 150,000 Select the applicable chart from the following pages. The 25 250 kcmil 16 #1/0 AWG E 100,000 charts are grouped by secondary system voltage, which is #4 AWG F 50,000 listed with each transformer. Within each group, the chart for the lowest kVA transformer is shown first, followed in 20 B 17 ascending order to the highest rated transformer. F 15 Step Three 18 Select the family of curves that is closest to the “available 10 4 – 750 kcmil source kVA.” The black line family of curves is for a source of 2 – 500 kcmil 250 kcmil 500,000 kVA. The lower value line (in red) family of curves is #1/0 AWG

ult Current i n Thous a nds o f Amperes a ult Current (Sym.) #4 AWG 19 for a source of 50,000 kVA. You may interpolate between F 5 curves if necessary, but for values above 100,000 kVA it is

appropriate to use the 500,000 kVA curves. 0 20 0 2 5 10 20 50 100 200 500 1000 2000 5000 Step Four Distance in Feet from Transformer to Breaker Location Select the specific curve for the conductor size being used. If 21 your conductor size is something other than the sizes shown Figure 1.3-13. 300 kVA Transformer/4.5% Impedance/208 V on the chart, refer to the conductor conversion Ta b l e 1. 3 - 10 .

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B 4 – 750 kcmil i 2 – 500 kcmil 250 kcmil UTILITY KV UTILITY KVA 30 #1/0 AWG 120 #4 AWG A INFINITE A INFINITE F B 500,000 B 500,000 C 250,000 C 250,000 ii D 150,000 4 – 750 kcmil D 150,000 25 E 100,000 100 2 – 500 kcmil E 100,000 F 50,000 250 kcmil F 50,000 #1/0 AWG #4 AWG 1 20 80 B

15 60 F 2 4 – 750 kcmil 2 – 500 kcmil 10 250 kcmil 40 #1/0 AWG 4 – 750 kcmil #4 AWG 2 – 500 kcmil 3 250 kcmil ult Current i n Thous a nds o f Amperes a ult Current (Sym.) ult Current i n Thous a nds o f Amperes a ult Current (Sym.) #1/0 AWG F F 5 20 #4 AWG 4 0 0 0 2 5 10 20 50 100 200 500 1000 2000 5000 0 2 5 10 20 50 100 200 500 1000 2000 5000 Distance in Feet from Transformer to Breaker Location Distance in Feet from Transformer to Breaker Location 5 Figure 1.3-14. 500 kVA Transformer/4.5% Impedance/208 V Figure 1.3-17. 1500 kVA Transformer/5.5% Impedance/208 V 6

UTILITY KVA UTILITY KVA 60 120 7 A INFINITE 4 – 750 kcmil A INFINITE B 500,000 2 – 500 kcmil B 500,000 250 kcmil 4 – 750 kcmil C 250,000 B C 250,000 2 – 500 kcmil D 150,000 #1/0 AWG D 150,000 50 250 kcmil E 100,000 100 #4 AWG E 100,000 8 #1/0 AWG F 50,000 F 50,000 #4 AWG

40 B 80

F 9 F 30 60 10 20 40 4 – 750 kcmil 4 – 750 kcmil 2 – 500 kcmil 2 – 500 kcmil 250 kcmil 250 kcmil #1/0 AWG ult Current i n Thous a nds o f Amperes a ult Current (Sym.) ult Current i n Thous a nds o f Amperes a ult Current (Sym.) #4 AWG F F 10 #1/0 AWG 20 11 #4 AWG

0 0 0 2 5 10 20 50 100 200 500 1000 2000 5000 0 2 5 10 20 50 100 200 500 1000 2000 5000 12 Distance in Feet from Transformer to Breaker Location Distance in Feet from Transformer to Breaker Location

Figure 1.3-15. 750 kVA Transformer/5.5% Impedance/208 V Figure 1.3-18. 2000 kVA Transformer/5.5% Impedance/208 V 13

14 4 – 750 kcmil UTILITY KVA UTILITY KVA 60 2 – 500 kcmil 12 250 kcmil A INFINITE A INFINITE #1/0 AWG B 500,000 B 500,000 15 B #4 AWG C 250,000 C 250,000 D 150,000 D 150,000 50 E 100,000 10 E 100,000 F 50,000 B F 50,000 F F 16 40 8

30 6 4 – 750 kcmil 17 4 – 750 kcmil 2 – 500 kcmil 2 – 500 kcmil 250 kcmil 250 kcmil #1/0 AWG #1/0 AWG #4 AWG 20 #4 AWG 4 18 4 – 750 kcmil ult Current i n Thous a nds o f Amperes a ult Current (Sym.) ult Current i n Thous a nds o f Amperes a ult Current (Sym.) 2 – 500 kcmil F F 10 2 250 kcmil #1/0 AWG #4 AWG 19 0 0 0 2 5 10 20 50 100 200 500 1000 2000 5000 0 2 5 10 20 50 100 200 500 1000 2000 5000 Distance in Feet from Transformer to Breaker Location Distance in Feet from Transformer to Breaker Location 20 Figure 1.3-16. 1000 kVA Transformer/5.5% Impedance/208 V Figure 1.3-19. 300 kVA Transformer/4.5% Impedance/480 V 21

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i UTILITY KVA UTILITY KVA 30 60 A INFINITE A INFINITE B 500,000 B 500,000 ii C 250,000 C 250,000 D 150,000 D 150,000 25 50 4 – 750 kcmil E 100,000 2 – 500 kcmil E 100,000 F 50,000 250 kcmil F 50,000 #1/0 AWG 1 #4 AWG 20 40 4 – 750 kcmil B 2 – 500 kcmil 250 kcmil 15 B #1/0 AWG 30 2 #4 AWG F F

10 20 3 4 – 750 kcmil 4 – 750 kcmil 2 – 500 kcmil 2 – 500 kcmil 250 kcmil ult Current i n Thous a nds o f Amperes a ult Current (Sym.) i n Thous a nds o f Amperes a ult Current (Sym.) #1/0 AWG F 5 250 kcmil F 10 #1/0 AWG #4 AWG 4 #4 AWG 0 0 0 2 5 10 20 50 100 200 500 1000 2000 5000 0 2 5 10 20 50 100 200 500 1000 2000 5000 5 Distance in Feet from Transformer to Breaker Location Distance in Feet from Transformer to Breaker Location Figure 1.3-20. 500 kVA Transformer/4.5% Impedance/480 V Figure 1.3-23. 1500 kVA Transformer/5.5% Impedance/480 V 6

UTILITY KVA UTILITY KVA 7 30 60 4 – 750 kcmil A INFINITE 2 – 500 kcmil A INFINITE B 500,000 250 kcmil B 500,000 C 250,000 C 250,000 4 – 750 kcmil #1/0 AWG D 150,000 B #4 AWG D 150,000 25 2 – 500 kcmil E 100,000 50 E 100,000 8 250 kcmil F 50,000 F 50,000 #1/0 AWG #4 AWG 20 B 40

9 F F 15 30

10 4 – 750 kcmil 10 2 – 500 kcmil 20 4 – 750 kcmil 250 kcmil 2 – 500 kcmil #1/0 AWG 250 kcmil #4 AWG #1/0 AWG ult Current i n Thous a nds o f Amperes a ult Current (Sym.) i n Thous a nds o f Amperes a ult Current (Sym.) #4 AWG 11 F 5 F 10

0 0 12 0 2 5 10 20 50 100 200 500 1000 2000 5000 0 2 5 10 20 50 100 200 500 1000 2000 5000 Distance in Feet from Transformer to Breaker Location Distance in Feet from Transformer to Breaker Location

13 Figure 1.3-21. 750 kVA Transformer/5.5% Impedance/480 V Figure 1.3-24. 2000 kVA Transformer/5.5% Impedance/480 V

14 4 – 750 kcmil UTILITY KVA 30 2 – 500 kcmil 250 kcmil A INFINITE 15 #1/0 AWG B 500,000 #4 AWG C 250,000 B D 150,000 25 E 100,000 F 50,000

16 F 20

17 15 4 – 750 kcmil 2 – 500 kcmil 250 kcmil 10 #1/0 AWG 18 #4 AWG ult Current i n Thous a nds o f Amperes a ult Current (Sym.)

F 5 19 0 0 2 5 10 20 50 100 200 500 1000 2000 5000 20 Distance in Feet from Transformer to Breaker Location Figure 1.3-22. 1000 kVA Transformer/5.5% Impedance/480 V 21

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Determining X and R Values How to Estimate Short-Circuit Method 2: Currents at Transformer Refer to Page 1.5-9 in the Reference i from Transformer Loss Data section, and use appropriate row of Secondaries: Method 1: data based on transformer kVA and primary short-circuit current available. ii Method 1: Given a 500 kVA, 5.5% Z transformer This will yield more accurate results with 9000W total loss; 1700W no-load To obtain three-phase rms symmetrical and allow for including motor short- loss; 7300W load loss and primary short-circuit current available at circuit contribution. 1 voltage of 480 V. transformer secondary terminals, use the formula: 2 100 I = I  ------SC FLC %Z 3 500 2 where %Z is the transformer impedance 3    R= 7300 W 3 0.480 in percent, from Tables 1.5-6 through 1.5-11, Page 1.5-11. 4 This is the maximum three-phase sym- metrical bolted-fault current, assuming sustained primary voltage during fault, 5 %R = 0.0067 ohms i.e., an infinite or unlimited primary power source (zero source impedance). 0.0067 500 %R = = 1.46% Because the power source must 6 2 10 0.48 always have some impedance, this is a conservative value; actual fault 2 2 %X = 5.5 – 1.46 = 5.30% current will be somewhat less. 7 Method 2: Note: This will not include motor short- circuit contribution. Using same values above. 8

2 I R Losses %R =  9 10 kVA 7300  = 1.46 10 500 10 2 2 %X= 5.5 – 1.46 = 5.30% 11

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CA08104001E For more information, visit: www.eaton.com/consultants 1.3-20 Power Distribution Systems System Analysis April 2016 Sheet 01 052

Voltage Drop Considerations Computer Equipment: With the Motor Starting i proliferation of data-processing and The first consideration for voltage computer- or microprocessor-controlled Motor inrush on starting must be limited drop is that under the steady-state manufacturing, the sensitivity of to minimize voltage dips. Table 1.3-11 ii conditions of normal load, the voltage computers to voltage has become an on the next page will help select the at the utilization equipment must be important consideration. Severe dips of proper type of motor starter for various adequate. Fine-print notes in the NEC short duration can cause a computer motors, and to select generators of 1 recommend sizing feeders and branch to “crash”—shut down completely, adequate size to limit voltage dip. circuits so that the maximum voltage and other voltage transients caused See Ta b 2 9 for additional data on drop in either does not exceed 3%, by starting and stopping motors can reduced voltage motor starting. with the total voltage drop for feeders 2 cause data-processing errors. While Utility Systems and branch circuits not to exceed 5%, voltage drops must be held to a mini- Where the power is supplied by a for efficiency of operation. (Fine print mum, in many cases computers will utility network, the motor inrush can 3 notes in the NEC are not mandatory.) require special power-conditioning be assumed to be small compared equipment to operate properly. In addition to steady-state conditions, to the system capacity, and voltage 4 voltage drop under transient condi- Industrial Plants: Where large motors at the source can be assumed to tions, with sudden high-current, short- exist, and unit substation transformers be constant during motor starting. time loads, must be considered. The are relatively limited in size, voltage Voltage dip resulting from motor 5 most common loads of this type are dips of as much as 20% may be per- starting can be calculated on the basis motor inrush currents during starting. missible in some cases, if they do not of the voltage drop in the conductors These loads cause a voltage dip on occur too frequently. Lighting is often between the power source and 6 the system as a result of the voltage supplied from separate transformers, the motor resulting from the inrush drop in conductors, transformers and and is minimally affected by voltage current. Where the utility system is generators under the high current. dips in the power systems. However, it limited, the utility will often specify the 7 This voltage dip can have numerous is usually best to limit dips to between maximum permissible inrush current adverse effects on equipment in the 5 and 10% at most. One critical consid- or the maximum hp motor they will system, and equipment and conduc- eration is that a large voltage dip can permit to be started across-the-line. tors must be designed and sized to cause a dropout (opening) of magnetic 8 Transformer Considerations minimize these problems. In many motor contactors and control relays. cases, reduced-voltage starting of The actual dropout voltage varies con- If the power source is a transformer, 9 motors to reduce inrush current siderably among starters of different and the inrush kVA or current of the will be necessary. manufacturers. The only standard that motor being started is small compared exists is that of NEMA, which states to the full-rated kVA or current of the 10 Recommended Limits of that a starter must not drop out at 85% transformer, the transformer voltage Voltage Variation of its nominal coil voltage, allowing dip will be small and may be ignored. only a 15% dip. While most starters As the motor inrush becomes a signifi- General Illumination: Flicker in cant percentage of the transformer 11 incandescent lighting from voltage will tolerate considerably more voltage dip before dropping out, limiting dip to full-load rating, an estimate of the dip can be severe; lumen output drops transformer voltage drop must be about three times as much as the 15% is the only way to ensure continu- 12 ity of operation in all cases. added to the conductor voltage drop voltage dips. That is, a 10% drop in to obtain the total voltage drop to the voltage will result in a 30% drop in X-Ray Equipment: Medical x-ray and motor. Accurate voltage drop calcula- 13 light output. While the lumen output similar diagnostic equipment, such as tion would be complex and depend drop in fluorescent lamps is roughly CAT-scanners, are extremely sensitive upon transformer and conductor proportional to voltage drop, if the to low voltage. They present a small, resistance, reactance and impedance, 14 voltage dips about 25%, the lamp will steady load to the system until the as well as motor inrush current and go out momentarily and then restrike. instant the x-ray tube is “fired.” This power factor. However, an approxima- For high-intensity discharge (HID) presents a brief but extremely high tion can be made on the basis of the 15 lamps such as mercury vapor, high- instantaneous momentary load. In low power-factor motor inrush current pressure sodium or metal halide, if the some modern x-ray equipment, the (30–40%) and impedance of the lamp goes out because of an excessive firing is repeated rapidly to create transformer. 16 voltage dip, it will not restrike until it multiple images. The voltage regula- has cooled. This will require several tion must be maintained within the For example, if a 480 V transformer minutes. These lighting flicker effects manufacturer’s limits, usually 2 to 3%, has an impedance of 5%, and the can be annoying, and in the case of under these momentary loads, to 17 motor inrush current is 25% of the HID lamps, sometimes serious. In ensure proper x-ray exposure. areas where close work is being done, transformer full-load current (FLC), such as drafting rooms, precision then the worst case voltage drop will 18 assembly plants, and the like, even be 0.25 x 5%, or 1.25%. a slight variation, if repeated, can be 19 very annoying, and reduce efficiency. The allowable motor inrush current is Voltage variation in such areas should determined by the total permissible be held to 2 or 3% under motor-starting voltage drop in transformer and 20 or other transient conditions. conductors.

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Table 1.3-11. Factors Governing Voltage Drop Type of Starting Starting How Starting Starting Torque per Unit of Full-Load Amperes i 1 2 Motor To r q u e Current Started Current Full Load Torque per kVA Generator 3 % Full-Load Motor Rpm Capacity for Each 3 1% Voltage Drop 1750 1150 850 ii

Design A Normal Normal Across-the-line 600–700 1.5 1.35 1.25 0.0109–.00936 resistance 480–560 ➁ 0.96 0.87 0.80 0.0136–.0117 1 autotransformer 375–450 ➁ 0.96 0.87 0.80 0.0170–.0146 Design B Normal Low Across-the-line 500–600 1.5 1.35 1.25 0.0131–.0109 resistance 400–480 ➁ 0.96 0.87 0.80 0.0164–.01365 2 autotransformer 320–400 ➁ 0.96 0.87 0.80 0.0205–.0170 Design C High Low Across-the-line 500–600 — 0.2 to 2.5 — 0.0131–.0109 resistance 400–480 ➁ — 1.28 to 1.6 — 0.0164–.01365 3 autotransformer 320–400 ➁ — 1.28 to 1.6 — 0.0205–.0170 Wound Rotor High Low Secondary controller 100% current — — — — for 100% — — — — torque — — — 0.0655 4 Synchronous (for compressors) Low — Across-the-line 300 40% Starting, 40% Pull-In 0.0218 Synchronous (for centrifugal pumps) Low — Across-the-line 450–550 60% Starting, 110% Pull-In 0.0145–.0118 4 Autotransformer 288–350 38% Starting, 110% Pull-In 0.0228–.0197 5 1 Consult NEMA MG-1 sections 1 and 12 for the exact definition of the design letter. 2 In each case, a solid-state reduced voltage starter can be adjusted and controlled to provide the required inrush current and torque characteristics. 3 Where accuracy is important, request the code letter of the the motor and starting and breakdown torques from the motor vendor. 6 4 Using 80% taps.

Engine Generator Systems From the nameplate data on the motor, Example: 7 With an engine generator as the the full-load amperes of a 7-1/2 hp. Assuming a project having a source of power, the type of starter 220 V, 1750 rpm, three-phase, squirrel- 1000 kVA generator, where the that will limit the inrush depends on cage motor is 19.0 A. Therefore: voltage variation must not exceed 8 the characteristics of the generator. Starting current (%F.L.) = 10%. Can a 75 hp, 1750 rpm, 220 V, Although automatic voltage regulators three-phase, squirrel-cage motor be are usually used with all AC engine- 10 100  1000 started without objectionable lamp 9   3.45 or 345%. generators, the initial dip in voltage is 19.0 220  3  0.40 flicker (or 10% voltage drop)? caused by the inherent regulation of From tables in the circuit protective 10 the generator and occurs too rapidly From Table 1.3-11, a NEMA design C or devices reference section, the full-load for the voltage regulator to respond. NEMA design D motor with an autotrans- amperes of this size and type of motor It will occur whether or not a regulator former starter gives approximately this is 158 A. To convert to same basis as 11 is installed. Consequently, the percent starting ratio. It could also be obtained column 7, 158 A must be divided by of initial voltage drop depends on the from a properly set solid-state adjust- the generator capacity and % voltage ratio of the starting kVA taken by the able reduced voltage starter. 12 motor to the generator capacity, the drop, or: The choice will depend upon the inherent regulation of the generator, 158 0.0158 A per kVA torque requirements of the load since = the power-factor of the load thrown 1000 x 10 per 1% voltage drop 13 on the generator, and the percentage the use of an autotransformer starter load carried by the generator. reduces the starting torque in direct Checking against the table, 0.0158 falls proportion to the reduction in starting within the 0.0170–0.0146 range. This A standard 80% power-factor engine- current. In other words, a NEMA indicates that a general-purpose motor 14 type generator (which would be design C motor with an autotrans- with autotransformer starting can used where power is to be supplied former would have a starting torque be used. to motor loads) has an inherent of approximately full-load (see Ta b l e 15 regulation of approximately 40% 1.3-11) whereas the NEMA design D Note: Designers may obtain calculated from no-load to full-load. This means motor under the same conditions information from engine generator manufacturers. that a 50% variation in load would would have a starting torque of 16 cause approximately 20% variation approximately 1-1/2 times full-load. The calculation results in conservative in voltage (50% x 40% = 20%). Note: If a resistance starter were used for results. The engineer should provide 17 Assume that a 100 kVA, 80% PF the same motor terminal voltage, the start- to the engine-generator vendor the engine-type generator is supplying ing torque would be the same as that starting kVA of all motors connected to the power and that the voltage drop obtained with autotransformer type, but the the generator and their starting sequence. 18 should not exceed 10%. Can a 7-1/2 hp, starting current would be higher, as shown. The engineer should also specify the 220 V, 1750 rpm, three-phase, squirrel- maximum allowable drop. The engi- cage motor be started without Shortcut Method neer should request that the engine-gen- 19 exceeding this voltage drop? Column 7 in Table 1.3-11 has been erator vendor consider the proper worked out to simplify checking. generator size when closed-transition Starting ratio = The figures were obtained by using the autotransformer reduced voltage start- 20 ers, and soft-start solid-state starter Percent voltage drop gen. kVA  1000 formula above and assuming  1 kVA generator capacity and 1% are used; so the most economical F.L. amperes volts  3  reg. of gen. voltage drop. method of installation is obtained. 21

CA08104001E For more information, visit: www.eaton.com/consultants 1.3-22 Power Distribution Systems System Analysis April 2016 Sheet 01 054

Voltage Drop Formulas If the receiving end voltage, load current and power factor i (PF) are known. Approximate Method Voltage Drop 2 2 ii EVD = ERcos + IR + ERsin + IX – ER E = IR cos + IX sin VD ER is the receiving end voltage. 1 where abbreviations are same as below “Exact Method.” Exact Method 2—If receiving or sending mVA and its power factor are known at a known sending or receiving voltage. Exact Methods 2 Voltage drop 2 2 2 ZMVAR E = E ++------2ZMVA cos– Exact Method 1—If sending end voltage and load PF S R 2 R R E 3 are known. R or 2 2 E = E ++IR cos IX sin – E – IX cos – IR sin VD S S 2 4 2 2 ZMVAR E E += ------– 2ZMVA cos– where: R S 2 S S ES 5 EVD = Voltage drop, line-to-neutral, volts where: ES = Source voltage, line-to-neutral, volts ER = Receiving line-line voltage in kV 6 I = Line (Load) current, amperes ES = Sending line-line voltage in kV R = Circuit (branch, feeder) resistance, ohms MVAR = Receiving three-phase mVA 7 X = Circuit (branch, feeder) reactance, ohms MVAS = Sending three-phase mVA cos = Power factor of load, decimal 8 Z = Impedance between and receiving ends sin = Reactive factor of load, decimal  = The angle of impedance Z

9 R = Receiving end PF S = Sending end PF, positive when lagging 10

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For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.3-23 April 2016 System Analysis Sheet 01 055

Voltage Drop Table 1.3-12. Temperature Correction Factors To select minimum conductor size: for Voltage Drop 1. Determine maximum desired i Voltage Drop Tables Conductor Percent Correction voltage drop, in volts. Size Power Factors % Note: Busway voltage drop tables are 2. Divide voltage drop by ii shown in Ta b 2 4 of this catalog. 10090807060 (amperes x circuit feet). No. 14 to No. 4 5.0 4.7 4.7 4.6 4.6 3. Multiply by 100. Tables for calculating voltage drop for No. 2 to 3/0 5.0 4.2 3.7 3.5 3.2 1 copper and aluminum conductors, in 4/0 to 500 kcmil 5.0 3.1 2.6 2.3 1.9 4. Find nearest lower voltage drop either magnetic (steel) or nonmagnetic 600 to 1000 kcmil 5.0 2.6 2.1 1.5 1.3 value in tables, in correct column (aluminum or non-metallic) conduit, for type of conductor, conduit and 2 appear on Page 1.3-24. These tables Calculations power factor. Read conductor size give voltage drop per ampere per for that value. 100 ft (30 m) of circuit length. The To calculate voltage drop: 3 circuit length is from the beginning 1. Multiply current in amperes by 5. Where this results in an oversized point to the end point of the circuit the length of the circuit in feet to cable, verify cable lug sizes for regardless of the number of conductors. get ampere-feet. Circuit length is molded case breakers and fusible 4 switches. Where lug size available Tables are based on the following the distance from the point of origin to the load end of the circuit. is exceeded, go to next higher conditions: rating. 5 1. Three or four single conductors in 2. Divide by 100. a conduit, random lay. For three- Example: 3. Multiply by proper voltage drop conductor cable, actual voltage value in tables. Result is voltage A three-phase, four-wire lighting 6 drop will be approximately the drop. feeder on a 208 V circuit is 250 ft same for small conductor sizes (76.2 m) long. The load is 175 A at and high power factors. Actual Example: 90% PF. It is desired to use aluminum 7 voltage drop will be from 10 to A 460 V, 100 hp motor, running at 80% conductors in aluminum conduit. What 15% lower for larger conductor PF, draws 124 A full-load current. It is size conductor is required to limit the sizes and lower power factors. fed by three 2/0 copper conductors in voltage drop to 2% phase-to-phase? 8 2 2.Voltage drops are phase-to-phase, steel conduit. The feeder length is 1. VD =   208= 4.16 V for three-phase, three-wire or 150 ft (46 m). What is the voltage drop 100 three-phase, four-wire 60 Hz in the feeder? What is the percentage 9 voltage drop? 2. 4.16 = 0.0000951 circuits. For other circuits, multiply 175 250 voltage drop given in the tables by 1. 124 A x 150 ft (46 m) = 18,600 A-ft 10 the following correction factors: 3. 0.0000951 100= 0.00951 2. Divided by 100 = 186 Three-phase, four-wire, 4. In table, under aluminum conduc- 11 phase-to-neutral x 0.577 3. Table: 2/0 copper, magnetic conduit, tors, nonmagnetic conduit, 90% Single-phase, two-wire x 1.155 80% PF = 0.0187 PF, the nearest lower value is Single-phase, three-wire, 186 x 0.0187 = 3.48 V drop 0.0091. Conductor required is 12 phase-to-phase x 1.155 3.48 x 100 = 0.76% drop 500 kcmil. (Size 4/0 THW would Single-phase, three-wire, 460 have adequate ampacity, but the phase-to-neutral x 0.577 4. Conclusion: 0.76% voltage drop voltage drop would be excessive.) 13 3. Voltage drops are for a conductor is very acceptable. (See NEC 2005 temperature of 75 °C. They may be Article 215, which suggests that a used for conductor temperatures voltage drop of 3% or less on a 14 between 60 °C and 90 °C with feeder is acceptable.) reasonable accuracy (within ±5%). However, correction factors in 15 Table 1.3-12 can be applied if desired. The values in the table are in percent of total voltage drop. 16 For conductor temperature of 60 °C– SUBTRACT the percentage from 17 Table 1.3-12. For conductor temperature of 90 °C– ADD the percentage from Table 1.3-12. 18

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CA08104001E For more information, visit: www.eaton.com/consultants 1.3-24 Power Distribution Systems System Analysis April 2016 Sheet 01 056

Table 1.3-13. Voltage Drop—Volts per Ampere per 100 Feet (30 m); Three-Phase, Phase-to-Phase i Conductor Size Magnetic Conduit (Steel) Nonmagnetic Conduit (Aluminum or Nonmetallic) AWG Load Power Factor, % Load Power Factor, % or kcmil ii 60 70 80 90 100 60 70 80 90 100 Copper Conductors 14 0.3390 0.3910 0.4430 0.4940 0.5410 0.3370 0.3900 0.4410 0.4930 0.5410 1 12 0.2170 0.2490 0.2810 0.3130 0.3410 0.2150 0.2480 0.2800 0.3120 0.3410 10 0.1390 0.1590 0.1790 0.1980 0.2150 0.1370 0.1580 0.1780 0.1970 0.2150 8 0.0905 0.1030 0.1150 0.1260 0.1350 0.0888 0.1010 0.1140 0.1250 0.1350 2 6 0.0595 0.0670 0.0742 0.0809 0.0850 0.0579 0.0656 0.0730 0.0800 0.0849 4 0.0399 0.0443 0.0485 0.0522 0.0534 0.0384 0.0430 0.0473 0.0513 0.0533 2 0.0275 0.0300 0.0323 0.0342 0.0336 0.0260 0.0287 0.0312 0.0333 0.0335 1 0.0233 0.0251 0.0267 0.0279 0.0267 0.0218 0.0238 0.0256 0.0270 0.0266 3 1/0 0.0198 0.0211 0.0222 0.0229 0.0213 0.0183 0.0198 0.0211 0.0220 0.0211 2/0 0.0171 0.0180 0.0187 0.0190 0.0170 0.0156 0.0167 0.0176 0.0181 0.0169 3/0 0.0148 0.0154 0.0158 0.0158 0.0136 0.0134 0.0141 0.0147 0.0149 0.0134 4 4/0 0.0130 0.0134 0.0136 0.0133 0.0109 0.0116 0.0121 0.0124 0.0124 0.0107 250 0.0122 0.0124 0.0124 0.0120 0.0094 0.0107 0.0111 0.0112 0.0110 0.0091 300 0.0111 0.0112 0.0111 0.0106 0.0080 0.0097 0.0099 0.0099 0.0096 0.0077 5 350 0.0104 0.0104 0.0102 0.0096 0.0069 0.0090 0.0091 0.0091 0.0087 0.0066 500 0.0100 0.0091 0.0087 0.0080 0.0053 0.0078 0.0077 0.0075 0.0070 0.0049 600 0.0088 0.0086 0.0082 0.0074 0.0046 0.0074 0.0072 0.0070 0.0064 0.0042 6 750 0.0084 0.0081 0.0077 0.0069 0.0040 0.0069 0.0067 0.0064 0.0058 0.0035 1000 0.0080 0.0077 0.0072 0.0063 0.0035 0.0064 0.0062 0.0058 0.0052 0.0029 Aluminum Conductors 7 12 0.3296 0.3811 0.4349 0.4848 0.5330 0.3312 0.3802 0.4328 0.4848 0.5331 10 0.2133 0.2429 0.2741 0.3180 0.3363 0.2090 0.2410 0.2740 0.3052 0.3363 8 0.1305 0.1552 0.1758 0.1951 0.2106 0.1286 0.1534 0.1745 0.1933 0.2115 8 6 0.0898 0.1018 0.1142 0.1254 0.1349 0.0887 0.1011 0.1127 0.1249 0.1361 4 0.0595 0.0660 0.0747 0.0809 0.0862 0.0583 0.0654 0.0719 0.0800 0.0849 2 0.0403 0.0443 0.0483 0.0523 0.0535 0.0389 0.0435 0.0473 0.0514 0.0544 9 1 0.0332 0.0357 0.0396 0.0423 0.0428 0.0318 0.0349 0.0391 0.0411 0.0428 1/0 0.0286 0.0305 0.0334 0.0350 0.0341 0.0263 0.0287 0.0322 0.0337 0.0339 2/0 0.0234 0.0246 0.0275 0.0284 0.0274 0.0227 0.0244 0.0264 0.0274 0.0273 3/0 0.0209 0.0220 0.0231 0.0241 0.0217 0.0160 0.0171 0.0218 0.0233 0.0222 10 4/0 0.0172 0.0174 0.0179 0.0177 0.0170 0.0152 0.0159 0.0171 0.0179 0.0172 250 0.0158 0.0163 0.0162 0.0159 0.0145 0.0138 0.0144 0.0147 0.0155 0.0138 300 0.0137 0.0139 0.0143 0.0144 0.0122 0.0126 0.0128 0.0133 0.0132 0.0125 11 350 0.0130 0.0133 0.0128 0.0131 0.0100 0.0122 0.0123 0.0119 0.0120 0.0101 500 0.0112 0.0111 0.0114 0.0099 0.0076 0.0093 0.0094 0.0094 0.0091 0.0072 600 0.0101 0.0106 0.0097 0.0090 0.0063 0.0084 0.0085 0.0085 0.0081 0.0060 12 750 0.0095 0.0094 0.0090 0.0084 0.0056 0.0081 0.0080 0.0078 0.0072 0.0051 1000 0.0085 0.0082 0.0078 0.0071 0.0043 0.0069 0.0068 0.0065 0.0058 0.0038 13

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For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.4-1 April 2016 System Application Considerations Sheet 01 057 Capacitors

Capacitors and Power Factor ANSI Standard C37.06 (indoor oilless Low Voltage Capacitor Switching circuit breakers) indicates the preferred i ratings of Eaton’s Type VCP-W vacuum Circuit breakers and switches for use Capacitor General Application breaker. For capacitor switching, with a capacitor must have a current Considerations careful attention should be paid to rating in excess of rated capacitor ii the notes accompanying the table. current to provide for overcurrent from Additional application information overvoltages at fundamental frequency is available in Ta b 3 5 regarding The definition of the terms are in ANSI Standard C37.04 Article 5.13 (for the and harmonic currents. The following 1 capacitors and harmonic filters percent of the capacitor-rated current as follows: latest edition). The application guide ANSI/IEEE Standard C37.012 covers the should be used as a general guideline: ■ Capacitor selection method of calculation of the Fused and unfused switches. . . . 165% 2 ■ Where to install capacitors in a plant quantities covered by C37.06 Standard. distribution system Molded case breaker or Note that the definitions in C37.04 equivalent ...... 150% 3 ■ Locating capacitors on reduced make the switching of two capacitors voltage and multi-speed starters banks in close proximity to the switch- DSII power circuit breakers . . . . 135% ■ Harmonic considerations gear bus a back-to-back mode of Magnum DS power 4 ■ switching. This classification requires Eliminating harmonic problems circuit breaker ...... 135% ■ National Electrical Code a definite purpose circuit breaker requirements (breakers specifically designed for Contactors: 5 capacitance switching). Open type ...... 135% Medium Voltage We recommend that such application Enclosed type...... 150% 6 Capacitor Switching be referred to Eaton. Capacitance switching constitutes The NEC, Section 460.8(C), requires A breaker specified for capacitor the disconnecting means to be rated not severe operating duty for a circuit switching should include as applicable: 7 breaker. At the time the breaker opens less than 135% of the rated capacitor at near current zero, the capacitor is 1. Rated maximum voltage. current (for 600 V and below). fully charged. After interruption, when 2. Rated frequency. See Ta b 3 5 for switching device 8 the alternating voltage on the source ampere ratings. They are based on side of the breaker reaches its opposite 3. Rated open wire line charging percentage of capacitor-rated current maximum, the voltage that appears switching current. as indicated (above). The interrupting 9 across the contacts of the open breaker rating of the switch must be selected 4. Rated isolated cable charging and is at least twice the normal peak line- to match the system fault current shunt capacitor switching current. to-neutral voltage of the circuit. If a available at the point of capacitor 10 breakdown occurs across the open 5. Rated back-to-back cable application. Whenever a capacitor contact, the arc is re-established. Due charging and back-to-back bank is purchased with less than the to the circuit constants on the supply capacitor switching current. ultimate kvar capacity of the rack or 11 side of the breaker, the voltage across enclosure, the switch rating should the open contact can reach three times 6. Rated transient overvoltage factor. be selected based on the ultimate the normal line-to-neutral voltage. 12 7. Rated transient inrush current and kvar capacity—not the initial installed After it is interrupted and with capacity. subsequent alternation of the supply its frequency. side voltage, the voltage across the 8. Rated interrupting time. Refer to Tab 35 for recommended 13 open contact is even higher. selection of capacitor switching 9. Rated capacitive current devices; recommended maximum switching life. capacitor ratings for various motor 14 types and voltages; and for required 10. Grounding of system and multipliers to determine capacitor kvar capacitor bank. required for power factor correction. 15 Load break interrupter switches are permitted by ANSI/IEEE Standard C37.30 to switch capacitance, but they 16 must have tested ratings for the purpose. Refer to Eaton Type MVS ratings. 17

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CA08104001E For more information, visit: www.eaton.com/consultants 1.4-2 Power Distribution Systems System Application Considerations April 2016 Sheet 01 058 Capacitors

