Power Distribution Systems 1.0-1 August 2017 Sheet 01 001

Contents i Power Distribution Systems System Protection Considerations System Design Overcurrent Protection ii Basic Principles...... 1.1-1 and Coordination ...... 1.5-1 Trends in Systems Design . . 1.1-1 Grounding/Ground Fault Protection Goals of System Design . . . 1.1-2 Grounding—Equipment, 1 Designing a Distribution System System, MV System, Development of a System LV System ...... 1.6-1 One-Line ...... 1.2-1 Typical Power System Components 2 Importance of a System Typical Power System One-Line ...... 1.2-2 Components ...... 1.7-1 3 Power System One-Line . . . 1.2-4 Transformers ...... 1.7-4 Standardized Drawing Generators and Symbols ...... 1.2-6 Generator Systems ...... 1.7-13 4 Types of Systems Generator Short-Circuit Types of Systems ...... 1.3-1 Characteristics...... 1.7-16 Power System Analysis Generator Set Sizing 5 Systems Analysis ...... 1.4-1 and Ratings...... 1.7-20 Short-Circuit Currents— Generator Set Installation 6 General ...... 1.4-1 and Site Considerations . . . 1.7-21 Fault Current Waveform Capacitors and Relationships ...... 1.4-3 Power Factor ...... 1.7-22 7 Fault Current Calculations Motor Power Factor and Methods Index ...... 1.4-4 Correction ...... 1.7-23 Typical Application by Facility Type Systems Fault Current Calculations 8 for Specific Equipment— Healthcare Facilities ...... 1.8-1 Exact Method ...... 1.4-5 Quick Connect Generator Application Quick Check and Load Bank 9 Table ...... 1.4-8 Capabilities ...... 1.8-7 Medium-Voltage Fuses— Power Quality Fault Calculations ...... 1.4-11 10 Low-Voltage Power Power Quality Terms Technical Circuit Breakers— Overview...... 1.9-1 Fault Calculations ...... 1.4-12 Other Application Considerations 11 Molded-Case Breakers Seismic Requirements . . . . 1.10-1 and Insulated Case Reference Data Circuit Breakers— 12 Fault Calculations ...... 1.4-13 Codes and Standards . . . . . 1.11-1 Low-Voltage Circuit Breaker Suggested IEEE Designations 13 Interrupting Derating for Suffix Letters...... 1.11-6 Factors ...... 1.4-13 Ampacities for Conductors Short-Circuit Calculations— Rated 0–2000 V...... 1.11-12 14 Shortcut Method ...... 1.4-14 Determining X and R Values from Transformer 15 Loss Data ...... 1.4-17 Voltage Drop ...... 1.4-20 16

19 Power Distribution Power 20

CA08104001E For more information, visit: www.eaton.com/consultants 1.0-2 Power Distribution Systems August 2017 Sheet 01 002

This page intentionally left blank. i ii

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.1-1 August 2017 System Design Sheet 01 003

Basic Principles Trends in Systems Design The growing impact of adverse weather conditions such as hurricanes and i The best distribution system is one There are many new factors to flooding is now driving incoming that will, cost-effectively and safely, consider in the design of power service and distribution equipment supply adequate electric service to distribution systems. rooms to be located out of basements ii both present and future probable and other low lying areas. Regions loads—this section is intended to aid Federal and state legislation has been prone to these storms often experience in selecting, designing and installing introduced to reduce the output of downed utility power lines and/or 1 such a system. carbon emissions into the environment; flooded manholes, resulting in a loss the intent being the reduction of their of power to thousands of customers. The function of the electric power impact on climate change. In order to In order to quickly return power to 2 distribution system in a building or address the subsequent need for clean these facilities, additional on-site an installation site is to receive power power, there has been an accelerating backup generation is being included in at one or more supply points and trend toward the incorporation of solar both new designs and as upgrades to 3 to deliver it to the lighting loads, and other sustainable energy sources existing sites. This trend for resiliency motors and all other electrically into existing and new building designs. is increasing among grocery stores, operated devices. The importance Energy storage systems (ESS) are now large chain stores and other distribution 4 of the distribution system to the making renewable energy a more facilities requiring refrigeration to keep function of a building makes it viable option by helping to stabilize products from spoiling as well as large imperative that the best system be power output during transient dips or multifamily dwelling complexes in low 5 designed and installed. interruptions to power production. lying flood plain areas. In order to design the best distribution Utility deregulation has also provided Building costs continue to rise and 6 system, the system design engineer financial incentives for building rentable or usable space is now at a must have information concerning the owners and facility managers to premium. To solve both problems, loads and a knowledge of the types participate in peak demand load many design and construction firms 7 of distribution systems that are shaving programs. These programs are looking at off-site prefabrication applicable. The various categories of are intended to reduce load on the of key elements. Forest City Ratner’s buildings have many specific design utility grid in response to a 1 hour or 32-story residential complex adjacent 8 challenges, but certain basic principles 1 day ahead signal from the utility. to Barclay's Arena in Brooklyn, NY, are common to all. Such principles, The users shedding or cycling of non- advanced the modular concept if followed, will provide a soundly essential loads is generally initiated by with individual building sections 9 executed design. a building management system (BMS) constructed at a factory off-site and in conjunction with power monitoring The basic principles or factors requiring erected by crane into place. Resiliency and lighting control equipment. To from storms and floods involving the 10 consideration during design of the ensure uninterrupted operation of key power distribution system include: relocation of electrical equipment out customer loads, incorporation of other of flood prone areas is costly, time ■ Functions of structure, present types of distributed generation such as consuming and takes up precious floor 11 and future fuel cells and diesel or natural gas fired space in a building. Electro Centers or reciprocating generator sets may be ■ Life and flexibility of structure Integrated Power Assemblies (IPA) can desired or required. ■ Locations of service entrance and be fitted out with a variety of electrical 12 distribution equipment, locations Hospital complexes and college distribution equipment and shipped to and characteristics of loads, campuses are increasingly adopting the the site in preassembled modules for locations of unit substations design of central utilities plants (CUPs). mounting on elevated foundation 13 piles, building setbacks or rooftops. ■ Demand and diversity factors In lieu of a separate boiler plant, of loads cogeneration is used to produce Finally, the need to have qualified electricity and the wasted heat from 14 ■ Sources of power; including building electrical operators, the combustion process is recaptured normal, standby and emergency maintenance departments and facility to provide hot water for the campus. (see Ta b 4 0 ) engineers has collided with growing 15 Large cogeneration plants (3 MW and expectations for improved productivity ■ Continuity and quality of power above) often include large turbines or available and required (see Ta b 3 3 ) and reduced overall operating costs. reciprocating engines as their prime The increasing proliferation of smart ■ 16 Energy efficiency and management movers for the generators. To enhance devices and enhanced connectivity ■ Distribution and utilization voltages service continuity, these generators with power distribution equipment ■ Busway and/or cable feeders use a continuous source of natural has expanded facility owner’s 17 (see Tab 24) gas as their fuel supply. Cogen plants options. These capabilities allow for generally have higher power conver- ■ Distribution equipment and automated communication of vital sion efficiencies and produce lower motor control power system information including carbon emissions. 18 ■ Power and lighting panelboards energy data, equipment wellness and and motor control centers predictive diagnostics, and electrical (see Tabs 22, 23 and 29) equipment control. 19 ■ Types of lighting systems ■ Installation methods 20 ■ Power monitoring systems (see Tabs 2 and 3) ■ Electric utility requirements 21

CA08104001E For more information, visit: www.eaton.com/consultants 1.1-2 Power Distribution Systems System Design August 2017 Sheet 01 004

The future “Internet of Things” provided, for speeding up the OSHA has qualified a number of i promises to add millions of more clearing time of a circuit breaker Nationally Recognized Testing sensors and other devices to collect that can be set to trip at 1200 A or Laboratories (NRTL) to demon- operational data and send it through above. Eaton’s Arcflash Reduction strate and certify “product ii the Internet to “cloud-based” comput- Maintenance System™ is avail- conformance to the applicable ing services. There, information from able in various electronic trip product safety test standards.” multiple devices can be analyzed and units for molded-case and power Among the oldest and most 1 actions can be taken to optimize circuit breakers to improve clear- respected of these electrical performance and reduce downtime. ing time and reduce the incident product testing organizations is energy level. Underwriters Laboratories (UL), 2 Various sections of this guide cover which was founded in 1894. the application and selection of such The National Electrical Code® systems and components that may (NEC®), NFPA® 70 and NFPA 70E, It is the responsibility of the design 3 be incorporated into the power as well as local electrical codes, engineer to be familiar with the equipment being designed. Also provide minimum standards and NFPA and NEC code requirements see Tabs 2, 3, 4, 23, 38, 39 and 41 requirements in the area of wiring as well as the customer’s facility, 4 for specific application details. design and protection, wiring process and operating procedures methods and materials, as well in order to design a system that Goals of System Design as equipment for general use with protects personnel from live electri- 5 the overall goal of providing safe cal conductors and uses adequate When considering the design of an electrical distribution systems circuit protective devices that will electrical distribution system for and equipment. selectively isolate overloaded or 6 a given customer and facility, the faulted circuits or equipment as The NEC also covers minimum quickly as possible. electrical engineer must consider requirements for special occupan- alternate design approaches that cies including hazardous locations In addition to NFPA and NEC 7 best fit the following overall goals. and special use type facilities such guidelines, the design professional 1. Safety: The No. 1 goal is to design as healthcare facilities, places of must also consider International 8 a power system that will not assembly, theaters and the like, Building Code (IBC) and local present any electrical hazard to as well as the equipment and municipality, state and federal the people who use the facility, systems located in these facilities. requirements. The United States 9 and/or the utilization equipment Special equipment and special Department of Energy, for example, fed from the electrical system. conditions such as emergency mandates minimum efficiencies for It is also important to design a systems, standby systems and transformers and other equipment. 10 system that is inherently safe for communication systems are also covered in the code. Many of these regulatory codes the people who are responsible for reference ANSI/ASHRAE/IES electrical equipment maintenance 2. Regulatory Requirements: Standard 90.1-2013 “Energy 11 and upkeep. Over the course of the past Standard for Buildings Except The Occupational Safety and century, electrical product safety Low-Rise Residential Buildings”. 12 Health Administration (OSHA) and performance standards have Section 8.1 covers power and is a federal agency whose been developed in cooperation includes receptacle load control. “mission is to assure safe and between various agencies such Subsection 8.4.3 is titled Electrical 13 healthful workplaces by setting as: American National Standards Energy Monitoring and covers and enforcing standards, and by Institute (ANSI) as well as industry metering and monitoring systems providing training, outreach, groups such as the Institute that notify building tenants and 14 education and assistance.” OSHA’s of Electrical and Electronics engineers of the increased use of electrical requirements are covered Engineers (IEEE) and the National electric power. Section 9.1 covers under several categories, the Electrical Manufacturers Associa- lighting and lighting control 15 broadest being 1910 Subpart 10 tion (NEMA). These are often system requirements. Electrical including references to referenced together with specific test standards developed in Other building standards organiza- the National Fire Protection Agency tions that offer certifications, (NFPA) 70 and 70E. conjunction with Underwriters 16 Laboratories (UL). As an example, such as the U.S. Green Building To address the concerns for low-voltage switchgear falls under Council’s LEED Accreditation, personnel safety from arc flash ANSI C37.20.1 and is tested in require measurement and 17 hazards, the 2014 Edition of the compliance with UL 1558. verification that actual energy NEC as well as the 2015 Edition and water use meet initial building of NFPA 70E have enhanced the The 2014 National Electrical Code design criteria. The U.S. Green 18 requirements for personnel (NEC) Article 110.2 states that: Building Council has teamed protection when working on or “The conductors and equipment with ANSI and ASHRAE to near live equipment. The 2014 required or permitted by this produce ANSI/ASHRAE/USGBC/ 19 NEC introduces new arc flash Code shall be acceptable only if IES Standard 189.1-2014 titled, labeling requirements. approved.” The informational “Standard for the Design of note references the definitions High-Performance Green Build- 20 Additionally, Article 240.87 offers a in Article 100 for Approved, ings Except Low Rise Buildings”. number of prescriptive alternative Identified, Labeled and Listed. methods for arc flash energy 21 reduction; one of which must be