Motor Power Factor % AR—percent reduction in line To derate a capacitor used on a system i current due to the capacitor. A voltage lower than the capacitor Correction capacitor located on the motor side voltage rating, such as a 240 V of the overload relay reduces line capacitor used on a 208 V system, ii See Ta b 3 5 containing suggested current through the relay. Therefore, a use the following formula: maximum capacitor ratings for different overload relay and/or setting Actual kvar = induction motors switched with the may be necessary. The reduction in capacitor. The data is general in nature 2 1 line current may be determined by Applied Voltage and representative of general purpose Nameplate kvar  ------measuring line current with and 2 induction motors of standard design. without the capacitor or by calculation Nameplate Voltage 2 The preferable means to select capacitor as follows: ratings is based on the “maximum For the kVAC required to correct the recommended kvar” information (Original PF) power factor from a given value of % AR 100– 100   3 available from the motor manufacturer. (Improved PF) COS 1 to COS 2, the formula is: If this is not possible or feasible, the kVAC = kW (tan phase –tan phase ) tables can be used. If a capacitor is used with a lower kvar 1 2 rating than listed in tables, the % AR 4 An important point to remember Capacitors cause a voltage rise. can be calculated as follows: is that if the capacitor used with the At light load periods the capacitive motor is too large, self-excitation Actual kvar voltage rise can raise the voltage at % AR Listed % AR   the location of the capacitors to an 5 may cause a motor-damaging over- kvar in Table voltage when the motor and capacitor unacceptable level. This voltage rise combination is disconnected from the The tables can also be used for other can be calculated approximately by the 6 line. In addition, high transient torques motor ratings as follows: formula: capable of damaging the motor shaft A. For standard 60 Hz motors MVAr or coupling can occur if the motor is operating at 50 Hz: % VR  7 MVASC reconnected to the line while rotating kvar = 1.7–1.4 of kvar listed and still generating a voltage of % AR= 1.8–1.35 of % AR listed self-excitation. MVAR is the capacitor rating and 8 B. For standard 50 Hz motors MVASC is the system short-circuit Definitions operating at 50 Hz: capacity. kvar—rating of the capacitor in kvar = 1.4–1.1 of kvar listed With the introduction of variable speed 9 reactive kilovolt-amperes. This value % AR= 1.4–1.05 of % AR listed drives and other harmonic current is approximately equal to the motor generating loads, the capacitor no-load magnetizing kilovars. C. For standard 60 Hz wound-rotor 10 motors: impedance value determined must kvar = 1.1 of kvar listed not be resonant with the inductive reactances of the system. 11 % 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 12 mult., etc. 13

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For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.4-3 April 2016 System Application Considerations Sheet 01 059 Protection and Coordination

Overcurrent Protection damage or withstand characteristics, substation transformer can be coordi- (e) calculation of maximum short- nated with the low voltage breakers. i and Coordination circuit currents (and ground fault Transformer damage points, based on currents if ground fault protection is ANSI standards, and low voltage cable Overcurrents in a power distribution included) available at each protective heating limits can be plotted on this ii system can occur as a result of both device location, (f) understanding of set of curves to ensure that apparatus normal (motor starting, transformer operating characteristics and available limitations are not exceeded. inrush, etc.) and abnormal (overloads, adjustments of each protective device, 1 ground fault, line-to-line fault, etc.) (g) any special overcurrent protection Ground-fault curves may also be conditions. In either case, the funda- requirements including utility limita- included in the coordination study mental purposes of current-sensing tions. Refer to Figure 1.4-1. if ground-fault protection is provided, 2 protective devices are to detect the but care must be used in interpreting abnormal overcurrent and with proper To ensure complete coordination, the their meaning. coordination, to operate selectively time-trip characteristics of all devices 3 to protect equipment, property in series should be plotted on a single Standard definitions have been and personnel while minimizing the sheet of standard log-log paper. established for overcurrent protective outage of the remainder of the system. Devices of different-voltage systems devices covering ratings, operation 4 With the increase in electric power can be plotted on the same sheet by and application systems. consumption over the past few converting their current scales, using M—Motor (100 hp). Dashed line shows decades, dependence on the contin- the voltage ratios, to the same voltage- initial inrush current, starting current 5 ued supply of this power has also basis. Such a coordination plot is during 9-sec. acceleration, and drop to increased so that the direct costs shown in Figure 1.4-1. In this manner, 124 A normal running current, all well of power outages have risen signifi- primary fuses and circuit breaker below CBA trip curve. 6 cantly. Power outages can create relays on the primary side of a dangerous and unsafe conditions as a result of failure of lighting, elevators, 7 ventilation, fire pumps, security SCALE X 100 = CURRENT IN AMPERES AT 480V

.8.7.5.6 .9 1243 56 87 9 10 20 504030 60 70 80 9 0 100 200 300 400 500 600 700 800 9 00 1000 2000 3000 4000 5000 6000 7000 8000 9 000 10,000 systems, communications systems, 1000 1000 900 900 and the like. In addition, economic loss 800 4.16 kV 250 MVA 800 700 700 8 from outages can be extremely high 600 600 500 500 as a result of computer downtime, 400 400 B or, especially in industrial process 300 300 9 A D plants, interruption of production. 200 200 C

Protective equipment must be adjusted D 100 250A 100 10 and maintained in order to function 90 90 80 1000 80 70 70 properly when an overcurrent occurs, 60 kVA 4,160V Δ 5.75% 60 but coordination begins during power 50 480/277V 50 40 40 11 system design with the knowledgeable ANSI Three-Phase 19,600A 30 Thru Fault 30 analysis and selection and application Protection Curve 20 (More Than 10 in C 1,600A 20 of each overcurrent protective device Lifetime) 12 in the series circuit from the power 24,400A 10 B 10 source(s) to each load apparatus. The 9 9 8 600A 8 7 7 objective of coordination is to localize M TIME IN SECONDS 6 6 13 5 5 the overcurrent disturbance so that the 20,000A protective device closest to the fault 4 4 3 3 on the power-source side has the first A 175A 14 chance to operate; but each preceding 2 B C 2 protective device upstream toward the TIME IN SECONDS 1 1 power source should be capable, within .9 .9 .8 100 hp – .8 15 its designed settings of current and .7 M 124A FLC .7 .6 .6 time, to provide backup and de-energize .5 .5 .4 X = Available fault current .4 the circuit if the fault persists. Sensitivity including motor .3 contribution. .3 16 of coordination is the degree to which Ground the protective devices can minimize .2 Fault Trip .2 the damage to the faulted equipment. C 17 .1 .1 .09 .09 To study and accomplish coordination .08 .08 .07 .07 Transformer requires (a) a one-line diagram, the .06 B .06 .05 Inrush .05 18 roadmap of the power distribution .04 .04 system, showing all protective devices .03 .03 A and the major or important distribution .02 .02 and utilization apparatus, (b) identifica- 19 M a x. Three-Ph se 4.16 kV F a ult tion of desired degrees of power M a x. 480V F a ult .01 .01 .8.7.5.6 .9 1243 56 87 9 10 20 504030 60 70 9 0 80 100 200 300 400 500 600 700 800 9 00 continuity or criticality of loads 1000 2000 3000 4000 5000 6000 7000 8000 9 000 10,000 throughout system, (c) definition SCALE X 100 = CURRENT IN AMPERES AT 480V 20 of operating-current characteristics (normal, peak, starting) of each Figure 1.4-1. Time-Current Characteristic Curves for Typical Power Distribution System utilization circuit, (d) equipment Protective Devices Coordination Analysis 21

CA08104001E For more information, visit: www.eaton.com/consultants 1.4-4 Power Distribution Systems System Application Considerations April 2016 Sheet 01 060 Protection and Coordination

A—CB (175 A) coordinates selectively Maximum 480 V three-phase fault available fault current at their point of i with motor M on starting and running indicated on the horizontal current axis. application. All breakers are equipped and with all upstream devices, except with long-time-delay (and possibly that CB B will trip first on low level Maximum 4160 V three-phase fault short delay) and instantaneous over- ii ground faults. indicated, converted to 480 V basis. current trip devices. A main breaker 4160 may have short time-delay tripping to B—CB (600 A) coordinates selectively I I   480V 4160V 480 allow a feeder breaker to isolate the 1 with all upstream and downstream fault while power is maintained to all devices, except will trip before A on The ANSI protection curves are the remaining feeders. limited ground faults, since A has no specified in ANSI C57.109 for liquid- ground fault trips. A selective or fully coordinated system 2 filled transformers and C57.12.59 for permits maximum service continuity. dry-type transformers. C—Main CB (1600 A) coordinates The tripping characteristics of each selectively with all downstream Illustrative examples such as shown overcurrent device in the system must 3 devices and with primary fuse D, here start the coordination study from be selected and set so that the breaker for all faults on load side of CB. the lowest rated device proceeding nearest the fault opens to isolate the 4 D—Primary fuse (250 A, 4160 V) coor- upstream. In practice, the setting or faulted circuit, while all other breakers dinates selectively with all secondary rating of the utility’s protective device remain closed, continuing power to protective devices. Curve converted to sets the upper limit. Even in cases the entire unfaulted part of the system. where the customer owns the medium 5 480 V basis. Clears transformer inrush The National Electrical Code 1 voltage or higher distribution system, point (12 x FLC for 0.1 sec.), indicating contains specific requirements for the setting or rating of the lowest set that fuse will not blow on inrush. designing certain circuits with selective protective device at the source deter- 6 Fuse is underneath right-half of ANSI coordination. Article 100 defines mines the settings of the downstream three-phase withstand curve, indicating selective coordination: Coordination devices and the coordination. fuse will protect transformer for high- (Selective), the following definition: 7 magnitude faults up to ANSI rating. Therefore the coordination study “Localization of an overcurrent condi- Delta-wye secondary side short should start at the present setting tion to restrict outages to the circuit or 8 circuit is not reflected to the primary or rating of the upstream device and equipment affected, accomplished by by the relation work toward the lowest rated device. If the choice of overcurrent protective this procedure results in unacceptable devices and their ratings or settings.” V settings, the setting or rating of the 1 9 S NEC 2011 NFPA 70: National Electrical Code IP   IS upstream device should be reviewed. VP International Electrical Code Series. Where the utility is the sole source, Article 620.62 (elevators, dumbwaiters, for L-L and L-G faults. For line-to-line they should be consulted. Where the 10 escalators, moving walks, wheelchair fault, the secondary (low voltage) side owner has its own medium or higher lifts, and stairway chair lifts) requires fault current is 0.866 x I three-phase voltage distribution, the settings or “Where more than one driving machine 11 fault current. ratings of all upstream devices should be checked. disconnecting means is supplied by a However, the primary (high voltage) single feeder, the overcurrent protective 12 side fault is the same as if the secondary If perfect coordination is not feasible, devices in each disconnecting means fault was a three-phase fault. Therefore then lack of coordination should be shall be selectively coordinated with in coordination studies, the knee of the limited to the smallest part of the system. any other supply side overcurrent 13 short-time pickup setting on the sec- Application data is available for all protective device.” A similar require- ondary breaker should be multiplied by protective equipment to permit ment under Article 700.27 is as follows; systems to be designed for adequate “Emergency system(s) overcurrent 1 or 1.1547 devices shall be selectively coordinated 14 0.866 overcurrent protection and coordina- tion. For circuit breakers of all types, with all supply side overcurrent protective devices.” Article 701.27 before it is compared to the minimum time-current curves permit selection of states that “Legally required standby 15 melting time of the upstream primary instantaneous and inverse-time trips. system(s) overcurrent devices shall be fuse curve. In the example shown, the For more complex circuit breakers, selectively coordinated with all supply knee is at 4000 A 30 sec., and the 30- with solid-state trip units, trip curves side overcurrent devices.” 16 sec. trip time should be compared to include long- and short-time delays, the MMT (minimum melt time) of the as well as ground-fault tripping, with a Exception: Selective coordination fuse curve at 4000 x 1.1547 = 4619 A. In wide range of settings and features to shall not be required between two 17 this case, there is adequate clearance provide selectivity and coordination. overcurrent devices located in series to the fuse curve. For current-limiting circuit breakers, if no loads are connected in parallel fuses, and circuit breakers with with the downstream device. 18 In the example shown, the ANSI integral fuses, not only are time- three-phase through fault protection current characteristic curves available, In addition, for health care facilities, curve must be multiplied by 0.577 but also data on current-limiting Article 517.26, Application of Other 19 and replotted in order to determine performance and protection for Articles requires that “The essential the protection given by the primary downstream devices. electrical system shall meet the for a single line to ground fault in requirements of Article 700, except 20 the secondary. In a fully rated system, all circuit as amended by Article 517.” breakers must have an interrupting capacity adequate for the maximum 21

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.4-5 April 2016 System Application Considerations Sheet 01 061 Protection and Coordination

All breakers must have an interrupting Protection of Conductors (Excerpts E. Tap Conductors. Tap conductors capacity not less than the maximum shall be permitted to be protected i available short-circuit current at their from NFPA 70-2011, Article 240.4) against overcurrent in accordance point of application. A selective Conductors, other than flexible cords with the following: system is a fully rated system with and fixture wires, shall be protected ii tripping devices chosen and adjusted against overcurrent in accordance with 1. 210.19(A)(3) and (A)(4) Household to provide the desired selectivity. their ampacities as specified in Section Ranges and Cooking Appliances The tripping characteristics of each 310.15, unless otherwise permitted or and Other Loads. 1 overcurrent device should not over- required in (A) through (G). 2. 240.5(B)(2) Fixture Wire. lap, but should maintain a minimum time interval for devices in series (to A. Power Loss Hazard. Conductor 3. 240.21 Location in Circuit. 2 allow for normal operating tolerances) overload protection shall not be 4. 368.17(B) Reduction in Ampacity at all current values. Generally, a required where the interruption of Size of Busway. maximum of four low voltage circuit the circuit would create a hazard, 3 breakers can be operated selectively such as in a material handling magnet circuit or fire pump circuit. 5. 368.17(C) Feeder or Branch Circuits in series, with the feeder or branch (busway taps). breaker downstream furthest from Short-circuit protection shall be 4 the source. provided. 6. 430.53(D) Single Motor Taps. Note: FPN See NFPA 20-2003, standard Specify true rms sensing devices in for the Installation of Stationary Pumps Circuit Breaker Cable 5 order to avoid false trips due to rapid for Fire Protection. currents or spikes. Specify tripping Temperature Ratings 2 4 elements with I t or I t feature for B. Devices Rated 800 A or Less. The UL listed circuit breakers rated 125 A or 6 improved coordination with other next higher standard overcurrent less shall be marked as being suitable 2 4 devices having I t or I t (such as device rating (above the ampacity for 60 ºC (140ºF), 75 ºC (167 ºF) only or OPTIM™ trip units) characteristics of the conductors being protected) 60/75 ºC (140/167ºF) wire. All Eaton 7 and fuses. shall be permitted to be used, breakers rated 125 A or less are marked 60/75 ºC (140/167 ºF). All UL listed circuit In general for systems such as shown provided all of the following conditions are met. breakers rated over 125 A are suitable 8 in the example: for 75 ºC conductors. Conductors rated 1. The settings or ratings of the 1. The conductors being protected for higher temperatures may be used, primary side fuse and main breaker are not part of a branch circuit but must not be loaded to carry more 9 must not exceed the settings supplying more than one receptacle current than the 75 ºC ampacity of that allowed by NEC Article 450. for cord-and-plug-connected size conductor for equipment marked portable loads. or rated 75 ºC or the 60 ºC ampacity of 10 2. At 12 x I the minimum melting that size conductor for equipment FL 2. The ampacity of the conductors time characteristic of the fuse marked or rated 60 ºC. However, when does not correspond with the should be higher than 0.1 second. applying derated factors, so long as the standard ampere rating of a fuse or 11 actual load does not exceed the lower a circuit breaker without overload 3. The primary fuse should be to the of the derated ampacity or the 75 ºC or trip adjustments above its rating left of the transformer damage 60 ºC ampacity that applies. curve as much as possible. The (but that shall be permitted to have 12 correction factor for a single line- other trip or rating adjustments). Zone Selective Interlocking to-ground factor must be applied 13 to the damage curve. 3. The next higher standard rating Trip elements equipped with zone selected does not exceed 800 A. selective interlocking, trip without 4. The setting of the short-time delay intentional time delay unless a element must be checked against C. Overcurrent Devices Rated Over 14 800 A. Where the overcurrent restraint signal is received from the fuse MMT after it is corrected a protective device downstream. for line-to-line faults. device is rated over 800 A, the ampacity of the conductors it Breakers equipped with this feature 15 5. The maximum fault current must protects shall be equal to or reduce the damage at the point of be indicated at the load side of greater than the rating of the fault if the fault occurs at a location each protective device. overcurrent device as defined in between the zone of protection. 16 Section 240.6. 6. The setting of a feeder protective The upstream breaker upon receipt of the restraint signal will not trip until device must comply with Article D. Small Conductors. Unless 17 240 and Article 430 of the NEC. specifically permitted in 240.4(E) its time-delay setting times out. If the It also must allow the starting or 240.4(G), the overcurrent breaker immediately downstream of the fault does not open, then after timing and acceleration of the largest protection shall not exceed 15 A 18 motor on the feeder while carrying for 14 AWG, 20 A for 12 AWG, and out, the upstream breaker will trip. all the other loads on the feeder. 30 A for 10 AWG copper; or 15 A Breakers equipped with ground fault for 12 AWG and 25 A for 10 AWG trip elements should also be specified 19 aluminum and copper-clad to include zone interlocking for the aluminum after any correction ground fault trip element. factors for ambient temperature 20 and number of conductors have been applied. 21

CA08104001E For more information, visit: www.eaton.com/consultants 1.4-6 Power Distribution Systems System Application Considerations April 2016 Sheet 01 062 Protection and Coordination

Ground Fault Protection Suggested Ground Fault Settings The Series G high performance, i current-limiting circuit breaker series Article 230.95 of NEC requires ground- For the main devices: offers interrupting ratings to 200 kA. fault protection of equipment shall be A ground fault pickup setting equal Frames are EGC, EGU, EGX, JGC, JGU, ii provided for solidly grounded wye to 20–30% of the main breaker rating JGX, LGC, LGU and LGX. electrical services of more than 150 V but not to exceed 1200 A, and a time to ground, but not exceeding 600 V delay equal to the delay of the short- Any of these current-limiting devices— 1 phase-to-phase for each service time element, but not to exceed fuses, fused breakers or current-limit- disconnect rated 1000 A or more. 1 second. ing breakers—cannot only clear these large faults safely, but also will limit The rating of the service disconnect 2 2 For the feeder ground fault setting: the Ip and I t let-through significantly shall be considered to be the rating A setting equal to 20–30% of the feeder to prevent damage to apparatus of the largest fuse that can be installed ampacity and a time delay to coordinate downstream, extending their zone 3 or the highest continuous current trip with the setting of the main (at least of protection. Without the current setting for which the actual overcurrent 6 cycles below the main). limitation of the upstream device, device installed in a circuit breaker is the fault current could exceed the with- If the desire to selectively coordinate rated or can be adjusted. stand capability of the downstream 4 ground fault devices results in settings equipment. Underwriters The maximum allowable settings are: that do not offer adequate damage Laboratories tests and lists these 1200 A pickup, 1 second or less trip protection against arcing single line- series combinations. Application 5 delay at currents of 3000 A or greater. ground faults, the design engineer information is available for should decide between coordination The characteristics of the ground-fault combinations that have been tested and damage limitation. 6 trip elements create coordination and UL®-listed for safe operation problems with downstream devices For low voltage systems with high- downstream from MDSL, TRI-PAC, not equipped with ground fault magnitude available short-circuit and Current Limit-R, or Series C 7 protection. The National Electrical currents, common in urban areas and breakers of various ratings, under Code exempts fire pumps and large industrial installations, several high available fault currents. continuous industrial processes solutions are available. High interrupt- Protective devices in electrical from this requirement. ing Series C® molded case breakers, 8 distribution systems may be properly current-limiting circuit breakers, or It is recommended that in solidly coordinated when the systems are current-limiting fuses, limiters integral grounded 480/277 V systems where designed and built, but that is no 9 with molded-case circuit breakers main breakers are specified to be guarantee that they will remain (TRI-PAC®) or mounted on power equipped with ground fault trip elements coordinated. System changes and circuit breakers (MDSL) can be used to that the feeder breakers be specified additions, plus power source changes, 10 handle these large fault currents. To to be equipped with ground fault trip frequently modify the protection provide current limiting, these devices elements as well. requirements, sometimes causing loss must clear the fault completely within of coordination and even increasing 11 the first half-cycle, limiting the peak fault currents beyond the ratings of current (I ) and heat energy (I2t) p some devices. Consequently, periodic let-through to considerably less than study of protective-device settings 12 what would have occurred without and ratings is as important for safety the device. For a fully fusible system, and preventing power outages rule-of-thumb fuse ratios or more as is periodic maintenance of the 13 accurate I2t curves can be used to distribution system. provide selectivity and coordination. For fuse-breaker combinations, the 14 fuse should be selected (coordinated) so as to permit the breaker to handle those overloads and faults within its 15 capacity; the fuse should operate before or with the breaker only on large faults, approaching the interrupt- 16 ing capacity of the breaker, to minimize fuse blowing. Recently, unfused, truly current-limiting circuit breakers with 17 interrupting ratings adequate for the largest systems (Type Series C, FDC, JDC, KDC, LDC and NDC frames 18 or Type Current Limit-R®) have become available. 19

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For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.4-7 April 2016 System Application Considerations Sheet 01 063 Grounding/Ground Fault Protection

Grounding above ground potential. Any person The equipment grounding system coming in contact with such an object must be bonded to the grounding i Grounding encompasses several while grounded could be seriously electrode at the source or service; different but interrelated aspects of injured or killed. In addition, current however, it may be also connected electrical distribution system design flow from the accidental grounding of to ground at many other points. ii and construction, all of which are an energized part of the system could This will not cause problems with essential to the safety and proper generate sufficient heat (often with the safe operation of the electrical operation of the system and equip- arcing) to start a fire. To prevent the distribution system. Where computers, 1 ment supplied by it. Among these establishment of such unsafe poten- data processing, or microprocessor- are equipment grounding, system tial difference requires that (1) the based industrial process control grounding, static and lightning equipment grounding conductor pro- systems are installed, the equipment 2 protection, and connection to earth vide a return path for ground fault cur- grounding system must be designed as a reference (zero) potential. rents of sufficiently low impedance to to minimize interference with their prevent unsafe voltage drop, and (2) proper operation. Often, isolated 3 1. Equipment Grounding the equipment grounding conductor grounding of this equipment, or be large enough to carry the maximum isolated electrical supply systems are Equipment grounding is essential ground fault current, without burning required to protect microprocessors 4 to safety of personnel. Its function is off, for sufficient time to permit protec- from power system “noise” that does to ensure that all exposed noncurrent- tive devices (ground fault relays, circuit not in any way affect motors or other carrying metallic parts of all structures breakers, fuses) to clear the fault. The electrical equipment. Such systems 5 and equipment in or near the electrical grounded conductor of the system must use single-point ground concept distribution system are at the same (usually the neutral conductor), although to minimize “noise” and still meet potential, and that this is the zero grounded at the source, must not be the NEC requirements. Any separate 6 reference potential of the earth. used for equipment grounding. isolated ground mat must be tied to the Equipment grounding is required rest of the facility ground mat system by both the National Electrical Code The equipment grounding conductor for NEC compliance. 7 (Article 250) and the National Electrical may be the metallic conduit or raceway Safety Code regardless of how the of the wiring system, or a separate 2. System Grounding power system is grounded. Equipment equipment grounding conductor, 8 grounding also provides a return path run with the circuit conductors, as System grounding connects the for ground fault currents, permitting permitted by NEC. If a separate electrical supply, from the utility, from protective devices to operate. Acciden- equipment grounding conductor is transformer secondary windings, or 9 tal contact of an energized conductor of used, it may be bare or insulated; if from a generator, to ground. A system the system with an improperly insulated, the insulation must be green, can be solidly grounded (no intentional grounded noncurrent-carry metallic green with yellow stripe or green tape. impedance to ground), impedance 10 part of the system (such as a motor Conductors with green insulation may grounded (through a resistance or frame or panelboard enclosure) would not be used for any purpose other than reactance), or ungrounded (with no raise the potential of the metal object for equipment grounding. intentional connection to ground. 11 3. Medium Voltage System: Grounding Table 1.4-1. Features of Ungrounded and Grounded Systems (from ANSI C62.92) 12 Description A B C D E Ungrounded Solidly Grounded Reactance Grounded Resistance Grounded Resonant Grounded 13 (1) Apparatus Fully insulated Lowest Partially graded Partially graded Partially graded insulation (2) Fault to Usually low Maximum value rarely Cannot satisfactorily be Low Negligible except when 14 ground current higher than three-phase reduced below one-half Petersen coil is short short circuit current or one-third of values for circuited for relay solid grounding purposes when it may compare with solidly 15 grounded systems (3) Stability Usually unimportant Lower than with other Improved over solid Improved over solid Is eliminated from methods but can be grounding particularly grounding particularly consideration during 16 made satisfactory by use if used at receiving end if used at receiving end single line-to-ground of high-speed breakers of system of system faults unless neutralizer is short circuited to isolate fault by relays 17 (4) Relaying Difficult Satisfactory Satisfactory Satisfactory Requires special provisions but can be made satisfactory 18 (5) Arcing Likely Unlikely Possible if reactance is Unlikely Unlikely grounds excessive (6) Localizing Effect of fault transmitted Effect of faults localized Effect of faults localized to Effect of faults Effect of faults 19 faults as excess voltage on to system or part of system or part of system transmitted as excess transmitted as excess sound phases to all system where they occur where they occur unless voltage on sound phases voltage on sound phases parts of conductively reactance is quite high to all parts of conductively to all parts of conductively connected network connected network connected network 20 (7) Double Likely Likely Unlikely unless Unlikely unless Seem to be more likely faults reactance is quite high resistance is quite high but conclusive information and insulation weak and insulation weak not available 21

CA08104001E For more information, visit: www.eaton.com/consultants 1.4-8 Power Distribution Systems System Application Considerations April 2016 Sheet 01 064 Grounding/Ground Fault Protection

Table 1.4-1. Features of Ungrounded and Grounded Systems (Continued) i Description A B C D E Ungrounded Solidly Grounded Reactance Grounded Resistance Grounded Resonant Grounded ii (8) Lightning Ungrounded neutral Highest efficiency and If reactance is very high Arresters for ungrounded, Ungrounded neutral protection service arresters must be lowest cost arresters for ungrounded neutral service usually service arresters must applied at sacrifice in cost neutral service must be must be applied at be applied at sacrifice and efficiency applied at sacrifice in cost sacrifice in cost and in cost and efficiency 1 and efficiency efficiency (9) Telephone Will usually be low Will be greatest in Will be reduced from Will be reduced from Will be low in magnitude interference except in cases of double magnitude due to higher solidly grounded values solidly grounded values except in cases of double 2 faults or electrostatic fault currents but can faults or series resonance induction with neutral be quickly cleared at harmonic frequencies, displaced but duration particularly with high but duration may be great 3 may be great speed breakers (10) Radio May be quite high during Minimum Greater than for Greater than for May be high during faults interference faults or when neutral solidly grounded, solidly grounded, 4 is displayed when faults occur when faults occur (11) Line Will inherently clear Must be isolated for Must be isolated for Must be isolated for Need not be isolated but availability themselves if total length each fault each fault each fault will inherently clear itself of interconnected line is in about 60 to 80 percent 5 low and require isolation of faults from system in increas- ing percentages as length 6 becomes greater (12) Adaptability Cannot be interconnected Satisfactory indefinitely Satisfactory indefinitely Satisfactory with solidly- Cannot be interconnected to interconnection unless interconnecting with reactance-grounded with solidly-grounded or reactance-grounded unless interconnected system is ungrounded systems systems systems with proper system is resonant 7 or isolating transformers attention to relaying grounded or isolating are used transformers are used. Requires coordination 8 between interconnected systems in neutralizer settings 9 (13) Circuit Interrupting capacity Same interrupting Interrupting capacity Interrupting capacity Interrupting capacity breakers determined by three- capacity as required for determined by three- determined by three- determined by three- phase conditions three-phase short circuit phase fault conditions phase fault conditions phase fault conditions will practically always be 10 satisfactory (14) Operating Ordinarily simple but Simple Simple Simple Taps on neutralizers must procedure possibility of double be changed when major 11 faults introduces system switching is per- complication in times formed and difficulty may of trouble arise in interconnected systems. Difficult to tell 12 where faults are located (15) Total cost High, unless conditions Lowest Intermediate Intermediate Highest unless the arc are such that arc tends suppressing characteris- 13 to extinguish itself, when tic is relied on to eliminate transmission circuits may transmission circuits be eliminated, reducing when it may be lowest 14 total cost for the particular types of service 15 Because the method of grounding The aforementioned definition is of the three-phase current at the point affects the voltage rise of the unfaulted of significance in medium voltage of fault. Damage to cable shields must phases above ground, ANSI C62.92 distribution systems with long lines be checked. Although this fact is not 16 classifies systems from the point of and with grounded sources removed a problem except in small cables, it is a view of grounding in terms of a during light load periods so that in good idea to supplement the cable coefficient of grounding some locations in the system the shields returns of ground fault current 17 X0/X1, R0/X1 may exceed the defining to prevent damage, by installing an Highest Power Frequency limits. Other standards (cable and equipment grounding conductor. rms Line – Ground Voltage COG = ------lightning arrester) allow the use of 18 rms Line – Line Voltage at Fault 100% rated cables and arresters The burdens on the current transformers Location with the Fault Removed selected on the basis of an effectively must be checked also (for saturation grounded system only where the considerations), where residually This same standard also defines criteria in the above are met. In connected ground relays are used 19 systems as effectively grounded when effectively grounded system the line- and the current transformers supply COG ð .8 such a system would have to-ground fault current is high and current to phase relays and meters. X /X ð 3.0 and R /X ð 1.0. Any other 0 1 0 1 there is no significant voltage rise in 20 grounding means that does not satisfy If ground sensor current transformers the unfaulted phases. these conditions at any point in a (zero sequence type) are used they system is not effectively grounded. With selective ground fault isolation must be of high burden capacity. 21 the fault current should be at least 60%

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.4-9 April 2016 System Application Considerations Sheet 01 065 Grounding/Ground Fault Protection

Table 1.4-2 taken from ANSI-C62.92 should not be limited to less than the Grounding Point indicates the characteristics of the current transformers rating of the The most commonly used grounding i various methods of grounding. source. This rule will provide sensitive point is the neutral of the system or the differential protection for wye-connected Reactance Grounding neutral point created by means of a generators and transformers against zigzag or a wye-broken delta grounding ii It is generally used in the grounding line-to-ground faults near the neutral. transformer in a system that was oper- of the neutrals of generators directly Of course, if the installation of ground ating as an ungrounded delta system. connected to the distribution system fault differential protection is feasible, 1 bus, in order to limit the line-to-ground or ground sensor current transformers In general, it is a good practice that all fault to somewhat less than the three- are used, sensitive differential relaying source neutrals be grounded with the phase fault at the generator terminals. in resistance grounded system with same grounding impedance magnitude. 2 If the reactor is so sized, in all probability greater fault limitation is feasible. However, neutrals should not be tied the system will remain effectively In general, ground sensor current together to a single resistor. Where grounded. transformers (zero sequence) do not one of the medium voltage sources is 3 have high burden capacity. Resistance the utility, their consent for impedance Resistance Grounded grounded systems limit the circulating grounding must be obtained. Medium voltage systems in general currents of triple harmonics and limit 4 The neutral impedance must have a should be low resistance grounded. the damage at the point of fault. This voltage rating at least equal to the rated The ground fault is typically limited to method of grounding is not suitable line-to-neutral voltage class of the sys- about 200–400 A but less than 1000 A for line-to-neutral connection of loads. 5 (a cable shield consideration). With a tem. It must have at least a 10-second properly sized resistor and relaying On medium voltage systems, 100% rating equal to the maximum future application, selective fault isolation cable insulation is rated for phase-to- line-to-ground fault current and a 6 is feasible. The fault limit provided neutral voltage. If continued operation continuous rating to accommodate the has a bearing on whether residually with one phase faulted to ground is triple harmonics that may be present. connected relays are used or ground desired, increased insulation thickness 7 sensor current transformers are used is required. For 100% insulation, fault 4. Low Voltage System: Grounding for ground fault relaying. clearance is recommended within Solidly grounded three-phase systems one minute; for 133% insulation, one (Figure 1.4-2) are usually wye- 8 In general, where residually connected hour is acceptable; for indefinite connected, with the neutral point ground relays are used (51N), the fault operation, as long as necessary, grounded. Less common is the “red- current at each grounded source 173% insulation is required. leg” or high-leg delta, a 240 V system 9 supplied by some utilities with one Table 1.4-2. Characteristics of Grounding winding center-tapped to provide 120 V Grounding Classes Ratios of Symmetrical Percent Fault Per Unit Transient 10 1 to ground for lighting. This 240 V, three- and Means Component Parameters Current LG Voltage phase, four-wire system is used where 2 3 120 V lighting load is small compared X0/X1 R0/X1 R0/X0 A. Effectively ➃ to 240 V power load, because the 11 1. Effective 0-3 0-1 — >60 ð2 installation is low in cost to the utility. 2. Very effective 0-1 0-0.1 — >95 <1.5 A corner-grounded three-phase delta B. Noneffectively system is sometimes found, with 12 1. Inductance one phase grounded to stabilize all a. Low inductance 3-10 0-1 — >25 <2.3 8 voltages to ground. Better solutions b. High inductance >10 — <2 <25 ð2.73 13 2. Resistance are available for new installations. a. Low resistance 0-10 — Š2 <25 <2.5 b. High resistance — >100 ð(-1) <1 ð2.73 3. Inductance and resistance >10 — >2 <10 ð2.73 Phase A 14 5 4. Resonant — — <1 ð2.73 • • Phase B 5. Ungrounded/capacitance • N 6 9 a. Range A -× to -40 — — <8 ð3 • Phase C 79 15 b. Range B -40 to 0 — — >8 >3 • Neutral 1 Values of the coefficient of grounding (expressed as a percentage of maximum phase-to-phase voltage) corresponding to various combinations of these ratios are shown in the ANSI C62.92 Grounded Wye 16 Appendix figures. Coefficient of grounding affects the selection of arrester ratings. 2 Ground-fault current in percentage of the three-phase short-circuit value. • Phase B 3 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. • • • Phase C 17 4 Phase A 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%. • Neutral 5 See ANSI 62.92 para. 7.3 and precautions given in application sections. 18 6 Usual isolated neutral (ungrounded) system for which the zero-sequence reactance is capacitive Center-Tapped (High-Leg) Delta (negative). 7 Same as NOTE (6) and refer to ANSI 62.92 para. 7.4. Each case should be treated on its own merit. Phase A 8 • 19 Under restriking arcing ground fault conditions (e.g., vacuum breaker interrupter operation), this value can approach 500%. Phase B 9 • • Under arcing ground fault conditions, this value can easily reach 700%, but is essentially unlimited. • Phase C 20

Corner-Grounded Delta 21 Figure 1.4-2. Solidly Grounded Systems

CA08104001E For more information, visit: www.eaton.com/consultants 1.4-10 Power Distribution Systems System Application Considerations April 2016 Sheet 01 066 Grounding/Ground Fault Protection

Ungrounded systems (Figure 1.4-3) Selecting the Low Voltage System used as substitutes for ungrounded i can be either wye or delta, although Grounding Method systems where high system the ungrounded delta system is far There is no one “best” distribution availability is required. more common. ii system for all applications. In choosing With one phase grounded, the voltage among solidly grounded, resistance to ground of the other two phases grounded, or ungrounded power • Phase A rises 73%, to full phase-to-phase distribution, the characteristics of the voltage. In low voltage systems this 1 system must be weighed against the • • Phase B is not important, since conductors Phase C requirements of power loads, lighting are insulated for 600 V. Ungrounded Delta loads, continuity of service, safety 2 and cost. A low voltage resistance grounded Phase A system is normally grounded so that • • Phase B Under ground fault conditions, each the single line-to-ground fault current 3 • N system behaves very differently. A exceeds the capacitive charging • Phase C solidly grounded system produces current of the system. If data for the Ungrounded Wye high fault currents, usually with arcing, charging current is not available, use 4 and the faulted circuit must be cleared 40–50 ohm resistor in the neutral Figure 1.4-3. Ungrounded Systems on the first fault within a fraction of a of the transformer. second to minimize damage. An 5 Resistance-grounded systems ungrounded system will pass limited In commercial and institutional (Figure 1.4-4) are simplest with a current into the first ground fault—only installations, such as office buildings, wye connection, grounding the neutral the charging current of the system, shopping centers, schools and hospitals, 6 point directly through the resistor. caused by the distributed capacitance lighting loads are often 50% or more Delta systems can be grounded by to ground of the system wiring and of the total load. In addition, a feeder means of a zig-zag or other grounding equipment. In low voltage systems, outage on first ground fault is seldom 7 transformer. Wye broken delta this is rarely more than 1 or 2 A. crucial—even in hospitals, that have transformer banks may also be used. Therefore, on first ground fault, an emergency power in critical areas. For ungrounded system can continue in these reasons, a solidly grounded wye 8 service, making it desirable where distribution, with the neutral used for Phase A power outages cannot be tolerated. lighting circuits, is usually the most • Phase B • • However, if the ground fault is economical, effective and convenient 9 N design. In some instances, it is an R Phase C intermittent, sputtering or arcing, a • high voltage—as much as 6 to 8 times NEC requirement. phase voltage—can be built up across 10 the system capacitance, from the In industrial installations, the effect Resistance-Grounded Wye phase conductors to ground. Similar of a shutdown caused by a single ground fault could be disastrous. Phase A high voltages can occur as a result 11 • • of resonance between system An interrupted process could cause the loss of all the materials involved, often • • • Phase B capacitance and the inductances • Phase C of transformers and motors in the ruin the process equipment itself, and 12 • system. The phase-to-phase voltage sometimes create extremely danger- ous situations for operating personnel. N • is not affected. This high transient R • phase-to-ground voltage can puncture On the other hand, lighting is usually 13 insulation at weak points, such as only a small fraction of the total motor windings, and is a frequent industrial electrical load. A solidly Delta With Derived Neutral Resistance- cause of multiple motor failures on grounded neutral circuit conductor 14 Grounded Using Zig-Zag Transformer ungrounded systems. Locating a first is not imperative and, when required, fault on an ungrounded system can can be obtained from inexpensive Figure 1.4-4. Resistance-Grounded Systems lighting transformers. 15 be difficult. If, before the first fault is This derives a neutral point, which cleared, a second ground fault occurs Because of the ability to continue in can be either solidly or impedance- on a different phase, even on a operation with one ground fault on 16 grounded. If the grounding transformer different, remote feeder, it is a high- the system, many existing industrial has sufficient capacity, the neutral current phase-to-ground-to-phase plants use ungrounded delta distribu- created can be solidly grounded and fault, usually arcing, that can cause tion. Today, new installations can have 17 used as part of a three-phase, four-wire severe damage if at least one of the all the advantages of service continuity system. Most transformer-supplied grounds is not cleared immediately. of the ungrounded delta, yet minimize systems are either solidly grounded If the second circuit is remote, enough the problems of the system, such 18 or resistance grounded. Generator current may not flow to cause as the difficulty of locating the first neutrals are often grounded through protection to operate. This can leave ground fault, risk of damage from a a reactor, to limit ground fault (zero high voltages and stray currents on second ground fault, and damage 19 sequence) currents to values the structures and jeopardize personnel. transient overvoltages. A high- generator can withstand. In general, where loads will be resistance grounded wye distribution connected line-to-neutral, solidly can continue in operation with a 20 grounded systems are used. High ground fault on the system and will resistance grounded systems are not develop transient overvoltages. 21

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.4-11 April 2016 System Application Considerations Sheet 01 067 Grounding/Ground Fault Protection

And, because the ground point is disconnecting means rated 1000 A or established, locating a ground fault is more on solidly grounded wye services Main i less difficult than on an ungrounded of more than 150 V to ground, but system especially when a “pulsing not exceeding 600 V phase-to-phase. Neutral Service contactor” design is applied. When Practically, this makes ground fault Transformer ii Sensor GFR combined with sensitive ground-fault protection mandatory on 480Y/277 V Typical protection, damage from a second services, but not on 208Y/120 V ser- Ground Bus Feeder ground fault can be nearly eliminated. vices. On a 208 V system, the voltage 1 Main Bonding Ungrounded delta systems can be to ground is 120 V. If a ground fault Jumper converted to high-resistance grounded occurs, the arc goes out at current Typical Grounding Equipment 4W Load systems, using a zig-zag or other zero, and the voltage to ground is Electrode Grounding 2 grounding transformer to derive a often too low to cause it to restrike. Conductor Conductor neutral, with similar benefits, see Therefore, arcing ground faults on 208 Ta b 3 6 . While the majority of V systems tend to be self-extinguish- Figure 1.4-5. Ground Return Sensing Method 3 manufacturing plants use solidly ing. On a 480 V system, with When an energized conductor faults grounded systems, in many instances, 277 V to ground, restrike usually takes to grounded metal, the fault current the high-resistance grounded distribu- place after current zero, and the arc returns along the ground return path to 4 tion will be the most advantageous. tends to be self-sustaining, causing the neutral of the source transformer. severe and increasing damage, until This path includes the main bonding Ground Fault Protection the fault is cleared by a protective jumper as shown in Figure 1.4-5. 5 A ground fault normally occurs in one device. A current sensor on this conductor of two ways: by accidental contact of The NEC requires ground fault (which can be a conventional bar-type 6 an energized conductor with normally protection on the service disconnecting or window type CT) will respond to grounded metal, or as a result of means. This protection works so fast ground fault currents only. Normal an insulation failure of an energized that for ground faults on feeders, or neutral currents resulting from 7 conductor. When an insulation failure even branch circuits, it will often open unbalanced loads will return along occurs, the energized conductor the service disconnect before the the neutral conductor and will not be contacts normally noncurrent-carrying feeder or branch circuit overcurrent detected by the ground return sensor. 8 grounded metal, which is bonded to device can operate. This is highly or part of the equipment grounding This is an inexpensive method of sensing undesirable, and in the NEC (230.95) ground faults where protection per conductor. In a solidly grounded a Fine Print Note (FPN) states that 9 system, the fault current returns to the NEC (230.95) is desired. For it to additional ground fault protective operate properly, the neutral must be source primarily along the equipment equipment will be needed on feeders grounding conductors, with a small grounded in only one place as indicated and branch circuits where maximum in Figure 1.4-5. In many installations, 10 part using parallel paths such as build- continuity of electric service is neces- ing steel or piping. If the ground return the servicing utility grounds the neutral sary. Unless it is acceptable to discon- at the transformer and additional impedance was as low as that of the nect the entire service on a ground 11 circuit conductors, ground fault currents grounding is required in the service fault almost anywhere in the system, equipment per NEC (250.24(A)(2)). would be high, and the normal phase such additional stages of ground overcurrent protection would clear In such cases, and others including fault protection must be provided. multiple source with multiple, inter- 12 them with little damage. Unfortunately, At least two stages of protection are the impedance of the ground return connected neutral ground points, mandatory in health care facilities residual or zero sequence ground path is usually higher, the fault itself (NEC Sec. 517.17). 13 is usually arcing and the impedance sensing methods should be employed. of the arc further reduces the fault Overcurrent protection is designed A second method of detecting ground current. In a 480Y/277 V system, the to protect conductors and equipment faults involves the use of a zero 14 voltage drop across the arc can be against currents that exceed their sequence sensing method, as illus- from 70 to 140 V. The resulting ground ampacity or rating under prescribed trated in Figure 1.4-6. This sensing fault current is rarely enough to cause time values. An overcurrent can result method requires a single, specially 15 the phase overcurrent protection from an overload, short circuit or (high designed sensor either of a toroidal device to open instantaneously and level) ground fault condition. When or rectangular shaped configuration. prevent damage. Sometimes, the currents flow outside the normal This core balance current transformer 16 ground fault is below the trip setting of current path to ground, supplementary surrounds all the phase and neutral the protective device and it does not ground fault protection equipment will conductors in a typical three-phase, trip at all until the fault escalates and be required to sense low-level ground four-wire distribution system. The 17 extensive damage is done. For these fault currents and initiate the protection sensing method is based on the fact reasons, low level ground protection required. Normal phase overcurrent that the vectorial sum of the phase and devices with minimum time delay protection devices provide no protection neutral currents in any distribution 18 settings are required to rapidly clear against low-level ground faults. circuit will equal zero unless a ground ground faults. This is emphasized by There are three basic means of sensing fault condition exists downstream from the NEC requirement that a ground ground faults. The most simple and the sensor. All currents that flow only 19 fault relay on a service shall have a direct method is the ground return in the circuit conductors, including maximum delay of one second for method as illustrated in Figure 1.4-5. balanced or unbalanced phase-to-phase faults of 3000 A or more. This sensing method is based on the fact and phase-to-neutral normal or fault 20 The NEC (Sec. 230.95) requires that that all currents supplied by a trans- currents, and harmonic currents, will ground fault protection, set at no more former must return to that transformer. result in zero sensor output. 21 than 1200 A, be provided for each service

CA08104001E For more information, visit: www.eaton.com/consultants 1.4-12 Power Distribution Systems System Application Considerations April 2016 Sheet 01 068 Grounding/Ground Fault Protection

However, should any conductor become neutral. In a residual sensing scheme, levels of ground fault protection are i grounded, the fault current will return the relationship of the polarity markings desired for added service continuity. along the ground path—not the normal —as noted by the “X” on each sensor— Additional grounding points may be circuit conductors—and the sensor will is critical. Because the vectorial sum of employed upstream of the residual ii have an unbalanced magnetic flux the currents in all the conductors will sensors, but not on the load side. condition, and a sensor output will total zero under normal, non-ground be generated to actuate the ground faulted conditions, it is imperative Both the zero sequence and 1 fault relay. that proper polarity connections are residual sensing methods have employed to reflect this condition. been commonly referred to as “vectorial summation” methods. Zero Alternate 2 Sequence Sensor Sensor Location Sensor Most distribution systems can use Residual Polarity Main Sensors Marks either of the three sensing methods

Main exclusively or a combination of the 3 sensing methods depending upon Neutral the complexity of the system and the degree of service continuity and 4 Neutral GFR Typical selective coordination desired. Feeder Typical Different methods will be required GFR 5 Feeder depending upon the number of supply Typical sources, and the number and location 4W Load Typical of system grounding points. 4W Load 6 Figure 1.4-6. Zero Sequence Sensing Method As an example, one of the more Figure 1.4-7. Residual Sensing Method frequently used systems where Zero sequence sensors are available As with the zero sequence sensing continuity of service to critical loads 7 with various window openings for is a factor is the dual source system circuits with small or large conductors, method, the resultant residual sensor output to the ground fault relay or illustrated in Figure 1.4-8. This system and even with large rectangular win- uses tie-point grounding as permitted dows to fit over busbars or multiple integral ground fault tripping circuit 8 under NEC Sec. 250.24(A)(3). The use large size conductors in parallel. Some will be zero if all currents flow only sensors have split cores for installation in the circuit conductors. Should a of this grounding method is limited over existing conductors without ground fault occur, the current from to services that are dual fed (double- 9 disturbing the connections. the faulted conductor will return along ended) in a common enclosure or the ground path, rather than on the grouped together in separate enclo- This method of sensing ground faults other circuit conductors, and the resid- sures, employing a secondary tie. 10 can be employed on the main discon- ual sum of the sensor outputs will not nect where protection per NEC (230.95) This scheme uses individual sensors be zero. When the level of ground fault is desired. It can also be easily employed connected in ground return fashion. 11 in multi-tier systems where additional current exceeds the pre-set current Under tie breaker closed operating levels of ground fault protection are and time delay settings, a ground conditions, either the M1 sensor or desired for added service continuity. fault tripping action will be initiated. M2 sensor could see neutral unbalance 12 Additional grounding points may be This method of sensing ground faults currents and possibly initiate an employed upstream of the sensor, but can be economically applied on main improper tripping operation. However, not on the load side. service disconnects where circuit break- with the polarity arrangements of 13 Ground fault protection employing ers with integral ground fault protection these two sensors along with the tie ground return or zero sequence sensing are provided. It can be used in protec- breaker auxiliary switch (T/a) and methods can be accomplished by the tion schemes per NEC (230.95) or in interconnections as shown, this 14 use of separate ground fault relays multi-tier schemes where additional possibility is eliminated. (GFRs) and disconnects equipped with standard shunt trip devices or by circuit 15 breakers with integral ground fault Power Power protection with external connections Transformer Transformer arranged for these modes of sensing. In 16 some cases, a reliable source of control power is needed. Main Neutral Sensor Neutral Sensor Main Bkr. Main Bkr. 52-1 Tie Bkr. Main Bkr. 52-2 Bkr. The third basic method of detecting 52-1 52-T 52-2 17 ground faults involves the use of ØA, ØB, ØC ØA, ØB, ØC multiple current sensors connected in Neutral Neutral Neutral Sensor a residual sensing method as illustrated Tie Bkr. 52-T ( )B5 18 in Figure 1.4-7. This is a very common Typical ( )B5 Typical 4-Wire ( )B4 ( )B4 52-T 52-T 4-Wire sensing method used with circuit break- Feeder Feeder TN a TG a M2N M1G M2G ers equipped with electronic trip units, M1N 19 current sensors and integral ground 33- 4-Wire 52-T 4-Wire fault protection. The three-phase sensors B5 B4 B4 B5 B4 B5 Load Load are required for normal phase overcur- Digitrip Digitrip Digitrip rent protection. Ground fault sensing B4 B5 Main Bkr. Main Bkr. Main Bkr. B4 B5 20 is obtained with the addition of an Digitrip 52-1 52-T 52-2 Digitrip identically rated sensor mounted on the 21 Figure 1.4-8. Dual Source System—Single Point Grounding Note: This GF scheme requires trip units to be set to source ground sensing.

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.4-13 April 2016 System Application Considerations Sheet 01 069 Grounding/Ground Fault Protection

Selective ground fault tripping coordi- or a combination of all types may be GFR is an indication that any occurring nation between the tie breaker and the employed to accomplish the desired ground fault is within the zone of the i two main circuit breakers is achieved end results. GFR next upstream from the fault and by pre-set current pickup and time that device will operate instantaneously delay settings between devices GFR/1, Because the NEC (230.95) limits the to clear the fault with minimum dam- ii GFR/2 and GFR/T. maximum setting of the ground fault age and maximum service continuity. protection used on service equipment This operating mode permits all GFRs The advantages of increased service to 1200 A (and timed tripping at 3000 A to operate instantaneously for a fault 1 continuity offered by this system can for one second), to prevent tripping within their zone and still provide only be effectively used if additional of the main service disconnect on a complete selectivity between zones. levels of ground fault protection are feeder ground fault, ground fault The National Electrical Manufacturers 2 added on each downstream feeder. protection must be provided on all the Association (NEMA) states, in their Some users prefer individual grounding feeders. To maintain maximum service application guide for ground fault of the transformer neutrals. In such continuity, more than two levels (zones) protection, that zone interlocking is 3 cases, a partial differential ground fault of ground fault protection will be necessary to minimize damage from scheme should be used for the mains required, so that ground fault outages ground faults. A two-wire connection and tie breaker. can be localized and service interrup- is required to carry the restraining 4 tion minimized. To obtain selectivity An example of a residual partial differ- signal from the GFRs in one zone to between different levels of ground the GFRs in the next zone. ential scheme is shown in Figure 1.4-9. fault relays, time delay settings should 5 The scheme typically relies upon the be employed with the GFR furthest Circuit breakers with integral ground vector sum of at least two neutral downstream having the minimum fault protection and standard circuit sensors in combination with each time delay. This will allow the GFR breakers with shunt trips activated 6 breakers’ three-phase sensors. To nearest the fault to operate first. by the ground fault relay are ideal for reduce the complexity of the drawing, With several levels of protection, this ground fault protection. Many fused each of the breakers’ three-phase will reduce the level of protection for switches over 1200 A, and Eaton Type 7 sensors have not been shown. It is faults within the upstream GFR zones. FDP fusible switches with ratings absolutely critical that the sensors’ Zone interlocking was developed for from 400 to 1200 A, are listed by UL polarities are supplied as shown, the GFRs to overcome this problem. as suitable for ground fault protection. 8 neutral sensor ratings of the mains and Fusible switches so listed must be tie are the same, and that there are GFRs (or circuit breakers with integral equipped with a shunt trip, and be able no other grounds on the neutral bus ground fault protection) with zone to open safely on faults up to 12 times 9 made downstream of points shown. interlocking are coordinated in a their rating. system to operate in a time delayed An infinite number of ground fault mode for ground faults occurring most Power distribution systems differ 10 protection schemes can be developed remote from the source. However, this widely from each other, depending depending upon the number of alternate time delayed mode is only actuated upon the requirements of each user, sources, the number of grounding points when the GFR next upstream from the and total system overcurrent protec- 11 and system interconnections involved. fault sends a restraining signal to the tion, including ground fault currents, Depending upon the individual system upstream GFRs. The absence of a must be individually designed to meet configuration, either mode of sensing restraining signal from a downstream these needs. Experienced and knowl- 12 edgeable engineers must consider the power sources (utility or on-site), the Power Power effects of outages and costs of down- 13 Transformer Transformer time, safety for people and equipment, initial and lifecycle costs, and many other factors. They must apply protec- 14 tive devices, analyzing the time-current X X X Neutral Neutral X characteristics, fault interrupting Sensor Main Sensor Main capacity, and selectivity and coordina- Main Breaker 52-1 Breaker 52-2 Main 15 Breaker Breaker tion methods to provide the most safe 52-1 52-2 and cost-effective distribution system. 16 Phase A, Tie Breaker Phase A, Further Information Phase B, 52-T Phase B, ■ PRSC-4E—System Neutral Ground- Phase C Phase C ing and Ground Fault Protection Neutral Neutral 17 X (ABB Publication) Neutral Sensor X Tie Breaker 52-T ■ PB 2.2—NEMA Application Guide X X Typical X Typical X for Ground Fault Protective Devices 18 Four-Wire Four-Wire for Equipment i p Un t Feeder i p Un t 52-1 52-T 52-2 Feeder Tr Tr ■ a a a IEEE Standard 142—Grounding of Industrial and Commercial Power 19 Four-Wire Load Four-Wire Load Systems (Green Book) Trip Unit Trip Unit Trip Unit ■ IEEE Emerald Book (Standard 1100) Main Breaker Tie Breaker Main Breaker ■ 20 52-1 52-T 52-2 UL 96A, Installation Requirements for Lightning Protection Systems Figure 1.4-9. Dual Source System—Multiple Point Grounding 21

CA08104001E For more information, visit: www.eaton.com/consultants 1.4-14 Power Distribution Systems System Application Considerations April 2016 Sheet 01 070 Grounding/Ground Fault Protection

Lightning and Surge Protection The electrical distribution system and Surge Protection i equipment ground must be connected Physical protection of buildings to this grounding electrode system by Eaton’s VacClad-W metal-clad switch- from direct damage from lightning a grounding electrode conductor. All gear is applied over a broad range of ii is beyond the scope of this section. other grounding electrodes, such as circuits, and is one of the many types Requirements will vary with geographic those for the lightning protection sys- of equipment in the total system. The location, building type and environ- tem, the telephone system, television distribution system can be subject to 1 ment, and many other factors (see antenna and cable TV system grounds, voltage transients caused by lighting IEEE/ANSI Standard 142, Grounding and computer systems, must be bonded or switching surges. of Industrial and Commercial Power to this grounding electrode system. Systems). Any lightning protection Recognizing that distribution system 2 can be subject to voltage transients system must be grounded, and the Medium Voltage Equipment Surge lightning protection ground must be caused by lighting or switching, the 3 bonded to the electrical equipment Protection Considerations industry has developed standards to grounding system. provide guidelines for surge protection Transformers of electrical equipment. Those guide- 4 Grounding Electrodes If the voltage withstand/BIL rating of lines should be used in design and the transformer is less than that of the protection of electrical distribution At some point, the equipment and switchgear feeding the transformer, systems independent of the circuit system grounds must be connected surge protection is recommended at breaker interrupting medium. The 5 to the earth by means of a grounding the transformer terminals, in line with industry standards are: electrode system. established practices. In addition, ANSI C62 6 Outdoor substations usually use a consideration should be given to using Guides and Standards for Surge ground grid, consisting of a number of surge arresters and/or surge capacitors Protection ground rods driven into the earth and for transformers having equal or 7 bonded together by buried copper greater withstand/BIL ratings than that IEEE 242—Buff Book conductors. The required grounding of the switchgear feeding the trans- IEEE Recommended Practice for electrode system for a building is former for distribution systems where Protection and Coordination of 8 spelled out in the NEC Article 250. reflected voltage waves and/or reso- Industrial and Commercial Power nant conditions may occur. Typically Systems The preferred grounding electrode incoming voltage surges are reflected 9 is a metal underground water pipe in at the transformer primary terminals IEEE 141—Red Book direct contact with the earth for at least (because of the change in impedance) Recommended Practice for 10 ft (3 m). However, because under- resulting in voltages at the ends of the Electric Power Distribution for 10 ground water piping is often plastic transformer primary terminals/wind- Industrial Plants outside the building, or may later be ings of up to two times the incoming IEEE C37.20.2 replaced by plastic piping, the NEC voltage wave. System capacitance and Standards for Metal-Clad Switchgear 11 requires this electrode to be supple- inductance values combined with the mented by and bonded to at least one transformer impedance values can Eaton’s medium voltage metal-clad other grounding electrode, such as cause resonant conditions resulting and metal-enclosed switchgear that 12 the effectively grounded metal frame in amplified reflected waves. Surge uses vacuum circuit breakers is applied of the building, a concrete-encased arresters/capacitors when required, over a broad range of circuits. It is one electrode, a copper conductor ground should be located as close to the trans- of the many types of equipment in the 13 ring encircling the building, or a made former primary terminals as practical. total distribution system. Whenever a electrode such as one or more driven switching device is opened or closed, ground rods or a buried plate. Where Motors certain interactions of the power 14 any of these electrodes are present, Surge capacitors and, where appropri- system elements with the switching they must be bonded together into one ate, surge arresters should be applied device can cause high frequency voltage grounding electrode system. at the motor terminals. transients in the system. Due to the wide range of applications and variety 15 One of the most effective grounding Generators of ratings used for different elements electrodes is the concrete-encased Surge capacitors and station in the power systems, a given circuit electrode, sometimes called the Ufer class surge arresters at the machine may or may not require surge protec- 16 ground, named after the man who terminals. tion. Therefore, Eaton does not include developed it. It consists of at least surge protection as standard with its 20 ft (6 m) of steel reinforcing bars or metal-clad or metal-enclosed medium 17 rods not less than 1/2 inches (12.7 mm) voltage switchgear. The user exercises in diameter, or at least 20 ft (6 m) of the options as to the type and extent bare copper conductor, size No. 4 AWG of the surge protection necessary 18 or larger, encased in at least 2 inches depending on the individual circuit (50.8 mm) of concrete. It must be characteristics and cost considerations. 19 located within and near the bottom of a concrete foundation or footing that The following are Eaton’s recommen- is in direct contact with the earth. Tests dations for surge protection of medium 20 have shown this electrode to provide voltage equipment. Please note these a low-resistance earth ground even in recommendations are valid when poor soil conditions. using Eaton’s vacuum breakers only. 21

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.4-15 April 2016 System Application Considerations Sheet 01 071 Grounding/Ground Fault Protection

Surge Protection Recommendations RC Snubber and/or ZORC damp 6. Capacitor Switching—No surge Note: The abbreviation ZORC® used in the internal transformer resonance: protection is required. Make sure i text below refers to Surge Protection Device that the capacitor’s lightning manufactured by Strike Technology (Pty) The natural frequency of transformer impulse withstand rating is equal Ltd. An equivalent device offered by other windings can under some circumstances to that of the switchgear. ii manufacturers, such as Type EHZ by ABB, be excited to resonate. Transformer and Protec Z by Northern Technologies SA windings in resonance can produce 7. Shunt Reactor Switching— can also be used. elevated internal voltages that produce Provide Surge Arrester in parallel 1 insulation damage or failure. An RC with RC Snubber, or ZORC at the 1. For circuits exposed to lightning, Snubber or a ZORC applied at the reactor terminals. surge arresters should be applied transformer terminals as indicated 2 in line with Industry standard above can damp internal winding 8. Motor Starting Reactors or Reduced practices. resonance and prevent the production Voltage Auto-Transformers— of damaging elevated internal voltages. Provide Surge Arrester in parallel 2. Transformers 3 This is typically required where rectifiers, with RC Snubber, or ZORC at the reactor or RVAT terminals. a. Close-Coupled to medium UPS or similar electronic equipment is voltage primary breaker: on the transformer secondary. 9. Switching Underground Cables— 4 Provide transients surge pro- 3. Arc-Furnace Transformers— Surge protection not needed. tection, such as Surge Arrester Provide Surge Arrester in parallel in parallel with RC Snubber, or with RC Snubber, or ZORC at the Types of Surge Protection Devices 5 ZORC. The surge protection transformer terminals. device selected should be Generally surge protective devices should be located as closely as possible located and connected at the 4. Motors—Provide Surge Arrester in 6 transformer primary terminals to the circuit component(s) that require parallel with RC Snubber, or ZORC protection from the transients, and or it can be located inside the at the motor terminals. For those switchgear and connected on connected directly to the terminals of 7 motors using VFDs, surge protec- the component with conductors that the transformer side of the tion should be applied and precede primary breaker. are as short and flat as possible to the VFD devices as well. minimize the inductance. It is also b. Cable-Connected to medium 8 5. Generators—Provide station class important that surge protection devices voltage primary breaker: Surge Arrester in parallel with RC should be properly grounded for Provide transient surge protec- Snubber, or ZORC at the generator effectively shunting high frequency tion, such as Surge Arrester in 9 terminals. transients to ground. parallel with RC Snubber, or ZORC for transformers con- nected by cables with lengths 10 up to 75 feet. The surge protec- tion device should be located and connected at the transformer 11 terminals. No surge protection is needed for transformers with lightning impulse withstand 12 ratings equal to that of the switchgear and connected to the switchgear by cables at 13 least 75 feet or longer. For transformers with lower BIL, provide surge arrester in parallel Figure 1.4-10. Surge Protection Devices 14 with RC Snubber or ZORC. 15

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CA08104001E For more information, visit: www.eaton.com/consultants 1.4-16 Power Distribution Systems System Application Considerations April 2016 Sheet 01 072 Grounding/Ground Fault Protection

Surge Arresters Surge Capacitors ZORC i The modern metal-oxide surge Metal-oxide surge arresters limit the A ZORC device consists of parallel arresters are recommended because magnitude of prospective surge over- combination of Resistor (R) and Zinc this latest advance in arrester design voltage, but are ineffective in control- Oxide Voltage Suppressor (ZnO), con- ii ensures better performance and high ling its rate of rise. Specially designed nected in series with a Surge Capacitor. reliability of surge protection schemes. surge capacitors with low internal The resistor R is sized to match surge Manufacturer’s technical data must inductance are used to limit the rate of impedance of the load cables, typically 1 be consulted for correct application rise of this surge overvoltage to protect 20 to 30 ohms. The ZnO is a gapless of a given type of surge arrester. turn-to-turn insulation. Recommended metal-oxide nonlinear arrester, set 2 Notice that published arrester MCOV values for surge capacitors are: 0.5 µf to trigger at 1 to 2 PU voltage, where (Maximum Continuous Operating on 5 and 7.5 kV, 0.25 µf on 15 kV, and 1 PU = 1.412*(VL- L /1.732). The Surge Voltage) ratings are based on 40º or 0.13 µf on systems operating at 24 kV Capacitor is typically sized to be 0.15 to 45 ºC ambient temperature. In general, and higher. 0.25 microfarad. As with RC Snubber, 3 the following guidelines are recom- under normal operating conditions, mended for arrester selections, when RC Snubber impedance of the capacitor is very installed inside Eaton’s medium A RC Snubber device consists of a high, effectively “isolating” the resistor 4 voltage switchgear: non-inductive resistor R sized to match R and ZnO from the system at normal surge impedance of the load cables, power frequencies, and minimizing A. Solidly Grounded Systems: typically 20 to 30 ohms, and connected heat dissipation during normal opera- 5 Arrester MCOV rating should be in series with a Surge Capacitor C. The tion. Under high frequency transient equal to 1.05 x VLL/(1.732 x T), Surge Capacitor is typically sized to be conditions, the capacitor offers very where VLL is nominal line-to-line 0.15 to 0.25 microfarad. Under normal low impedance, thus effectively 6 service voltage, 1.05 factor allows operating conditions, impedance of “inserting” the resistor R and ZnO in for +5% voltage variation above the capacitor is very high, effectively the power system as cable terminating the nominal voltage according “isolating” the resistor R from the network, thus minimizing reflection of 7 to ANSI C84.1, and T is derating system at normal power frequencies, the steep wave-fronts of the voltage factor to allow for operation at and minimizing heat dissipation during transients and prevents voltage dou- 55 ºC switchgear ambient, which normal operation. Under high frequency bling of the traveling wave. The ZnO 8 should be obtained from the transient conditions, the capacitor element limits the peak voltage magni- arrester manufacturer for the type offers very low impedance, thus effec- tudes. The combined effects of R, ZnO, 9 of arrester under consideration. tively “inserting” the resistor R in the and Capacitor of the ZORC device Typical values of T are: 0.946 to 1.0. power system as cable terminating provides optimum protection against B. Low Resistant Grounded Systems resistor, thus minimizing reflection of high frequency transients by absorbing, 10 (systems grounded through the steep wave-fronts of the voltage damping, and by limiting the peak resistor rated for 10 seconds): transients and prevents voltage dou- amplitude of the voltage wave-fronts. Arrester 10-second MCOV capability bling of the traveling wave. The RC Please note that the ZORC is not a 11 at 60 ºC, which is obtained from Snubber provides protection against lightning protection device. If lightning manufacturer’s data, should be high frequency transients by absorb- can occur or be induced in the electrical ing and damping and the transients. system, a properly rated and applied equal to 1.05 x VLL, where VLL is 12 nominal line-to-line service voltage, Please note RC Snubber is most effec- surge arrester must precede the ZORC. and 1.05 factor allows for +5% tive in mitigating fast-rising transient voltage variation above the voltages, and in attenuating reflections 13 nominal voltage. and resonances before they have a chance to build up, but does not limit C. Ungrounded or Systems the peak magnitude of the transient. 14 Grounded through impedance Therefore, the RC Snubber alone may other than 10-second resistor: not provide adequate protection. To Arrester MCOV rating should be limit peak magnitude of the transient, 15 equal to 1.05 x VLL/T, where VLL application of surge arrester should and T are as defined above. also be considered. Refer to Ta b l e 1. 4 - 3 for recommended 16 ratings for metal-oxide surge arresters that are sized in accordance with the above guidelines, when located in 17 Eaton’s switchgear.