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.1-3 August 2017 System Design Sheet 01 005

Finally, utility incoming service Typically, service continuity and Power monitoring communication standards for customer intercon- reliability can be increased by: systems connected to electronic i nects are key elements in the metering can provide the trending selection of both the incoming A. Supplying multiple utility power and historical data necessary to service voltage and the protection sources or services. ensure future capacity for growth. ii required for this equipment. B. Supplying multiple connection 6. Maximum Electrical Efficiency Knowledge of these standards paths to the loads served. is particularly important when (Minimum Operating Costs): 1 incorporating renewable energy C. Using short-time rated power Electrical efficiency can generally or distributed generation circuit breakers. be maximized by designing resources into a design. 1 systems that minimize the losses 2 D. Providing alternate customer- in conductors, transformers and 1 Contact Eaton’s local application engineer owned power sources such as utilization equipment. Proper for assistance with design compliance. generators or batteries supplying voltage level selection plays a 3 Energy Storage Systems or key factor in this area and will 3. Minimum Initial Investment: uninterruptable power supplies. be discussed later. The owner’s overall budget for first cost purchase and installation E. Selecting the highest quality elec- Selecting equipment, such as 4 of the electrical distribution trical equipment and conductors. transformers, with lower operating system and electrical utilization losses, generally means higher F. Using the best installation equipment will be a key factor first cost and increased floor space 5 methods, including proper in determining which of various requirements. Thus there is a system grounding design. alternate system designs are to be balance to be considered between 6 selected. When trying to minimize G. Designing appropriate system the owner’s long-term utility cost initial investment for electrical alarms, monitoring and diagnostics. for the losses in the transformer or equipment, consideration should other equipment versus the initial be given to the total cost of H. Selecting preventative mainte- budget and cost of money. 7 the installation. This includes nance systems or equipment to reducing on-site assembly time alarm before an outage occurs. 7. Minimum Maintenance Cost: and cost by prefabricating various Usually the simpler the electrical 8 5. Maximum Flexibility and system design and the simpler electrical components into a single Expandability: In many industrial deliverable system and reducing the electrical equipment, the lower manufacturing plants, electrical the associated maintenance costs 9 floor space and possible extra utilization loads are periodically cooling requirements. and operator errors. As electrical relocated or changed requiring systems and equipment become 4. Maximum Service Continuity: changes in the electrical distribu- more complicated to provide 10 The degree of service continuity tion system. Consideration of greater service continuity or and reliability needed will vary the layout and design of the flexibility, the maintenance costs depending on the type and use electrical distribution system to and chance for operator error 11 of the facility as well as the loads accommodate these changes must increases. or processes being supplied by the be considered. For example, pro- electrical distribution system. For viding many smaller transformers When designing complex systems, 12 example, for a smaller commercial or loadcenters associated with a the engineer should consider add- office building, a power outage given area or specific groups of ing an alternate power circuit to of considerable time, say several machinery may lend more flexibility take electrical equipment (requiring 13 hours, may be acceptable, whereas for future changes than one large periodic maintenance) out of in a larger commercial building or transformer; the use of plug-in service without dropping essential industrial plant only a few minutes busways to feed selected equip- loads. Use of drawout type protec- 14 may be acceptable. In other facilities ment in lieu of conduit and wire tive devices such as breakers and such as hospitals, many critical may facilitate future revised combination starters can also loads permit a maximum of equipment layouts. minimize maintenance cost and 15 10 seconds outage and certain out-of-service time. Utilizing sealed In addition, consideration must be equipment in lieu of ventilated loads cannot tolerate a loss of given to future building expansion, power for even a few cycles. equipment may minimize mainte- 16 and/or increased load require- nance costs and out-of-service time ments due to added utilization as well. equipment when designing the 17 electrical distribution system. In many cases considering transformers with increased capacity 18 or fan cooling to serve unexpected loads as well as including spare additional protective devices and/ 19 or provision for future addition of these devices may be desirable. Also to be considered is increasing 20 appropriate circuit capacities to assure future capacity for growth. 21

CA08104001E For more information, visit: www.eaton.com/consultants 1.1-4 Power Distribution Systems System Design August 2017 Sheet 01 006

8. Maximum Power Quality: Summary This revision of Tab 1 includes updates i The power input requirements based on changes to the 2014 National of all utilization equipment has It is to be expected that the engineer Electrical Code (NEC), 2015 NFPA 99 and to be considered, including the will never have complete load infor- other pertinent ANSI/IEEE Standards. It ii acceptable operating range of mation available when the system is also includes a significant revision in the equipment. Consequently, the designed. The engineer will have to the flow of the material presented. electrical distribution system has expand the information made avail- Additional new information has been 1 to be designed to meet these able to him or her on the basis of added to the document in recognition needs. For example, what is the experience with similar projects. that users will be at differing levels of required input voltage, current, Of course, it is desirable that the engi- experience. For those engineers either 2 power factor requirement? neer has as much definite information beginning their careers or early into Consideration to whether the as possible concerning the function, them, guidance is provided for the loads are affected by harmonics requirements, and characteristics of design and development of Power 3 (multiples of the basic 60 Hz sine the utilization devices. Systems One-Line Diagrams. wave) or generate harmonics must be taken into account as well as The engineer should know whether cer- An expanded section on voltage 4 transient voltage phenomena. tain loads function separately or selection, including both service and together as a unit, the magnitude of the utilization voltages, has been added. The above goals are interrelated and demand of the loads viewed separately This narrative discusses consider- 5 in some ways contradictory. As more and as units, the rated voltage and ations for utility metering at medium redundancy is added to the electrical frequency of the devices, their physical and low voltages. However, the system design along with the best location with respect to each other description of types of systems and 6 quality equipment to maximize service and with respect to the source and the diagrams used to explain the types continuity, flexibility and expandability, the probability and possibility of the of systems on the following pages and power quality, the more initial relocation of load devices and addition omit the location of utility revenue 7 investment and maintenance are of loads in the future. metering equipment for clarity. increased. Thus, the designer must Further pages address short-circuit weigh each factor based on the type Coupled with this information, a calculations, coordination, overcurrent 8 of facility, the loads to be served, the knowledge of the major types of electric protection, voltage drop, ground fault owner’s past experience and criteria. power distribution systems equips the protection, motor protection and engineers to arrive at the best system application considerations for typical 9 design for the particular building. equipment utilized in a power system. It is beyond the scope of this guide to present a detailed discussion of loads 10 that might be found in each of several types of buildings. Assuming that the design engineer has assembled the 11 necessary load data, the following pages discuss some of the various types of electrical distribution systems 12 that can be used. 13

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.2-1 August 2017 Designing a Distribution System Sheet 01 007

Development of a A System One-Line may start out in Moving into the Construction the Design Development Phase of Document Phase of a project, i System One-Line a project as a basic concept. Other alterations are made to the Design information can be added throughout Development Electrical Drawing set. Power system designers communicate the design cycle. It can then be copied At some level of completion (typically ii their design requirements through a and modified to create a number of 90%), these drawings are sent out combination of drawings, schedules alternate drawings showing different to finalize budgetary estimates and and specifications. system approaches. This permits the narrow the field of contractors to be 1 One of the key tools in developing power system designer to analyze the included in the selection process. and documenting an electrical power impact of each arrangement on cost, During the push from 90% to 100% system is the System One-Line (also redundancy and projected physical completion of the construction 2 called a Single Line Diagram). This space requirements. documents, the construction manager or the general contractor drawing starts with the incoming The System One-Line takes on power source from the utility service is asked to provide a Guaranteed 3 increasingly more importance as the Maximum Price (GMP). and/or on-site generation and their project evolves through the Design associated distribution equipment. Development Phase. Input from the During the Bid or Negotiation Phase It then follows the power flow down 4 other architectural, mechanical, of a project, Bid Document Drawing through the various conductors as well plumbing, electrical and fire Sets are sent out to a list of potential as any voltage transformations to feed protection professionals on the contractors. Estimators at these distribution equipment buses for the 5 design team helps to better define contractors review the Bid Package key loads served. the various equipment loads and and tabulate the value of the electrical Initially, the System One-Line provides develop the power system one-line equipment, conduit and cable costs 6 a framework for the incorporation of to accommodate them. plus manpower necessary to build out the project. different types of required information At some point in this stage, a such as: construction manager may be 7 1. Incoming service voltage and brought in to assist the owner and utilization voltages required. architect in assessing the design’s constructability. Various improve- 8 2. Electrical distribution equipment ments that could increase energy ampacity and short-circuit ratings. efficiency and/or reduce construction 9 costs are often suggested. 3. Overcurrent/short-circuit protection. Moving toward the end of the Design Development Phase, the One-Line 10 4. Conductor types (i.e., cable or and associated drawings such as busway) and sizes. (Cable lengths equipment room elevations and floor- may also be estimated to determine plans are provided to the client for 11 voltage drop and any upsizing their review and approval. At this necessary.) point, both the client’s comments and 5. Transformer kVA sizes, ampacity, the construction manager’s additional 12 impedance and voltages. inputs are integrated into the design. This final set of approved design 6. Generator kW sizes and voltages. development drawings, which include 13 7. Motor loads and voltages. the Power System One-Line, are used as the basis for the development of the 8. Other power quality equipment construction drawings. 14 such as surge protection devices, power factor correction capacitors or uninterruptible power supplies. 15

CA08104001E For more information, visit: www.eaton.com/consultants 1.2-2 Power Distribution Systems Designing a Distribution System August 2017 Sheet 01 008

Importance of the Other requirements such as: Zone The System One-Line is the common i Selective Interlocking of breakers, 100% map that all the other project System One-Line rated breakers, drawout or electrically documents must reference and be operated breakers and key interlock checked against. To ensure consistency It is important for the power system ii schemes can be overlooked if they are and avoid conflicts after a project is designer to ensure the System One- not documented on a One-Line and awarded to a contractor, distribution Line and other design documents coordinated in the specifications. panelboard schedules and specifica- contain as much information as 1 tions also need to include the correct possible, to assure that bidding Finally, electrical equipment is subject information about details such as the contractors include all the correct to environmental issues such as enclosure type required. 2 requirements in their pricing. Errors wet areas and may require specific and/or omissions on the construction enclosure types to be provided. For these reasons, it is critical that contract documents can lead to Nomenclature on the One-Line, such the engineer be vigilant and take a 3 expensive contractor change orders as 3R or 4X, adjacent to these items proactive role in identifying changes and project cost overruns after the can clarify what enclosure type is to and updating the System One-Line contract is awarded. be provided. and associated design documents appropriately and consistently. 4 During the various stages of a project The proper use of notes on the One-Line design, changes are made often to can further define the requirements. The One-Line diagram on the following reflect the client’s preferences and As an example, a note can be added pages is an example developed for 5 budget. As the design process clarifying that all NEMA 4X rated illustrative purposes only and was continues, coordination between enclosures are to be of 316 stainless developed to show a wide range of the MEP (Mechanical, Electrical and steel versus the less expensive 304 product applications. This diagram 6 Plumbing) design disciplines become Grade. The difference between these will be referenced throughout the more critical. two grades is critical as 316 Stainless is remainder of this section. far more resistant to saltwater, sulfuric 7 If the design professionals are not acid and chlorides, and is preferred in The references to external drawings is synchronized on these changes, a several applications including pharma- for illustration only and not referencing previously unanticipated piece of ceutical manufacturing and wastewater actual documents within this section 8 equipment may be chosen or added treatment plants. or elsewhere. to the project. As an example, where an engineer had previously allocated 9 a 250 A circuit breaker to feed the DSB-DF2A anticipated load, as a result of an 480 V, 600 A, equipment change, a 400 A breaker 3Ø, 3W, 65 KAIC 10 must now be provided. The impact of this change can result in a contractor 150AF 150AF 150AF 150AF bid that does not include both the 15AT 90AT 15AT 90AT 11 correct breaker AND the correct cable sizes to feed the larger load. 12 Oftentimes, requirements such as electronic trip units or their protective 2 4X functions such as Long, Short, FUEL HVAC HEAT COMFORT Instantaneous and Ground (LSIG) PUMP AHU-1,2,3,4 REJ. COOLING 13 FOP-1 UNITS CH-1 or Ground Alarm (LSIA) are not HRU-1,2,3,4 indicated on the One-Line. This can 14 lead to equipment being supplied Figure 1.2-1. Example of Notes on One-Line with standard thermal-magnetic trip units that may lack the setting 15 capabilities to achieve the proper selective coordination required. 16