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For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.4-17 April 2016 System Application Considerations Sheet 01 073 Grounding/Ground Fault Protection

Surge Protection Summary Good protection: Surge Arrester Best protection: ZORC, plus proper in parallel with Surge Capacitor for surge arrester preceding ZORC where i Minimum protection: Surge Arrester protection from high overvoltage needed for protection against lightning. for protection from high overvoltage peaks and fast rising transient. This ZORC provides protection from high peaks, or Surge Capacitor for protec- option may not provide adequate frequency voltage transients and limits ii tion from fast-rising transient. Please surge protection from escalating peak magnitude of the transient to note that the surge arresters or surge voltages caused by circuit resonance. 1 to 2 PU (see ZORC description on capacitor alone may not provide When applying surge capacitors on Page 1.4-16 for more detail). Surge 1 adequate surge protection from both sides of a circuit breaker, surge arrester provides protection from escalating voltages caused by circuit capacitor on one side of the breaker higher voltage peaks resulting from resonance. Note that when applying must be RC Snubber or ZORC, lightning surges. 2 surge capacitors on both sides of a to mitigate possible virtual circuit breaker, surge capacitor on current chopping. Further Information one side of the breaker must be ■ IEEE/ANSI Standard 142—Grounding 3 RC Snubber or ZORC, to mitigate Better protection: RC Snubber in Industrial and Commercial Power possible virtual current chopping. parallel with Surge Arrester for Systems (Green Book) protection from high frequency ■ IEEE Standard 241—Electric Power 4 transients and voltage peaks. Systems in Commercial Buildings (Gray Book) ■ IEEE Standard 141—Electric Power 5 Distribution for Industrial Plants (Red Book) 6 Table 1.4-3. Surge Arrester Selections—Recommended Ratings Service Distribution Class Arresters Station Class Arresters 7 Voltage Solidly Low Resistance High Resistance or Solidly Low Resistance High Resistance or Line-to-Line Grounded System Grounded System Ungrounded System Grounded System Grounded System Ungrounded System kV Arrester Ratings kV Arrester Ratings kV 8 Nominal MCOV Nominal MCOV Nominal MCOV Nominal MCOV Nominal MCOV Nominal MCOV

2.30 3 2.55 3 2.55 3 2.55 3 2.55 3 2.55 3 2.55 2.40 3 2.55 3 2.55 6 5.10 3 2.55 3 2.55 6 5.10 9 3.30 3 2.55 3 2.55 6 5.10 3 2.55 3 2.55 6 5.10 4.00 3 2.55 6 5.10 6 5.10 3 2.55 6 5.10 6 5.10 4.16 6 5.10 6 5.10 6 5.10 6 5.10 6 5.10 6 5.10 4.76 6 5.10 6 5.10 9 7.65 6 5.10 6 5.10 9 7.65 10 4.80 6 5.10 6 5.10 9 7.65 6 5.10 6 5.10 9 7.65 6.60 6 5.10 6 5.10 9 7.65 6 5.10 6 5.10 9 7.65 6.90 6 5.10 6 5.10 9 7.65 6 5.10 9 7.65 9 7.65 11 7.20 6 5.10 6 5.10 10 8.40 6 5.10 9 7.65 10 8.40 8.32 9 7.65 9 7.65 12 10.20 9 7.65 9 7.65 12 10.20 8.40 9 7.65 9 7.65 12 10.20 9 7.65 9 7.65 12 10.20 12 11.00 9 7.65 9 7.65 15 12.70 9 7.65 10 8.40 15 12.70 11.50 9 7.65 10 8.40 18 15.30 9 7.65 12 10.20 18 15.30 12.00 10 8.40 10 8.40 18 15.30 10 8.40 12 10.20 18 15.30 13 12.47 10 8.40 12 10.20 18 15.30 10 8.40 12 10.20 18 15.30 13.20 12 10.20 12 10.20 18 15.30 12 10.20 12 10.20 18 15.30 13.80 12 10.20 12 10.20 18 15.30 12 10.20 15 12.70 18 15.30 14.40 12 10.20 12 10.20 21 17.00 12 10.20 15 12.70 21 17.00 14 18.00 15 12.70 15 12.70 27 22.00 15 12.70 18 15.30 27 22.00 20.78 18 15.30 18 15.30 30 24.40 18 15.30 21 17.00 30 24.40 22.00 18 15.30 18 15.30 30 24.40 18 15.30 21 17.00 30 24.40 15 22.86 18 15.30 21 17.00 — — 18 15.30 24 19.50 36 29.00 23.00 18 15.30 21 17.00 — — 18 15.30 24 19.50 36 29.00 24.94 21 17.00 24 19.50 — — 21 17.00 24 19.50 36 29.00 16 25.80 21 17.00 24 19.50 — — 21 17.00 24 19.50 36 29.00 26.40 21 17.00 24 19.50 — — 21 17.00 27 22.00 39 31.50 33.00 27 22.00 30 24.40 — — 27 22.00 36 29.00 45 36.50 34.50 30 24.40 30 24.40 — — 30 24.40 36 29.00 48 39.00 17 38.00 30 24.40 — — — — 30 24.40 36 29.00 — — 18

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CA08104001E For more information, visit: www.eaton.com/consultants 1.4-18 Power Distribution Systems System Application Considerations April 2016 Sheet 01 074 Power Quality

Power Quality Terms Defining the Problem Another option is to buy power condi- i Power quality problems can be resolved tioning equipment to correct any and Technical Overview in three ways: by reducing the variations all perceived power quality problems in the power supply (power distur- without any on-site investigation. ii Introduction bances), by improving the load equip- Power Quality Terms Sensitive electronic loads deployed ment’s tolerance to those variations, or Power disturbance: Any deviation today by users require strict require- by inserting some interface equipment from the nominal value (or from some 1 ments for the quality of power delivered (known as power conditioning equip- selected thresholds based on load to loads. ment) between the electrical supply and the sensitive load(s) to improve the tolerance) of the input AC power 2 For electronic equipment, power compatibility of the two. Practicality characteristics. disturbances are defined in terms of and cost usually determine the extent Total harmonic distortion or distortion amplitude and duration by the elec- to which each option is used. factor: The ratio of the root-mean- 3 tronic equipment operating envelope. square of the harmonic content to the Electronic loads may be damaged Many methods are used to define root-mean-square of the fundamental and disrupted, with shortened life power quality problems. For example, quantity, expressed as a percentage 4 expectancy, by disturbances. one option is a thorough on-site investigation, which includes inspecting of the fundamental. The proliferation of computers, variable wiring and grounding for errors, Crest factor: Ratio between the frequency motor drives, UPS systems 5 monitoring the power supply for peak value (crest) and rms value of and other electronically controlled power disturbances, investigating a periodic waveform. equipment is placing a greater demand equipment sensitivity to power distur- 6 on power producers for a disturbance- bances, and determining the load Apparent (total) power factor: The free source of power. Not only do these disruption and consequential effects ratio of the total power input in watts types of equipment require quality (costs), if any. In this way, the power to the total volt-ampere input. 7 power for proper operation; many quality problem can be defined, Sag: An rms reduction in the AC times, these types of equipment are alternative solutions developed, voltage, at the power frequency, for also the sources of power disturbances and optimal solution chosen. 8 that corrupt the quality of power in a the duration from a half-cycle to a few given facility. Before applying power-conditioning seconds. An undervoltage would have equipment to solve power quality a duration greater than several seconds. Power quality is defined according problems, the site should be checked 9 Interruption: The complete loss of volt- to IEEE Standard 1100 as the concept for wiring and grounding problems. age for a time period. of powering and grounding electronic Sometimes, correcting a relatively 10 equipment in a manner that is suitable inexpensive wiring error, such as a Tr a n s i e n t : A sub-cycle disturbance to the operation of that equipment. loose connection or a reversed neutral in the AC waveform that is evidenced IEEE Standard 1159 notes that “within and ground wire, can avoid a more by a sharp brief discontinuity of the 11 the industry, alternate definitions or expensive power conditioning solution. waveform. May be of either polarity interpretations of power quality have and may be additive to or subtractive Sometimes this approach is not practical been used, reflecting different points from the nominal waveform. 12 of view.” because of limitations in time; expense is not justified for smaller installations; Surge or impulse: See transient. In addressing power quality problems monitoring for power disturbances at an existing site, or in the design may be needed over an extended Noise: Unwanted electrical signals 13 stages of a new building, engineers period of time to capture infrequent that produce undesirable effects need to specify different services or disturbances; the exact sensitivities of in the circuits of control systems 14 mitigating technologies. The lowest the load equipment may be unknown in which they occur. cost and highest value solution is and difficult to determine; and finally, to selectively apply a combination Common-mode noise: The noise the investigative approach tends to voltage that appears equally and in of different products and services solve only observed problems. Thus 15 as follows: phase from each current-carrying unobserved or potential problems may conductor to ground. Key services/technologies in the not be considered in the solution. For 16 “power quality” industry: instance, when planning a new facility, Normal-mode noise: Noise signals there is no site to investigate. There- measurable between or among active ■ Power quality surveys, analysis fore, power quality solutions are often circuit conductors feeding the subject 17 and studies implemented to solve potential or per- load, but not between the equipment ■ Power monitoring ceived problems on a preventive basis grounding conductor or associated ■ Grounding products and services instead of a thorough on-site investi- signal reference structure and the active gation. circuit conductors. 18 ■ Surge protection ■ Voltage regulation 19 ■ Harmonic solutions ■ Lightning protection (ground rods, hardware, etc.) 20 ■ Uninterruptible power supply (UPS) or motor-generator (M-G) set 21

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.4-19 April 2016 System Application Considerations Sheet 01 075 Power Quality

Methodology for Ensuring Effective The proliferation of communication The benefit of implementing cascaded Power Quality to Electronic Loads and computer network systems network protection is shown in i The power quality pyramid is an has increased the need for proper Figure 1.4-12. Combined, the two effective guide for addressing power grounding and wiring of AC and data/ stages of protection at the service quality problems at an existing facility. communication lines. In addition to entrance and branch panel locations ii The framework is also effective for reviewing AC grounding and bonding reduce the IEEE 62.41 recommended specifying engineers who are design- practices, it is necessary to prevent test wave (C3–20 kV, 10 kA) to less than ing a new facility. Power quality starts ground loops from affecting the signal 200 V voltage, a harmless disturbance 1 with grounding (the base of the reference point. level for 120 V rated sensitive loads. pyramid) and then moves upward 2. Surge Protection If only building entrance feeder 2 to address the potential issues. This protection were provided, the let- simple, yet proven methodology, Surge protection devices (SPDs) through voltage will be approximately will provide the most cost-effective are recommended as the next stage 950 V in a 277/480 V system exposed 3 approach. As we move higher up the power quality solutions. NFPA, to induced lightning surges. This pyramid, the cost per kVA of mitigating UL 96A, IEEE Emerald Book and level of let-through voltage can cause potential problems increase and the equipment manufacturers recom- degradation or physical damage of 4 quality of the power increases (refer mend the use of surge protectors. most electronic loads. to Figure 1.4-11). The SPD shunt short duration voltage disturbances to ground, thereby Wherever possible, consultants, 5 preventing the surge from affecting specifiers and application engineers electronic loads. When installed as should ensure similar loads are fed part of the facility-wide design, SPDs from the same source. In this way, 6 are cost-effective compared to all disturbance-generating loads are other solutions (on a $/kVA basis). separated from electronic circuits affected by power disturbances. For The IEEE Emerald Book recommends example, motor loads, HVAC systems 7 the use of a two-stage protection and other linear loads should be Cost Per kVA Cost Per concept. For large surge currents, separated from the sensitive process diversion is best accomplished in control and computer systems. 8 two stages: the first diversion should be performed at the service entrance The most effective and economic 5. Uninterruptible Power Supply to the building. Then, any residual solution for protecting a large number 9 (UPS, Gen. Sets, etc.) voltage resulting from the action of loads is to install parallel SPDs at 4. Harmonic Distortion can be dealt with by a second the building service entrance feeder 3. Voltage Regulation protective device at the power and panelboard locations. This reduces 10 2. Surge Protection panel of the computer room the cost of protection for multiple (or other critical loads). sensitive loads. 1. Grounding 11

Figure 1.4-11. Power Quality Pyramid 12 Input—high energy 1. Grounding SPD transient disturbance; IEEE Category CP C3 Impulse 20,000V; 10,000A SPD 20,000V Grounding represents the foundation 480V 120/208V 13 of a reliable power distribution system. Grounding and wiring Computer or Best achievable Sensitive performance with single SPD problems can be the cause of up to Loads Stage 1 Protection at main panel (950V, at Stage 1) 14 80% of all power quality problems. (Service Entrance) Stage 2 Protection (Branch Location) All other forms of power quality 800V solutions are dependent upon good System Test Parameters: PEAK VOLTAGE 400V 15 grounding procedures. IEEE C62.41[10] and C62.45 [10] test procedures using category; 0 480V main entrance panels; 25 uS 50 uS TIME (MICROSECONDS) 100 ft (30m) of three-phase wire; 16 480/208V distribution transformer; Two stage (cascade and 208V branch panel. approach) achieves best possible protection (less = SPD than 200V at Stage 2) 17

Figure 1.4-12. Cascaded Network Protection 18

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CA08104001E For more information, visit: www.eaton.com/consultants 1.4-20 Power Distribution Systems System Application Considerations April 2016 Sheet 01 076 Power Quality

The recommended system approach ■ Building entrance SPDs protect By twisting the installation wires, the i for installing SPDs is summarized in the facility against large external area between wires is reduced and the Figure 1.4-13. transients, including lightning mutual inductance affect minimized. ■ ii SPDs are bi-directional and prevent Increasing the diameter of the installation transient and noise disturbances wires is of negligible benefit. Induc- 1. from feeding back within a system Identify Critical Loads tance is a “skin effect” phenomenon and when installed at distribution or a function of wire circumference. Since 1 branch panels 2. only a marginal reduction in inductance ■ Identify Non-Critical Loads Two levels of protection safeguard is achieved when the diameter of the 2 sensitive loads from physical installation conductors is increased, damage or operational upset the use of large diameter wire results 3. Identify Noise and Side-Mounted SPD vs. Integral SPD in only minimal improvement (see Disturbance Generating Loads Figure 1.4-15). 3 Directly connecting the surge sup- presser to the busbar of electrical Further benefits provided by integrated 4. distribution equipment results in surge suppression designs are the 4 Review Internal Power Distribution Layout the best possible level of protection. elimination of field installation costs and Compared to side-mounted devices, the amount of expensive “outboard” 5. connecting the SPD unit to the busbar wall space taken up by side-mounted 5 Identify Facility Exposure to eliminates the need for lead wires SPD devices. Expected Levels of Disturbance and reduces the let-through voltage up to 50% (see Figure 1.4-14). Building Entrance Feeder Installation 6 6. Considerations Apply Mitigating Equipment to: Given that surges are high frequency Installing an SPD device immediately a) Service Entrance Main Panels disturbances, the inductance of the after the switchgear or switchboard 7 b) Key Sub-Panels installation wiring increases the main breaker is the optimal location c) Critical Loads let-through voltage of the protective d) Data and Communication Lines for protecting against external distur- device. Figure 1.4-15 shows that bances such as lightning. When placed 8 for every inch of lead length, the in this location, the disturbance is Figure 1.4-13. System Approach for Installing SPDs let-through voltage is increased by “intercepted” by the SPD and reduced There may be specific critical loads an additional 15–25 V above the to a minimum before reaching the 9 within a facility that require a higher manufacturers stated suppression distribution and/or branch panel(s). level of protection. A series SPD is best performance. suited for protecting such loads. The use of a disconnect breaker 10 Lead length has the greatest effect on eliminates the need to de-energize Advantages of the system approach are: the actual level of protection realized. the building entrance feeder equip- Twisting of the installation wires is ■ The lowest possible investment ment should the SPD fail or require 11 the second most important installation isolation for Megger testing. in mitigating equipment to protect consideration. a facility 12

208Y/120 Panelboard 13 (integrated versus side mounted SPD)

1000 Side-Mounted SPD Device Side-Mounted SPD SPD Integrated (assuming 14-inch (355.6 mm) lead length to bus) 14 used for Retrofit into Panelboards, Applications Switchboards, MCCs 800

15 600

N SPD 400 16 Integrated SPD SPD 200 (direct bus bar connection) 17 0 GRO UND GROUND Let-Throu g h Volt ag e a t Bus B r Surge Event 18 G –200 G –2.00 0.00 2.00 4.00 6.00 8.00 10.00

\ N 19 Microseconds Figure 1.4-14. Performance Comparison of Side-Mounted vs. Integrated SPD 20

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Reference Ta b 3 4 for detailed Additional Let-Through Voltage Using IEEE C1(6000V, 3000A)[3] information on SPDs. i Waveform (UL 1449 Test Wave)[12] 900 14 AWG 3. Voltage Regulation 800 209V (23%) 10 AWG 700 ii 4 AWG Voltage regulation (i.e., sags or over- 600 673V (75%) 500 voltage) disturbances are generally 400 site- or load-dependent. A variety of 300 mitigating solutions are available 1 200 depending upon the load sensitivity, 100 0 fault duration/magnitude and the 2 3 ft (914.4 mm) 1 ft (304.8 mm) specific problems encountered. It is Lead Length Lead Length, recommended to install monitoring Add i t on a l Let-Through Volt ge ¿ Loose Wiring Twisted Wires Twisted Wires equipment on the AC power lines to 3 assess the degree and frequency of Figure 1.4-15. The Effect of Installation Lead Length on Let-Through Voltage 1 occurrences of voltage regulation Additional to UL 1449 ratings. problems. The captured data will allow 4 The size or capacity of a suppressor is This increase in disturbance voltage for the proper solution selection. measured in surge current per phase. can result in process disruption Larger suppressers rated at approxi- and downtime. 4. Harmonics Distortion 5 mately 250 kA per phase should be Harmonics and Nonlinear Loads installed at the service entrance to Installing Dataline Surge Protection survive high-energy surges associated Most facilities also have communica- Until recently, most electrical loads were 6 with lightning. tion lines that are potential sources linear. Linear loads draw the full sine for external surges. As identified by wave of electric current at its 60 cycle A 250 kA per phase surge rating allows the power quality pyramid, proper (Hz) fundamental frequency—Figure 7 for over a 25-year life expectancy grounding of communication lines is 1.4-16 shows balance single-phase, assuming an IEEE defined high essential for dependable operation. linear loads. As the figure shows, exposure environment. Lower surge NEC Article 800 states that all data, little or no current flows in the neutral 8 rating devices may be used; however, power and cable lines be grounded conductor when the loads are non- device reliability and long-term and bonded. linear and balanced. performance may be compromised. 9 Power disturbances such as lightning With the arrival of nonlinear electronic For aerial structures, the 99.8 percentile can elevate the ground potential loads, where the AC voltage is con- recorded lightning stroke current is between two communicating pieces verted to a DC voltage, harmonics are 10 less than 220 kA. The magnitude of of electronic equipment with different created because of the use of only part surges conducted or induced into a ground references. The result is current of the AC sine wave. In this conversion facility electrical distribution system is flowing through the data cable, causing from AC to DC, the electronics are turned 11 considerably lower given the presence component failure, terminal lock-up, on in the 60 cycle wave at a given point of multiple paths for the surge to travel data corruption and interference. in time to obtain the required DC level. along. It is for this reason that IEEE The use of only part of the sign wave C62.41 recommends the C3 (20 kV, NFPA 780 D—4.8 warns that “surge causes harmonics. 12 10 kA) test wave for testing SPDs suppression devices should be installed installed at building entrance feeders. on all wiring entering or leaving elec- It is important to note that the current tronic equipment, usually power, data distortion caused by loads such as 13 SPDs with surge ratings greater than or communication wiring.” rectifiers or switch mode power 250 kA are not required, however, supplies causes the voltage distortion. higher ratings are available and may Surge suppressers should be installed That voltage distortion is caused by 14 provide longer life. at both ends of a data or communica- distorted currents flowing through an tion cable. In those situations where impedance. The amount of voltage Installing Panelboard Surge one end of the cable is not connected distortion depends on: 15 Protection Devices into an electronic circuit (e.g., contactor Smaller surge capacity SPDs (120 kA coil), protection on the electronic end ■ System impedance per phase) are installed at branch pan- only is required. ■ Amount of distorted current 16 elboards where power disturbances are of lower energy, but occur much To prevent the coupling or inducing of Devices that can cause harmonic more frequently. This level of surge power disturbances into communication disturbances include rectifiers, 17 current rating should result in a lines, the following should be avoided: thrusters and switching power sup- plies, all of which are nonlinear. greater than 25-year life expectancy. ■ Data cables should not be run over Further, the proliferation of electronic 18 When isolated ground systems are fluorescent lighting fixtures equipment such as computers, UPS used, the SPD should be installed such ■ Data cables should not be in the systems, variable speed drives, that any common mode surges are vicinity of electric motors programmable logic controllers, and 19 shunted to the safety ground. ■ The right category cable should the like: non-linear loads have become be used to ensure transmission a significant part of many installations. The use of a disconnect breaker is performance Other types of harmonic-producing optional. The additional let-through 20 ■ Data cables must be grounded at loads include arcing devices (arc voltage resulting from the increased furnaces, fluorescent lights) and iron inductance caused by the disconnect both ends when communicating between buildings core storable devices (transformers, 21 switch is about 50–60 V. especially during energization).

CA08104001E For more information, visit: www.eaton.com/consultants 1.4-22 Power Distribution Systems System Application Considerations April 2016 Sheet 01 078 Power Quality

Nonlinear load currents vary widely present on the three phases add Harmonic Issues i from a sinusoidal wave shape; often together in the neutral, as shown in they are discontinuous pulses. This Figure 1.4-17, rather than cancel each Harmonic currents perform no work and result in wasted electrical energy means that nonlinear loads are other out, as shown in Figure 1.4-16. that may over burden the distribution extremely high in harmonic content. Odd non-triplen harmonics are ii system. This electrical overloading classified as “positive sequence” may contribute to preventing an Triplen harmonics are the 3rd, 9th, or “negative sequence” and are the existing electrical distribution system 1 15th,...harmonics. Further, triplen 1st, 5th, 7th, 11th, 13th, etc. harmonics are the most damaging from serving additional future loads. to an electrical system because these In general, as the order of a harmonic In general, harmonics present on 2 harmonics on the A-phase, B-phase gets higher, its amplitude becomes a distribution system can have the and C-phase are in sequence with each smaller as a percentage of the funda- following detrimental effects: other. Meaning, the triplen harmonics mental frequency. 3 1. Overheating of transformers and rotating equipment. 60 Hz Fundamental 4 2. Increased hysteresis losses. 3. Decreased kVA capacity. A Phase 5 4. Overloading of neutral. 5. Unacceptable neutral-to-ground voltages. 6 120º 6. Distorted voltage and current Lagging B Phase waveforms. 7 7. Failed capacitor banks. 8. Breakers and fuses tripping. 8 9. Double or ever triple sized neutrals 120º to defy the negative effects of Lagging C Phase 9 triplen harmonics. In transformers, generators and uninterruptible power supplies (UPS) systems, harmonics cause overheating 10 Balance Neutral and failure at loads below their ratings Current because the harmonic currents cause 11 greater heating than standard 60 Hz current. This results from increased Figure 1.4-16. Balanced Neutral Current Equals Zero eddy current losses, hysteresis losses 12 in the iron cores, and conductor skin effects of the windings. In addition, 60 Hz Fundamental the harmonic currents acting on the 13 3rd Harmonic impedance of the source cause harmonics in the source voltage, which A Phase is then applied to other loads such as 14 motors, causing them to overheat. The harmonics also complicate the application of capacitors for power 15 120º B Phase factor correction. If, at a given harmonic Lagging frequency, the capacitive impedance 16 equals the system reactive impedance, the harmonic voltage and current can reach dangerous magnitudes. At the same time, the harmonics create 17 120º C Phase Lagging problems in the application of power factor correction capacitors, they 18 lower the actual power factor. The rotating meters used by the utilities for watthour and various measurements 19 Neutral do not detect the distortion component Triplen caused by the harmonics. Rectifiers Current

à with diode front ends and large DC side capacitor banks have displacement 20 Phase Triplen Harmonics Added in the Neutral power factor of 90% to 95%. More recent electronic meters are capable 21 of metering the true kVA hours taken Figure 1.4-17. Unbalanced Single-Phase Loads with Triplen Harmonics by the circuit.

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Single-phase power supplies for Total Harmonic Distortion Table 1.4-7. Current Distortion Limits for computer and fixture ballasts are General Distribution Systems (120– 69,000 V) i rich in third harmonics and their Revised standard IEEE 519-1992 indicates the limits of current distor- Maximum Harmonic Current Distortion in odd multiples. Percent of I tion allowed at the PCC (Point of L ii Even with the phase currents perfectly Common Coupling) point on the Individual Harmonic Order (Odd Harmonics) balanced, the harmonic currents in system where the current distortion ISC/IL <11 11 17 23 35 TDD the neutral can total 173% of the is calculated, usually the point of < h < h < h < h <17 <23 <35 1 phase current. This has resulted in connection to the utility or the main 3 overheated neutrals. The Information supply bus of the system. <20 4.0 2.0 1.5 0.6 0.3 5.0 Technology Industry Council (ITIC) 20<50 7. 0 3.5 2.5 1.0 0.5 8.0 2 formerly known as CBEMA, recom- The standard also covers the harmonic 50<100 10.0 4.5 4.0 1.5 0.7 12.0 mends that neutrals in the supply to limits of the supply voltage from the 100<1000 12.0 5.5 5.0 2.0 1.0 15.0 utility or cogenerators. >1000 15.0 7. 0 6.0 2.5 1.4 20.0 electronic equipment be oversized 3 3 to at least 173% of the ampacity of All power generation equipment is limited Table 1.4-5. Low Voltage System Classification to these values of current distortion, the phase conductors to prevent and Distortion Limits for 480 V Systems regardless of actual ISC/IL where: problems. ITIC also recommends I = Maximum short-circuit current at PCC. Class CAN DF SC 4 derating transformers, loading them IL = Maximum demand load current 2 to no more than 50% to 70% of their Special application 10 16,400 3% (fundamental frequency component) at PCC. nameplate kVA, based on a rule-of- General system 5 22,800 5% TDD = Total Demand Distortion. Even 5 thumb calculation, to compensate Dedicated system 2 36,500 10% harmonics are limited to 25% of the odd 2 harmonic limits above. Current distortions for harmonic heating effects. Special systems are those where the rate that result in a DC offset, e.g., half-wave of change of voltage of the notch might converters, are not allowed. 6 In spite of all the concerns they mistrigger an event. AN is a measurement cause, nonlinear loads will continue of notch characteristics measured in Harmonic Solutions to increase. Therefore, the design of volt-microseconds, C is the impedance nonlinear loads and the systems that ratio of total impedance to impedance In spite of all the concerns nonlinear 7 at common point in system. DF is loads cause, these loads will continue supply them will have to be designed distortion factor. so that their adverse effects are greatly to increase. Therefore, the design reduced. Ta b l e 1. 4 - 4 shows the typical of nonlinear loads and the systems 8 Table 1.4-6. Utility or Cogenerator Supply that supply them will need design so harmonic orders from a variety of Voltage Harmonic Limits harmonic generating sources. adverse harmonic effects are greatly Voltage 2.3–69 kV 69–138 kV >138 kV reduced. Table 1.4-8 and depicts many 9 Table 1.4-4. Source and Typical Harmonics Range harmonic solutions along with their Source Typical Maximum 3.0% 1.5% 1.0% advantages and disadvantages. 1 Harmonics individual 10 harmonic Eaton’s Engineering Services & Systems Group (EESS) can perform 6-pulse rectifier 5, 7, 11, 13, 17, 19… Total 5.0% 2.5% 1.5% 12-pulse rectifier 11, 13, 23, 25… harmonic harmonic studies and recommend 11 18-pulse rectifier 17, 19, 35, 37… distortion solutions for harmonic problems. Switch-mode power supply 3, 5, 7, 9, 11, 13… V 12 Fluorescent lights 3, 5, 7, 9, 11, 13… Percentages are h x 100 for each Arcing devices 2, 3, 4, 5, 7… V Transformer energization 2, 3, 4 harmonic 1 1 13 Generally, magnitude decreases as harmonic and order increases.

h = hmax 1/2 14 2 Vthd = ² V h h = 2 15 It is important for the system designer to know the harmonic content of the utility’s supply voltage because it will 16 affect the harmonic distortion of the system. 17

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CA08104001E For more information, visit: www.eaton.com/consultants 1.4-24 Power Distribution Systems System Application Considerations April 2016 Sheet 01 080 Power Quality

Table 1.4-8. Harmonic Solutions for Given Loads i Load Solutions Advantages Disadvantages Ty p e ii Drives and rectifiers— Line reactors ■ Inexpensive ■ May require additional compensation includes three-phase ■ For 6-pulse standard drive/rectifier, can UPS loads reduce harmonic current distortion from 1 80% down to about 35–40% K-rated/drive isolation ■ Offers series reactance (similar to line ■ No advantage over reactors for transformer reactors) and provides isolation for reducing harmonics unless in pairs some transients for shifting phases 2 DC choke ■ Slightly better than AC line reactors ■ Not always an option for drives for 5th and 7th harmonics ■ Less protection for input semiconductors 12-pulse convertor ■ 85% reduction versus standard ■ Cost difference approaches 18-pulse drive 3 6-pulse drives and blocking filters, which guarantee IEEE 519 compliance Harmonic mitigating ■ Substantial (50–80%) reduction in harmonics ■ Harmonic cancellation highly dependent 4 transformers/phase shifting when used in tandem on load balance ■ Must have even multiples of matched loads Tuned filters ■ Bus connected—accommodates ■ Requires allocation analysis 5 load diversity ■ Sized only to the requirements of that system; ■ Provides PF correction must be resized if system changes Broadband filters ■ Makes 6-pulse into the equivalent ■ Higher cost 6 of 18-pulse ■ Requires one filter per drive 18-pulse converter ■ Excellent harmonic control for drives ■ High cost above 100 hp 7 ■ IEEE 519 compliant Active filters ■ Handles load/harmonic diversity ■ High cost 8 ■ Complete solution up to 50th harmonic Computers/ Neutral blocking filter ■ Eliminates the 3rd harmonic from load ■ High cost switch-mode ■ Relieves system capacity ■ May increase voltage distortion 9 power supplies ■ Possible energy savings Harmonic mitigating ■ 3rd harmonic recalculated back to the load ■ Requires fully rated circuits and transformers ■ When used as phase-shifted transformers, oversized neutrals to the loads reduces other harmonics 10 ■ Reduces voltage “flat-topping” Oversized neutral/derated ■ Tolerate harmonics rather than correct ■ Upstream and downstream equipment 11 transformer ■ Typically least expensive fully rated for harmonics K-rated transformer ■ Tolerate harmonics rather than correct ■ Does not reduce system harmonics Fluorescent Harmonic mitigating ■ 3rd harmonic recalculated back to the load ■ Requires fully rated circuits and 12 lighting transformers ■ When used as phase-shifted transformers, oversized neutrals to the loads reduces other harmonics ■ Reduces voltage “flat-topping” 13 K-rated transformer ■ Tolerate harmonics rather than correct them ■ Does not reduce system harmonics Low distortion ballasts ■ Reduce harmonics at the source ■ Additional cost and typically more expensive than “system” solutions 14 Welding/arcing Active filters ■ Fast response and broadband ■ High cost loads harmonic correction ■ Reduces voltage flicker 15 Tuned filters ■ SCR controlled tuned filters simulates ■ SCR controlled units are high cost an active filter response but fixed filters are reasonable System Tuned filters ■ Provides PF correction ■ System analysis required to verify application. 16 solutions ■ Lower cost compared to other systems Must be resized if system changes Harmonic mitigating ■ Excellent choice for new design or upgrade ■ No PF correction benefit transformers 17 Active filters ■ Ideal solution and handles system diversity ■ Highest cost

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5. Uninterruptible Power The normal power source supplied by Uninterruptible power supply (UPS) the local utility or provider is not stable systems have evolved to serve the i Systems (UPS) enough over time to continuously needs of sensitive equipment and The advent of solid-state semiconduc- serve these loads without interruption. can supply a stable source of electrical tors over 40 years ago, and their It is possible that a facility outside a power, or switch to backup to allow ii subsequent evolution to transistors, major metropolitan area served by the for an orderly shutdown of the loads and the miniaturization of electronics utility grid will experience outages of without appreciable loss of data or into microprocessor over 25 years ago, some nature 15–20 times in one year. process. In the early days of main- 1 has created numerous computation Certain outages are caused by the frame computers, motor-generator machines that assist us in every weather, and others by the failure sets provide isolation and clean power conceivable manner. These machines, of the utility supply system due to to the computers. They did not have 2 and their clever configurations, equipment failures or construction deep reserves, but provided extensive whether they take the form of interruptions. Some outages are ride-through capability while other computers, appliance controls, fax only several cycles in duration, while sources of power (usually standby 3 machines, phone systems, computers others may be for hours at a time. emergency engine generator sets) were of all sizes, server systems and server brought to serve the motor-generator farms, emergency call centers, data In a broader sense, other problems sets while the normal source of power 4 processing at banks, credit companies, exist in the area of power quality, and was unstable or unavailable. private company communication many of those issues also contribute networks, government institutions and to the failure of the supply to provide UPS systems have evolved along the 5 defense agencies, all rely on a narrow that narrow range of power to the lines of rotary types and static types range of nominal AC power in order sensitive loads mentioned above. of systems, and they come in many for these devices to work properly. Power quality problems take the configurations, and even hybrid 6 Indeed, many other types of equip- form of any of the following: power designs having characteristics of ment also require that the AC electrical failure, power sag, power surge, both types. The discussion that power source be at or close to nominal undervoltage, overvoltage, line noise, follows attempts to compare and 7 voltage and frequency. Disturbances of frequency variations, switching contrast the two types of UPS the power translate into failed transients and harmonic distortion. systems, and give basic guidance processes, lost data, decreased Regardless of the reason for outages on selection criteria. This discussion 8 efficiency and lost revenue. and power quality problems, the will focus on the medium, large and sensitive loads can not function very large UPS systems required by normally without a backup power users who need more than 10 kVA of 9 source, and in many cases, the loads clean reliable power. must be isolated from the instabilities of the utility supply and power quality 10 problems and given clean reliable power on a continuous basis, or be able to switch over to reliable clean 11 electrical power quickly. 12

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CA08104001E For more information, visit: www.eaton.com/consultants 1.4-26 Power Distribution Systems Uninterruptible Power Systems (UPS) April 2016 Sheet 01 082

Power Ratings of UPS Systems types of hybrid UPS systems are not system checks are performed then the focus of this discussion, because the input contactor is closed. The static i ■ Small UPS: Typically 300 VA to 10 kVA, only one or two vendors offer these disconnect switch is turned on and the and sometimes as high as 18 kVA hybrid types of rotary UPS systems, conduction angle is rapidly increased ii ■ Medium UPS: 10–60 kVA although admittedly they continue to from zero to an angle that causes the ■ Large UPS: 100–200 kVA units, and be used in very large-scale data center DC bus voltage between the utility higher when units are paralleled applications. See Figure 1.4-18 for the converter and the flywheel converter 1 ■ Very Large UPS: 200–750 kVA modern high speed Rotary UPS to reach approximately 650 V through units, and higher when units systems discussed in this section the rectifying action of the freewheel- are paralleled of the guide. These types of modern ing diodes in the utility converter. 2 rotary UPS systems are advanced, As soon as this level of DC voltage is Each of these categories is arbitrary integrated designs using scalable reached, the static disconnect turns because manufacturers have many configurations of high-speed flywheel, on fully. The next steps involved the 3 different UPS offerings for the same motor and generator in one compact utility converter IGBTs to start firing, application. The choice of UPS type UPS package. The new rotary which allows the converter to act as and the configuration of UPS modules technologies have the potential to a rectifier, a regulating voltage source 4 for a given application depends upon replace battery backup systems, or and an active harmonic filter. As the many factors, including how many at least reduce the battery content IGBTs begin to operate, the DC bus power quality problems the UPS is for certain applications. The appeal is increased to a normal operating 5 expected to solve; how much future of rotary systems is the avoidance of voltage of approximately 800 V, and capacity is to be purchased now for the purchase, maintenance and facility the output bus is transferred from future loads; the nature of the sensi- space required by DC battery based bypass to the output of the power 6 tive loads and load wiring; which backup systems. electronics module. The transfer from type of UPS system is favored, rotary bypass is completed when the output or static; choices of battery or DC High-Speed Rotary contactor is closed and the bypass 7 storage technology considered; and Concept of Operation contactor opened in a make-before- a host of other application issues. break manner. The modern rotary type of UPS 8 Rotary UPS Systems operation is understood by reviewing The firing of the SCRs in the static the four topics below: startup mode, disconnect switch is now changed so Typical Ratings normal operation mode, discharge that each SCR in each phase is only 9 300–900 kVA/720 kW maximum. mode and recharge mode. turned on during the half-cycle, which permits real power to flow from the Typical Rotary Configurations Startup Mode utility supply to the UPS. This firing 10 Rotary UPS systems are among the The UPS output is energized on pattern at the static disconnect switch oldest working systems developed bypass as soon as power is applied prevents power from the flywheel to protect sensitive loads. Many of from the source to the system input. from feeding backward into the 11 these systems are complicated engine- The UPS continues the startup utility supply and ensures that all of generator sets coupled with high procedure automatically when the the flywheel energy is available to inertial flywheels operated at relatively front panel controls are placed into support the load. 12 low rotational speeds. These legacy the “Online” position. Internal UPS

13 Static Bypass Option It = Input Current Ir = Real Load Current 14 Ic = Charging Current Ig = Voltage Regulation Current Bypass Contactor 15 Id = Ih + Ix + Ir It = Ir + Ic + Ig Input Static Disconnect Output Contactor Switch Line Inductor 16 Contactor Source Load

Flywheel Converter Utility Converter Ic Inverter 17 Fuse Output Transformer

Ix dc Filter Inductor Ig Id = Output Current 18 Field Coil ac Ih = Harmonic Current Driver dc ac Ix = Reactive Load Current 19 Ir = Real Load Current Ih Integrated Motor/Flywheel/ 20 and Generator Figure 1.4-18. Typical-High Speed Modern Rotary UPS 21

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.4-27 April 2016 Uninterruptible Power Systems (UPS) Sheet 01 083