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.2-3 August 2017 Designing a Distribution System Sheet 01 009

This page intentionally left blank. i

CA08104001E For more information, visit: www.eaton.com/consultants 1.2-4 Power Distribution Systems Designing a Distribution System August 2017 Sheet 01 010

i UTILITY FEEDER #1 UTILITY FROM PSG-2A (SEE DWG E102) BUSWAY RISER 13.8 kV, 3Ø, + GND 60Hz METERING 4.16 kV, 3Ø, 60Hz (SEE DWG E106) M SPLICE IN PROPERTY LINE MANHOLE M1 4 6 ii M1-00 RBP-F3A T5-RBP-F3A PXM6000 N.O. (3) (3) SINGLE PHASE POTHEADS (1/Ø) P=208A S=1804A METER USG-1A "POINT A" 11.65KA SCA A PT'S M. H 480V:120V 13.8kV, 1200A, AVAILABLE FROM UTILITY 8 AL (4) GROUND STUDS (3-Ø, 1-GND) 250KA 50 kA SYM S.C. LO 300E (2) UTILITY PT's /Ø.SPD 1 (15kV - 95KV BIL RATED) MAIN CB (6) LIVE LINE INDICATORS (2/Ø) 14,400:120V 10A E.O. "RBS-F3A" N.C. M. H P 2000 AF 7 1500kVA 1800 AT LO F3D 4.16kV-480/277V LSG TRIP M1 2 5.75% Z (3) 2000:5 TRIP S1 UTILITY (3) PT'S CT's (2) 500:5 RHBP-F3A T4-RHBP-F3A 14,400:120V N.O. P=104A S=2082A 120:1 M. H A 3 (3) (3) AL 27 59 6 TS RESIDENCE M1 M1 VFI-3A HALL B (3) (3) 600A SB (SEE DWG E105) (3) 800:5 N.C. P STD (C100) M. H 750kVA FR3 VFI PADMOUNT 4 5 SELECTOR SWITCH 55/65C 5.75% Z EDR-5000-M1 1 TRIP M1 W/SURGE+LIGHTNING 4.16kV-60KV BIL G R A ARRESTERS 208/120V-20KV BIL 52-M1 TRIP S1 M1A LO N.C. 1200A 52 (1) (3) (1) C/S DFP-F3A T3-DFP-F3A 5 M1-L N.O. 50/51N 50/51 86 TRIP M1 (1) P=139A S=1203A M. H A M1 M1 M1 TRIP S1 86 AL T1 4 LO TS SB 200E DINING (3) 800:5 TS FACILITY 6 STD (C100) (SEE DWG E104) (1) (3) N.C. 87 M. H P 51G 3 1000kVA PXM6000 T1 T1 METER (3) 600:5 MR LO F3B 4.16kV-480/277V Set at 350:5 ETR-5000-T1 5.75% Z 7 (4) GROUND STUDS TS TS TS (3-Ø, 1-GND) RHAP-F3A T2-RHAP-F3A N.O. P=104A S=2082A TRANSFORMER "T1" M. H A 2 AL PRIMARY UNIT SUBSTATION STYLE M1-00 8 (1) RESIDENCE 13.8KV DELTA PRIMARY - 95KV BIL H2 63 "POINT C" F3A - VFI-2A P/FA=479A HALL A 4.16/2.4KV GROUNDED WYE - 60KV BIL T1 11.32KA SCA 600A (SEE DWG E103) EATON "PEAK" 55C/65C/75C WITHOUT MOTOR N.C. H1 H3 CU 71 49 SCA & CABLE Z TO M. H P 7500/8400/9156 KVA KNAN 750kVA FR3 VFI PADMOUNT X 3 T1 T1 1 "POINT D" - 40,400 SCA X 0 T1 & T2-RHAP SELECTOR SWITCH 55/65C 5.75% Z 9 9375/10500/11445 KVA KNAF X 1 WITH UNLIMITED PRIMARY SCA S/FA=1589A W/SURGE+LIGHTNING 4.16kV-60KV BIL FR-3 FLUID FILLED, 6.5% MINIMUM Z (1) (1) X 2 ARRESTERS 208/120V-20KV BIL & 50% MOTOR CONTRIBUTION WITH SURGE + LIGHTNING ARRESTERS SEE XFMR TABLE 1.6-7 FOR (1) 600:5 M1-03 2000A BUSWAY HI (C200) T2 ESTIMATING PURPOSES.

10 (4) GROUND STUDS (4) GROUND STUDS PSG-1A "POINT B" T1 - 11.32KA CHILLER #1 (3-Ø, 1-GND) (3-Ø, 1-GND) "BUS A" 4.16KV, SCA WITHOUT MOTOR SCA, CUP SB CABLE % Z TO T1 & 2000A, 60KV BIL, (3) 2000:5 SB (SEE DWG E107) BUSWAY % Z (3) 2000:5 40KA SC RATED STD (C200) STD (C200) 11 M EDR 1 (3) 600:5 MR 3000-S1 G R A Set at 600:5 52-S1 EDR PXM6000 M1-04 (3) (1) S1A LO N.C. METER TRIP S1 2000A 52 3000-F3 86 C/S (1) 12 TRIP F1 51 TRIP S1 S1-L VFD-F2A TRIP F2 S1 S1 50/51N F3 G R A TRIP F3 52-F3 TS SB F3A LO N.C. (3) 2000:5 1200 52 TS 50/51 86 C/S DRAW-OUT STD (C200) TRIP F3 F3-L F3 F3 DC TO AC (1) EBR 13 (3) INVERTER 86 87 3000 (3) 2000:5 (1) (3) 600:5 B1 B1 -B1 STD (C200) STD (C100) (3) SB TS SB TS AC TO DC 14 CONVERTER TS SB TS SB (3) 600:5 (3) 600:5 INTEGRAL STD (C100) STD (C100) (3) (3) 24 PULSE XFMR 50/51 50/51 15 F1 G R A F2 G R A (1) 52-F1 (1) 52-F2 F1A LO N.C. F2A LO N.C. 1200A 52 1200 52 CONTACTOR 50/51N 86 C/S (3) PT'S 50/51N 86 C/S TRIP F1 F1-L TRIP F2 F2-L F1 4200V: F2 F1 120V F2 (1) (1) 16 EDR 35:1 EDR 3000-F1 (3) 600:5 MR 3000-F2 (3) 600:5 MR Set at 400:5 Set at 300:5 (3) 400A PXM6000 PXM6000 METER METER ISOLATION (3) 2000:5 17 (3) 2000:5 E SWITCH STD (C200) SB SB STD (C200) (4) GROUND STUDS (4) GROUND STUDS SC9000EP (3-Ø, 1-GND) (3-Ø, 1-GND) MV-VFD 18 M1-02 M1-02 19 Figure 1.2-2. Power System One-Line (Continued on Next Page) 20

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.2-5 August 2017 Designing a Distribution System Sheet 01 011

i FROM PSG-2A (SEE DWG E102) DRAWING NOTES 4.16 kV, 3Ø, 60Hz 1 Provide M1 Electrical Interlock With S1 Breaker. M1 Cannot Close if S1 is Open. S1 Cannot Close Until M1 is Closed. Include Key Interlocks as Shown. DIESEL

ENGINE ii N.O. Provide MB-F1A Key Interlock With Generator Breaker "GB" and Tie Breaker CUP-F1A 2 M. H A "LTA". Only the Single "MGTA" Key Can be Used to Close Any of these Breakers. 10 Provide Priority Load Shed Controls for Feeder Breakers in SUS-F1A Switchgear. LO 3 G Provide Interface With Generator Breaker "GB" to Enable Operation When Non- N.C. Priority Loads have Been Shed. 1 M. H P FDR (SEE DWG E108) 9 "G" Provide All Magnum Breakers in SUS-F1A & RBS-F3A Switchgear With DT1150+ LO F1A 4 4000A BUSWAY TO 2000AF Trip Units Including Zone Selective Interlocking (ZSI) and Arc Flash Reduction CLE TIE CB "LTB" IN 600A 2000AT Maintenance System (ARMS) in Compliance with Article 240.87 of the 2014 NEC. PORTABLE "SUS-F1B" LOAD BANK Provide Remote Touchscreen Panel With "Switchgear Dashboard Interface" to 2 P FA=461A 5 Monitor Operational Variables and Enable Arc Flash Reduction Maintenance Mode. XFMR "ST-F1A" CU 2500/3333kVA TOUCH Wire All DT1150+ Trip Units Communications Ports to an Ethernet Gateway With 5 6 115C AA/FA SCREEN BACnet IP Connectivity. BMS Vendor Will Provide Field Wiring and Integrate Into 4.16KV-480/277V BMS System on a Separate Contract. 3 S FA=4000A Z=5.75% 2 3 2 MAIN CB TIE CB SECONDARY UNIT SUBSTATION "SUS-F1A" MGTA "MB-F1A" (3) PT'S "GB" "LTA" 480V: EG BACNET IP 4 LO E.O. 4000 AF 120V TO BMS LO E.O. 2000AF LO E.O. 4000 AF 4000 AT 2000AT 4000 AT TO DT1150 N.C. LSG PXM6000 N.O. LSG N.O. LSG METER ETHERNET TRIP UNITS "DF5A" 01B (3) 4000:5 GATEWAY MAIN SWGR. BUS "A" 85KA, 480/277V, 4000A, 3-PH, 4W 5 01D 02A 02B 02C 02D 03A 03B 03C 03D 04A 04B 04C 04D "DF1A" "DF2A" "DF3A" "DF4A" "DF6A" "DF7A" "DF8A" "DF9A" "DF1OA" "DF11A" "DF12A"

250KA/Ø E.O. 800AF E.O. 800AF E.O. 1600AF E.O. 1600AF E.O. 800AF E.O. 800AF E.O. 800AF E.O. 1600AF E.O. 800AF E.O. 800AF E.O. 800AF SPD 600 AT 600 AT 1600 AT 1600 AT 800 AT 400 AT 600 AT 1600 AT 400 AT 500 AT 500 AT 6 LSIG LSIG LSIG LSIG LSIG LSIG LSIG LSIG LSIG LSIG LSIG SPARE SPARE SPARE SPARE (SEE DWG E109) FROM GEN A 7 NORMAL ATS-A GENERATOR SOURCE SOURCE BYPASS ATC-900 1600AF DSB-DF4A SEE SCHEDULE DSB-DF4A ISOLATION TRANSFER 1600AT ATS CONTROL 8 480V, 1600A, FOR LOADS PP-DF6A 3Ø, 4W, 65 KAIC 480V, 600A, 120KA/Ø 800AF 3Ø, 3W, 65 KAIC SPD 800AT

480/277V, 800A, MAINTENANCE 9 225AF 400AF 800AF 600AF 400AF 225AF 400AF ISOLATION 175AT 250AT 800AT 600AT 250AT 200AT 250AT 3Ø, 4W, 65 KAIC BYPASS MBP BIB RIB SPARE SPACE 2X SEE SCHEDULE PP-DF6A UPS1 10 FOR LOADS 300KVA

1600A MCC-DF3A FREEDOM FLASHGARD MCC MLO 120KA/Ø 480V, 1600A, SPD 3Ø, 3W, 65 KAIC 11

400A 150A 150A 150A 150A 400A 400A 150A 150A 150A 150A 150A 150A FR10 SIZE4 SIZE4 SIZE4 SIZE4 SIZE5 SIZE5 SIZE4 SIZE4 SIZE4 SIZE4 SIZE4 SIZE4 261A FVNR FVNR FVNR FVNR FVNR FVNR FVNR FVNR FVNR FVNR FVNR FVNR MIS 12 18 2S2W 2S2W 2S2W 2S2W Eaton 9395 UPS PULSE SS0L SS0L SS0L SS0L SSRV SSRV SS0LSS0L SS0L SS0L SS0L SS0L VFD W/GFP W/GFP W/GFP W/GFP W/GFP W/GFP W/GFP W/GFP W/GFP W/GFP DC-DS-A 13 3R 3R 3R 3R 6 POLE 6 POLE 6 POLE 6 POLE 200 75 75 75 75 150 150 75 75 75 75 75 75 BAT-A NCHWP-1 CWP-1 CWP-2 CWP-3 CWP-4 CHWP-1 CHWP-2 CT-1 CT-2 CT-3 CT-4 SA-1 EF-1 14 240FLA 96FLA 96FLA 96FLA 96FLA 180FLA 180FLA 96FLA 96FLA 96FLA 96FLA 96FLA 96FLA PDU-1 480V-3Ø 600AF 120KA/Ø IFS-DF7A 500AT 600AF 400AF 3W,65kA SPD 600AT 400AT 150A DSB-DF2A P=361A 15 120KA/Ø 480V, 600A, XFMR-DF8A P=361A SPD 3Ø, 3W, 65 KAIC XFMR-DF7A P=90A 300KVA XFMR-UPS1 225A 75KVA 480-208/120V 300KVA 480- 480-208/120V 208/120V S=833A 150AF 150AF 150AF 150AF 150AF 150AF 150AF S=208A S=833A 16 "DF7AP" 208/120V, 3Ø, 4W 40AT 15AT 90AT 100AT 90AT 100AT 100AT 480/277V 225A RP-DF8A SPARE SPACE 2X 225A 3Ø, 4W, 65KA 1200AF 400AF 400AF POW-R-COMMAND 1000AT 400AT 400AT LIGHTING CONTROL 208/120V, 225A, 17 3Ø, 4W, 10 KAIC POW-R-COMMAND 208/120V, 1200A, CDP-A CDP-B 10 2 4X 4X RECEPTACLE CONTROL 3Ø, 4W, 65 KAIC 42 Circuit 42 Circuit GYCOL FUEL HVAC HEAT COMFORT HEAT PUMP PUMP AHU-1,2,3,4 REJ. COOLING REJ. 18 GCP-1 FOP-1 UNITS CH-1 UNITS SEE SCHEDULE IFS-DF7AP & DF7AS SEE SCHEDULE RP-DF8A SEE SCHEDULE PDU-1 HRU-1,2,3,4 HRU-5-9 FOR NORMAL & CONTROLLED LOADS FOR LOADS FOR CRITICAL LOADS 19 Figure 1.2-2. Power System One-Line (Continued) 20

CA08104001E For more information, visit: www.eaton.com/consultants 1.2-6 Power Distribution Systems Designing a Distribution System August 2017 Sheet 01 012

Standardized Drawing Symbols Medium-voltage circuit breakers half of the system one-line on i shown on a one-line typically incorpo- Page 1.2-4 shows “T1” as Eaton In the North American market, the rate the Basic Square Breaker symbol “Peak” Style Triple Temperature Rated, American National Standards Institute with the ANSI Device Number 52 7.5 MVA, FR3 Envirotemp™ Fluid Filled, ii or ANSI for short, in cooperation with inside. Medium-voltage breakers may Power Transformer. The transformer’s the Institute of Electrical & Electronics be either fixed mount (square with kVA ratings are indicated at the KNAN, Engineers has developed standardized device number inside) or drawout as (Natural Air Cooled by Convection— 1 drawing symbols and nomenclature to shown in Figure 1.2-3 as well as the Over 300C Fire Point Fluid Filled) represent common devices represented system one-line on Page 1.2-4. and KNAF (Forced Air Cooled Over on one-lines, control schematics and 300C Fire Point Fluid Filled) ratings. It is important to develop a naming 2 other electrical drawings. The existing See Tab 16 for details. convention so personnel working Standard for North America (including on or responding to an event on the The “T1” transformer is described as the Canadian Standard CSA Z99) is IEEE power system can readily identify “Delta” Primary, “Wye” Secondary 3 315-1975 (Reaffirmed 1993)/ANSI Y32.2. the equipment experiencing any configuration in the text as well as This version recognizes that “Electrical problems. This naming convention is further depicted by the relationship of 4 diagrams are a factor in international also useful for those doing preventa- the “H1, H2 and H3” connections to the trade: the use of one common symbol tive maintenance in documenting X1, X2, X3 and X0 symbols adjacent language ensures a clear presentation which specific switchgear, breaker, to it. Similarly, the verbiage in the 5 and economical diagram preparation transformer or protective relay they text calls for surge and lightning for a variety of users.” Consequently, need to address. protection. Symbols for the arrester the Standards Coordinating Committee and the capacitor are shown connected Transformers are common compo- has added various International to the incoming terminations. Their 6 nents of a power system and are used Electrotechnical Commission (IEC) actual ratings should be defined on on both medium-voltage and low- symbols that are in use worldwide. the drawing or in the specifications. 7 voltage applications to step a voltage Item A4.1.1 of IEEE 315 defines a up or down to a desired level. They Both the transformer’s primary and Single-Line or (One-Line) Diagram as: are available in a variety of winding secondary amps are included as a 8 “A diagram which shows, by means of configurations as detailed in the reference for sizing the conductors. single lines and graphic symbols, the “Typical Components of a Power This is useful to determine the quantity course of an electric circuit or system System” in Section 1.6 of this Tab 1 and size of the MV cables per NEC 9 of circuits and the component devices document.) Article 310.60. While medium-voltage or parts used therein.” conductors are available in 90C (MV90) Because there are many types and or 105C (MV105) ratings, the actual 10 Components such as those represent- configurations of transformers terminations in the transformer or ing circuit protective devices like fuses available, it is necessary to properly switchgear cable compartments are and circuit breakers are indicated in document the specific requirements limited to 90C. When sizing the MV 11 their most basic form. Device repre- on the One-Line. Primary unit cables, the NEC derating factors must sentations can be created by adding substation transformers are used also be applied depending on the other components and nomenclature to convert a medium voltage to type of raceway or duct bank that to the base component drawing. another medium voltage. See Tab 13 will be required. 12 Low-voltage <1000 V circuit breakers for details. are represented by the first two of Where higher transformer secondary Secondary Unit Substation the following symbols shown in currents are involved, a busway flange Transformers transform a Medium 13 Figure 1.2-3. and non-segregated busway can be Voltage to a Low Voltage Level, supplied to connect it to the down- generally under 1000 Vac. They are stream MV switchgear (as shown 14 available in Fluid-Filled and Dry-Type in Figure 1.2-4). Proper selection and LOW LOW MEDIUM styles. See Tab 14 for details. VOLTAGE VOLTAGE VOLTAGE application of the busway requires that 15 Both types of unit substation trans- the rated short time and short circuit formers can be supplied with fans to withstand current values be specified. increase the transformer’s kVA ratings. See Tab 11 for details. 16 52 Figure 1.2-4 from the medium-voltage

17 FIXED DRAW-OUT DRAW-OUT TRANSFORMER “T1” M1-00 MOUNT POWER POWER PRIMARY UNIT SUBSTATION STYLE (1) CIRCUIT CIRCUIT CIRCUIT 13.8 KV DELTA PRIMARY - 95KV BIL H2 63 P/FA = 479A 18 BREAKER BREAKER BREAKER 4.16/2.4 KV GROUNDED WYE - 60KV BIL T1 EATON “PEAK” 55C/65C/75C H1 H3 CU 71 49 7500/8400/9156 KVA KNAN X Figure 1.2-3. Circuit Breaker Symbols X 3 T1 T1 19 9375/10500/11445 KVA KNAF X 0 1 S/FA = 1589A (1) (1) FR-3 FLUID FILLED, 6.5% MINIMUM Z X2 WITH SURGE + LIGHTNING ARRESTERS (1) 600:5 20 P/FA = CURRENT RATING. PRIMARY, FORCED AIR. 2000 A BUSWAY HI (C200) S/FA = CURRENT RATING. SECONDARY, FORCED AIR.

21 Figure 1.2-4. Transformer Information and Symbols

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.2-7 August 2017 Designing a Distribution System Sheet 01 013

Short-circuit values are critical in INCOMING SERVICE CALCULATIONS the design and specification of all i electrical equipment in a power Megawatts Required 8.17 MW KW = 8170 KVA = 10,213 KVA Conversion = Kilowatts x Power Factor PF = 0.8 system. The transformer’s Impedance, NUMBER OF INCOMING SERVICES PARALLELED 1 (often abbreviated as %Z) must be Contingency = 0 Feeders ii shown on the One-Line in order Transformers Must Be Sized to have: 1 Carry Entire Load. Min KVA Each = 10,213 to calculate the required ratings of Primary Temp Rise % Capacity Primary Secondary Secondary % Available downstream equipment as indicated Voltage KV Rating Increase KVA Rating Current Voltage Current Impedence Sec SC * 1 13.8 55C KNAN Base Rating 7500 313.8 4.16 1040.9 6.5 16014 in Figure 1.2-5. 13.8 65C KNAN 12.0% 8400 351.4 4.16 1165.8 13.8 75C KNAN 22.1% 9158 383.1 4.16 1271.0 It is important to remember that 13.8 55C KNAF 25.0% 9375 392.2 4.16 1301.2 13.8 65C KNAF 40.0% 10500 439.3 4.16 1457.3 2 all transformers designed to ANSI 13.8 75C KNAF 52.6% 11445 478.8 4.16 1588.5 standards have a plus and minus Transformer Available Amps for Contingency Conditions = 1588.5 Calculated Required Amps for Contingency Conditions = 1417.4 7.5% tolerance for impedance. If a 3 transformer requires an absolute SHORT CIRCUIT CALCULATIONS AND SWITCHGEAR MVA SELECTION CRITERIA minimum impedance to ensure the 5kV Max If Known SC= 11650 Available Primary SC Fault Current secondary short-circuit level does Breaker KA Rating f = 2.4132649 FORMULA = (SC*PV*1000*1.732*Z)/(100000*KVA) 4 not exceed a critical value, it must be 50 VCP-W 25 25 M = 0.2929746 FORMULA = 1/(1+f) 50 VCP-W 40 40 I2 = 11323 FORMULA = (PV/SV)*M*SC noted on the One-Line and in the 50 VCP-W 50 50 # of Services Paralleled = 1 accompanying project specifications. 50 VCP-W 63 63 With Known SC Current * Unlimited short circuit Available Secondary Short Circuit Current 11,323 16014 5