Immediately after the output is trans- causes a voltage boost across the line as the load power is completely ferred from bypass to the power elec- inductor, and a lagging current causes transferred to the input source, the util- i tronic module, the flywheel field is a bucking voltage. By controlling the ity converter and flywheel converter excited, which also provides magnetic utility converter to maintain nominal start to recharge the flywheel and lift to unload the flywheel bearings. output voltage, just enough reactive return to normal operation mode. The ii The flywheel inverter is turned on current flows through the line inductor flywheel recharge power is program- and gradually increases frequency to make up the difference between the mable between a slow and fast rate, at a constant rate to accelerate the input voltage and the output voltage. and using the fast rate results in an 1 flywheel to approximately 60 rpm. increase of UPS input current over Once the flywheel reaches 60 rpm, The load current consists of three nominal levels. Recharging the flywheel the flywheel inverter controls the components: the harmonic current is accomplished by controlling the 2 acceleration to keep currents below the required by the load, the reactive load utility and flywheel converter in a maximum charging and the maximum current, and the real current, which similar manner as is used to maintain input settings. Once the flywheel does the work. The utility converter full charge in the normal operation 3 reaches 4000 rpm, the UPS is fully supplies both the harmonic and mode, however the IGBT gating points functional and capable of supporting reactive currents. Because these are changed to increase current into the load during a power quality event. currents supply no net power to the the flywheel. 4 flywheel acceleration continues until load, the flywheel supplies no energy the Flywheel reaches “full charge” at for these currents. They circulate High-Speed Rotary Advantages 7700 rpm. The total time to complete between the utility converter and the ■ Addresses all power quality 5 startup is less than 5 minutes. load. The power stage controls analyze problems the harmonic current requirements of ■ Battery systems are not required the load and set the firing angle of Normal Operation Mode or used 6 the inverter IGBTs to make the utility Once the UPS is started and the ■ No battery maintenance required flywheel is operating at greater than converter a very low impedance source ■ 4000 rpm, the UPS is in the normal to any harmonic currents. Thus, Unlimited discharge cycles 7 operating mode where it is regulating nonlinear load currents are supplied ■ 150-second recharge time available output voltage and supplying reactive almost entirely from the utility ■ Wide range of operating tempera- and harmonic currents required by the converter with little effect on the tures can be accommodated 8 load. At the same time it cancels the quality of the UPS output voltage (–20 ° to 40 °C) waveform and with almost no effect of load current harmonics on the ■ Small compact size and less floor transmission of load harmonics UPS output voltage. space required (500 kW systems 9 currents to the input of the UPS. Input current consists of three compo- takes 20 sq ft) nents: real load current, charging Discharge Mode ■ N+1 reliability available up to 10 current, and voltage regulation current. The UPS senses the deviation of 900 kVA maximum Real current is current that is in phase the voltage or frequency beyond ■ No disposal issues with the supply voltage and supplies programmed tolerances and quickly 11 real power to the load. Real current disconnects the supply source by High-Speed Rotary Disadvantages flowing through the line inductor causes turning off the static disconnect switch ■ Flywheel does not have deep a slight phase shift of the current and opening the input contactor. The reserve capacity—rides through 12 lagging the voltage by 10 degrees disconnect occurs in less than one-half for up to 13 seconds at 100% load and ensures that the UPS can quickly cycle. Then the utility converter starts ■ Some enhanced flywheel systems transfer to bypass without causing delivering power from the DC bus to may extend the ride through to 13 unacceptable switching transients. The the load, and the flywheel converter 30 seconds at 100% load second component is charging current changes the firing point of its IGBTs ■ Mechanical flywheel maintenance required by the flywheel to keep the to deliver power to the DC bus. The required every 2–3 years, and oil 14 rotating mass fully charged at rated UPS maintains a clean output voltage changes required every year rpm, or to recharge the rotating mass within 3% or nominal voltage to the ■ after a discharge. The power to main- load when input power is lost. Recharge fast rates require the 15 tain full charge is low at 2 kW and input to be sized for 125% of is accomplished by the IGBTs of the Recharge Mode nominal current flywheel converter gating to provide When input power is restored to ■ Flywheels failures in field not 16 small pulses of motoring current to the acceptable limits, the UPS synchronizes understood flywheel. This current can be much the output and input voltages, closes ■ Requires vacuum pumps for higher if fast recharge times are the input contactor and turns on the high-speed flywheels 17 selected. The final component of input static disconnect switch. The utility ■ Limited number of vendors and current is the voltage regulation current, converter then transfers power from experience which is usually a reactive current that the flywheel to the input source by 18 circulates between the input and the linearly increasing the real input utility converter to regulate the output current. The transfer time is program- voltage. Leading reactive current mable from 1 to 15 seconds. As soon 19

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CA08104001E For more information, visit: www.eaton.com/consultants 1.4-28 Power Distribution Systems Uninterruptible Power Systems (UPS) April 2016 Sheet 01 084

Static UPS Systems 2. The Rectifier/Charger function mode in 150–120 milliseconds. i converts the normal AC power to When the UPS recognizes a Typical Ratings DC power to charge the battery requirement to transfer to the 40–750 kVA/600 kW, and higher when and power the inverter. The load bypass mode, it simultaneously ii multiple units are paralleled. is isolated from the normal turns the static switch ON, the input source. output breaker to OPEN, and the Typical Static UPS Configurations bypass breaker to CLOSE. The 3. The battery stores DC energy 1 Static UPS systems modules are output breaker opens and the for use when input power to the available in three basic types of bypass breaker closes in about UPS fails. The amount of power configurations known as standby, line 50 milliseconds. The restoration available from the DC battery 2 interactive and double conversion. of normal conditions at the UPS system and time to discharge See Ta b 3 3 in this guide for details on results in the automatic restoration voltage is a function of the type of all the UPS configurations available of the UPS module powering the battery selected and the ampere- 3 from Eaton. The lighter power ratings load through the rectifier/charger hour sized used. Battery systems are likely to be one of the first two and inverter with load isolation should be sized for no less than types of configurations, e.g., standby from power quality problems, and 5 minutes of clean power usage 4 or line interactive. Most medium or the opening of the bypass circuit. from a fully charged state, and, in large static UPS installations use the many cases, are sized to provide Static Double Conversion Advantages double conversion technology in one more time on battery power. 5 or multiple module configurations, ■ Addresses all power quality i.e., or multiple UPS units in parallel. 4. The DC link connects the output problems Figure 1.4-19 illustrates the one-line of the rectifier/charger to the input ■ Suitable for applications from 6 diagram of a simple single Double of the inverter and to the battery. 5 kVA to over 2500 kVA Conversion UPS module. Brief Typically the rectifier/charger is ■ Simple battery systems are 7 explanations appear for the standby sized slightly higher than 100% of sized for application and line interactive UPS systems UPS output because it must power ■ Long battery backup times and after the text explaining the Double the inverter and supply charger long life batteries are available Conversion static UPS type of system. power to the battery. 8 ■ Higher reliability is available A. Double conversion concept of 5. The bypass circuit provides a using redundant UPS modules operation—the basic operation of path for unregulated normal 9 the Double Conversion UPS is: power to be routed around the major electronic sub-assemblies 1. Normal power is connected to of the UPS to the load so that the the UPS input through the facility 10 load can continue to operate during electrical distribution system. maintenance, or when the UPS This usually involves two input electronics fails. The bypass static circuits that must come from the 11 switch can switch to conducting same source. 12

Bypass Breaker (Optional) UPS Module 13 Bypass Static Switch 14 Source Load Normal Output Rectifier/Charger Inverter Breaker Breaker 15 AC DC DC AC

16 Battery Breaker

17 Battery

18 Figure 1.4-19. Typical Static UPS, Double Conversion Type with Battery Backup

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For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.4-29 April 2016 Uninterruptible Power Systems (UPS) Sheet 01 085

Static Double Conversion Disadvantages 3. The battery stores DC energy for C. Static line interactive UPS ■ Battery systems, battery maintenance use by the inverter when input concept of operation—the basic i and battery replacement are required power to the UPS fails. The operation of the Line Interactive amount of power available from UPS is: ■ Large space requirement for the DC battery system and time to battery systems (higher life takes ii discharge voltage is a function of 1. The Line Interactive type of UPS more space, e.g., 500 kW takes the type of battery selected and has a different topology than the 80–200 sq ft depending upon the the ampere-hour sized used. static double conversion and 1 type of battery used, VRLA 10 year, Battery systems should be sized standby systems. The normal VRLA 20 year or flooded) for the anticipated outage. input power is connected to the ■ Limited discharge cycles of load in parallel with a battery 2 battery system 4. The DC link connects the output of and bi-directional inverter/charger ■ Narrow temperature range the rectifier/charger to the input of assembly. The input source usu- for application the inverter and to the battery. ally terminates at a line inductor 3 Typically the rectifier/charger and the output of the inductor is ■ Efficiencies are in the 90–94% is sized only to supply charger connected to the load in parallel range, which is lower than some line power to the battery, and is with the battery and inverter/ interactive configurations 4 rated far lower than in the charger circuit. See Figure 1.4-21 ■ Bypass mode places load at risk double conversion UPS. for more details. unless bypass has UPS backup 5 ■ Redundancy of UPS modules 5. The bypass circuit provides a 2. The traditional rectifier circuit results in higher costs direct connection of input source is eliminated and this results to the load. The load operates in a smaller footprint and ■ Output faults are cleared by the from unregulated power. The weight reduction. However, line 6 bypass circuit bypass static switch can switch conditioning is compromised. ■ Output rating of the UPS is 150% to non-conducting mode in 150– for 30 seconds 120 milliseconds. When the UPS 3. When the input power fails, the 7 ■ Battery disposal and safety recognizes the loss of normal battery/inverter charger circuit issues exist input power, it transfers to battery/ reverses power and supplies the inverter mode by simultaneously load with regulated power. 8 B. Standby UPS concept of turning the Inverter ON and the operation—The basic operation of Static Line Interactive UPS Advantages static switch OFF. the Standby UPS is: ■ Slight improvement of power 9 Static Standby UPS Advantages conditioning over standby 1. The Standby UPS topology is UPS systems similar to the double conversion ■ Lower costs than double conversion ■ 10 type, but the operation of the UPS ■ Rectifier and charger are Small footprints and weights is different in significant ways. economically sized ■ Efficient design Normal power is connected to ■ Efficient design ■ Batteries are sized for the 11 the UPS input through the facility ■ Batteries are sized for the application electrical distribution system. application This usually involves two input Static Line Interactive UPS Disadvantages 12 circuits that must come from the Static Standby UPS Disadvantages ■ Impractical over 5 kVA same source. See Figure 1.4-20 ■ Impractical over 2 kVA ■ Not as good conditioning as for details. ■ Little to no isolation of load from double conversion 13 2. The rectifier/charger function power quality disturbances ■ Standby power is from battery alone converts the normal AC power to ■ Standby power is from battery alone ■ Battery systems, battery mainte- 14 DC power to charge the battery ■ Battery systems, battery mainte- nance and battery replacement only, and does not simultaneously nance and battery replacement are required power the inverter. The load is are required ■ Limited discharge cycles for the connected to the input source 15 ■ Limited discharge cycles of battery system through the bypass static switch. battery system ■ Narrow temperature range for The inverter is in the standby application mode ready to serve the load ■ Narrow temperature range for 16 ■ Battery disposal and safety from battery power if the input application issues exist power source fails. ■ Output faults are cleared by the bypass circuit 17 ■ Battery disposal and safety issues exist 18

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CA08104001E For more information, visit: www.eaton.com/consultants 1.4-30 Power Distribution Systems Uninterruptible Power Systems (UPS) April 2016 Sheet 01 086

i UPS Module ii Bypass Static Switch

1

2 Source Load Rectifier/ Normal Charger Inverter Output 3 Breaker Breaker AC DC

4 DC AC Battery 5 Breaker

6 Battery

7 Figure 1.4-20. Typical Static UPS, Standby Type with Battery Backup 8 UPS Module 9

10 Source Load Inductor 11

Bidirectional 12 Inverter/Charger DC 13 AC 14

15 Battery

16 Figure 1.4-21. Typical Static UPS, Line Interactive Type with Battery Backup 17

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For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.4-31 April 2016 System Application Considerations Sheet 01 087 Other Application Considerations

Secondary Voltage Selection Technical Factors supplied from a 480 V system through The principal advantage of the use of step-down transformers, voltage drop i The choice between 208Y/120 V and in the 480 V supply conductors can be 480Y/277 V secondary distribution for higher secondary voltages in buildings is that for a given load, less current compensated for by the tap adjust- commercial and institutional buildings ments on the transformer, resulting ii depends on several factors. The most means smaller conductors and lower voltage drop. Also, a given conductor in full 120 V output. Because these important of these are size and types transformers are usually located close of loads (motors, fluorescent lighting, size can supply a large load at the same voltage drop in volts, but a lower to the 120 V loads, secondary voltage 1 incandescent lighting, receptacles) drop should not be a problem. If it is, and length of feeders. In general, large percentage voltage drop because of the higher supply voltage. Fewer or taps may be used to compensate by motor and fluorescent lighting loads, raising the voltage at the transformer. 2 and long feeders, will tend to make the smaller circuits can be used to transmit higher voltages, such as 480Y/277 V, the power from the service entrance The interrupting ratings of circuit more economical. Very large loads point to the final distribution points. breakers and fuses at 480 V have 3 and long runs would indicate the use Smaller conductors can be used in many increased considerably in recent years, of medium voltage distribution and branch circuits supplying power loads, and protective devices are now available loadcenter unit substations close to and a reduction in the number of light- for any required fault duty at 480 V. 4 the loads. Conversely, small loads, ing branch circuits is usually possible. In addition, many of these protective short runs and a high percentage of It is easier to keep voltage drops within devices are current limiting, and can incandescent lighting would favor acceptable limits on 480 V circuits than be used to protect downstream equip- 5 lower utilization voltages such as on 208 V circuits. When 120 V loads are ment against these high fault currents. 208Y/120 V. Industrial installations, with large 6 motor loads, are almost always 480 V, often ungrounded delta or resistance 7 grounded delta or wye systems (see Elevator section on ground fault protection). Panel Practical Factors Typical 8 Because most low voltage distribution equipment available is rated for up to Typical Emergency HVAC Lighting Panel 9 600 V, and conductors are insulated for Panel (Typical Every 600 V, the installation of 480 V systems Third Floor) uses the same techniques and is 10 essentially no more difficult, costly, or 480Y/277 V 208Y/120 V Typical hazardous than for 208 V systems. The Panel Panel major difference is that an arc of 120 V Dry Type Transformer 480Δ-208Y/120 V 11 to ground tends to be se lf-extinguish- (Typical Every Floor) ing, while an arc of 277 V to ground HVAC Busway Emergency Elevator tends to be self-sustaining and likely to Feeder Riser Lighting Riser cause severe damage. For this reason, Riser 12 the National Electrical Code requires ground fault protection of equipment Building and Typical Typical on grounded wye services of more Miscellaneous 13 Loads than 150 V to ground, but not exceeding Typical 600 V phase-to-phase (for practical purpose, 480Y/277 V services), for any 14 Typical Typical service disconnecting means rated Spare 1000 A or more. The National Electrical 15 Code permits voltage up to 300 V 1111 1 11 to ground on circuits supplying permanently installed electric discharge Automatic 4000 A 16 lamp fixtures, provided the luminaires 1 Transfer Switch Main CB do not have an integral manual switch Gen. CB and are mounted at least 8 ft (2.4 m) Utility Emergency CTs Metering or Standby 17 above the floor. This permits a three- PTs Generator phase, four-wire, solidly grounded Utility 4000A at 480Y/277V 480Y/277 V system to supply directly all Service 100,000A Available Fault Current 18 of the fluorescent and high-intensity discharge (HID) lighting in a building at Figure 1.4-22. Typical Power Distribution and Riser Diagram for a Commercial Office Building 1 277 V, as well as motors at 480 V. Include ground fault trip. 19

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CA08104001E For more information, visit: www.eaton.com/consultants 1.4-32 Power Distribution Systems System Application Considerations April 2016 Sheet 01 088 Other Application Considerations

Economic Factors Motors and controls are another cause NEMA standard TP-1 is being adopted i Utilization equipment suitable for of wasted energy that can be reduced. by many states and is another method principal loads in most buildings New, energy-efficient motor designs of energy-efficient design. NEMA TP-1 is available for either 480 V or 208 V are available using more and better establishes minimum operating ii systems. Three-phase motors and core steel, and larger windings. efficiencies for each distribution their controls can be obtained for either transformer size at a loading equal to For any motor operating 10 or more 35% of the transformer full load kVA. voltage, and for a given horsepower hours per day, it is recommended to 1 are less costly at 480 V. Fluorescent and The 35% loading value in the NEMA use the energy-efficient types. These standard reflects field studies con- HID lamps can be used with either 277 V motors have a premium cost of about or 120 V ballasts. However, in almost all ducted by the U.S. Department of 2 20% more than standard motors. Energy, which showed that dry-type cases, the installed equipment will have Depending on loading, hours of use a lower total cost at the higher voltage. transformers installed in commercial and the cost of energy, the additional facilities are typically loaded at an 3 Energy Conservation initial cost could be repaid in energy average of 35% of their full load saved within a few months, and it capacity over a 24-hour time period. Because of the greatly increased cost rarely takes more than two years. Table 1.4-9 compares losses for 4 of electrical power, designers must Because, over the life of a motor, the both low temperature rise and TP-1 consider the efficiency of electrical cost of energy to operate it is many transformers using a 75 kVA design. distribution systems, and design for times the cost of the motor itself, any 5 energy conservation. In the past, motor with many hours of use should Table 1.4-9. Load Losses especially in commercial buildings, be of the energy-efficient type. Te m p . Load Losses in Watts design was for lowest first cost, Rise ºC Where a motor drives a load with No 25% 35% 50% 75% Full 6 because energy was inexpensive. Loss Load Load Load Load Load Today, even in the speculative office variable output requirements such building, operating costs are so high as a centrifugal pump or a large fan, 150 360 490 620 885 1535 2450 7 that energy-conserving designs can customary practice has been to run the 115 420 480 610 805 1170 1950 justify their higher initial cost with a motor at constant speed, and to throttle 80 500 535 615 730 945 1410 rapid payback and continuing savings. the pump output or use inlet vanes or TP-1 150 230 310 480 745 1235 2280 8 Buildings that must meet LEED certifi- outlet dampers on the fan. This is highly cations may require energy-saving inefficient and wasteful of energy. In Efficiencies above TP-1. Candidates designs. There are four major sources recent years, solid-state variable- Standard Level (CSL) is a DOE 9 of energy conservation in a commercial frequency, variable-speed drives for efficiency evaluation for transformers. building—the lighting system, the ordinary induction motors have been CSL-1 is equivalent to TP-1. Levels motors and controls, the transformers available, reliable and relatively a r e f r o m C S L- 1 t o C S L- 5 . C S L- 3 i s b e i n g 10 and the HVAC system. inexpensive. Using a variable-speed promoted for higher efficiency applica- drive, the throttling valves, inlet vanes tions. A NEMA white paper Clarifica- The lighting system must take or output dampers can be eliminated, tions on the Use of DOE Design—Lines 11 advantage of the newest equipment saving their initial cost and energy 6, 7 and 8 is available from NEMA that and techniques. New light sources, over the life of the system. An elaborates on familiar light sources with higher additional benefit of both energy- the matter. 12 efficiencies, solid-state ballasts with efficient motors and variable-speed dimming controls, use of daylight, drives (when operated at less than HVAC systems have traditionally been environmental design, efficient full speed) is that the motors operate very wasteful of energy, often being 13 luminaires, computerized or at reduced temperatures, resulting in designed for lowest first cost. This, programmed control, and the like, increased motor life. too, is changing. For example, reheat are some of the methods that can systems are being replaced by variable 14 increase the efficiency of lighting Transformers have inherent losses. air volume systems, resulting in equal systems. They add up to providing Transformers, like motors, are designed comfort with substantial increases in the necessary amount of light, with the for lower losses by using more and efficiency. While the electrical engineer 15 desired color rendition, from the most better core materials, larger conductors, has little influence on the design of the efficient sources, where and when it is etc., and this results in increased initial HVAC system, he/she can specify that needed, and not providing light where cost. Because the 480 V to 208Y/120 V all motors with continuous or long duty 16 or when it is not necessary. Using the stepdown transformers in an office cycles are specified as energy-efficient best of techniques, office spaces that building are usually energized 24 hours types, and that the variable-air-volume originally required as much as 3.5W a day, savings from lower losses can fans do not use inlet vanes or outlet 17 per square foot have been given be substantial, and should be consid- dampers, but are driven by variable- improved lighting, with less glare ered in all transformer specifications. speed drives. Variable-speed drives and higher visual comfort, using as One method of obtaining reduced can often be desirable on centrifugal 18 little as 1.0 to 2.0W per square foot. losses is to specify transformers with compressor units as well. Since some In an office building of 200,000 square 220 °C insulation systems designed for of these requirements will be in HVAC feet (60,960 m), this could mean a 150 °C average winding temperature specifications, it is important for the 19 saving of 400 kW, which, at $0.05 per rise, with no more than 80 °C (or energy-conscious electrical engineer kWh, 250 days per year, 10 hours per sometimes 115 °C) average winding to work closely with the HVAC engineer day, could save $50,000 per year in temperature rise at full load. A better at the design stage. 20 energy costs. Obviously, efficient method would be to evaluate transformer lighting is a necessity. losses, based on actual loading cycles throughout the day, and consider the cost of losses as well as the initial cost 21 of the transformers in purchasing.

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.4-33 April 2016 System Application Considerations Sheet 01 089 Other Application Considerations

Building Control Systems Because building design and control This has been changed by the high for maximum energy saving is impor- cost of purchased energy, plus a i In order to obtain the maximum benefit tant and complex, and frequently federal law (Public Utility Regulatory from these energy-saving lighting, involves many functions and several Policies Act, known as PURPA) that power and HVAC systems, they must systems, it is necessary for the design requires public utilities to purchase ii be controlled to perform their functions engineer to make a thorough building any excess power generated by the most efficiently. Constant monitoring and environmental study, and to weigh cogeneration plant. In many cases, would be required for manual operation, the costs and advantages of many practical commercial cogeneration 1 so some form of automatic control systems. The result of good design systems have been built that provide is required. The simplest of these can be economical, efficient operation. some or all of the electric power energy-saving controls, often very Poor design can be wasteful and required, plus hot water, steam, and 2 effective, is a time clock to turn various extremely costly. sometimes steam absorption-type systems on and off. Where flexible air conditioning. Such cogeneration control is required, programmable Distributed Energy Resources systems are now operating success- 3 controllers may be used. These range fully in hospitals, shopping centers, from simple devices, similar to multi- Distributed energy resources (DER) are increasingly becoming prominent high-rise apartment buildings and function time clocks, up to full micro- even commercial office buildings. 4 processor-based, fully programmable sources of electric power. Distributed devices, really small computers. For energy resources are usually small-to- Where a cogeneration system is being complete control of all building systems, medium sources of electric generation, considered, the electrical distribution 5 computers with specialized software either from renewable or non-renew- system becomes more complex. The can be used. Computers can not only able sources. Sources include: interface with the utility company is control lighting and HVAC systems, ■ Photovoltaic (PV) systems critical, requiring careful relaying 6 and provide peak demand control, to (solar systems) to protect both the utility and the minimize the cost of energy, but they cogeneration system. Many utilities ■ can perform many other functions. Fire Wind have stringent requirements that 7 detection and alarm systems can oper- ■ Fossil-fueled (diesel, natural gas, must be incorporated into the system. ate through the computer, which can landfill gas, coal-bed methane) Proper generator control and protec- also perform auxiliary functions such generators (reciprocating engines) tion is necessary, as well. An on-site 8 as elevator control and building com- ■ Gas-fired turbines (natural gas, land- electrical generating plant tied to an munication in case of fire. Building fill gas, coal-bed methane) electrical utility, is a sophisticated security systems, such as closed-circuit ■ Water-powered (hydro) engineering design. 9 television monitoring, door alarms and ■ Fuel cells intruder sensing, can be performed by Utilities require that when the the same building computer system. ■ Microturbines protective device at their substation 10 ■ Wave power opens that the device connecting a The time clocks, programmable cogenerator to the utility open also. ■ Coal-fired boilers controllers and computers can One reason is that most cogenerators 11 obtain data from external sensors Distributed energy resources may also are connected to feeders serving other and control the lighting, motors and be termed alternative energy resources. other equipment by means of hard customers. Utilities desire to reclose 12 wiring-separate wires to and from Prime Power the feeder after a transient fault is each piece of equipment. In the more DER can be used for generating prime cleared. Reclosing in most cases will complex systems, this would result in power or for cogeneration. Prime power damage the cogenerator if it had 13 a tremendous number of control concerns a system that is electrically remained connected to their system. wires, so other methods are frequently separated from the electrical grid. Islanding is another reason why the used. A single pair of wires, with elec- Prime power is generated at remote utility insists on the disconnection of 14 tronic digital multiplexing, can control sites where commercial electrical the cogenerator. Islanding is the event or obtain data from many different power is not available. that after a fault in the utility’s system points. Sometimes, coaxial cable is is cleared by the operation of the 15 used with advanced signaling equip- Cogeneration protective devices, a part of the ment. Some systems dispense with Cogeneration is another outgrowth of system may continue to be supplied control wiring completely, sending and the high cost of energy. Cogeneration by cogeneration. Such a condition is 16 receiving digital signals over the is the production of electric power con- dangerous to the utility’s operation power wiring. The newest systems currently with the production of steam, during restoration work. may use fiber-optic cables to carry hot water and similar energy uses. The 17 tremendous quantities of data, free Major cogenerators are connected to electric power can be the main prod- from electromagnetic interference. the subtransmission or the transmission uct, and steam or hot water the The method used will depend on system of a utility. Major cogenerators byproduct, as in most commercial 18 the type, number and complexity have buy-sell agreements. In such installations, or the steam or hot water of functions to be performed. cases, utilities use a trip transfer can be the most required product, scheme to trip the cogenerator breaker. and electric power a byproduct, as 19 in many industrial installations. In Guidelines that are given in ANSI some industries, cogeneration has Guide Standard 1001 are a good been common practice for many starting point, but the entire design 20 years, but until recently it has not should be coordinated with the utility. been economically feasible for most commercial installations. 21

CA08104001E For more information, visit: www.eaton.com/consultants 1.4-34 Power Distribution Systems System Application Considerations April 2016 Sheet 01 090 Other Application Considerations

PV System Design Considerations The S-Max follows standard industry High Temperature Equation i and code practices in determining the Successful photovoltaic (PV) design Once the maximum number of maximum number of solar modules modules per string is established, and construction is a complex multi- per string for the open-circuit photo- discipline endeavor. Proper planning the minimum number of modules per ii voltaic (PV) voltage rise in cold includes the site-layout study for string needs to be calculated. Here, weather (Voc < 600 V as per NEC). Its more site-related aspects come into maximizing the sun’s energy harvest- low 300 V MPPT lower-limit ensures ing for solar module selection, and play, as the voltage of solar modules 1 that multiple configurations are for updating the electrical/mechanical decreases with increasing tempera- possible for solar systems hot weather ture. The modules’ (photovoltaic cell) design and construction to the latest voltage drop (i.e., Vmp as a function code and local constraints, including temperature is influenced by the 2 of temperature, solar irradiance and fire marshal and seismic regulations. ambient temperature, reflected sun- array-conductor voltage drop). The loads from nearby structures, parapet Professionally prepared bid, permit, following equations are the basis of construction and as-build drawings walls, roof-coatings, etc. Air-flow 3 all solar system layout and design. shall be required and maintained. above and behind the solar modules Consult professional engineering to affect the cell temperature. The For installation in/on/for existing help when planning any solar system. structures and sites, it is advised accepted industry standards to add 4 Engineering design firms offering that, at the minimum, pre-design to the module heating is listed below. complete solar systems “turn-key” Unusual mounting systems may and construction tests be performed calculations, drawings, construction for existing power-quality issues, adjust these figures, and it is best to 5 management and procurement are water drainage and the utility feeder/ seek assistance in establishing and a good place to start. Eaton offers planning such installations. transformer, and that electrical professional S-Max inverter applica- distribution panel ratings are verified 6 tion assistance, on-site commissioning ■ 20 °C for ground or pole mounted sufficient for the planned solar system, and maintenance services. Eaton solar systems and the necessary arc flash studies be maintains a working relationship with ■ 25 °C for roof-top solar systems performed. Connection to the utility 7 the best engineering services firms mounted at inclined angles is always a utility interconnect agree- across the country, and helps arrange (offers improved air-flow behind ment (application) process, and is the successful implantation of your the modules) typically required for the available 8 solar system. The S-Max 250 kW solar incentives and programs offered ■ 30 °C for roof-top solar systems inverter and up-fit solutions easily mounted flat, yet at least 6.00 inches by the utility, municipality, state, and perform well in Mega-Watt and Utility- various federal agencies and depart- (152.4 mm) above the roof surface 9 Scale systems. Eaton also offers a ments. State, and IRS tax incentives wide range of balance-of-system Vmp_min = Vmp + (temp-differential x require well-documented records. (BOS) products, ranging from solar temp-coefficient-of-Vmp) 10 module source and array combiners, Solar systems, while low maintenance, The temp-differential in this case to DC and AC breakers, electrical and do require periodic service. The solar includes the above temperature distribution panels and switchgear. 11 modules need to be washed-clean on “adders.” The Vmp and related a regular basis and electrical termina- Low Temperature Equation temperature coefficients are listed tions require initial and annual checks. on the solar module’s data sheets. 12 Cooling system filters are periodic Voc_max = Voc + (temp-differential x maintenance items, with the re-fresh temp-coefficient-of-Voc) While the code doesn’t indicate the rate dependent upon typical and The temp-differential is the difference high temperature to use (i.e., because 13 unusual circumstances. between the standard module rating it is an equipment application issue), at 25 °C and the low temperature. the industry standard is to evaluate the Solar systems installed near other new ASHRAE 2% and 4% high temperature construction where dust is generated The voltage (Voc) will rise with 14 temperatures under 25 °C. figures, coupled to known location (e.g., grading, paving) or agricultural differences. Record high temperatures environments may require additional Seek the solar module data sheet for provide an indication of system 15 solar-system checks and services. a list of standard test condition (STC) performance when climatic condition Planning for such contingencies is data, temperature coefficients, and any reaches these levels. the business of solar-system design, special module-related information to 16 construction and on-going operation. determine the low-temperature open Beyond the damaging temperature Performance-based incentives circuit voltage. The NEC 2011, and affects on photovoltaic module Vmp require verifiable metering, often industry practice, requires the voltage levels, voltage drop in PV 17 by registered/approved independent use of the site’s Extreme Annual conductors under such conditions also third parties. Such monitoring periods Mean Minimum Design Dry Bulb need to be calculated and evaluated, are typically for 60 or more months. Temperature data, available in the beyond normal temperatures. The inverter only uses (knows) the Vmp 18 The S-Max inverter offers a wide range ASHRAE Handbook. Code requires that the resulting maximum voltage voltage at the inverter, not at the of features and options to enable a PV modules. successful and long-lived solar-energy (Voc) when added in the “string of 19 harvesting solution. The isolation modules” be under 600 V. Record Increasing grid voltages also puts a step-up transformer, coupled to either low temperatures provide an constraint on the minimum Vmp a negative or a positive grounded indication of system performance voltage at the DC input stage. 20 solar array, ensures that the S-Max when temperatures drop to these can match to all (known) solar module levels. The S-Max inverter is designed technologies. to standards higher than 600 Vdc. 21

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.4-35 April 2016 System Application Considerations Sheet 01 091 Other Application Considerations

To ensure the full MPPT range without governmental agency having jurisdic- a charger to keep it at full capacity power-clipping (reduced power output), tion. Optional standby systems, not when normal power is on, one or more i prudent PV system designs shall con- legally required, are also covered in lamps, and a relay to connect the sider the PV array’s Vmp voltage drop the NEC (Article 702). battery to the lamps on loss of normal to the point of the inverter connection, power, is also permitted. Because ii ambient temperatures and the PV Emergency systems are intended to of the critical nature of emergency system installation type’s effects on supply power and illumination essen- power, ground fault protection is not Vmp, solar module miss-match and tial for safety to human life, when the required. It is considered preferable 1 tolerance variations, degradation of normal supply fails. NEC requirements to risk arcing damage, rather than to solar modules over time (solar system are stringent, requiring periodic testing disconnect he emergency supply com- life), etc. Typical Vmp design values, under load and automatic transfer to pletely. For emergency power, ground 2 based upon known and expected emergency power supply on loss of fault alarm is required by NEC 700.7(D) conditions are 5–10% over the normal supply. See Figure 1.4-23. to indicate a ground fault in solidly minimum MPPT tracking voltage. All wiring from emergency source to grounded wye emergency systems 3 Reference NEC 2011 Section 690, emergency loads must be kept separate of more than 150 V to ground and Solar Photovoltaic Systems. from all other wiring and equipment, circuit-protective devices rated 1000 A in its own distribution and raceway or more. 4 Emergency Power system, except in transfer equipment enclosures and similar locations. The Legally required standby systems, as Most areas have requirements most common power source for large required by the governmental agency 5 for emergency and standby power emergency loads is an engine-generator having jurisdiction, are intended to systems. The National Electrical Code set, but the NEC also permits the supply power to selected loads, other does not specifically call for any emergency supply (subject to local code than those classed as emergency 6 emergency or standby power, but requirements) to be storage batteries, systems, on loss of normal power. does have requirements for those uninterruptible power supplies, a These are usually loads not essential systems when they are legally separate emergency service, or a to human safety, but loss of which 7 mandated and classed as emergency connection to the service ahead of the could create hazards or hamper (Article 700), legally required standby normal service disconnecting means. rescue or fire-fighting operations. (Article 701) by municipal, state, Unit equipment for emergency illumi- 8 federal or other codes, or by any nation, with a rechargeable battery, 9 Utility Source Typical Application: Three engine generator sets serve the load, plus one additional engine generator set for redundancy to achieve N+1 level of performance. Open or Closed transition is available. 10

G1 G2 G3 G4 Paralleling Switchgear 11 with Distribution Revenue Metering HMI 12 Touchscreen 52G1 52G2 52G3 52G4 13 Main D1 D2 D3 D4 Service 14

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ATS1 N ENENENEATS2 ATS3 ATS4 To Normal To Emergency Distribution Circuits 17 Circuits

EDP1 EDP2 EDP3 EDP4 18

Optional Remote PC 19 with Software LP1 BP1 LP2 BP2 LP3 BP3 LP4 BP4 20 Figure 1.4-23. Typical Emergency Power System 21

CA08104001E For more information, visit: www.eaton.com/consultants 1.4-36 Power Distribution Systems System Application Considerations April 2016 Sheet 01 092 Other Application Considerations

NEC requirements are similar to those Industrial plants, especially in process It is important that the electrical sys- i for emergency systems, except that industries, usually have some form tem designer providing a substantial wiring may occupy the same distribu- of alternate power source to prevent source of emergency and standby tion and raceway system as the extremely costly shutdowns. These power investigate the possibility of ii normal wiring if desired. Optional standby generating systems are using it for peak shaving, and even standby systems are those not legally critical when needed, but they are of partial utility company financing. required, and are intended to protect needed only infrequently. They Frequently, substantial savings in 1 private business or property where represent a large capital investment. power costs can be realized for a life safety does not depend on To be sure that their power will be small additional outlay in distribution performance of the system. Optional available when required, they should and control equipment. 2 systems can be treated as part of the be tested periodically under load. normal building wiring system. Both Peak shaving equipment operating in legally required and optional standby The cost of electric energy has risen parallel with the utility are subject to the 3 systems should be installed in such to new high levels in recent years, and comments made under cogeneration a manner that they will be fully avail- utilities bill on the basis not only of as to separation from the utility under able on loss of normal power. It is power consumed, but also on the fault conditions. 4 preferable to isolate these systems basis of peak demand over a small as much as possible, even though not interval. As a result, a new use for Sound Levels required by code. in-house generating capacity has 5 developed. Utilities measure demand Sound Levels of Electrical Equipment Where the emergency or standby charges on the basis of the maximum for Offices, Hospitals, Schools and source, such as an engine generator demand for electricity in any given Similar Buildings 6 or separate service, has capacity to specific period (typically 15 or 30 Insurance underwriters and building supply the entire system, the transfer minutes) during the month. Some owners desire and require that the scheme can be either a full-capacity utilities have a demand “ratchet clause” electrical apparatus be installed 7 automatic transfer switch, or, less that will continue demand charges on for maximum safety and the least costly but equally effective, normal a given peak demand for a full year, interference with the normal use of and emergency main circuit breakers, unless a higher peak results in even the property. Architects should take 8 electrically interlocked such that on higher charges. One large load, coming particular care with the designs for failure of the normal supply the on at a peak time, can create higher hospitals, schools and similar build- emergency supply is connected to the electric demand charges for a year. ings to keep the sound perception of 9 load. However, if the emergency or Obviously, reducing the peak demand such equipment as motors, blowers standby source does not have capacity and transformers to a minimum. for the full load, as is usually the can result in considerable savings in 10 case, such a scheme would require the cost of electrical energy. For those Even though transformers are automatic disconnection of the installations with engine generators relatively quiet, resonant conditions nonessential loads before transfer. for emergency use, modern control may exist near the equipment, which 11 Simpler and more economical in systems (computers or programmable will amplify their normal 120 Hz hum. such a case is a separate emergency controllers) can monitor the peak Therefore, it is important that consid- bus, supplied through an automatic demand, and start the engine-generator eration be given to the reduction of 12 transfer switch, to feed all critical to supply part of the demand as it amplitude and to the absorption of loads. The transfer switch connects approaches a preset peak value. The energy at this frequency. This problem this bus to the normal supply, in engine-generator must be selected begins in the designing stages of the 13 normal operation. On failure of the to withstand the required duty cycle. equipment and the building. There are normal supply, the engine-generator The simplest of these schemes transfer two points worthy of consideration: 1) is started, and when it is up to speed specific loads to the generator. More What sound levels are desired in the 14 the automatic switch transfers the complex schemes operate the generator normally occupied rooms of this build- emergency loads to this source. On in parallel with the normal utility supply. ing? 2) To effect this, what sound level return of the normal source, manual or The savings in demand charges can in the equipment room and what type 15 automatic retransfer of the emergency reduce the cost of owning the emer- of associated acoustical treatment loads can take place. gency generator equipment. will give the most economical installation overall? 16 In some instances, utilities with little Peak Shaving reserve capacity have helped finance A relatively high sound level in the Many installations now have the cost of some larger customer- equipment room does not indicate 17 emergency or standby generators. owned generating equipment. In an abnormal condition within the In the past, they were required for return, the customer agrees to take apparatus. However, absorption may hospitals and similar locations, but some or all of his load off the utility be necessary if sound originating in 18 not common in office buildings or system and on to his own generator at an unoccupied equipment room is shopping centers. However, many the request of the utility (with varying objectionable outside the room. costly and unfortunate experiences limitations) when the utility load Furthermore, added absorption 19 during utility blackouts in recent years approaches capacity. In some cases, material usually is desirable if have led to the more frequent installa- the customer’s generator is paralleled there is a “build-up” of sound tion of engine generators in commer- with the utility to help supply the peak due to reflections. 20 cial and institutional systems for safety utility loads, with the utility buying and for supplying important loads. the supplied power. Some utilities have been able to delay large capital expenditures for additional generating 21 capacity by such arrangements.

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.4-37 April 2016 System Application Considerations Sheet 01 093 Other Application Considerations

Some reduction or attenuation takes Table 1.4-11. Maximum Average Sound Levels for Medium Voltage Transformers—Decibels place through building walls, the kVA Liquid-Filled Transformers Dry-Type Transformers i remainder may be reflected in various Self-Cooled Forced-Air Self-Cooled Forced-Air directions, resulting in a build-up or Rating (OA) Cooled Rating (FA) Rating (AA) Cooled Rating (FA) apparent higher levels, especially if ii resonance occurs because of room 300 55 — 58 67 dimensions or material characteristics. 500 56 — 60 67 750 57 67 64 67 1 Area Consideration 1000 58 67 64 67 In determining permissible sound lev- 1500 60 67 65 68 2000 61 67 66 69 els within a building, it is necessary to 2 consider how the rooms are to be used 2500 62 67 68 71 3000 63 67 68 71 and what levels may be objectionable 3750 64 67 70 73 to occupants of the building. The 3 5000 65 67 71 73 ambient sound level values given in 6000 66 68 72 74 Table 1.4-10 are representative average 7500 67 69 73 75 values and may be used as a guide in 10,000 68 70 — 76 4 determining suitable building levels. Decrease in sound level varies at an Because values given in Table 1.4-11 transmitted vibration is approximately 5 approximate rate of 6 dB for each are in general higher than those given 98%. If the floor or beams beneath doubling of the distance from the in Table 1.4-10, the difference must be the transformer are light and flexible, source of sound to the listener. For attenuated by distance and by proper the isolator must be softer or have 6 example, if the level 6 ft (1.8 m) from use of materials in the design of the improved characteristics in order to a transformer is 50 dB, the level at a building. An observer may believe keep the transmitted vibrations to a distance of 12 ft (3.7 m) would be 44 dB that a transformer is noisy because minimum. (Enclosure covers and 7 and at 24 ft (7.3 m) the level decreases the level in the room where it is ventilating louvers are often improp- to 38 dB, etc. However, this rule applies located is high. Two transformers of erly tightened or gasketed and only to equipment in large areas the same sound output in the same produce unnecessary noise.) The 8 equivalent to an out-of-door installation, room increase the sound level in the building structure will assist the with no nearby reflecting surfaces. room approximately 3 dB, and three dampeners if the transformer is transformers by about 5 dB, etc. mounted above heavy floor members Table 1.4-10. Typical Sound Levels or if mounted on a heavy floor slab. 9 Sounds due to structure-transmitted Positioning of the transformer in Description Average vibrations originating from the trans- Decibel relation to walls and other reflecting Level (dB) former are lowered by mounting the surfaces has a great effect on reflected 10 transformers on vibration dampeners noise and resonances. Often, placing Radio, recording and TV studios 25–30 or isolators. There are a number of the transformer at an angle to the wall, Theatres and music rooms 30–35 different sound vibration isolating 11 Hospitals, auditoriums and churches 35–40 rather than parallel to it, will reduce materials that may be used with noise. Electrical connections to a Classrooms and lecture rooms 35–40 good results. Dry-type power trans- substation transformer should Apartments and hotels 35–45 formers are often built with an isolator 12 Private offices and conference rooms 40–45 be made with flexible braid or mounted between the transformer conductors; connections to an Stores 45–55 support and case members. The Residence (radio, TV off) individually mounted transformer and small offices 53 natural period of the core and coil should be in flexible conduit. 13 Medium office (3 to 10 desks) 58 structure when mounted on vibration Residence (radio, TV on) 60 dampeners is about 10% of the funda- Large store (5 or more clerks) 61 mental frequency. The reduction in the 14 Factory office 61 Large office 64 Average factory 70 15 Average street 80

Transformer Sound Levels 16 Transformers emit a continuous 120 Hz hum with harmonics when connected to 60 Hz circuits. The 17 fundamental frequency is the “hum” that annoys people primarily because of its continuous nature. For purposes 18 of reference, sound measuring instruments convert the different frequencies to 1000 Hz and a 40 dB 19 level. Transformer sound levels based on NEMA publication TR-1 are listed in Table 1.4-11. 20 21

CA08104001E For more information, visit: www.eaton.com/consultants 1.4-38 Power Distribution Systems April 2016 Sheet 01 094

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For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.5-1 April 2016 Reference Data Sheet 01 095 IEEE Protective Relay Numbers

Table 1.5-1. Selected IEEE Device Numbers for Switchgear Apparatus Device Function Definition Typical i Number Uses 2 Time-delay starting or closing relay A device that functions to give a desired amount Used for providing a time-delay for ii of time delay before or after any point of operation re-transfer back to the normal source in a switching sequence or protective relay system, in an automatic transfer scheme. except as specifically provided by device functions 48, 62 and 79 described later. 1 6 Starting circuit breaker A device whose principal function is to connect — a machine to its source of starting voltage. 19 Starting to running transition timer A device that operates to initiate or cause the Used to transfer a reduced voltage 2 automatic transfer of a machine from the starting starter from starting to running. to the running power connection. 21 Distance relay A device that functions when the circuit — 3 admittance, impedance or reactance increases or decreases beyond predetermined limits. 23 Temperature control device A device that functions to raise or to lower the Used as a thermostat to control 4 temperature of a machine or other apparatus, or space heaters in outdoor equipment. of any medium, when its temperature falls below or rises above, a predetermined level. 5 24 Volts per hertz relay A device that operates when the ratio of voltage — to frequency is above a preset value or is below a different preset value. The relay may have any combination of instantaneous or time delayed 6 characteristics. 25 Synchronizing or synchronism check device A device that operates when two AC circuits are In a closed transition breaker within the desired limits of frequency, phase angle transfer, a 25 relay is used to ensure 7 or voltage, to permit or cause the paralleling of two-sources are synchronized before these two circuits. paralleling. Eaton FP-5000/EDR-5000 feeder protective relays. 8 27 Undervoltage relay A device which functions on a given value of Used to initiate an automatic transfer undervoltage. when a primary source of power is lost. Eaton FP-5000/FP-4000/MP-4000/ 9 EDR-5000/EDR-4000 protective relays. 30 Annunciator relay A non-automatically reset device that gives a Used to remotely indicate that a number of separate visual indications upon the protective relay has functioned, or functioning of protective devices, and which may that a circuit breaker has tripped. 10 also be arranged to perform a lockout function. Typically, a mechanical “drop” type annunciator panel is used. 32 Directional power relay A relay that functions on a desired value of power Used to prevent reverse power from 11 flow in a given direction, or upon reverse power feeding an upstream fault. Often resulting from arc back in the anode or cathode used when primary backup generation circuits of a power rectifier. is used in a facility. Eaton FP-5000/ 12 EDR-5000 protective relays. 33 Position switch A device that makes or breaks contact when the Used to indicate the position of a main device or piece of apparatus, which has no drawout circuit breaker (TOC switch). 13 device function number, reaches a given point. 34 Master sequence device A device such as a motor-operated multi-contact — switch, or the equivalent, or a programmable device, that establishes or determines the operating 14 sequence of the major devices in equipment during starting and stopping, or during sequential switching operations. 15 37 Undercurrent or underpower relay A relay that functions when the current or power Eaton MP-3000/MP-4000/EMR-3000 flow decreases below a predetermined value. motor protective relays. 38 Bearing protective device A device that functions on excessive bearing Eaton MP-3000/MP-4000 motor 16 temperature, or on other abnormal mechanical protective relays. conditions, such as undue wear, which may eventually result in excessive bearing temperature. 17 40 Field relay A device that functions on a given or abnormally — high or low value or failure of machine field current, or on an excessive value of the reactive component of armature current in an AC machine indicating 18 abnormally high or low field excitation. 41 Field circuit breaker A device that functions to apply, or to remove, — the field excitation of a machine. 19 42 Running circuit breaker A device whose function is to connect a machine — to its source of running or operating voltage. This function may also be used for a device, such 20 as a contactor, that is used in series with a circuit breaker or other fault-protecting means, primarily for frequent opening and closing of the circuit. 21

CA08104001E For more information, visit: www.eaton.com/consultants 1.5-2 Power Distribution Systems Reference Data April 2016 Sheet 01 096 IEEE Protective Relay Numbers

Table 1.5-1. Selected IEEE Device Numbers for Switchgear Apparatus (Continued) i Device Function Definition Typical Number Uses ii 43 Manual transfer or selector device A manually operated device that transfers control — or potential circuits in order to modify the plan of operation of the associated equipment or of some of the associated devices. 1 44 Unit sequence starting relay A device that functions to start the next available — unit in multiple-unit equipment upon the failure or non-availability of the normally preceding unit. 2 46 Reverse-phase, or phase balance, A relay that functions when the polyphase Eaton FP-5000/FP-4000/EDR-5000/ current relay currents are of reverse-phase sequence, or when EDR-4000 feeder protective relays and the polyphase currents are unbalanced or contain MP-3000/MP-4000/EMR-3000 motor 3 the negative phase-sequence components above protective relays. a given amount. 47 Phase-sequence voltage relay A relay that functions upon a predetermined Eaton FP-5000/FP-4000/EDR-5000/ 4 value of polyphase voltage in the desired phase EDR-4000 feeder protective relays sequence. and MP-3000/MP-4000 motor protective relays. 48 Incomplete sequence relay A relay that generally returns the equipment to the — 5 normal, or off, position and locks it out of the normal starting, or operating or stopping sequence is not properly completed within a predetermined 6 amount of time. If the device is used for alarm purposes only, it should preferably be designated as 48 A (alarm). 7 49 Machine, or transformer, thermal relay A relay that functions when the temperature of a Eaton MP-3000/MP-4000/EMR-3000/ machine armature, or other load carrying winding ETR-4000 motor protective relays. or element of a machine, or the temperature of a power rectifier or power transformer 8 (including a power rectifier transformer) exceeds a predetermined value. 50 Instantaneous overcurrent, A relay that functions instantaneously on an Used for tripping a circuit breaker 9 or rate-of-rise relay excessive value of current, or an excessive rate of instantaneously during a high-level current rise, thus indicating a fault in the apparatus short circuit. Can trip on phase- of the circuit being protected. phase (50), phase-neutral (50N), 10 phase-ground (50G) faults. Eaton Digitrip 3000, FP-5000/ FP-4000/EDR-5000/EDR-4000/ EDR-3000 protective relays, 11 MP-3000/MP-4000/EMR-3000/ ETR-4000 motor protective relays. 51 AC time overcurrent relay A relay with either a definite or inverse time Used for tripping a circuit breaker 12 characteristic that functions when the current in an after a time delay during a sustained AC circuit exceeds a predetermined value. overcurrent. Used for tripping a circuit breaker instantaneously during a high-level short circuit. 13 Can trip on phase (51), neutral (51N) or ground (51G) overcurrents. Eaton Digitrip 3000, FP-5000/ 14 FP-4000/EDR-5000/EDR-4000/ EDR-3000 protective relays, MP-3000/MP-4000/EMR-3000/ 15 ETR-4000 motor protective relays. 52 AC circuit breaker A device that is used to close and interrupt an A term applied typically to medium AC power circuit under normal conditions or to voltage circuit breakers, or low interrupt this circuit under fault or emergency voltage power circuit breakers. 16 conditions. Eaton VCP-W vacuum circuit breaker, magnum DS low voltage power circuit breaker 17 53 Exciter or DC generator relay A device that forces the DC machine field excitation — to build up during starting or that functions when the machine voltage has built up to a given value. 18 55 Power factor relay A relay that operates when the power factor Eaton FP-5000/FP-4000/EDR-5000 in an AC circuit rises above or below a feeder protective relays and MP-4000 predetermined value. motor protective relay. 19 56 Field application relay A device that automatically controls the application — of the field excitation to an AC motor at some predetermined point in the slip cycle. 59 Overvoltage relay A relay that functions on a given value of Used to trip a circuit breaker, 20 overvoltage. protecting downstream equipment from sustained overvoltages. Eaton FP-5000/FP-4000/EDR-5000 21 feeder protective relays and MP-4000 motor protective relay.

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.5-3 April 2016 Reference Data Sheet 01 097 IEEE Protective Relay Numbers

Table 1.5-1. Selected IEEE Device Numbers for Switchgear Apparatus (Continued) Device Function Definition Typical i Number Uses 60 Voltage or current balance relay A relay that operates on a given difference in — ii voltage, or current input or output of two circuits. 62 Time-delay stopping or opening relay A time-delay relay that serves in conjunction with Used in conjunction with a 27 device the device that initiates the shutdown, stopping to delay tripping of a circuit breaker or opening operation in an automatic sequence. during a brief loss of primary voltage, 1 to prevent nuisance tripping. 63 Pressure switch A switch that operates on given values or on a Used to protect a transformer during given rate of change of pressure. a rapid pressure rise during a short 2 circuit. This device will typically act to open the protective devices above and below the transformer. Typically 3 used with a 63-X auxiliary relay to trip the circuit breaker. 64 Ground protective relay A relay that functions on a failure of the insulation Used to detect and act on a ground- 4 of a machine, transformer or of other apparatus to fault condition. In a pulsing high ground, or on flashover of a DC machine to ground. resistance grounding system, a 64 device will initiate the alarm. 65 Governor A device consisting of an assembly of fluid, — 5 electrical or mechanical control equipment used for regulating the flow of water, steam or other media to the prime mover for such purposes as starting, 6 holding speed or load, or stopping. 66 Notching or jogging device A device that functions to allow only a specified Eaton MP-3000/MP-4000/EMR-3000 number of operations of a given device, or motor protective relays. 7 equipment, or a specified number of successive operations within a given time of each other. It also functions to energize a circuit periodically or for fractions of specified time intervals, or that is used 8 to permit intermittent acceleration or jogging of a machine at low speeds for mechanical positioning. 67 AC directional overcurrent relay A relay that functions on a desired value of AC Eaton FP-5000/EDR-5000 feeder 9 overcurrent flowing in a predetermined direction. protective relays. 69 Permissive control device A device that is generally a two-position manually Used as a remote-local switch for operated switch that in one position permits the circuit breaker control. 10 closing of a circuit breaker, or the placing of equipment into operation, and in the other position prevents the circuit breaker to the equipment from being operated. 11 71 Level switch A switch that operates on given values, or on a Used to indicate a low liquid level within given rate of change of level. a transformer tank in order to save transformers from loss-of-insulation 12 failure. An alarm contact is available as a standard option on a liquid level gauge. It is set to close before an unsafe 13 condition actually occurs. 72 DC circuit breaker A device that is used to close and interrupt a — DC power circuit under normal conditions or to 14 interrupt this circuit under fault or emergency conditions. 73 Load-resistor contactor A device that is used to shunt or insert a step of — load limiting, shifting or indicating resistance in 15 a power circuit; to switch a space heater in circuit; or to switch a light or regenerative load resistor of a power rectifier or other machine in and out 16 of circuit. 74 Alarm relay A device other than an annunciator, as covered — under device number 30, which is used to operate, 17 or to operate in connection with, a visible or audible alarm. 78 Phase-angle measuring relay A device that functions at a predetermined phase — 18 angle between two voltages, between two currents, or between voltage and current. 79 AC reclosing relay A relay that controls the automatic closing and Used to automatically reclose a locking out of an AC circuit interrupter. circuit breaker after a trip, assuming 19 the fault has been cleared after the power was removed from the circuit. The recloser will lock-out after a 20 predetermined amount of failed attempts to reclose. 21

CA08104001E For more information, visit: www.eaton.com/consultants 1.5-4 Power Distribution Systems Reference Data April 2016 Sheet 01 098 IEEE Protective Relay Numbers

Table 1.5-1. Selected IEEE Device Numbers for Switchgear Apparatus (Continued) i Device Function Definition Typical Number Uses ii 81 Frequency relay A relay that functions on a predetermined value of Used to trip a generator circuit frequency—either under or over, or on normal breaker in the event the frequency system frequency—or rate of change frequency. drifts above or below a given value. Eaton FP-5000/FP-4000/EDR-5000/ 1 EDR-4000 feeder protective relays and MP-4000 motor protective relay. 2 83 Automatic selective control or transfer relay A relay that operates to select automatically Used to transfer control power between certain sources or conditions in sources in a double-ended equipment, or performs a transfer operation switchgear lineup. 3 automatically. 85 Carrier or pilot-wire relay A device that is operated or restrained by a signal — transmitted or received via any communications 4 media used for relaying. 86 Locking-out relay An electrically operated hand, or electrically, reset Used in conjunction with protective relay that functions to shut down and hold an relays to lock-out a circuit breaker equipment out of service on the occurrence of (or multiple circuit breakers) after 5 abnormal conditions. a trip. Typically required to be manually reset by an operator before the breaker can be reclosed. 6 87 Differential protective relay A protective relay that functions on a percentage or Used to protect static equipment, phase angle or other quantitative difference of two such as cable, bus or transformers, currents or of some other electrical quantities. by measuring the current differential between two points. Typically the 7 upstream and/or downstream circuit breaker will be incorporated into the “zone of protection.” Eaton FP-5000 8 feeder protective relay (87B) and MD-3000 protective relay. 90 Regulating device A device that functions to regulate a quantity or — 9 quantities, such as voltage, current, power, speed, frequency, temperature and load, at a certain value or between certain (generally close) limits for 10 machines, tie lines or other apparatus. 91 Voltage directional relay A device that operates when the voltage across an — open circuit breaker or contactor exceeds a given value in a given direction. 11 94 Tripping or trip-free relay A relay that functions to trip a circuit breaker, — contactor or equipment, or to permit immediate tripping by other devices, or to prevent immediate 12 reclosure of a circuit interrupter, in case it should open automatically even though its closing circuit is maintained closed. 13

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For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.5-5 April 2016 Reference Data Sheet 01 099 Suggested IEEE Designations for Suffix Letters

Main Device Other Suffix Letters Suggested IEEE Designations i for Suffix Letters The following letters denote the main The following letters cover all other device to which the numbered device distinguishing features, characteristics Auxiliary Devices is applied or is related: or conditions not specifically described ii in Auxiliary Devices through Main These letters denote separate auxiliary A Alarm/auxiliary power Device Parts, which serve to describe devices, such as the following: AC Alternating current the use of the device in the equipment, 1 C Closing relay/contactor such as: BP Bypass CL Auxiliary relay, closed A Automatic BT Bus tie 2 (energized when main device BF Breaker failure is in closed position) C Capacitor C Close CS Control switch DC Direct current 3 D Decelerating/down D “Down” position switch relay E Exciter E Emergency 4 L Lowering relay F Feeder/field F Failure/forward O Opening relay/contactor G Generator/ground HS High speed 5 OP Auxiliary relay, open M Motor/metering (energized when main device L Local/lower is in open position) MOC Mechanism operated contact M Manual 6 PB Push button S Synchronizing/secondary O Open R Raising relay T Transformer 7 OFF Off U “UP” position switch relay TOC Truck-operated contacts ON On 8 X Auxiliary relay Main Device Parts R Raise/reclosing/remote/reverse Y Auxiliary relay These letters denote parts of the main device, except auxiliary con- T Test/trip 9 Z Auxiliary relay tacts, position switches, limit switches TDC Time-delay closing contact and torque limit switches: Actuating Quantities TDDO Time delayed relay coil 10 C Coil/condenser/capacitor These letters indicate the condition or drop-out electrical quantity to which the device CC Closing coil/closing contactor TDO Time-delay opening contact responds, or the medium in which it is 11 located, such as the following: HC Holding coil TDPU Time delayed relay coil pickup A Amperes/alternating M Operating motor THD Total harmonic distortion 12 C Current OC Opening contactor F Frequency/fault S Solenoid 13 I0 Zero sequence current SI Seal-in 14 I-, I2 Negative sequence current T Target TC Trip coil I+, I1 Positive sequence current 15 P Power/pressure PF Power factor 16 S Speed T Temperature 17 V Voltage/volts/vacuum VAR Reactive power 18 VB Vibration W Watts 19 20

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CA08104001E For more information, visit: www.eaton.com/consultants 1.5-6 Power Distribution Systems Reference Data April 2016 Sheet 01 100 Codes and Standards

Codes and Standards a number of other testing laboratories A design engineer should conform i have been recognized and accepted. to all applicable codes, and require The National Electrical Code (NEC), The Institute of Electrical and Electronic equipment to be listed by UL or NFPA Standard No. 70, is the most Engineers (IEEE) publishes a number another recognized testing laboratory prevalent electrical code in the United ii of books (the “color book” series) on wherever possible, and to meet States. The NEC, which is revised every recommended practices for the design ANSI or NEMA standards. ANSI/IEEE three years, has no legal standing of of industrial buildings, commercial recommended practices should its own, until it is adopted as law by 1 buildings, emergency power systems, be followed to a great extent. In a jurisdiction, which may be a city, grounding, and the like. Most of these many cases, standards should be county or state. Most jurisdictions IEEE standards have been adopted as exceeded to get a system of the adopt the NEC in its entirety; some 2 ANSI standards. They are excellent quality required. The design goal adopt it with variations, usually more guides, although they are not in any should be a safe, efficient, long- rigid, to suit local conditions and way mandatory. lasting, flexible and economical requirements. A few large cities, such 3 electrical distribution system. as New York and Chicago, have their own electrical codes, basically similar Professional Organizations 4 to the NEC. The designer must deter- mine which code applies in the area American National Standards Institute National Electrical Manufacturers of a specific project. (ANSI) Association (NEMA) 5 Headquarters: 1300 North 17th Street The Occupational Safety and Health Suite 1847 Act (OSHA) of 1970 sets uniform 1819 L Street, NW Rosslyn, VA 22209 national requirements for safety in the 6th Floor 703-841-3200 6 workplace—anywhere that people are Washington, DC 20036 employed. Originally OSHA adopted 202-293-8020 www.nema.org the 1971 NEC as rules for electrical 7 safety. As the NEC was amended every Operations: National Fire Protection Association three years, the involved process for 25 West 43rd Street (NFPA) modifying a federal law such as OSHA 4th Floor 1 Battery March Park 8 made it impossible for the act to adopt New York, NY 10036 Quincy, MA 02169-7471 each new code revision. To avoid this 212-642-4900 617-770-3000 problem, the OSHA administration 9 in 1981 adopted its own code, a con- www.ansi.org www.nfpa.org densed version of the NEC containing Institute of Electrical and Electronic Underwriters Laboratories (UL) only those provisions considered Engineers (IEEE) 333 Pfingsten Road 10 related to occupational safety. OSHA Northbrook, IL 60062-2096 was amended to adopt this code, Headquarters: 847-272-8800 11 based on NFPA Standard 70E, Part 1, 3 Park Avenue which is now federal law. 17th Floor www.ul.com The NEC is a minimum safety New York, NY 10016-5997 12 212-419-7900 International Code Council (ICC) standard. Efficient and adequate 5203 Leesburg Pike design usually requires not just Operations: Suite 600 meeting, but often exceeding NEC 445 Hoes Lane Falls Church, VA 22041 13 requirements to provide an effective, Piscataway, NJ 08854-1331 1-888-422-7233 reliable, economical electrical system. 732-981-0060 www.iccsafe.org Many equipment standards have been 14 www.ieee.org established by the National Electrical The American Institute of Architects (AIA) Manufacturers’ Association (NEMA) International Association of Electrical 1735 New York Avenue, NW 15 and the American National Standards Inspectors (IAEI) Washington, DC 20006-5292 Institute (ANSI). Underwriters 901 Waterfall Way 202-626-7300 Laboratories (UL) has standards that Suite 602 equipment must meet before UL will www.aia.org 16 Richardson, TX 75080-7702 list or label it. Most jurisdictions and 972-235-1455 OSHA require that where equipment 17 listed as safe by a recognized labora- www.iaei.org tory is available, unlisted equipment may not be used. UL is by far the most 18 widely accepted national laboratory, although Factory Mutual Insurance Company lists some equipment, and 19

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For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.5-7 April 2016 Reference Data Sheet 01 101 Motor Protective Device Data

Motor Protection Table 1.5-2. Motor Circuit Protector (MCP), Circuit Breaker and Fusible Switch Selection Guide i Consistent with the 2011 NEC Horsepower Full Load Fuse Size NEC 430.52 Recommended Eaton Amperes Maximum Circuit Motor Circuit 430.6(A)(1) circuit breaker, HMCP and (NEC) FLA Amperes fuse rating selections are based on Breaker Protector Type HMCP ii full load currents for induction motors Time Delay Non-Time Delay Amperes Amperes Adj. Range running at speeds normal for belted 230 V, Three-Phase motors and motors with normal 1 3.6 10 15 15 7 21–70 1 torque characteristics using data taken 1-1/2 5.2 10 20 15 15 45–150 from NEC Table 430.250 (three-phase). 2 6.8 15 25 15 15 45–150 Actual motor nameplate ratings shall 3 9.6 20 30 20 30 90–300 2 be used for selecting motor running 5 15.2 30 50 30 30 90–300 overload protection. Motors built 7-1/2 22 40 70 50 50 150–500 special for low speeds, high torque 10 28 50 90 60 50 150–500 15 42 80 150 90 70 210–700 3 characteristics, special starting conditions and applications will 20 54 100 175 100 100 300–1000 25 68 125 225 125 150 450–1500 require other considerations as 30 80 150 250 150 150 450–1500 4 defined in the application section 40 104 200 350 150 150 750–2500 of the NEC. 50 130 250 400 200 150 750–2500 60 154 300 500 225 250 1250–2500 5 These additional considerations may 75 192 350 600 300 400 2000–4000 require the use of a higher rated HMCP, 100 248 450 800 400 400 2000–4000 or at least one with higher magnetic 125 312 600 1000 500 600 1800–6000 6 pickup settings. 150 360 700 1200 600 600 1800–6000 200 480 1000 1600 700 600 1800–6000 Circuit breaker, HMCP and fuse ampere rating selections are in 460 V, Three-Phase 7 line with maximum rules given in 1 1.8 6 6 15 7 21–70 NEC 430.52 and Table 430.250. Based 1-1/2 2.6 6 10 15 7 21–70 2 3.4 6 15 15 7 21–70 on known characteristics of Eaton type 3 4.8 10 15 15 15 45–150 8 breakers, specific units are recom- 5 7.6 15 25 15 15 45–150 mended. The current ratings are no 7-1/2 11 20 35 25 30 90–300 more than the maximum limits set by 10 14 25 45 35 30 90–300 9 the NEC rules for motors with code 15 21 40 70 45 50 150–500 letters F to V or without code letters. 20 27 50 90 50 50 150–500 Motors with lower code letters will 25 34 60 110 70 70 210–700 10 require further considerations. 30 40 70 125 70 100 300–1000 40 52 100 175 100 100 300–1000 In general, these selections were 50 65 125 200 110 150 450–1500 11 based on: 60 77 150 150 125 150 750–2500 75 96 175 300 150 150 750–2500 1. Ambient—outside enclosure not 100 124 225 400 175 150 750–2500 12 more than 40 °C (104 °F). 125 156 300 500 225 250 1250–2500 150 180 350 600 250 400 2000–4000 2. Motor starting—infrequent 200 240 450 800 350 400 2000–4000 starting, stopping or reversing. 13 575 V, Three-Phase 3. Motor accelerating time— 1 1.4 3 6 15 3 9–30 10 seconds or less. 1-1/2 2.1 6 10 15 7 21–70 2 2.7 6 10 15 7 21–70 14 4. Locked rotor—maximum 6 times 3 3.9 10 15 15 7 21–70 motor FLA. 5 6.1 15 20 15 15 45–150 7-1/2 9 20 30 20 15 45–150 15 Type HMCP motor circuit protector 10 11 20 35 25 30 90–300 may not set at more than 1300% of 15 17 30 60 40 30 90–300 the motor full-load current to comply 20 22 40 70 50 50 150–500 16 with NEC 430.52. (Except for NEMA 25 27 50 90 60 50 150–500 Design B energy high-efficiency 30 32 60 100 60 50 150–500 motors that can be set up to 1700%.) 40 41 80 125 80 100 300–1000 17 50 52 100 175 100 100 300–1000 Circuit breaker selections are based 60 62 110 200 125 150 750–2500 on types with standard interrupting 75 77 150 250 150 150 750–2500 18 ratings. Higher interrupting rating types 100 99 175 300 175 150 750–2500 may be required to satisfy specific 125 125 225 400 200 250 1250–2500 system application requirements. 150 144 300 450 225 250 1250–2500 200 192 350 600 300 400 2000–4000 19 For motor full load currents of 208 V and 200 V, increase the corresponding 230 V motor values 20 by 10 and 15% respectively. 21

CA08104001E For more information, visit: www.eaton.com/consultants 1.5-8 Power Distribution Systems Reference Data April 2016 Sheet 01 102 Motor Protective Device Data

Table 1.5-3. 60 Hz, Recommended Protective Setting for Induction Motors i hp Full Load Minimum Wire Size Minimum Conduit Size, Fuse Size NEC 430.52 Recommended Eaton: 1 Amperes 75 °C Copper Ampacity Inches (mm) Maximum Amperes Circuit Motor Circuit (NEC) FLA at 125% FLA 2 ii THW THWN Time Non-Time Breaker Protector Size Amperes XHHN Delay Delay Amperes Amperes Adjustable Range 115 V, Single-Phase 1 3/4 13.8 14 20 0.50 (12.7) 0.50 (12.7) 25 45 30 Two-pole device 1 16 14 20 0.50 (12.7) 0.50 (12.7) 30 50 35 not available 1-1/2 20 12 30 0.50 (12.7) 0.50 (12.7) 35 60 40 2 2 24 10 30 0.50 (12.7) 0.50 (12.7) 45 80 50 3 34 8 50 0.75 (19.1) 0.50 (12.7) 60 110 70 5 56 4 85 1.00 (25.4) 0.75 (19.1) 100 175 100 3 7-1/2 80 3 100 1.00 (25.4) 1.00 (25.4) 150 250 150 230 V, Single-Phase 3/4 6.9 14 20 0.50 (12.7) 0.50 (12.7) 15 25 15 Two-pole device 1 8 14 20 0.50 (12.7) 0.50 (12.7) 15 25 20 not available 4 1-1/2 10 14 20 0.50 (12.7) 0.50 (12.7) 20 30 25 2 12 14 20 0.50 (12.7) 0.50 (12.7) 25 40 30 3 17 12 30 0.50 (12.7) 0.50 (12.7) 30 60 40 5 5 28 10 50 0.50 (12.7) 0.50 (12.7) 50 90 60 7-1/2 40 8 50 0.75 (19.1) 0.50 (12.7) 70 125 80 1 Consult fuse manufacturer’s catalog for smaller fuse ratings. 6 2 Types are for minimum interrupting capacity breakers. Ensure that the fault duty does not exceed breaker’s I.C.