Consideration must also be given to NOTE: CALCULATION DOES NOT INCLUDE DOWNSTREAM MOTOR CONTRIBUTION the types of cable terminations based 6 on the available short-circuit ratings. Figure 1.2-5. Incoming Service Calculation Where the available short-circuit This is done to indicate to the equip- exceeds 12.5 kA, medium-voltage ment manufacturer or installing molded rubber deadfront termina- 7 contractor that the CT inputs to the tions are generally not an option. In relay should not be grounded in these cases, the type of terminations more than one location. must be specified. Stress Cone cable 8 OR terminations are available in either Hot CTs generally are wired to shorting ter- Shrink or Cold Shrink configurations. minal blocks as indicated by the “SB” 9 Porcelain terminators or potheads are in the box shown in Figure 1.2-7. These a more expensive option, but often are used to short out the secondary of have higher short-circuit ratings. OR the CTs prior to equipment installation 10 or when servicing them. Current transformers are used in both low- and medium-voltage applications as sensing devices for protective 11 relays and meters. They are available UTILITY (3) PT'S CT’s (2) 500:5 in “donut” style, which encircle the Figure 1.2-6. Current Transformer Symbols 14,400:120 V (3) 120:1 (3) 13.8 kV, 1200 A, 50 kA SYM S.C. 12 conductor, as well as bar style, which (15 kV - 95 KV BIL RATED)

In the case of Differential Protection SB is bolted in series with the load (3) 800:5 conductors. Both styles work on Circuits such as the 87-T1 Transformer STD (C100) 1 TRIP M1 the principal of electromagnetic Differential or the 87-B1 Bus Differential, GR A 13 52-M1 TRIP S1 M1A LO N.C. 1200 A 52 the CTs are oriented in opposing (1) C/S coupling; a current flowing through M1-L 86 TRIP M1 (1) the conductor they surround induces directions as illustrated in Figure 1.2-7. M1 TRIP S1 86 T1 a proportional isolated low level This permits the Differential Relays SB 14 (3) 800:5 TS STD (C100) signal (either 1 A or 5 A) that can be to measure the current going into a (1) (3) 51G 87 measured by an electromechanical or transformer or busbar and deduct the (3) 600:5 MR T1 T1 Set at 350:5 ETR-5000-T1 (4) GROUND STUDS 15 electronic device. current flowing out of it. When more TS TS TS current is flowing into the zone of (3-Ø, 1-GND)

Current transformers may be shown M1-00 protection than is proportionally (1) H2 63 in several formats as indicated in P/FA=479 A 16 flowing out, the relay senses the T1 Figure 1.2-6. “differential” and trips the circuit H3 CU 71 49 X3 T1 T1 X0 1 S/FA=1589 A (1) (1) breakers at high speed to protect X The dots, X’s or boxes are used to 2 (1) 600:5 against a fault anywhere in the zone. 2000 A BUSWAY 17 denote the instantaneous polarity HI (C200) orientation of the CT. The polarity (4) GROUND STUDS “POINT B” T1 - 11.32 KA Note the “Y” symbol, as well as the (3-Ø, 1-GND) SCA WITHOUT MOTOR SCA, SB CABLE % Z TO T1 & (3) 2000:5 marks on the conductor generally face BUSWAY % Z quantity “(3)” next to the CTs. This STD (C200) 18 toward the source of the current flow. represents three CTs configured in a 1 GR A 52-S1 The polarity mark on the CT winding (1) S1A LO N.C. three-phase grounded wye arrange- 2000 A 52 86 C/S represents the relationship of the TRIP S1 S1-L ment. While most of the CTs on the S1 19 CT’s X1 secondary terminal to the H1 TS SB system one-line on Page 1.2-4 are (3) 2000:5 medium-voltage terminal on bar type shown this way, the CTs on the output STD (C200) CTs or its input orientation for donut (3) 2000:5 side of the 2000 A breaker S1A are STD (C200) SB 20 style CTs. not grounded. “BUS A” 4.16 KV, 2000 A, 60 KV BIL, 40 KA SC RATED Figure 1.2-7. Example of Differential Circuit 21 with Current Transformer Symbols

CA08104001E For more information, visit: www.eaton.com/consultants 1.2-8 Power Distribution Systems Designing a Distribution System August 2017 Sheet 01 014

It is highly recommended that the Standard for Device Function i design engineer show Test Switches Numbers, Acronyms and Contact on the System One-Line and include Designations. them in the specifications. These are ii shown on the one-line as a box with See Ta b l e 1. 11- 1 in Power Distribution (3) PT’S Systems Reference Data Section of “TS” in it. Test switches are used 4200 V: 120 V this document for Device Function during protective relay testing to 35:1 1 provide an alternate path to inject Number information. current and voltage from a test set, These element numbers are shown in when commissioning these devices a circle on the One-Line. A given relay 2 in the field. may have multiple voltage and current When designing a power system, it Figure 1.2-8. Voltage Transformer Symbol elements shown in a common box, such as the EDR 5000-M1 protecting is necessary to select the ratio and The secondary output of both voltage 3 the 52-M1 breaker in Figure 1.2-9. the accuracy class for the CT’s. For and current transformers are measured protective relaying, the CT must be by protective relays and used in calcula- The numbers in parenthesis define the 4 sized to ensure they do not saturate tions involving preset thresholds. quantity of each specific element. In under fault conditions. This may result many cases this quantity is (3); one Voltage monitoring elements of in a higher accuracy class with more for each of the three phases. In some protective relays compare the input 5 physical mass or a higher CT ratio cases, such as the 50/51N function, from the VTs against a desired set- being specified. Most of the CTs this is shown as a quantity of (1). point to see if the system voltage is shown on Figure 1.2-7 are Standard The symbol to the right of this relay over or under that nominal value. If 6 Accuracy Class for the ratios selected. represents a transition from (3) the value exceeds a plus or minus The exception is the single 600:5 CT individual phase elements to a single tolerance band around the set-point, in transformer T1’s Neutral to Ground residual neutral protective element. 7 Connection. This is shown as a high an output contact or contacts in the accuracy CT. relay change state to signal an alarm The output of each protective function or trip the circuit breaker open. is shown with a dashed line and arrow When selecting CTs for metering indicating what action is to be taken if 8 Microprocessor-based relays offer purposes, such as those connected the relay determines the monitored tremendous functionality over the to the Eaton PXM-6000 Power Quality values exceed the preset thresholds. older electromechanical and solid- Meter (see Tab 3 for details) it is The EDR-5000-M1 Relay’s 50/51 9 state predecessors. Many of these best to use the CT ratio as close to Elements (Instantaneous Overcurrent devices offer multiple types of voltage the actual load as possible. This is and Time Overcurrent respectively) and current protective elements. 10 done to increase the accuracy at the are shown tripping a high-speed 86-M1 low end of the range because the CT’s Protective relay elements are generally Lockout Relay. The elements of the excitation begins to deteriorate at denoted by a number or characters ETR-5000-T1 Transformer Differential 11 about 10% of its ratio setting. As an as defined in the ANSI/IEEE C37.2 Relay are shown similarly, also tripping example, a 600:5A fixed ratio CT an 86-T1 lockout relay. would begin to lose accuracy at 60 A. 12 Where loads are light, during construction or during early build out USG-1A (3) SINGLE PHASE POTHEADS (1/Ø) “POINT A” 11.65 KA SCA AVAILABLE FROM UTILITY stages, the actual current that must be (4) GROUND STUDS (3-Ø, 1-GND) 13 measured by the meter may be only (2) UTILITY PT’s 100 A. Multi-ratio CTs are frequently (6) LIVE LINE INDICATORS (2/Ø) 14,400:120 V 10 A 14 used to set the maximum ratio lower. If set at 100:5A, this would improve TRIP M1 accuracy down to 10 A for a 100 A TRIP S1 UTILITY load. Conversely, as the end loads (3) PT’S CT’s (2) 500:5 15 grow, the maximum ratio setting can 14,400:120 V (3) 120:1 (3) 13.8 kV, 1200 A, 50 kA SYM S.C. be easily increased by changing the 27 59 TS (15 kV - 95 kV BIL RATED) CT tap settings. M1 M1 16 (3) (3) SB (3) 800:5 Voltage transformers are used to step STD (C100) higher voltages down to safe levels EDR-5000-M1 1 TRIP M1 17 for inputs to relays and meters. GR A 52-M1 TRIP S1 M1A LO N.C. Traditionally, voltage transformers 1200A 52 (1) (3) (1) C/S (VTs) utilize a higher primary voltage M1-L 50/51N 50/51 86 TRIP M1 (1) 18 winding that is a fixed ratio to the M1 M1 M1 TRIP S1 86 T1 120 Vac secondary winding. Examples TS SB (3) 800:5 TS shown on the One-Line are STD (C100) 19 14,400 V:120 V (a ratio of 120:1) or (1) (3) 51G 87 4200 V:120 V (a ratio of 35:1). Voltage PXM6000 T1 T1 METER (3) 600:5 MR transformers are often referred to as Set at 350:5 ETR-5000-T1 (4) GROUND STUDS 20 potential transformers or PTs. They are TS TS TS (3-Ø, 1-GND) illustrated symbolically as shown in Figure 1.2-8. 21 Figure 1.2-9. Protective Relay Element Symbols

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.2-9 August 2017 Designing a Distribution System Sheet 01 015