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For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.5-9 April 2016 Reference Data Sheet 01 103 Chart of Short Circuit Currents for Transformers

Table 1.5-4. Secondary Short-Circuit Current of Typical Power Transformers Tra n s - Maximum 208 V, Three-Phase 240 V, Three-Phase 480 V, Three-Phase 600 V, Three-Phase i former Short- Rated Short-Circuit Current Rated Short-Circuit Current Rated Short-Circuit Current Rated Short-Circuit Current Rating Circuit Load rms Symmetrical Amps Load rms Symmetrical Amps Load rms Symmetrical Amps Load rms Symmetrical Amps Three- kVA Contin- Tr a n s - 50% Com- Contin- Tra n s - 100% Com- Contin- Tra n s - 100% Com- Contin- Tra n s - 100% Com- ii Phase Available uous uous uous uous kVA and from former Motor bined former Motor bined former Motor bined former Motor bined Current, Alone 1 Load 2 Current, Alone 1 Load 2 Current, Alone 1 Load 2 Current, Alone 1 Load 2 Impedance Primary Amps Amps Amps Amps Percent System 1 300 50,000 834 14,900 1700 16,600 722 12,900 2900 15,800 361 6400 1400 7800 289 5200 1200 6400 5% 100,000 834 15,700 1700 17,400 722 13,600 2900 16,500 361 6800 1400 8200 289 5500 1200 6700 150,000 834 16,000 1700 17,700 722 13,900 2900 16,800 361 6900 1400 8300 289 5600 1200 6800 2 250,000 834 16,300 1700 18,000 722 14,100 2900 17,000 361 7000 1400 8400 289 5600 1200 6800 500,000 834 16,500 1700 18,200 722 14,300 2900 17,200 361 7100 1400 8500 289 5700 1200 6900 Unlimited 834 16,700 1700 18,400 722 14,400 2900 17,300 361 7200 1400 8600 289 5800 1200 7000 3 500 50,000 1388 21,300 2800 25,900 1203 20,000 4800 24,800 601 10,000 2400 12,400 481 8000 1900 9900 5% 100,000 1388 25,200 2800 28,000 1203 21,900 4800 26,700 601 10,900 2400 13,300 481 8700 1900 10,600 150,000 1388 26,000 2800 28,800 1203 22,500 4800 27,300 601 11,300 2400 13,700 481 9000 1900 10,900 4 250,000 1388 26,700 2800 29,500 1203 23,100 4800 27,900 601 11,600 2400 14,000 481 9300 1900 11,200 500,000 1388 27,200 2800 30,000 1203 23,600 4800 28,400 601 11,800 2400 14,200 481 9400 1900 11,300 Unlimited 1388 27,800 2800 30,600 1203 24,100 4800 28,900 601 12,000 2400 14,400 481 9600 1900 11,500 750 50,000 2080 28,700 4200 32,900 1804 24,900 7200 32,100 902 12,400 3600 16,000 722 10,000 2900 12,900 5 5.75% 100,000 2080 32,000 4200 36,200 1804 27,800 7200 35,000 902 13,900 3600 17,500 722 11,100 2900 14,000 150,000 2080 33,300 4200 37,500 1804 28,900 7200 36,100 902 14,400 3600 18,000 722 11,600 2900 14,500 250,000 2080 34,400 4200 38,600 1804 29,800 7200 37,000 902 14,900 3600 18,500 722 11,900 2900 14,800 6 500,000 2080 35,200 4200 39,400 1804 30,600 7200 37,800 902 15,300 3600 18,900 722 12,200 2900 15,100 Unlimited 2080 36,200 4200 40,400 1804 31,400 7200 38,600 902 15,700 3600 19,300 722 12,600 2900 15,500 1000 50,000 2776 35,900 5600 41,500 2406 31,000 9800 40,600 1203 15,500 4800 20,300 962 12,400 3900 16,300 5.75% 100,000 2776 41,200 5600 46,800 2406 35,600 9800 45,200 1203 17,800 4800 22,600 962 14,300 3900 18,200 7 150,000 2776 43,300 5600 48,900 2406 37,500 9800 47,100 1203 18,700 4800 23,500 962 15,000 3900 18,900 250,000 2776 45,200 5600 50,800 2406 39,100 9800 48,700 1203 19,600 4800 24,400 962 15,600 3900 19,500 500,000 2776 46,700 5600 52,300 2406 40,400 9800 50,000 1203 20,200 4800 25,000 962 16,200 3900 20,100 8 Unlimited 2776 48,300 5600 53,900 2406 41,800 9800 51,400 1203 20,900 4800 25,700 962 16,700 3900 20,600 1500 50,000 4164 47,600 8300 55,900 3609 41,200 14,400 55,600 1804 20,600 7200 27,800 1444 16,500 5800 22,300 5.75% 100,000 4164 57,500 8300 65,800 3609 49,800 14,400 64,200 1804 24,900 7200 32,100 1444 20,000 5800 25,800 9 150,000 4164 61,800 8300 70,100 3609 53,500 14,400 57,900 1804 26,700 7200 33,900 1444 21,400 5800 27,200 250,000 4164 65,600 8300 73,900 3609 56,800 14,400 71,200 1804 28,400 7200 35,600 1444 22,700 5800 28,500 500,000 4164 68,800 8300 77,100 3609 59,600 14,400 74,000 1804 29,800 7200 37,000 1444 23,900 5800 29,700 Unlimited 4164 72,500 8300 80,800 3609 62,800 14,400 77,200 1804 31,400 7200 38,600 1444 25,100 5800 30,900 10 2000 50,000 — — — — — — — — 2406 24,700 9600 34,300 1924 19,700 7800 27,500 5.75% 100,000 — — — — — — — — 2406 31,000 9600 40,600 1924 24,800 7800 32,600 150,000 — — — — — — — — 2406 34,000 9600 43,600 1924 27,200 7800 35,000 11 250,000 — — — — — — — — 2406 36,700 9600 46,300 1924 29,400 7800 37,200 500,000 — — — — — — — — 2406 39,100 9600 48,700 1924 31,300 7800 39,100 Unlimited — — — — — — — — 2406 41,800 9600 51,400 1924 33,500 7800 41,300 12 2500 50,000 — — — — — — — — 3008 28,000 12,000 40,000 2405 22,400 9600 32,000 5.75% 100,000 — — — — — — — — 3008 36,500 12,000 48,500 2405 29,200 9600 38,800 150,000 — — — — — — — — 3008 40,500 12,000 52,500 2405 32,400 9600 42,000 13 250,000 — — — — — — — — 3008 44,600 12,000 56,600 2405 35,600 9600 45,200 500,000 — — — — — — — — 3008 48,100 12,000 60,100 2405 38,500 9600 48,100 Unlimited — — — — — — — — 3008 52,300 12,000 64,300 2405 41,800 9600 51,400 3000 50,000 — — — — — — — — 3609 30,700 14,000 44,700 2886 24,600 11,500 36,100 14 5.75% 100,000 — — — — — — — — 3609 41,200 14,000 55,200 2886 33,000 11,500 44,500 150,000 — — — — — — — — 3609 46,600 14,000 60,600 2886 37,300 11,500 48,800 250,000 — — — — — — — — 3609 51,900 14,000 65,900 2886 41,500 11,500 53,000 15 500,000 — — — — — — — — 3609 56,800 14,000 70,800 2886 45,500 11,500 57,000 Unlimited — — — — — — — — 3609 62,800 14,000 76,800 2886 50,200 11,500 61,700 3750 50,000 — — — — — — — — 4511 34,000 18,000 52,000 3608 27,200 14,400 41,600 16 5.75% 100,000 — — — — — — — — 4511 47,500 18,000 65,500 3608 38,000 14,400 52,400 150,000 — — — — — — — — 4511 54,700 18,000 72,700 3608 43,700 14,400 58,100 250,000 — — — — — — — — 4511 62,200 18,000 80,200 3608 49,800 14,400 64,200 500,000 — — — — — — — — 4511 69,400 18,000 87,400 3608 55,500 14,400 69,900 17 Unlimited — — — — — — — — 4511 78,500 18,000 96,500 3608 62,800 14,400 77,200 1 Short-circuit capacity values shown correspond to kVA and impedances shown in this table. For impedances other than these, short-circuit currents are inversely proportional to impedance. 18 2 The motor’s short-circuit current contributions are computed on the basis of motor characteristics that will give four times normal current. For 208 V, 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. 19

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CA08104001E For more information, visit: www.eaton.com/consultants 1.5-10 Power Distribution Systems Reference Data April 2016 Sheet 01 104 Transformer Full Load Amperes

Table 1.5-5. Transformer Full-Load Current, Three-Phase, Self-Cooled Ratings i Voltage, Line-to-Line kVA 208 240 480 600 2400 4160 7200 12,000 12,470 13,200 13,800 22,900 34,400 ii 30 83.3 72.2 36.1 28.9 7.22 4.16 2.41 1.44 1.39 1.31 1.26 0.75 0.50 45 125 108 54.1 43.3 10.8 6.25 3.61 2.17 2.08 1.97 1.88 1.13 0.76 75 208 180 90.2 72.2 18.0 10.4 6.01 3.61 3.47 3.28 3.14 1.89 1.26 1 112-1/2 312 271 135 108 27.1 15.6 9.02 5.41 5.21 4.92 4.71 2.84 1.89 150 416 361 180 144 36.1 20.8 12.0 7.22 6.94 6.56 6.28 3.78 2.52 225 625 541 271 217 54.1 31.2 18.0 10.8 10.4 9.84 9.41 5.67 3.78 300 833 722 361 289 72.2 41.6 24.1 14.4 13.9 13.1 12.6 7.56 5.04 2 500 1388 1203 601 481 120 69.4 40.1 24.1 23.1 21.9 20.9 12.6 8.39 750 2082 1804 902 722 180 104 60.1 36.1 34.7 32.8 31.4 18.9 12.6 1000 2776 2406 1203 962 241 139 80.2 48.1 46.3 43.7 41.8 25.2 16.8 3 1500 4164 3608 1804 1443 361 208 120 72.2 69.4 65.6 62.8 37.8 25.2 2000 — 4811 2406 1925 481 278 160 96.2 92.6 87.5 83.7 50.4 33.6 2500 — — 3007 2406 601 347 200 120 116 109 105 63.0 42.0 3000 — — 3609 2887 722 416 241 144 139 131 126 75.6 50.4 4 3750 — — 4511 3608 902 520 301 180 174 164 157 94.5 62.9 5000 — — — 4811 1203 694 401 241 231 219 209 126 83.9 7500 — — — — 1804 1041 601 361 347 328 314 189 126 5 10,000 — — — — 2406 1388 802 481 463 437 418 252 168

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For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.5-11 April 2016 Reference Data Sheet 01 105 Impedances Data

Approximate Impedance Data Table 1.5-9. 15 kV Class Primary— Table 1.5-11. 600V Primary Class Three-Phase Dry-Type Substation Transformers DOE 2016 Energy-Efficient Dry-Type i Table 1.5-6. Typical Impedances— Distribution Transformers, Copper Wound Three-Phase Transformers Liquid-Filled 1 kVA %Z %R %X X/R 150 °C Rise kVA %Z %X %R X/R kVA Liquid-Filled ii 300 4.50 150 °C Rise Copper Network Padmount 2.87 3.47 1.21 500 5.75 2.66 5.10 1.92 15 3.10 1.59 2.66 0.60 750 5.75 37.5 — — 2.47 5.19 2.11 30 2.52 0.79 2.39 0.33 45 — — 1000 5.75 2.16 5.33 2.47 45 3.80 2.60 2.77 0.94 1 50 — — 1500 5.75 1.87 5.44 2.90 75 2.84 1.94 2.08 0.93 75 — 3.4 2000 5.75 1.93 5.42 2.81 112.5 3.63 3.11 1.88 1.66 112.5 — 3.4 2500 5.75 1.74 5.48 3.15 150 3.02 2.64 1.46 1.81 2 150 — 3.4 80 °C Rise 225 4.34 3.98 1.73 2.31 225 — 3.4 300 4.50 1.93 4.06 2.10 300 3.48 3.19 1.38 2.31 300 5.00 3.4 500 5.75 1.44 5.57 3.87 3 500 5.00 4.6 115 °C Rise Copper 750 5.75 1.28 5.61 4.38 750 5.00 5.75 15 2.90 1.59 2.43 0.66 1000 5.75 0.93 5.67 6.10 1000 5.00 5.75 30 2.35 0.97 2.14 0.45 1500 5.75 0.87 5.68 6.51 4 1500 7.00 5.75 45 3.85 2.87 2.57 1.12 2000 5.75 0.66 5.71 8.72 2000 7.00 5.75 75 2.86 2.12 1.92 1.10 2500 5.75 0.56 5.72 10.22 2500 7.00 5.75 112.5 4.02 3.59 1.82 1.97 3000 — 5.75 150 3.34 3.05 1.37 2.23 5 3750 — 6.00 Table 1.5-10. 600 V Primary Class Three- 225 5.03 4.78 1.58 3.02 5000 — 6.50 Phase DOE 2016 Energy-Efficient Dry-Type 300 4.14 3.94 1.29 3.06 Distribution Transformers, Aluminum Wound 1 Values are typical. For guaranteed values, 80 °C Rise Copper 6 refer to transformer manufacturer. kVA %Z %X %R X/R 15 3.09 2.04 2.32 0.88 150 °C Rise Aluminum 30 2.53 1.73 1.85 0.94 Table 1.5-7. 15 kV Class Primary— 45 1.70 1.16 1.25 0.93 7 15 4.04 2.08 3.46 0.60 Oil Liquid-Filled Substation Transformers 30 2.52 1.13 2.25 0.50 75 2.42 2.07 1.25 1.66 kVA %Z %R %X X/R 45 3.75 2.64 2.67 0.99 112.5 2.27 1.98 1.09 1.81 150 2.89 2.65 1.15 2.31 8 75 4.05 3.34 2.29 1.46 65 °C Rise 225 3.11 2.95 0.96 3.06 112.5 4.66 4.22 1.99 2.12 112.5 5.00 1.71 4.70 2.75 150 3.48 3.09 1.61 1.92 150 5.00 1.88 4.63 2.47 9 225 5.00 1.84 4.65 2.52 225 4.20 3.96 1.39 2.85 300 5.00 1.35 4.81 3.57 300 4.46 4.26 1.32 3.23 500 5.00 1.50 4.77 3.18 115 °C Rise Aluminum 750 5.75 1.41 5.57 3.96 10 15 3.77 2.08 3.14 0.66 1000 5.75 1.33 5.59 4.21 30 2.34 1.37 1.90 0.72 1500 5.75 1.12 5.64 5.04 45 4.26 3.44 2.52 1.37 2000 5.75 0.93 5.67 6.10 11 75 4.45 3.90 2.14 1.83 2500 5.75 0.86 5.69 6.61 112.5 5.17 4.81 1.89 2.54 150 3.89 3.59 1.49 2.41 Table 1.5-8. DOE 2016 Transformer 225 4.90 4.73 1.28 3.69 12 Efficiencies—Medium Voltage Three-Phase 300 4.80 4.65 1.21 3.85 Distribution Transformers 1 80 °C Rise Aluminum 13 kVA % Efficiency 15 4.19 2.94 2.98 0.99 Liquid- Dry Transformers 30 2.50 1.76 1.78 0.99 Filled 45 2.43 2.01 1.37 1.46 14 All 25–45 46–95 M96 kV 75 3.11 2.81 1.32 2.12 BILs kV BIL kV BIL BIL 112.5 2.61 2.31 1.21 1.92 150 2.80 2.64 0.93 2.85 15 98.65 97.5 97.18 — 225 3.35 3.20 0.99 3.23 15 30 98.83 97.9 97.63 — 45 98.92 98.1 97.86 — 75 99.03 98.33 98.13 — 16 112 . 5 99.11 98.52 98.36 — 150 99.16 98.65 98.51 — 225 99.23 98.82 98.69 98.57 17 300 99.27 98.93 98.81 98.69 500 99.35 99.09 98.99 98.89 750 99.40 99.21 99.12 99.02 1000 99.43 99.28 99.2 99.11 18 1500 99.48 99.37 99.3 99.21 2000 99.51 99.43 99.36 99.28 2500 99.53 99.47 99.41 99.33 19 1 Based on transformer operating at 50% of nameplate base kVA. 20

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CA08104001E For more information, visit: www.eaton.com/consultants 1.5-12 Power Distribution Systems Reference Data April 2016 Sheet 01 106 Transformer Losses

Transformer Loss Data Transformer losses for various At 0% load: i loading can be estimated in the 1800 watts See product sections for data. following manner. The no load watt Transformer Losses at Reduced Loads losses of the transformer are due to At 50% load: magnetization and are present 2 ii Information on losses based on actual 1800 watts + (13,300)(0.5) = whenever the transformer is transformer test data can be obtained 1800 watts + 3325 watts = 5125 watts energized. The load watt losses are from the manufacturer. Transformer 1 the difference between the no load At 100% load: manufacturers provide no load watt watt losses and the full load watt 1800 watts + 13,300 watts = 15,100 watts losses and total watt losses in accor- losses. The load watt losses are dance with ANSI standards. The At 110% load: 2 proportional to I2R and can be calculated difference between the estimated to vary with the transformer 1800 watts + (13,300)(1.1)2 = no load losses and the total losses load by the square of the load current. 1800 watts + 16,093 watts = 17,893 watts 3 are typically described as the load losses. Although transformer coils For example, the approximate watts Because transformer losses vary are manufactured with either aluminum loss data for a 1000 kVA oil-filled between designs and manufacturers, 4 or copper conductors, the industry substation transformer is shown in additional losses such as from has sometimes referred to these load the table as having 1800 watts no cooling fans can be ignored for losses as the “copper losses.” load losses and 15,100 watts full load these approximations. 5 losses, so the load losses are approxi- Note: 1 watthour = 3.413 Btu. mately 13,300 watts (15,100–1800). The transformer losses can be calculated 6 for various loads as follows.

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For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.5-13 April 2016 Reference Data Sheet 01 107 Power Equipment Losses and Enclosures/Knockout Dimensions

Power Equipment Losses Enclosures i Table 1.5-12. Power Equipment Losses The following are reproduced from NEMA 250. Equipment Watts Table 1.5-13. Comparison of Specific Applications of Enclosures for Indoor Nonhazardous Locations Loss ii Provides a Degree of Protection Against the Enclosure Type Medium Voltage Switchgear (Indoor, 5 and 15 kV) Following Environmental Conditions 1 1 2 1 44X566P1212K13 1200 A breaker 600 2000 A breaker 1400 Incidental contact with the enclosed equipment ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ 1 3000 A breaker 2100 Falling dirt ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ 4000 A breaker 3700 Falling liquids and light splashing ■ ■ ■ ■ ■ ■ ■ ■ ■ Medium Voltage Switchgear (Indoor, 5 and 15 kV) Circulating dust, lint, fibers and flyings 2 ■ ■ ■ ■ ■ ■ ■ 2 Settling airborne dust, lint, fibers and flyings 2 ■ ■ ■ ■ ■ ■ ■ ■ 600 A unfused switch 500 Hosedown and splashing water ■ ■ ■ ■ 1200 A unfused switch 750 100 A CL fuses 840 Oil and coolant seepage ■■■ Oil or coolant spraying and splashing ■ 3 Medium Voltage Starters (Indoor, 5 kV) Corrosive agents ■■ 400 A starter FVNR 600 Occasional temporary submersion ■■ 800 A starter FVNR 1000 Occasional prolonged submersion ■ 4 600 A fused switch 500 1 These enclosures may be ventilated. 1200 A fused switch 800 2 These fibers and flying are nonhazardous materials and are not considered the Class III type Low Voltage Switchgear (Indoor, 480 V) ignitable fibers or combustible flyings. For Class III type ignitable fibers or combustible flyings, 5 800 A breaker 400 see the National Electrical Code, Article 500. 1600 A breaker 1000 2000 A breaker 1500 Table 1.5-14. Comparison of Specific Applications of Enclosures for Outdoor Nonhazardous Locations 6 3200 A breaker 2400 Provides a Degree of Protection Against the Enclosure Type 4000 A breaker 3000 Following Environmental Conditions 33R 3 3S 4 4X 6 6P 5000 A breaker 4700 7 Fuse limiters—800 A CB 200 Incidental contact with the enclosed equipment ■ ■ ■ ■ ■ ■ ■ 4 Fuse limiters—1600 A CB 500 Rain, snow and sleet ■ ■ ■ ■ ■ ■ ■ 5 ■ Fuse limiters—2000 A CB 750 Sleet ■■■■ ■ ■ 8 Fuse truck—3200 A CB 3600 Windblown dust Hosedown ■ ■ ■ ■ Fuse truck—4000 A CB 4500 Corrosive agents ■ ■ Structures—3200 A 4000 Occasional temporary submersion ■■ 9 Structures—4000 A 5000 Occasional prolonged submersion ■ Structures—5000 A 7000 3 These enclosures may be ventilated. High resistance grounding 1200 4 External operating mechanisms are not required to be operable when the enclosure is ice covered. 10 Panelboards (Indoor, 480 V) 5 External operating mechanisms are operable when the enclosure is ice covered. 225 A, 42 circuit 300 Low Voltage Busway (Indoor, Copper, 480 V) Table 1.5-15. Comparison of Specific Applications of Enclosures for Indoor Hazardous Locations 11 Provides a Degree of Protection Against Class Enclosure Types Enclosure Type 800 A 44 per foot 6 6 1200 A 60 per foot Atmospheres Typically Containing 7 and 8, Class I Groups 9, Class II Groups 1350 A 66 per foot (For Complete Listing, See NFPA 497M) ABCDEFG10 12 1600 A 72 per foot Acetylene I ■ 2000 A 91 per foot Hydrogen, manufactured gas I ■ 2500 A 103 per foot diethyl ether, ethylene, cyclopropane I ■ 13 3200 A 144 per foot Gasoline, hexane, butane, naphtha, propane, 4000 A 182 per foot acetone, toluene, isoprene I ■ 5000 A 203 per foot Metal dust II ■ 14 ■ Motor Control Centers (Indoor, 480 V) Carbon black, coal dust, coke dust II Flour, starch, grain dust II ■ NEMA Size 1 starter 39 Fibers, flyings 7 III ■ NEMA Size 2 starter 56 Methane with or without coal dust MSHA ■ 15 NEMA Size 3 starter 92 6 For Class III type ignitable fibers or combustible flyings, see the National Electrical Code, Article 500. NEMA Size 4 starter 124 7 Due to the characteristics of the gas, vapor or dust, a product suitable for one class or group may NEMA Size 5 starter 244 not be suitable for another class or group unless so marked on the product. 16 Structures 200 Note: If the installation is outdoors and/or additional protection is required by Tables 1.5-13 and Adjustable Frequency Drives (Indoor, 480 V) 1.5-14, a combination-type enclosure is required. Adjustable frequency drives > 96% 17 efficiency

Note: The information provided on power 18 equipment losses is generic data intended to be used for sizing of HVAC equipment. 19

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CA08104001E For more information, visit: www.eaton.com/consultants 1.5-14 Power Distribution Systems Reference Data April 2016 Sheet 01 108 Power Equipment Losses and Enclosures/Knockout Dimensions

Table 1.5-16. Conversion of NEMA Enclosure Type Ratings to IEC 60529 Enclosure Classification Designations (IP) i (Cannot be Used to Convert IEC Classification Designations to NEMA Type Ratings)

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For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.5-15 April 2016 Reference Data Sheet 01 109 Conductor Resistance, Reactance, Impedance

2 2 Average Characteristics of Application Notes ■ ZX R i 600 V Conductors— ■ Resistance and reactance are ■ For busway impedance data, see Ohms per 1000 ft (305 m) phase-to-neutral values, based on Ta b 2 1 of this catalog 60 Hz AC, three-phase, four-wire ■ For PF (power factor) values less The tables below are average charac- ii distribution, in ohms per 100 ft than 1.0, the effective impedance Ze teristics based on data from IEEE (30 m) of circuit length (not total is calculated from Standard 141-1993. Values from conductor lengths) different sources vary because of Ze R PF X sin (arc cos PF) 1 ■ Based upon conductivity of 100% for operating temperatures, wire ■ copper, 61% for aluminum For copper cable data, resistance stranding, insulation materials based on tinned copper at 60 Hz; ■ Based on conductor temperatures 2 and thicknesses, overall diameters, 600 V and 5 kV nonshielded cable of 75 °C. Reactance values will random lay of multiple conductors based on varnished cambric insula- have negligible variation with in conduit, conductor spacing, and tion; 5 kV shielded and 15 kV cable temperature. Resistance of both 3 other divergences in materials, test based on neoprene insulation conditions and calculation methods. copper and aluminum conductors will be approximately 5% lower ■ For aluminum cable data, cable is These tables are for 600 V 5 kV and cross-linked polyethylene insulated 15 kV conductors, at an average at 60 °C or 5% higher at 90 °C. 4 temperature of 75 °C. Other parame- Data shown in tables may be ters are listed in the notes. For used without significant error medium voltage cables, differences between 60 ° and 90 °C 5 among manufacturers are consider- ■ For interlocked armored cable, ably greater because of the wider vari- use magnetic conduit data for ations in insulation materials and steel armor and non-magnetic 6 thicknesses, shielding, jacketing, over- conduit data for aluminum armor all diameters, and the like. Therefore, 7 data for medium voltage cables should be obtained from the manufacturer of the cable to be used. 8

Table 1.5-17. 60 Hz Impedance Data for Three-Phase Copper Cable Circuits, in Approximate Ohms per 1000 ft (305 m) at 75 °C (a) Three Single Conductors Wire Size, In Magnetic Duct In Non-Magnetic Duct 9 AWG or 600 V and 5 kV Non-Shielded 5 kV Shielded and 15 kV 600 V and 5 kV Non-Shielded 5 kV Shielded and 15 kV kcmil RXZRXZRXZRXZ 10 8 0.811 0.0754 0.814 0.811 0.0860 0.816 0.811 0.0603 0.813 0.811 0.0688 0.814 8 (solid) 0.786 0.0754 0.790 0.786 0.0860 0.791 0.786 0.0603 0.788 0.786 0.0688 0.789 6 0.510 0.0685 0.515 0.510 0.0796 0.516 0.510 0.0548 0.513 0.510 0.0636 0.514 11 6 (solid) 0.496 0.0685 0.501 0.496 0.0796 0.502 0.496 0.0548 0.499 0.496 0.0636 0.500 4 0.321 0.0632 0.327 0.321 0.0742 0.329 0.321 0.0506 0.325 0.321 0.0594 0.326 4 (solid) 0.312 0.0632 0.318 0.312 0.0742 0.321 0.312 0.0506 0.316 0.312 0.0594 0.318 12 2 0.202 0.0585 0.210 0.202 0.0685 0.214 0.202 0.0467 0.207 0.202 0.0547 0.209 1 0.160 0.0570 0.170 0.160 0.0675 0.174 0.160 0.0456 0.166 0.160 0.0540 0.169 1/0 0.128 0.0540 0.139 0.128 0.0635 0.143 0.127 0.0432 0.134 0.128 0.0507 0.138 2/0 0.102 0.0533 0.115 0.103 0.0630 0.121 0.101 0.0426 0.110 0.102 0.0504 0.114 13 3/0 0.0805 0.0519 0.0958 0.0814 0.0605 0.101 0.0766 0.0415 0.0871 0.0805 0.0484 0.0939 4/0 0.0640 0.0497 0.0810 0.0650 0.0583 0.0929 0.0633 0.0398 0.0748 0.0640 0.0466 0.0792 250 0.0552 0.0495 0.0742 0.0557 0.0570 0.0797 0.0541 0.0396 0.0670 0.0547 0.0456 0.0712 14 300 0.0464 0.0493 0.0677 0.0473 0.0564 0.0736 0.0451 0.0394 0.0599 0.0460 0.0451 0.0644 350 0.0378 0.0491 0.0617 0.0386 0.0562 0.0681 0.0368 0.0393 0.0536 0.0375 0.0450 0.0586 400 0.0356 0.0490 0.0606 0.0362 0.0548 0.0657 0.0342 0.0392 0.0520 0.0348 0.0438 0.0559 15 450 0.0322 0.0480 0.0578 0.0328 0.0538 0.0630 0.0304 0.0384 0.0490 0.0312 0.0430 0.0531 500 0.0294 0.0466 0.0551 0.0300 0.0526 0.0505 0.0276 0.0373 0.0464 0.0284 0.0421 0.0508 600 0.0257 0.0463 0.0530 0.0264 0.0516 0.0580 0.0237 0.0371 0.0440 0.0246 0.0412 0.0479 750 0.0216 0.0495 0.0495 0.0223 0.0497 0.0545 0.0194 0.0356 0.0405 0.0203 0.0396 0.0445 16 Note: More tables on Page 1.5-16. 17

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CA08104001E For more information, visit: www.eaton.com/consultants 1.5-16 Power Distribution Systems Reference Data April 2016 Sheet 01 110 Conductor Resistance, Reactance, Impedance

Table 1.5-18. 60 Hz Impedance Data for Three-Phase Copper Cable Circuits, in Approximate Ohms per 1000 ft (305 m) at 75 °C (b) Three Conductor Cable i Wire Size, In Magnetic Duct and Steel Interlocked Armor In Non-Magnetic Duct and Aluminum Interlocked Armor AWG or 600 V and 5 kV Non-Shielded 5 kV Shielded and 15 kV 600 V and 5 kV Non-Shielded 5 kV Shielded and 15 kV kcmil ii RXZRXZRXZRXZ 8 0.811 0.0577 0.813 0.811 0.0658 0.814 0.811 0.0503 0.812 0.811 0.0574 0.813 8 (solid) 0.786 0.0577 0.788 0.786 0.0658 0.789 0.786 0.0503 0.787 0.786 0.0574 0.788 1 6 0.510 0.0525 0.513 0.510 0.0610 0.514 0.510 0.0457 0.512 0.510 0.0531 0.513 6 (solid) 0.496 0.0525 0.499 0.496 0.0610 0.500 0.496 0.0457 0.498 0.496 0.0531 0.499 4 0.321 0.0483 0.325 0.321 0.0568 0.326 0.321 0.0422 0.324 0.321 0.0495 0.325 4 (solid) 0.312 0.0483 0.316 0.312 0.0508 0.317 0.312 0.0422 0.315 0.312 0.0495 0.316 2 2 0.202 0.0448 0.207 0.202 0.0524 0.209 0.202 0.0390 0.206 0.202 0.0457 0.207 1 0.160 0.0436 0.166 0.160 0.0516 0.168 0.160 0.0380 0.164 0.160 0.0450 0.166 1/0 0.128 0.0414 0.135 0.128 0.0486 0.137 0.127 0.0360 0.132 0.128 0.0423 0.135 3 2/0 0.102 0.0407 0.110 0.103 0.0482 0.114 0.101 0.0355 0.107 0.102 0.0420 0.110 3/0 0.0805 0.0397 0.0898 0.0814 0.0463 0.0936 0.0766 0.0346 0.0841 0.0805 0.0403 0.090 4/0 0.0640 0.0381 0.0745 0.0650 0.0446 0.0788 0.0633 0.0332 0.0715 0.0640 0.0389 0.0749 4 250 0.0552 0.0379 0.0670 0.0557 0.0436 0.0707 0.0541 0.0330 0.0634 0.0547 0.0380 0.0666 300 0.0464 0.0377 0.0598 0.0473 0.0431 0.0640 0.0451 0.0329 0.0559 0.0460 0.0376 0.0596 350 0.0378 0.0373 0.0539 0.0386 0.0427 0.0576 0.0368 0.0328 0.0492 0.0375 0.0375 0.0530 5 400 0.0356 0.0371 0.0514 0.0362 0.0415 0.0551 0.0342 0.0327 0.0475 0.0348 0.0366 0.0505 450 0.0322 0.0361 0.0484 0.0328 0.0404 0.0520 0.0304 0.0320 0.0441 0.0312 0.0359 0.0476 500 0.0294 0.0349 0.0456 0.0300 0.0394 0.0495 0.0276 0.0311 0.0416 0.0284 0.0351 0.0453 600 0.0257 0.0343 0.0429 0.0264 0.0382 0.0464 0.0237 0.0309 0.0389 0.0246 0.0344 0.0422 6 750 0.0216 0.0326 0.0391 0.0223 0.0364 0.0427 0.0197 0.0297 0.0355 0.0203 0.0332 0.0389

7 Table 1.5-19. 60 Hz Impedance Data for Three-Phase Aluminum Cable Circuits, in Approximate Ohms per 1000 Ft (305 m) at 90 °C (a) Three Single Conductors Wire Size, In Magnetic Duct In Non-Magnetic Duct AWG or 600 V and 5 kV Non-Shielded 5 kV Shielded and 15 kV 600 V and 5 kV Non-Shielded 5 kV Shielded and 15 kV kcmil 8 RXZRXZRXZRXZ 6 0.847 0.053 0.849 — — — 0.847 0.042 0.848 — — — 4 0.532 0.050 0.534 0.532 0.068 0.536 0.532 0.040 0.534 0.532 0.054 0.535 9 2 0.335 0.046 0.338 0.335 0.063 0.341 0.335 0.037 0.337 0.335 0.050 0.339 1 0.265 0.048 0.269 0.265 0.059 0.271 0.265 0.035 0.267 0.265 0.047 0.269 1/0 0.210 0.043 0.214 0.210 0.056 0.217 0.210 0.034 0.213 0.210 0.045 0.215 10 2/0 0.167 0.041 0.172 0.167 0.055 0.176 0.167 0.033 0.170 0.167 0.044 0.173 3/0 0.133 0.040 0.139 0.132 0.053 0.142 0.133 0.037 0.137 0.132 0.042 0.139 4/0 0.106 0.039 0.113 0.105 0.051 0.117 0.105 0.031 0.109 0.105 0.041 0.113 250 0.0896 0.0384 0.0975 0.0892 0.0495 0.102 0.0894 0.0307 0.0945 0.0891 0.0396 0.0975 11 300 0.0750 0.0375 0.0839 0.0746 0.0479 0.0887 0.0746 0.0300 0.0804 0.0744 0.0383 0.0837 350 0.0644 0.0369 0.0742 0.0640 0.0468 0.0793 0.0640 0.0245 0.0705 0.0638 0.0374 0.0740 400 0.0568 0.0364 0.0675 0.0563 0.0459 0.0726 0.0563 0.0291 0.0634 0.0560 0.0367 0.0700 12 500 0.0459 0.0355 0.0580 0.0453 0.0444 0.0634 0.0453 0.0284 0.0535 0.0450 0.0355 0.0573 600 0.0388 0.0359 0.0529 0.0381 0.0431 0.0575 0.0381 0.0287 0.0477 0.0377 0.0345 0.0511 700 0.0338 0.0350 0.0487 0.0332 0.0423 0.0538 0.0330 0.0280 0.0433 0.0326 0.0338 0.0470 13 750 0.0318 0.0341 0.0466 0.0310 0.0419 0.0521 0.0309 0.0273 0.0412 0.0304 0.0335 0.0452 1000 0.0252 0.0341 0.0424 0.0243 0.0414 0.0480 0.0239 0.0273 0.0363 0.0234 0.0331 0.0405 14 Table 1.5-20. 60 Hz Impedance Data for Three-Phase Aluminum Cable Circuits, in Approximate Ohms per 1000 ft (30 m) at 90 °C (b) Three Conductor Cable Wire Size, In Magnetic Duct and Steel Interlocked Armor In Non-Magnetic Duct and Aluminum Interlocked Armor AWG or 600 V and 5 kV Non-Shielded 5 kV Shielded and 15 kV 600 V and 5 kV Non-Shielded 5 kV Shielded and 15 kV kcmil 15 RXZRXZRXZRXZ

6 0.847 0.053 0.849 — — — 0.847 0.042 0.848 — — — 4 0.532 0.050 0.534 — — — 0.532 0.040 0.534 — — — 16 2 0.335 0.046 0.338 0.335 0.056 0.340 0.335 0.037 0.337 0.335 0.045 0.338 1 0.265 0.048 0.269 0.265 0.053 0.270 0.265 0.035 0.267 0.265 0.042 0.268 1/0 0.210 0.043 0.214 0.210 0.050 0.216 0.210 0.034 0.213 0.210 0.040 0.214 17 2/0 0.167 0.041 0.172 0.167 0.049 0.174 0.167 0.033 0.170 0.167 0.039 0.171 3/0 0.133 0.040 0.139 0.133 0.048 0.141 0.133 0.037 0.137 0.132 0.038 0.138 4/0 0.106 0.039 0.113 0.105 0.045 0.114 0.105 0.031 0.109 0.105 0.036 0.111 18 250 0.0896 0.0384 0.0975 0.0895 0.0436 0.100 0.0894 0.0307 0.0945 0.0893 0.0349 0.0959 300 0.0750 0.0375 0.0839 0.0748 0.0424 0.0860 0.0746 0.0300 0.0804 0.0745 0.0340 0.0819 350 0.0644 0.0369 0.0742 0.0643 0.0418 0.0767 0.0640 0.0245 0.0705 0.0640 0.0334 0.0722 19 400 0.0568 0.0364 0.0675 0.0564 0.0411 0.0700 0.0563 0.0291 0.0634 0.0561 0.0329 0.0650 500 0.0459 0.0355 0.0580 0.0457 0.0399 0.0607 0.0453 0.0284 0.0535 0.0452 0.0319 0.0553 600 0.0388 0.0359 0.0529 0.0386 0.0390 0.0549 0.0381 0.0287 0.0477 0.0380 0.0312 0.0492 700 0.0338 0.0350 0.0487 0.0335 0.0381 0.0507 0.0330 0.0280 0.0433 0.0328 0.0305 0.0448 20 750 0.0318 0.0341 0.0466 0.0315 0.0379 0.0493 0.0309 0.0273 0.0412 0.0307 0.0303 0.0431 1000 0.0252 0.0341 0.0424 0.0248 0.0368 0.0444 0.0239 0.0273 0.0363 0.0237 0.0294 0.0378 21

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.5-17 April 2016 Reference Data Sheet 01 111 Conductor Ampacities

Current Carrying Capacities of Copper and Aluminum and Copper-Clad Aluminum Conductors From National Electrical Code (NEC), 2011 Edition (NFPA 70-2011) i Table 1.5-21. Allowable Ampacities of Insulated Conductors Rated 0–2000 V, 60 ° to 90 °C (140° to 194 °F). Not more than three current-carrying conductors in raceway, cable or earth (directly buried), based on ambient temperature of 30 °C (86 °F). ii Size Temperature Rating of Conductor (See Table 310.15 [B][16]) Size AWG or 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 or 1 kcmil Types Types kcmil TW, UF RHW, THHW, TBS, SA, SIS, FEP, TW, UF RHW, THHW, TBS, SA, SIS, THW, THWN, FEPB, MI, THW, THWN, THHN, THHW, XHHW, USE, ZW RHH, RHW-2, XHHW, USE THW-2, THWN-2, 2 THHN, THHW, RHH, RHW-2, THW-2, THWN-2, USE-2, XHH, USE-2, XHH, XHHW, XHHW-2, 3 XHHW, XHHW-2, ZW-2 ZW-2 Copper Aluminum or Copper-Clad Aluminum 4 18 — — 14 — — — — 16 — — 18 — — — — 14 1 15 20 25 — — — — 5 12 1 20 25 30 20 20 25 12 1 10 1 30 35 40 25 30 35 10 1 8 40 50 55 30 40 45 8 6 6 55 65 75 40 50 60 6 4 70 85 95 55 65 75 4 3 85 100 110 65 75 85 3 7 2 95 115 130 75 90 100 2 1 110 130 150 85 100 115 1 1/0 125 150 170 100 120 135 1/0 8 2/0 145 175 195 115 135 150 2/0 3/0 165 200 225 130 155 175 3/0 4/0 195 230 260 150 180 205 4/0 9 250 215 255 290 170 205 230 250 300 240 285 320 190 230 255 300 350 260 310 350 210 250 280 350 10 400 280 335 380 225 270 305 400 500 320 380 430 260 310 350 500 600 355 420 475 285 340 385 600 11 700 385 460 520 310 375 420 700 750 400 475 535 320 385 435 750 800 410 490 555 330 395 450 800 900 435 520 585 355 425 480 900 12 1000 455 545 615 375 445 500 1000 1250 495 590 665 405 485 545 1250 1500 520 625 705 435 520 585 1500 13 1750 545 650 735 455 545 615 1750 2000 560 665 750 470 560 630 2000 1 See NEC Section 240.4 (D). 14 Note: For complete details of using Table 1.5-21, see NEC Article 310 in its entirety.