In both cases, the associated (86) lockout relay then trips the incoming i main breaker “M1” and the transformer EDR-5000 1 secondary breaker “S1”. Lockout relays 27 A are used to multiply the tripping ii 74 50 59 46 50R 51R 50P 51P 67P 67N LOP Metering and contacts for a given function so they TC BF A Statistics can be wired into multiple breaker’s 59N Current and volt.: unbalance separate control circuits as indicated 3 %THD and THD 1 for the 86-B1 device on the System CTS SOTF CLPU Fund. and RMS 25 min./max./avg. 1 angles One-Line. Their primary function, 47 55 A/D however, is to require a manual reset Power: 2 3 Fund. and RMS of the Lockout Relay mechanism by MVA, Mwatt, Mvar, PF 27 59 81 trained personnel after the cause of the M M U/O 81R 78V 50X 51X 51V 67G 32 32V fault is determined and corrected. Event recorder 3 IRIG-B00X Zone Interlocking Breaker Wear Disturbance recorder Fault recorder The 27 and 59 functions shown in the EDR-5000 relay monitor undervoltage 4 and overvoltage respectively. Their Figure 1.2-10. EDR-5000 Protective Relay Elements Available outputs are shown combined into a single dashed line directly tripping both Figure 1.2-9 shows some additional One such requirement is the breaker’s 5 the incoming main breaker “M1” and important information about the close and latch rating. Where higher the transformer secondary breaker equipment required in the dashed fault current values exist, some “S1”. This reflects the engineer’s desire box that comprises utility switchgear utilities specify this value at 130 kA 6 to have only one output contact for “USG-1A”. This switchgear is defined peak, which is more in line with the both the 27 and 59 functions. Because as 15 kV Class with a 95 kV basic older 1000 MVA rated design. Because two breakers need to be tripped, this impulse rating. The bus is rated to the 40 kA K=1 design’s close and latch 7 will only require two separate relay handle 1200 A even though the actual rating is only 104 kA, the 130 kA close contacts instead of four individual ampacity flowing through it will be and latch rating for the 50 kA breaker output contacts otherwise necessary. under 500 A. The equipment will be would dictate it being used instead. 8 operating at 13.8 kV and have a short- It is very important to be cognizant of The direct trip shown on the System circuit rating of 50 kA Symmetrical. nuances in all utility specifications One-Line purposely does not use an See Tab 5 for details. to avoid costly problems or delays 9 86 lockout relay, as this under or over in energization. voltage disturbance is anticipated to Because this One-Line is for educational be caused by the utility and not a fault purposes, a hypothetical short-circuit Certain utilities mandate the type 10 on the end user’s power system. In value at “Point A” from the Utility is of cable termination that must be these instances, a separate contact shown for reference at 11.65 kA. In provided in the switchgear such as the from the relay may be allocated to actuality, this value would be part of a (3) single-phase pot-heads illustrated 11 start a backup generator or to initiate short-circuit study. If using a program on Figure 1.2-9. a Main-Tie-Main Transfer Scheme. such as SKM to calculate the downstream short-circuit values, the cable Utilities may also require neon glow The EDR-5000 Relay and the ETR-5000 lengths and conduit types as well as the tubes or other live line indicators to 12 Relay are programmable multi-function transformer impedance would factor be located on all three incoming devices with many protective elements into the calculations. phases. These devices are intended to that can be utilized simultaneously. caution personnel that the incoming 13 In a more fully developed protection The “USG-1A” switchgear on the circuit may be energized. scheme, certain protective elements One-Line is shown with a 50 kA rating (such as the 50/51 functions) can when other lower ratings such as 14 be used in both relays to back each 40 kA and 25 kA are available at 15 kV. other up in the event of a failure. This has been done as an example to Figure 1.2-10 shows the many future design engineers who may be 15 protective elements available in the involved in urban areas with medium- EDR-5000 Feeder Protective Relay. voltage services. These MV services (See Tab 4 for further details.) typically have higher available short- 16 circuit capacity. In most cases, the Eaton’s “E Series” relays include an serving utility may have specific ANSI 74 element to monitor the trip specifications for the switchgear and 17 coil of the circuit breaker or lockout breakers used as medium-voltage relay they are tripping. This circuit service equipment. ensures the integrity of the device to 18 operate correctly when a trip signal is applied. The example One-Line should show the relay circle with the “74” in 19 it next to the “86” lockout relay and breaker “52” symbols. These were purposely not shown on the drawing 20 as it would make it more crowded and difficult to read. 21

CA08104001E For more information, visit: www.eaton.com/consultants 1.2-10 Power Distribution Systems Designing a Distribution System August 2017 Sheet 01 016

However, it is always best to follow Key interlocks are also used in the Drawing Notes are extremely important i Occupational Safety and Health Main-Generator-Tie “Bus A” half as they describe specific functional Administration (OSHA) approved of double-ended 480/277 Vac requirements. In Figure 1.2-13, Note 3 practices and assume that the circuit is secondary unit substation as shown above switchgear “SUS-F1A” describes ii live until a calibrated voltage reading in Figure 1.2-11 and Figure 1.2-12. This an additional requirement for a Priority probe attached to a hot-stick deter- scheme permits only one source to Load Shed Scheme to ensure the mines otherwise. feed “Bus A” of the double-ended generator is not overloaded. The 1 switchgear at a time. details of this scheme would need to Most utilities and institutions involved be coordinated with the generator in the distribution of medium-voltage This arrangement, while functional in manufacturer and further defined in 2 power use portable ground cables physically blocking multiple sources the switchgear specifications. that are applied only after no voltage such as “MB-F1A”, “GB” and “MB-F1B” presence has been confirmed. from being paralleled, does not permit Note 4 calls for DT1150+ electronic 3 This requires that ground studs be Bus “B” of the double-ended substation breaker trip units that include an mounted in the switchgear in order to be alternately fed from the “MV-F1A” Arcflash Reduction Maintenance Mode. to facilitate their OSHA compliant breaker or the “GB” breaker. This may This feature limits arc flash energy in 4 grounding procedure. or may not be the intent of the design compliance with Article 240.87 of the engineer. In either case, the engineer 2014 NEC by using an alternate high- As shown on the System One-Line, must think through the intent of the speed analog instantaneous trip setting 5 there are ground studs on the incom- key interlock scheme and develop the to reduce arcing time. Note 5 requires ing and outgoing sides of both the logic accordingly. a touchscreen panel to monitor the “USG-1A”, (13.8 kV) and “PSG-1A” operating variables as well as be used 6 (4.16 kV) switchgear. Applying these Key interlocks are available in a variety to activate the Arcflash Reduction portable ground cables requires a safe of configurations including transfer Maintenance Mode remotely. This disconnection of power in the zone blocks to capture keys from multiple permits personnel who will be working 7 to be grounded to ensure personnel sources. They are often used as part on the equipment to be in a safe safety. Consequently, a Key Interlock of Lockout and Tag-Out procedures. location outside of the arc flash zone Scheme would be required to prevent It is recommended that the design when enabling the Arcflash Reduction 8 grounding unless the respective engineer refer to a key interlock Maintenance Mode. breakers in the zone were withdrawn manufacturer such as Kirk or Superior from their connected position and for further documentation and specific Note 4 also requires Zone Selective 9 locked open. operational details. Interlocking. This feature permits higher speed tripping of the Main breaker, if it The symbol representing the key does not receive a restraining signal 10 interlock shown on the One-Line next from a downstream feeder breaker that to the “M1” and “S1” breaker is the it is tripping to clear a fault. box with the circle and the letters “LO” 11 inside it. The “LO” nomenclature indicates that the key “M1A” or key FROM PSG-2A (SEE DWG E102) BUSWAY RISER “S1A” respectively is only removable 4.16 kV, 3Ø, 60Hz (SEE DWG E106) when the device (breaker or fused 4 6 12 RBP-F3A T5-RBP-F3A PXM6000 switch) is in the Locked Open position. (3) N.O. P=208A S=1804A METER M.H A PT’S AL 480 V:120 V 8 250 KA Key interlocks are also shown on the LO 300E /Ø.SPD MAIN CB 13 MVS switches in two of the (4) Primary E.O. “RBS-F3A” N.C. M.H P 2000 AF Selective Step-Down substations fed 7 1500 kVA 1800 AT F3DLO 4.16 kV-480/277 V LSG from MV Feeder Breaker F3A, as well 5.75% Z (3) 2000:5 as on the medium-voltage switch 14 RHBP-F3A T4-RHBP-F3A “CUP-F1A”. This is done to prevent N.O. P=104A S=2082A M.H A paralleling of the two different sources 6 AL RESIDENCE VFI-3A HALL B 15 involved in the Primary Selective 600 A (SEE DWG E105) N.C. P Scheme. See Tab 8 for details. M.H 750 kVA FR3 VFI PADMOUNT 5 SELECTOR SWITCH 55/65C 5.75% Z W/SURGE+LIGHTNING 4.16 kV-60 KV BIL 16 The 750 kVA pad-mounted transformers ARRESTERS 208/120 V-20 KV BIL on the One-Line, feeding “Residence DFP-F3A T3-DFP-F3A N.O. P=139A S=1203A Hall A” and “B”, are shown with internal M.H A 4 AL vacuum fault interrupters (VFIs) as their LO 200E DINING 17 FACILITY overcurrent protection. The VFIs offer (SEE DWG E104) N.C. M.H P many of the benefits of a circuit breaker, 3 1000kVA such as disconnection of all three F3BLO 4.16kV-480/277V 18 5.75% Z phases simultaneously, and may be RHAP-F3A T2-RHAP-F3A used with external protective relays N.O. P=104A S=2082A M.H A such as EDR-3000 Distribution or 2 AL 19 RESIDENCE “POINT C” F3A - VFI-2A HALL A ETR-3000 Transformer Differential 11.32 KA SCA 600 A (SEE DWG E103) WITHOUT MOTOR N.C. P Relay. The VFI option is available SCA & CABLE Z TO M.H 750 kVA FR3 VFI PADMOUNT 1 T1 & T2-RHAP SELECTOR SWITCH 55/65C 5.75% Z “POINT D” - 40,400 SCA for fluid-filled transformers in both WITH UNLIMITED PRIMARY SCA 20 W/SURGE+LIGHTNING 4.16 kV-60 KV BIL ARRESTERS 208/120 V-20 KV BIL & 50% MOTOR CONTRIBUTION pad-mounted and unit substation SEE XFMR TABLE 1.6-7 FOR M1-03 configurations. See Tab 17 for Ratings T2 ESTIMATING PURPOSES. 21 and Construction details. Figure 1.2-11. Drawing Notes and Key Interlock Scheme in LV Switchgear

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.2-11 August 2017 Designing a Distribution System Sheet 01 017

Note 6 adds a requirement for BACnet of the switchgear. This avoids bottom As outlined in Tab 24 of this Consulting communications functionality to a exiting cables from covering access to Application Guide, Eaton's low-voltage i future Building Management System. the lugs for the spare and generator busway can be supplied in ratings of It also provides a point of demarcation breakers. Consequently, it permits 6–30 cycles. The 4000 A busway shown between the scope of work to be room to terminate the future cables, has a 200 kA 6 cycle rms symmetrical ii provided by the installing contractor coming into the top of the switchgear, short-circuit rating that exceeds the and what portion of the wiring and easily at a later date. 85 kA rating of the “SUS-F1A” switch- interface will be required of the gear bus on the drawing. 1 BMS vendor. It is always wise to include spare breakers of important frame and trip The calculated short-circuit rating Each of the circuit breaker symbols sizes in a drawout switchgear lineup. required for the “SUS-F1A” switchgear 2 in the “SUS-F1A” switchgear are These spare breakers can either allow is dependent on a number of factors surrounded by double arrows signify- for future load growth or provide a including: the available short circuit ing that these breakers are drawout readily available backup that can be upstream, the inclusion of the cable 3 versus fixed mount. Additionally, the used in the event that an active breaker and transformer impedances feeding it, “E.O.” nomenclature in the middle requires maintenance or service. as well as the short-circuit contribution of the breaker symbol represents from the motors downstream. 4 “Electrically Operated”. This function Note that interference interlocks makes it easier to open and close the are supplied on breakers and in In actuality, the short-circuit current breaker. It also enables the opportunity switchgear compartments where available may be lower than the 85 kA 5 for remote control from a handheld the compartments are of the same shown on the drawing, permitting a pendant operating station or a wall- physical size. This rejection feature potential cost and space savings, if the mounted control panel. ensures that an insufficient short rating required is dropped to 65 kA or circuit or incorrect ampacity rated below. A short-circuit study would 6 Each circuit breaker is named and its breaker cannot be inserted into the need to be done to confirm this. Frame Size (AF), Trip Rating (AT) and wrong size cell. See Section 1.3 of this tab for further protective functions such as Long, information on short circuit and power 7 Short and Ground (LSG) or Long, As an example, a 1600 A breaker systems analysis. Short, Instantaneous and Ground cannot be used in a cell configured (LSIG) are noted accordingly. Since for 800 A as it would not likely protect Consequently, it is very important to 8 this equipment is drawout UL 1558 the cell bus runbacks and outgoing indicate the actual breaker short-circuit switchgear, the 4 cell high structure cables appropriately. Likewise, a 65 kA rating as well as the switchgear bus 9 number and associated breaker cell short circuit rated breaker could not be ratings on the One-Line. These also are illustrated. inserted into a switchgear cell rated need to be consistent with other for 85 kA. schedules and drawings, as well as “Spare” breakers have been located in in the equipment specifications. This 10 the top “A” cells 02A and 04A as well Figure 1.2-12 shows the main bus for can prevent a bidder from incorrectly as cells 04B and 4C in structure #4. The the switchgear rated at 4000 A with an quoting 85 kA rated switchgear with generator breaker is also located in top 85 kA short-circuit rating. A busway 65 kA rated breakers. See Tab 20 for 11 cell 03A of structure #3, for cable and symbol is illustrated above the tie further information on Low-Voltage conduit egress out the top. In this breaker, indicating that it is connecting Metal-Enclosed Drawout Switchgear. example, all other breaker cables to the other half of a double-ended 12 “feeding loads exit out the bottom switchgear lineup. 13