Table 1.5-22. Correction Factors From NFPA 70-2011 (See Table 310.15 [B][2][a]) 15 Ambient For ambient temperatures other than 30 °C (86 °F), multiply the allowable ampacities shown Ambient Temperature °C above by the appropriate factor shown below. Temperature °F 16 21–25 1.08 1.05 1.04 1.08 1.05 1.04 070–77 26–30 1.00 1.00 1.00 1.00 1.00 1.00 078–86 31–35 0.91 0.94 0.96 0.91 0.94 0.96 087–95 17 36–40 0.82 0.88 0.91 0.82 0.88 0.91 096–104 41–45 0.71 0.82 0.87 0.71 0.82 0.87 105–113 46–50 0.58 0.75 0.82 0.58 0.75 0.82 114–122 18 51–55 0.41 0.67 0.76 0.41 0.67 0.76 123–131 56–60 — 0.58 0.71 — 0.58 0.71 132–140 61–70 — 0.33 0.58 — 0.33 0.58 141–158 19 71–80 — — 0.41 — — 0.41 159–176 20

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CA08104001E For more information, visit: www.eaton.com/consultants 1.5-18 Power Distribution Systems Reference Data April 2016 Sheet 01 112 Conductor Ampacities

Ampacities for Conductors (4) Preservation of the safety benefits (4) Adjustment factors shall not i of established industry practices apply to Type AC cable or to Rated 0–2000 V (Excerpted and standardized procedures. Type MC cable under the following from NFPA 70-2011, 310.15) conditions: ii (1) General. For explanation of type let- Note: Fine Print Note (FPN) was changed ters used in tables and for a. The cables do not have an overall to Informational Note in the 2011 NEC. recognized sizes of conductors for outer jacket. 1 the various conductor insulations, (A) General. see Table 310.104(A) and Table b. Each cable has not more than three current-carrying conductors. (1) Tables or Engineering Supervision. 310.104(B). For installation 2 Ampacities for conductors shall requirements, see 310.1 through c. The conductors are 12 AWG copper. be permitted to be determined by 310.15(A)(3) and the various tables as provided in 310.15(B) or articles of this Code. For flexible d. Not more than 20 current-carrying 3 under engineering supervision, cords, see Table 400.4, Table conductors are installed without as provided in 310.15(C). 400.5(A)(1) and Table 400.5(A)(2). maintaining spacing, are stacked, or are supported on”bridle rings.” Note: Informational Note No. 1: Ampacities (3) Adjustment Factors. 4 provided by this section do not take voltage (5) An adjustment factor of 60 percent drop into consideration. See 210.19(A), (a) More Than Three Current- shall be applied to Type AC cable or Informational Note No. 4, for branch circuits Carrying Conductors in a Raceway Type MC cable under the following 5 and 215.2(A), Informational No. 2, for feeders. or Cable. Where the number of conditions: Note: Informational Note No. 2: For the current-carrying conductors in a allowable ampacities of Type MTW wire, raceway or cable exceeds three, or a. The cables do not have an overall 6 see Table 13.5.1 in NFPA 79-2007, Electrical where single conductors or multi- outer jacket. Standard for Industrial Machinery. conductor cables are installed b. The number of current carrying without maintaining spacing for conductors exceeds 20. 7 (2) Selection of Ampacity. Where a continuous length longer than more than one ampacity applies 24.00-inch (600 mm) and are not c. The cables are stacked or bundled for a given circuit length, the installed in raceways, the allowable longer that 24.00-inch (600 mm) 8 lowest value shall be used. ampacity of each conductor shall be without spacing being maintained. Exception: Where two different reduced as shown in Table ampacities apply to adjacent 310.15(B)(3)(a). Each current-carry- (b) More Than One Conduit, Tube, 9 portions of a circuit, the higher ing conductor of a paralleled set of or Raceway. Spacing between ampacity shall be permitted to conductors shall be counted as a conduits, tubing, or raceways be used beyond the point of current-carrying conductor. shall be maintained. 10 transition, a distance equal to 10 ft (3.0 m) or 10 percent of the circuit Note: Informational Note No. 1: See Annex (c) Circular Raceways Exposed to length figured at the higher B, Table B.310.15(B)(2)(11), for adjustment Sunlight on Rooftops. ampacity, whichever is less. factors for more than three current-carrying 11 conductors in a raceway or cable with Where conductors or cables are Note: Informational Note: See 110.14(C) for load diversity. installed in circular raceways exposed conductor temperature limitations due to to direct sunlight on or above rooftops, 12 termination provisions. Note: Informational Note No. 2: See 366.23(A) the adjustments shown in Table 1.5-23 for adjustment factors for conductors in shall be added to the outdoor (B) Tables. Ampacities for conductors sheet metal auxiliary gutters and 376.22(B) temperature to determine the 13 rated 0–2000 V shall be as specified for adjustment factors for conductors in applicable ambient temperature metal wireways. in the Allowable Ampacity for application of the correction 14 Table 310.15(B)(16) through (1) Where conductors are installed in factors in Table 310.15(B)(2)(a) or Table 310.15(B)(19), and cable trays, the provisions of Table 310.15(B)(2)(b). Ampacity Table 310.15(B)(20) and 392.80 shall apply. Table 310.15(B)(21) as modified Note: Informational Note: One source for 15 the average ambient temperatures in various by 310.15(B)(1) through (B)(7). (2) Adjustment factors shall not apply locations is the ASHRAE Handbook to conductors in raceways having Note: Informational Note: Table —Fundamentals. a length not exceeding 24.00-inch 16 310.15(B)(16) through Table 310.15(B)(19) are application tables for use in determining (600 mm). Table 1.5-23. NEC (2011) Table 310.15(B)(3)(c) Ambient Temperature Adjustment for Circular conductor sizes on loads calculated in (3) Adjustment factors shall not apply accordance with Article 220. Allowable Raceways Exposed to Sunlight On or 17 ampacities result from consideration of one to underground conductors enter- Above Rooftops or more of the following: ing or leaving an outdoor trench if those conductors have physical Distance Above Roof to Temperature Bottom of Conduit Adder ºF (ºC) 18 (1) Temperature compatibility with protection in the form of rigid connected equipment, especially metal conduit, intermediate metal 0–0.51-inch (0–13.0 mm) 60 (33) the connection points. conduit, rigid polyvinyl chloride Above 0.51-inch (13.0 mm)– 40 (22) 19 conduit (PVC), or reinforced 3.54-inch (90.0 mm) (2) Coordination with circuit and thermosetting resin conduit (RTRC) Above 3.54-inch (90.0 mm)– 30 (17) system overcurrent protection. 20 having a length not exceeding 11.81-inch (300.0 mm) (3) Compliance with the requirements 10 ft (3.05 m), and if the number of Above 12.00-inch (300.0 mm)– 25 (14) of product listings or certifications. conductors does not exceed four. 36.00-inch (900.0 mm) 21 See 110.3(B).

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.5-19 April 2016 Reference Data Sheet 01 113 Conductor Ampacities

(4) Bare or Covered Conductors. (b) In a three-wire circuit consisting (6) Grounding or Bonding Conductor. Where bare or covered conductors of two phase conductors and the A grounding or bonding conductor i are installed with insulated neutral conductor of a four-wire, shall not be counted when applying conductors, the temperature three-phase, wye-connected the provisions of 310.15(B)(3)(a). rating of the bare or covered system, a common conductor ii conductor shall be equal to the carries approximately the same lowest temperature rating of the current as the line-to-neutral load insulated conductors for the currents of the other conductors 1 purpose of determining ampacity. and shall be counted when applying the provisions of 310.15(B)(3)(a). (5) Neutral Conductor. 2 (c) On a four-wire, three-phase wye (a) A neutral conductor that carries circuit where the major portion of only the unbalanced current from the load consists of nonlinear loads, 3 other conductors of the same harmonic currents are present in circuit shall not be required to the neutral conductor; the neutral be counted when applying the conductor shall therefore be con- 4 provisions of 310.15(B)(3)(a). sidered a current-carrying conductor. 5

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CA08104001E For more information, visit: www.eaton.com/consultants 1.5-20 Power Distribution Systems Reference Data April 2016 Sheet 01 114 Formulas and Terms

Table 1.5-24. Formulas for Determining Amperes, hp, kW and kVA i To Direct Alternating Current Find Current Single-Phase Two-Phase—Four-Wire 1 Three-Phase

hp 746 hp 746 hp 746 hp 746 ii Amperes (l) when     horsepower is known E% eff E% eff pf 2E  % eff  pf 3E  % eff  pf Amperes (l) when kW 1000 kW 1000 kW 1000 kW 1000     1 kilowatts is known E Epf 2E  pf 3E  % pf Amperes (l) when — kVA 1000 kVA 1000 kVA 1000    kva is known E 2E 3E 2 Kilowatts IE lE  pf lE2  pf lE 3 pf     1000 1000 1000 1000 kVA — IE IE2 IE 3    3 1000 1000 1000 Horsepower (output) IE  % eff IE % eff pf IE2 % eff pf IE 3% eff pf     746 746 746 746 4 1 For two-phase, three-wire circuits, the current in the common conductor is 2 times that in either of the two other conductors. Note: Units of measurement and definitions for E (volts), I (amperes), and other abbreviations are given below under Common Electrical Terms. 5 Common Electrical Terms How to Compute Power Factor Ampere (l) = unit of current or rate of flow of electricity Watts Determining Watts pf = ------6 Volt (E) = unit of electromotive force Volts Amperes Ohm (R) = unit of resistance 1. 1. From watthour meter. E Watts = rpm of disc x 60 x Kh 7 Ohms law: I =  (DC or 100% pf) R Where Kh is meter constant Megohm = 1,000,000 ohms printed on face or nameplate 8 Volt Amperes (VA) = unit of apparent power of meter. = El (single-phase) If metering transformers are used, 9 = El  3 above must be multiplied by the Kilovolt Amperes (kVA) = 1000 volt-amperes transformer ratios. 10 Watt (W) = unit of true power 2. Directly from wattmeter reading. Where: = VA pf 11 = 0.00134 hp Volts = line-to-line voltage as measured by voltmeter. Kilowatt (kW) = 1000 watts 12 Power Factor (pf) = ratio of true to apparent power Amperes = current measured in W kW line wire (not neutral) by ammeter. = ------13 VA kVA Table 1.5-25. Temperature Conversion Watthour (Wh) = unit of electrical work (F° to C°) C° = 5/9 (F°–32°) = 1 watt for 1 hour (C° to F°) F° = 9/5(C°)+32° 14 = 3.413 Btu C° –15 –10 –5 0 5 10 15 20 = 2655 ft-lbs F° 5 14 23 32 41 50 59 68 Cº 25 30 35 40 45 50 55 60 15 Kilowatt-hour (kWh) = 1000 watthours F° 77 86 95 104 113 122 131 140 Horsepower (hp) = measure of time rate of doing work C° 65 70 75 80 85 90 95 100 F° 149 158 167 176 185 194 203 212 16 = equivalent of raising 33,000 lbs 1 ft in 1 minute = 746 watts 1 Inch = 2.54 centimeters 1 Kilogram = 2.20 lbs 17 Demand Factor = ratio of maximum demand to the total connected load 1 Square Inch = 1,273,200 circular mills Diversity Factor = ratio of the sum of individual maximum demands of 1 Circular Mill = 0.785 square mil 18 the various subdivisions of a system to the maximum 1 Btu = 778 ft lbs demand of the whole system = 252 calories 19 Load Factor = ratio of the average load over a designated period 1 Year = 8760 hours of time to the peak load occurring in that period 20

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For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.5-21 April 2016 Reference Data Sheet 01 115 Seismic Requirements

Seismic Requirements i

ii

1 General In the 1980s, Eaton embarked on a 2 comprehensive program centered around designing and building electrical distribution and control 3 equipment capable of meeting and exceeding the seismic load require- ments of the Uniform Building Code 4 (UBC) and California Building Code (CBC). These codes emphasize build- ing design requirements. Electrical 5 equipment and distribution system components are considered attach- ments to the building. The entire 6 program has been updated to show compliance with the 2009 International Building Code (IBC) and the 2010 CBC 7 seismic requirements. A cooperative Figure 1.5-1. Typical Earthquake Ground Motion Map for the United States effort with the equipment user, the building designer and the equipment International Building Code (IBC) California Building Code 8 installer ensures that the equipment On December 9, 1994, the International The 2001 CBC was based upon the is correctly anchored such that it can Code Council (ICC) was established 1997 UBC. In August of 2006, it was withstand the effects of an earthquake. as a nonprofit organization dedicated repealed by the California Building 9 Eaton’s electrical distribution and to developing a single set of compre- Standards Commission (CBSC) and control equipment has been tested hensive and coordinated codes. The replaced by the 2007 CBC, California and seismically proven for require- ICC founders—the Building Officials Code of Regulations (CCR), Title 24, 10 ments exceeding the IBC and CBC. and Code Administrators (BOCA), the Part 2 and used the 2006 IBC as the Over 100 different assemblies International Conference of Building basis for the code. The 2010 CBC representing essentially all product Officials (ICBO), and the Southern is based upon the 2009 IBC, with 11 lines have been successfully tested Building Code Congress International amendments as deemed appropriate and verified to seismic levels higher (SBCCI)—created the ICC in response by the CBSC. Eaton’s seismic than the maximum seismic require- to technical disparities among the qualification program fully envelopes 12 ments specified in the IBC and CBC. three nationally recognized model the requirements of the 2010 CBC. The equipment maintained structural codes now in use in the U.S. The integrity and demonstrated the ability ICC offers a single, complete set of Process 13 to function immediately after the construction codes without regional seismic tests. A technical paper, According to Chapter 16 of the 2009 limitations—the International IBC, structure design, the seismic Earthquake Requirements and Eaton Building Code. 14 Distribution and Control Equipment requirements of electrical equipment Seismic Capabilities (SA12501SE), Uniform Building Code (UBC) in buildings may be computed in two provides a detailed explanation steps. The first step is to determine 15 of the applicable seismic codes 1997 was the final year in which the the maximum ground motion to be and Eaton’s equipment qualification UBC was published. It has since been considered at the site. The second step program. The paper may be found replaced by the IBC. is to evaluate the equipment mounting 16 at www.eaton.com/seismic. Type and attachments inside the building in SA12501SE in the document or structure. These are then evaluated search field. to determine appropriate seismic test 17 requirements. The ground motion, seismic requirements of the equipment, and the seismic response spectrum 18 requirements are discussed on Page 1.5-23, see Figure 1.5-3. 19

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CA08104001E For more information, visit: www.eaton.com/consultants 1.5-22 Power Distribution Systems Reference Data April 2016 Sheet 01 116 Seismic Requirements

Ground Motion If the latitude and longitude of the SDS, the peak spectral acceleration, i building location is not known, extends between the values of T and According to the code, the first and 0 another convenient Web site is TS. T0 and TS are defined in the codes most important step in the process available that will provide this as follows: ii is to determine the maximum information based upon a street considered earthquake spectral address: http://geocoder.us/ T0 = 0.2 SD1/SDS = 0.2 x 1.24/1.90 = response acceleration at short 0.131 seconds (7.63 Hz) 1 periods of 0.2 seconds (SS) and at To determine the maximum considered a period of 1.0 second (S ). These earthquake ground motion for most TS = SD1/SDS = 1.24/1.90 = 1 0.653 seconds (1.53 Hz) values are determined from a set site classes (A through D), the code 2 of 24 spectral acceleration maps introduces site coefficients, which According to the IBC and ASCE 7, the (Figure 1.5-1) and include numerous when applied against the location- spectral acceleration (Sa) at periods contour lines indicating the severity specific site class, produces the less than 1.45 seconds may be com- 3 of the earthquake requirements at a adjusted maximum considered puted by using the following formula: particular location in the country. earthquake spectral response acceleration for the required site. Sa = SDS (0.6 T/T0 + 0.4) The spectral acceleration maps 4 The site coefficients are defined as Where T is the period where S is indicate low to moderate seismic F at 0.2 seconds short period and a requirements for the entire country, a being calculated: FV at 1.0 second period. From the 5 with the exception of two particular tables in the code, the highest adjust- Therefore, the acceleration at areas; the West Coast and the Midwest ing factor for S is equal to 1.0 and the 0.0417 seconds (24 Hz), for example, (the New Madrid area). The seismic S highest adjusting factor for S1 is 1.50. is equal to: 6 requirements at the New Madrid area are approximately 30% higher than the As a result, the adjusted maximum Sa = 1.90 (0.6 (0.0417/0.131) + 0.4) = 1.12 g maximum requirements of the West considered earthquake spectral Coast. The maps also suggest that the response for 0.2 second short period The acceleration at 0.03 seconds 7 (33 Hz) is equal to: high seismic requirements in both (SMS) and at 1.0 second (SM1), adjusted regions, West Coast and Midwest, for site class effects, are determined Sa = 1.90 (0.6 (0.03/0.131) + 0.4) = 1.02 g quickly decrease as one moves away from the following equations: 8 from the fault area. Therefore, the high At zero period (infinite frequency), requirements are only limited to a SMS = Fa SS = 1.0 x 2.85 g = 2.85 g T = 0.0, the acceleration (ZPA) is relatively narrow strip along the fault equal to: SM1 = Fv S1 = 1.5 x 1.24 g = 1.86 g 9 lines. Just a few miles away from this S = 1.90 (0.6 (0.0/0.131) + 0.4) = strip, only a small percentage of the ASCE 7 (American Society of Civil a 0.76 g (ZPA) 10 maximum requirements are indicated. Engineers), Section 11.4, provides a plot of the final shape of the design The acceleration to frequency Assuming the worse condition, which response spectra of the seismic relationship in the frequency range is a site directly located near a fault, ground motion. The plot is shown in of 1.0 Hz to TS is stated equal to: 11 the maximum considered earthquake Figure 1.5-2. ASCE 7 is referenced spectral response acceleration at short throughout the IBC as the source for Sa = SD1/T periods of 0.2 seconds (SS) is equal to numerous structural design criteria. 12 285% gravity and at 1.0 second period Where Sa is the acceleration at the T period. (S1) is 124% gravity. These numbers The design spectral acceleration curve are the maximum numbers for the can now be computed. The peak spec- At 1.0 Hz (T=1.0) this equation yields 13 entire country except for the New tral acceleration (SDS) and the spectral the following acceleration: Madrid area. These particular sites are acceleration at 1.0 second (SD1) may on the border of California and Mexico now be computed from the following Sa = 1.24/1 = 1.24 g 14 (S1) and in Northern California (SS). formulas in the code:

To help understand the 2009 IBC (and SDS = 2/3 x SMS = 2/3 x 2.85 g = 1.90 g 2010 CBC) seismic parameters for a 15 S = 2/3 x S = 2/3 x 1.8 g = 1.24 g specific building location, the link to D1 M1 the US Geological Society is extremely 16 helpful: http://earthquake.usgs.gov/ (g)

research/hazmaps/design/ a S Download the file “Java Ground DS 17 SD1 Motion Parameter Calculator”—and Sa = save it to your hard drive, then run the T 18 executable that was downloaded. The program will allow one to enter SD1 SD1 TL Sa = 2 the latitude and longitude of a T 19 location. (One must be connected to the Internet to run this application, even after downloading the program.) 20 The IBC (CBC) seismic parameters for T0 TS 1.0 TL that location will then be displayed. A cc eler a t i on S Spe c tur a l Response Period T (sec) 21 Figure 1.5-2. Design Response Spectrum

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.5-23 April 2016 Reference Data Sheet 01 117 Seismic Requirements

Testing has demonstrated that the It can be seen that Eaton has elected to This completes the ground motion lowest dominant natural frequency of develop generic seismic requirements design response spectrum. The i Eaton’s electrical equipment is above that envelop two criteria: spectral accelerations are equal to 3.2 Hz. This indicates that testing at 0.76 g at ZPA, or 33 Hz, and increases ■ 1.24g at 1 Hz is not necessary. In The highest possible spectral peak linearly to a peak acceleration of 1.90 g ii addition, having the low end of the accelerations and ZPA at 0.09 seconds (or 11.49 Hz) and stays spectra higher than realistically ■ The maximum frequency range constant to 0.653 seconds (1.53 Hz), required forces the shake table to required for many different sites then gradually decreases to 1.24 g at 1 move at extremely high displacements 1 second (or 1.0 Hz). This curve is to meet the spectral acceleration at shown in Figure 1.5-3. the low frequencies. 2 Testing to accommodate the low end 10 of the spectra using this acceleration 9 3 component can result in testing to a 8 7 Test Response Spectrum Zero Period factor 2 to 3 times greater than that 6 (TRS) Acceleration = Maximum realistically required. 5 Table Test Motion 4 4 Through testing experience and data 3 analysis, the seismic acceleration at a t i on ( g p e k) 5 1.0 Hz is taken equal to 0.7 g, which 2 Spectrum Dip – Not Important Because Frequency is Not an will ensure that the seismic levels are cc eler A Equipment Natural Frequency achieved well below 3.2 Hz. This yields 6 a more vigorous test over a wider 1. 0 .9 range of seismic intensities. .8 .7 Required Response Spectrum In developing the seismic requirements .6 Zero Period 7 .5 (RRS) Acceleration = Maximum above, it is important to recognize Floor Motion the following: .4 .3 8 T0 and TS are dependent on SMS and SD1. If SD1 is small relative to SMS then .2 T0 and TS will be smaller and the 9 associated frequencies will shift .1 higher. The opposite is also true. 1 23 4 5 678 9 10 20 30 40 60 80 100 This must be realized in developing Frequency Hz 10 the complete required response spectrum (RRS). Therefore, it is not Figure 1.5-3. Design Response Spectrum adequate to stop the peak spectral 11 acceleration at 7.63 Hz. There are other ASCE 7 Section 13.3—Seismic Rp = Component response modifica- contour line combinations that will Demands on Non-Structural tion factor that for electrical equipment produce higher T0. To account for this varies from 2.5 to 6.0. 12 variation it is almost impossible to Components consider all combinations. However, Ip = Component importance factor that ASCE 7 Paragraph 13.3.1 (IBC Section is either 1.0 or 1.5. a study of the spectral acceleration 1621.1.4) provides a formula for 13 maps indicates that all variations with computing the seismic requirements Z = Highest point of equipment in a high magnitude of contour lines could of electrical and mechanical equipment building relative to grade elevation. very well be enveloped by a factor inside a building or a structure. The 14 of 1.5. Therefore, T0 is recomputed formula is designed for evaluating the h = Average roof height of building as follows: equipment attachment to the equip- relative to grade elevation. ment foundations. The seismic loads 15 T0 = 0.2 SD1/(SDS x 1.5) = 0.2 x 1.24/(1.90 The following parameters produce the x 1.5) = 0.087 seconds (11.49 Hz) are defined as: maximum required force: Eaton ensures maximum certification Fp = 0.4 ap SDS Wp (1 + 2 Z/h)/(Rp/Ip) ■ Z is taken equal to h (equipment 16 by requiring peak acceleration during Where: on roof) testing to extend to 12 Hz. ■ Ip is taken equal to 1.5 17 Fp = Seismic design force imposed ■ a is taken equal to 2.5 at the component’s center of gravity p ■ (C.G.) and distributed relative to Rp is taken equal to 2.5 component mass distribution. ■ SDS is equal to 1.90 g as indicated 18 in the previous section ap = Component amplification factor that varies from 1.00 to 2.50. The acceleration (Fp/Wp) at the C.G. 19 of the equipment is then computed SDS = Ground level spectral equal to: acceleration, short period. 20 Acceleration = Fp/Wp = 0.4 x 2.5 x Wp = Component operating weight. 1.90 g (1 + 2) / (2.5/1.5) = 3.42 g 21

CA08104001E For more information, visit: www.eaton.com/consultants 1.5-24 Power Distribution Systems Reference Data April 2016 Sheet 01 118 Seismic Requirements

For equipment on (or below) grade, i the acceleration at the equipment C.G. 10 is then computed equal to:

ii Acceleration = Fp/Wp = 0.4 x 2.5 x 1.90 g (1 + 0) / (2.5 /1.5) = 1.14 g IBC 2009/CBC 2010 IBC 2009 New Madrid It is impractical to attempt to measure 1 the actual acceleration of the C.G. of a piece of equipment under seismic test. The seismic response at the middle of 2 base mounted equipment close to its 1 C.G. is at least 50% higher than the Eaton Seismic 3 floor input at the equipment natural frequency. The base accelerations A cc eler a t i on (g) associated with the accelerations of FP/WP at the C.G. of the equipment 4 could then be computed as 3.42 /1.5 = 2.28 g. It is the equipment base input acceleration that is measured and 0.1 5 documented during seismic testing 1 10 100 and is the acceleration value shown 6 on Eaton’s seismic certificates. Frequency (Hz) Final Combined Requirements Figure 1.5-4. Required Response Spectrum Curve 7 To better compare all seismic levels and determine the final envelope seismic requirements, the 2010 CBC, 10 8 2009 IBC for California, and 2009 IBC for New Madrid area seismic require- ments are plotted in Figure 1.5-4. All Eaton 120% Seismic Envelope 9 curves are plotted at 5% damping. An envelopment of the seismic levels in the frequency range of 3.2 Hz to 100 Hz is also shown. This level is taken as 10 Eaton 100% Seismic Envelope Eaton’s generic seismic test require- 1 ments for all certifications. Eaton 11 performed additional seismic test runs on the equipment at approximately

120% of the generic enveloping seismic A cc eler a t i on (g) 12 requirements (see Figure 1.5-5). Eaton has established this methodology to provide additional margin to accom- 13 modate potential changes with the spectral maps, thus eliminating the 0.1 need for additional testing. 14 1 10 100 Frequency (Hz)

15 Figure 1.5-5. Eaton Test Required Response Spectrum Curve

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For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.5-25 April 2016 Reference Data Sheet 01 119 Seismic Requirements

Product Specific Test Summaries i Table 1.5-26. Distribution Equipment Tested and Seismically Proven Against Requirements within IBC 2009 y ii Eaton Equipment

Low voltage metal-enclosed switchgear DS II 1 Magnum DS High resistance ground Panelboards 2 Pow-R-Line C 1a, 1a-LX, 2a, 2a-LX, 3a, 3E, 4, 5P, F-16 and Pow-R-Command™ Switchboards 3 Instant Pow-R-Line 5P Integrated facilities Pow-R-Line C Multimeter Pow-R-Line i MCC 4 Advantage® IT. FlashGard® Series 2100 Freedom 2100 5 Low voltage busway Pow-R-Way® and associated fittings Pow-R-Way III® and associated fittings 6 Dry type transformers Mini powercenters EP, EPT, DS-3, DT-3 Transfer switches 7 Automatic transfer switch equipment Uninterruptible power supplies (UPS) Battery modules 8 UPSs Enclosed control safety switches General-duty 9 Heavy-duty Elevator control module Medium voltage switchgear 10 Type VacClad-W Type MMVS MEF Type MVS/MEB MV bus Metal-enclosed non-segregated phase bus 11 Network protectors Type CM-22 Type CMD 12 Medium voltage control AMPGARD® SC9000 drives 13 Substation transformers Dry-type Liquid type Unitized dry-type power centers Figure 1.5-6. Sample Seismic Certificate 14

Note: See www.eaton.com/seismic for current seismic certificates. 15

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CA08104001E For more information, visit: www.eaton.com/consultants 1.5-26 Power Distribution Systems Reference Data April 2016 Sheet 01 120 Seismic Requirements

Additional Design and If steel, factors such as thickness or Stand-Alone or Free-Standing Equipment i Installation Considerations gauge, attachment via bolts or welding, If stand-alone or free-standing, then and the size and type of hardware this may require that additional width When installing electrical distribution must be considered. space be allowed at each end of the ii and control equipment, consideration If concrete, the depth, the PSI, the type equipment for additional seismic must be given as to how the methods bracing supplied by the manufacturer. employed will affect seismic forces of re-enforcing bars used, as well as 1 imposed on the equipment, equipment the diameter and embedment of Additional thought must be given to mounting surface, and conduits anchorage all must be considered. the clearances around the equipment entering the equipment. The designer must also give consider- to rigid structural edifices. Space must 2 ation if the equipment will be secured be allowed for the differing motions of Eaton recommends that when specify- the equipment and the structure, so ing a brand of electrical distribution to the wall, versus stand-alone or free- standing, which requires the equip- that they do not collide during a seis- 3 and control equipment, the designer mic event and damage one another. references the installation manuals of ment to withstand the highest level of that manufacturer to ascertain that the seismic forces. Top cable entry should Note: If the equipment is installed as stand- 4 requirements can be met through the be avoided for large enclosures, as alone or free-standing, with additional design and construction process. accommodation for cable/conduit seismic bracing at each end and not flexibility will need to be designed attached to the structure as tested, and yet, For Eaton electrical distribution and into the system. it is fitted tightly against a structural wall, 5 control products, the seismic installa- then this would be an incorrect installation tion guides for essentially all product For a manufacturer to simply state for the application of the seismic certificate. lines can be found at our Web site: “Seismic Certified” or “Seismic Furthermore, if conduits are to be 6 http://www.eaton.com/seismic. Qualified” does not tell the designer if the equipment is appropriate for installed overhead into the equipment, Electrical designers must work closely the intended installation. does the design call for flexible conduits 7 with the structural or civil engineers of sufficient length to allow for the for a seismic qualified installation. Note: Eaton recommends that designers conflicting motion of the equipment confirm with the manufacturer if the and the structure during a seismic event Consideration must be given to the seismic certification supplied with the 8 equipment is based on: so as to not damage the conductors type of material providing anchorage contained therein, and the terminations for the electrical equipment. points within the equipment. 9 1. ACTUAL shaker table test as required by the IBC and CBC. Structure Attached Equipment 2. The seismic certificate and test The designer must work closely 10 data clearly state if the equipment with the structural engineer if the was tested as free-standing— equipment is to be attached to the anchored at the bottom of the structure to ascertain that the internal 11 equipment to the shaker table. wall re-enforcement of the structure, type of anchor, and depth of embed- 3. Structure attached, that is, ment is sufficient to secure the 12 anchored at the center of gravity equipment so that the equipment, (C.G.) or at the TOP of the equip- conduits and structure move at or ment to a simulated wall on the near the same frequency. 13 shaker table.

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