PSG-2A (SEE DWG E102) DRAWING NOTES 4.16 kV, 3Ø, 60Hz 1 Provide M1 Electrical Interlock With S1 Breaker. M1 Cannot Close if S1 is Open. S1 Cannot Close Until M1 is Closed. Include Key Interlocks as Shown. 14

N.O. ENGINE DIESEL Provide MB-F1A Key Interlock With Generator Breaker “GB” and Tie Breaker CUP-F1A 2 A “LTA”. Only the Single “MGT” Key Can be Used to Close Any of these Breakers. Provide Priority Load Shed Controls for Feeder Breakers in SUS-F1A Switchgear. LO 3 G Provide Interface With Generator Breaker “GB” to Enable Operation When Non- 15 N.C. P FDR Priority Loads have Been Shed. (SEE DWG E108) “G” Provide All Magnum Breakers in SUS-F1A & RBS-F3A Switchgear With DT1150+ F1ALO 4 4000 A BUSWAY TO CLE 2000AF Trip Units Including Zone Selective Interlocking (ZSI) and Arc Flash Reduction TIE CB “LTB” IN 600 A 2000AT Maintenance System (ARMS) in Compliance with Article 240.87 of the 2014 NEC. PORTABLE “SUS-F1B” 16 LOAD BANK Provide Remote Touchscreen Panel With “Switchgear Dashboard Interface” to P FA=461 A 5 Monitor Operational Variables and Enable Arc Flash Reduction Maintenance Mode. XFMR “ST-F1A” CU 2500/3333 kVA TOUCH Wire All DT1150+ Trip Units Communications Ports to an Ethernet Gateway With 5 6 115C AA/FA SCREEN BACnet IP Connectivity. BMS Vendor Will Provide Field Wiring and Integrate Into 4.16 KV-480/277 V BMS System on a Separate Contract. 17 S FA=4000 A Z=5.75% 2 3 2 MAIN CB TIE CB SECONDARY UNIT SUBSTATION “SUS-F1A” MGT “MB-F1A” (3) PT’S “GB” “LTA” 480 V: EG BACNET IP LO E.O. 4000 AF 120 V TO BMS LO E.O. 2000AF LO E.O. 4000 AF 18 4000 AT 2000AT 4000 AT TO DT1150 N.C. LSG PXM6000 N.O. LSG N.O. LSG METER ETHERNET TRIP UNITS “DF5A” 01B (3) 4000:5 GATEWAY MAIN SWGR. BUS “A” 85 KA, 480/277 V, 4000 A, 3-PH, 4W, (ALL BREAKERS RATED SC AT 85 KA) 01D 02A 02B 02C 02D 03A 03B 03C 03D 04A 04B 04C 04D 19 “DF1A” “DF2A” “DF3A” “DF4A” “DF6A” “DF7A” “DF8A” “DF9A” “DF1OA” “DF11A” “DF12A”

250KA/Ø E.O.800AF E.O.800AF E.O.1600AF E.O. 800AF E.O.800AF E.O.800AF E.O.800AF E.O. 800AF E.O.800AF E.O.800AF E.O. 800AF SPD 600 AT 600 AT 1600 AT 600 AT 800 AT 400 AT 600 AT 600 AT 400 AT 500 AT 500 AT LSIG LSIG LSIG LSIG LSIG LSIG LSIG LSIG LSIG LSIG LSIG 20 SPARE SPARE SPARE SPARE

21 Figure 1.2-12. Drawing Notes and Key Interlock Scheme in LV Switchgear

CA08104001E For more information, visit: www.eaton.com/consultants 1.2-12 Power Distribution Systems Designing a Distribution System August 2017 Sheet 01 018

The System One-Line shows the Typical loads are shown, however, for Motor control centers are used to i incoming surge protective device the various motors being fed out of group overcurrent protection and (SPD) in “SUS-F1A” is rated at 250 kA motor control center MCC-DF3A. Each different starter types for the motors per phase. As shown in Figure 1.2-13, motor’s designation and full load in a portion of a power system. They ii SPDs in the other downstream amps are shown below the motor may also contain associated control equipment are rated at 120 kA per symbol that contains the motor’s and distribution equipment as well phase. This surge protection scheme horsepower rating. as connectivity interfaces to industrial 1 as shown is applied in a tiered control or Building Management approach per the IEEE Emerald Book. Safety switch symbols are shown Systems (BMS). Motor starters, and In this arrangement, the highest level between the MCC and the motor motor protective overload relays are 2 of surge protection is at the incoming symbol. Safety switches are used to available in both electromechanical source. Downstream switchboards electrically isolate the motor during and electronic solid-state configura- or panelboards closer to the loads maintenance or to ensure it does not tions. See Tab 30 for details. 3 provide the next of surge protection. start unexpectedly when personnel are See Tab 34 for further information on working on or in the equipment it is In a motor control center application, surge protection. powering. The operating handles of the starter is provided with either a 4 safety switches have provisions for thermal-magnetic circuit breaker or There is a considerable amount of applying a lock-out tag-out device. high magnetic circuit protector (HMCP) distribution equipment illustrated on They are generally provided with selected to permit the high inrush 5 the example System One-Line. For that fuse protection to ensure adequate current of the motor while starting. reason, reference is made to other short-circuit ratings for the application. Either type of overcurrent protective drawings and schedules that would For those situations requiring a short- device provided must be selected to 6 comprise the hypothetical bid package. circuit rating of 10 kA or less, a non- coordinate with the motor overload As an example, 1600 A distribution fused safety switch may be specified. protection relay. switchboard DSB-DF4A has a note to See Tab 28 for details. 7 see schedule DSB-DF4A for the end loads. The same is true for power panel PP-DF6A. 8

4000 AT 2000AT 4000 AT TO DT1150 N.C. LSG PXM6000 N.O. LSG SECONDARY UNIT SUBSTATION “SUS-F1A” N.O. LSG METER ETHERNET TRIP UNITS “DF5A” 9 01B (3) 4000:5 GATEWAY MAIN SWGR. BUS “A” 85 KA, 480/277 V, 4000 A, 3-PH, 4W 01D 02A 02B 02C 02D 03A 03B 03C 03D 04A 04B 04C 04D “DF1A” “DF2A” “DF3A” “DF4A” “DF6A” “DF7A” “DF8A” “DF9A” “DF1OA” “DF11A” “DF12A”

250 KA/Ø E.O.800AF E.O.800AF E.O.1600AF E.O. 1600AF E.O.800AF E.O.800AF E.O.800AF E.O. 1600AF E.O.800AF E.O.800AF E.O. 800AF SPD 600 AT 600 AT 1600 AT 1600 AT 800 AT 400 AT 600 AT 1600 AT 400 AT 500 AT 500 AT 10 LSIG LSIG LSIG LSIG LSIG LSIG LSIG LSIG LSIG LSIG LSIG SPARE SPARE SPARE SPARE (SEE DWG E109) FROM GEN A 11 NORMAL ATS-A GENERATOR SOURCE SOURCE BYPASS ATC-900 1600AF DSB-DF4A SEE SCHEDULE DSB-DF4A ISOLATION TRANSFER 1600AT ATS CONTROL 480V, 1600A, FOR LOADS PP-DF6A 3Ø, 4W, 65 KAIC 480 V, 600 A, 12 120 KA/Ø 800AF 3Ø, 3W, 65 KAIC SPD 800AT

480/277V, 800A, MAINTENANCE 225AF 400AF 800AF 600AF 400AF 225AF 400AF 3Ø, 4W, 65 KAIC ISOLATION 175AT 250AT 800AT 600AT 250AT 200AT 250AT BYPASS MBP BIB RIB 13 SPARE SPACE 2X SEE SCHEDULE PP-DF6A UPS1 FOR LOADS 300 KVA

1600 A MCC-DF3A FREEDOM FLASHGARD MCC MLO 120 KA/Ø 480 V, 1600 A, 14 SPD 3Ø, 3W, 65 KAIC

400 A 150 A 150 A 150 A 150 A 400 A 400 A 150 A 150 A 150 A 150 A 150 A 150 A FR10 SIZE4 SIZE4 SIZE4 SIZE4 SIZE5 SIZE5 SIZE4 SIZE4 SIZE4 SIZE4 SIZE4 SIZE4 15 261A FVNR FVNR FVNR FVNR FVNR FVNR FVNR FVNR FVNR FVNR FVNR FVNR MIS 18 2S2W 2S2W 2S2W 2S2W Eaton 9395 UPS PULSESS0L SS0L SS0L SS0L SSRV SSRV SS0LSS0L SS0L SS0L SS0L SS0L VFD W/GFP W/GFP W/GFP W/GFP W/GFP W/GFP W/GFP W/GFP W/GFP W/GFP DC-DS-A 16 3R 3R 3R 3R 6 POLE 6 POLE 6 POLE 6 POLE 200 75 75 75 75 150 150 75 75 75 75 75 75 BAT-A NCHWP-1 CWP-1 CWP-2 CWP-3 CWP-4 CHWP-1 CHWP-2 CT-1 CT-2 CT-3 CT-4 SA-1 EF-1 240FLA 96FLA 96FLA 96FLA 96FLA 180FLA 180FLA 96FLA 96FLA 96FLA 96FLA 96FLA 96FLA 17 PDU-1 480V-3Ø 600AF 120 KA/Ø IFS-DF7A 500AT 600AF 400AF 3W,65 kA SPD 600AT 400AT 150 A DSB-DF2A P=361A 120KA/Ø 480V, 600A, XFMR-DF8A P=361A SPD 3Ø, 3W, 65 KAIC XFMR-DF7A P=90A 300 KVA XFMR-UPS1 18 225 A 75KVA 480-208/120 V 300 KVA 480- 480-208/120 V 208/120 V S=833A 150AF 150AF 150AF 150AF 150AF 150AF 150AF S=208A S=833A “DF7AP” 208/120 V, 3Ø, 4W 40AT 15AT 90AT 100AT 90AT 100AT 100AT 480/277 V 225A RP-DF8A SPARE SPACE 2X 225A 3Ø, 4W, 65KA 1200AF 400AF 400AF 19 POW-R-COMMAND 1000AT 400AT 400AT LIGHTING CONTROL 208/120 V, 225 A, 3Ø, 4W, 10 KAIC CDP-A CDP-B POW-R-COMMAND 208/120 V, 1200 A, 10 2 42 Circuit 42 Circuit 4X 4X RECEPTACLE CONTROL 3Ø, 4W, 65 KAIC GYCOL FUEL HVAC HEAT COMFORT HEAT PUMP PUMP AHU-1,2,3,4 REJ.COOLING REJ. 20 GCP-1 FOP-1 UNITS CH-1 UNITS SEE SCHEDULE IFS-DF7AP & DF7AS SEE SCHEDULE RP-DF8A SEE SCHEDULE PDU-1 HRU-1,2,3,4 HRU-5-9 FOR NORMAL & CONTROLLED LOADS FOR LOADS FOR CRITICAL LOADS

21 Figure 1.2-13. Distributor Equipment Downstream of the SUS-P1A Switchgear

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.2-13 August 2017 Designing a Distribution System Sheet 01 019

This combination starter is mounted in Electromechanical overload relays Many two-speed starters are applied a removable “bucket”. Lower ampacity sense an overcurrent by directing the on motor loads such as cooling i buckets are wired to stabs on the rear current through a melting eutectic towers, where the fan needed to run of the bucket and manually plugged element or a heater pack. The heat is at a lower speed or higher speed, to directly onto the vertical power bus proportional to the amount of current optimize the heat transfer and main- ii bars in the MCC. flowing. When the eutectic element tain water temperature in the return melts or the bimetal bends due to the supply to the chiller. Note: Larger hp starter sizes may be heat from the heater pack, the relay 1 physically hardwired to the bus. opens the control circuit. ASHRE 90.1 is recommending the use of variable frequency drives in Eaton’s FlashGard™ motor control The “SSOL” nomenclature next to the applications where they can reduce 2 center “bucket” shown in Figure 1.2-14 overload relay shows these particular energy consumption and improve the adds an additional level of personnel starters as having solid-state overload performance of the equipment they are safety. The FlashGard design incorpo- relays. The text “W/GFP” calls for powering. As an example, in lieu of 3 rates a RotoTract™ lead screw assembly ground fault equipment protection. two-speed motors on cooling towers, that withdraws the stab assembly off In the past, this would have had to be VFDs are being used to maximize the energized bus bars and into the added as a separate relay, however, efficiency of the cooling process. In 4 bucket. A spring-loaded shutter then many of the new overload relays use these cases, a sensor is placed in the automatically closes off access to the microprocessors to monitor a number wet well of the cooling tower to bus bars. See Tab 29 for details. of variables including voltage to the monitor the temperature of the water. 5 The 75 hp Circulating Water Pump motor. Eaton’s C440, C441 and C445 A set-point controller in the VFD motors CWP1 through CWP4 shown all include phase loss and ground utilizes the output signal from a sensor in Figure 1.2-13 are examples of full fault protection. mounted in the return water pan as 6 voltage non-reversing starters (FVNR). feedback to modulate the speed of Eaton’s solid-state overload relays also the fan. The drawing documents these as have the ability to communicate status having a full load amp (FLA) rating including current per phase and other The 150 hp CHWP-1 and CHWP-2 7 of 96 A. Based on rating of 96 A key operational variables back to a chilled water pumps in MCC-DF3A (75 hp), which would require a control system. See Tab 4 for details. are shown being fed from solid-state NEMA Size 4 combination starter. reduced voltage starters (SSRV). These 8 Motors are available in a number SSRV starters reduce the motor inrush The starter symbol shown on the of winding styles and performance drawing includes a normally open and ramp them up smoothly to their 9 characteristics. The 75 hp CT-1 through full running speed. SSRV Starters contactor. This is followed by an over- CT-4 motors shown fed from MCC-DF3A load relay symbol. The overload relay can be used to reduce the “water are of the two-speed, two-winding hammer” effect where the pipes in measures the current flowing through variety. Note that six-pole disconnects 10 the starter contacts to the motor and the system experience a sudden thrust are required for two-speed, two-wind- of pressure. calculates when an extended overload ing motors. Because the cooling towers condition is present that will damage are typically located outdoors on a roof, Recent declines in the cost of VFDs 11 the motor. A contact from the overload a NEMA 3R drip-proof safety switch and their associated energy savings relay is wired into the control circuit of would be required. capability have led to their growing the starter, which deenergizes the con- popularity in a number of HVAC 12 tactor coil in the event of an overload. applications. While VFDs still have a higher initial purchase cost than standard starters or solid-state 13 reduced voltage starters, they have Racking Tool Receiver Unit Latch a relatively short payback period. A savvy building owner and design 14 Power Stab engineer will recognize that the total Position cost of ownership and energy savings ■ Connected Internal must be considered when electing to 15 ■ Disconnected Shutter specify VFDs. Position ■ Open Figure 1.2-13 illustrates a Clean Power, 16 Handle ■ Close (18 Pulse) VFD in the MCC-DF3A Mechanism feeding NCHWP-1, a 200 hp motor. This VFD contains a phase shifting 17 transformer that feeds an AC to DC Breaker converter. This DC voltage is maintained in capacitors on its DC Bus. 18 Pilot Device Insulated Gate Bipolar Transistors Island ■ Start, Stop, (IGBTs) are switched ON and OFF Starter Auto/Man at a high frequency to simulate an 19 AC sinusoidal output waveform. 20

21 Figure 1.2-14. Freedom FlashGard FVNR Starter

CA08104001E For more information, visit: www.eaton.com/consultants 1.2-14 Power Distribution Systems Designing a Distribution System August 2017 Sheet 01 020

The output voltage and frequency of Medium-voltage VFDs are used to start As soon as generator power is i this VFD can be set by a digital signal and control the speed of high horse- available, the ATS will transfer to from the keypad or an external analog power motors in sewage and fresh the generator source and begin to signal such as 4–20 mA. A set-point water pumping applications. They are feed the UPS’s inverter section. ii controller in the VFD can also be used also used on medium-voltage high hp to maintain a temperature, flow rate or HVAC chillers. See Tab 10 for details. In this arrangement, consideration pressure level by utilizing an external would need to be given to generator 1 feedback signal from a sensor. Below the MCC in Figure 1.2-13 is stability. An ATS or generator failure IFS-DF7A. This is an assembly that would potentially result in the UPS The use of VFDs in heating, ventilating, allows several pieces of electrical running on batteries until they were 2 air conditioning (HVAC) has been distribution equipment to be pre- out of reserve power. popularized due to the VFD’s ability wired into a switchboard at Eaton’s to save energy. When motors on manufacturing facility. As shown, If this approaches is utilized, the ATS 3 centrifugal fans and pumps are oper- the IFS includes a 480/277 V main should be of the BYPASS/ISOLATION ated at reduced speeds, the energy breaker feeding a 480/277 Vac 225 A design as indicated on the One-Line. required to produce the torque at lighting control panelboard. See Eaton’s contactor-based BYPASS/ 4 motor's output shaft is reduced by Tab 23 for details. ISOLATION transfer switch is available the cube of the speed. See Eaton with removable contactors. This Application Paper IA04003002E A 75 kVA 480 V to 208/120 V transformer permits them to be interchanged with a for details. is also part of the IFS switchboard. It spare or the alternate source contactor 5 feeds a 208/120 V panelboard with during maintenance and testing. This type of centrifugal load is best remote control breakers to feed various served by a variable torque VFD that receptacle loads. 6 optimizes the volts per hertz relationship throughout the speed range. In The Integrated Facility System 2 Switchboard (IFS) arrangement, TIE CB addition to the dramatic energy savings “LTA” 7 as shown in Figure 1.2-15 is a great LO E.O. 4000 AF that can be experienced below 80% of 4000 AT the motor’s base speed, VFDs ensure a alternative to traditional wall-mounted N.O. LSG SWITCHGEAR “SUS-F1A” soft motor start and acceleration panelboards and floor or trapeze 8 throughout the speed range. mounted transformers. Because all of 04C 04D this equipment comes as a prewired “DF11A” “DF12A” Eaton’s CPX Clean Power (18 Pulse) assembly, it generally takes less floor E.O. 800AF E.O. 800AF 500 AT 500 AT 9 VFDs are available in low voltage for and wall space than traditional con- LSIG LSIG operation with 208 V, 230 V, 480 V and struction methods. It also reduces 575 V motors. See Tab 31 for details. installation time and labor costs. (SEE DWG E109) 10 See Tab 21 for details. FROM GEN A As illustrated on the Power System NORMAL ATS-A GENERATOR SOURCE SOURCE One-Line on Page 1.2-4, a medium- Figure 1.2-16 shows one possible BYPASS ATC-900 ISOLATION TRANSFER 11 voltage Clean Power VFD is available application of an Eaton 9395 ATS CONTROL 480 V, 600 A, for use with 4.16 kV motors. The input uninterruptable power supply (UPS-1) 3Ø, 3W, 65 KAIC voltage can be either 4.16 kV or its being fed through automatic transfer

12 internal phase shifting transformer can switch (ATS-A). This arrangement UPS1 be configured to step-down a higher addresses a potential loss of power 300 KVA MBP BIB RIB input voltage, such as 13.8 kV, to from switchgear SUS-F1A. 13 power a 4.16 kV motor. During normal operation, power flows from the “Preferred” Normal source 14 from breaker DF12A in switchgear SUS-F1A, through the ATS feeding the inputs to the rectifier input 15 breaker (RIB) and manual isolation MIS switch (MIS). Eaton 9395 UPS When power is lost at the input 16 to ATS-A, the ATS sends a run DC-DS-A command to Generator A. While the generator is starting and no BAT-A 17 power is available to the UPS, the LOAD UPS inverter will use the DC energy stored in its batteries to generate an Figure 1.2-16. UPS-1 Connection Option 1 18 AC sine wave to feed the loads.

20 Figure 1.2-15. Integrated Facility System Switchboards 21

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.2-15 August 2017 Designing a Distribution System Sheet 01 021

A second option for feeding the UPS This would provide an alternate In a data center application, a UPS would be to avoid providing the ATS path to supply the UPS during a may be used to feed power to one i and feed the “MBP” and “BIB” from maintenance event, such as servicing or more power distribution units one breaker in switchgear SUS-F1A a breaker or cable termination. (PDUs). These PDUs are similar in and the “RIB” input breaker from one Unfortunately, in the event of a power functionality to an IFS Switchboard. ii breaker in switchgear SUS-F1A and outage to the “SUS-F1A” switchgear, They incorporate an integral trans- the “BIB” input breaker from another due to substation transformer failure former to step down the incoming as shown in Figure 1.2-17. or maintenance, power to both the 480 V UPS feed to a 208/120 V supply. 1 UPS Inverter and static switch would The end utilization voltage is distrib- be lost. Since the purpose of the static uted through integrated panelboards bypass is to operate in the event of a out to the various computer loads. 2 2 TIE CB downstream fault, the UPS inverter Individual circuits have CTs so each “LTA” would not be capable of responding can be monitored on the common LO E.O. 4000 AF 4000 AT to faults of this nature. It would, touchscreen display. 3 N.O. LSG SWITCHGEAR “SUS-F1A” however, continue to use battery power to feed the loads until the Eaton PDUs can be provided in a 04C 04D variety of configurations including “DF11A” “DF12A” batteries were fully discharged. 4 other larger frame breakers that can E.O. 800AF E.O. 800AF 500 AT 500 AT Because most UPS battery systems are feed remote power panels (RPPs). LSIG LSIG not intended to provide long periods See Tab 33 for details. 5 of standby power under the aforementioned condition, resumption of Normal power from the “SUS-F1A” switchgear 6 would need to be done quickly. This may be difficult as personnel would need to first open the 4000 A “MB-F1A” 7 main breaker. They would then need to manually operate the Key Interlock UPS1 300 KVA Scheme to enable a second source, 8 MBP BIB RIB such as the 2000 kW generator or the tie breaker to the other half of the double-ended switchgear. 9 To ensure a quick resumption of power, transfer switches are also used in a 10 number of healthcare and mission- critical applications to automatically MIS connect to an alternate source should 11 Eaton 9395 UPS main power fail. While UPSs are traditionally used to back up sensitive DC-DS-A servers and data processing equip- 12 ment, there are many other places they BAT-A are utilized. In healthcare, they ensure a continuous source of reliable power Figure 1.2-18. Power Distribution Unit LOAD 13 is available for electronic imaging Figure 1.2-17. UPS-1 Connection Option 2 equipment. See Tab 25 for details. Larger kVA UPSs are used in industrial 14 applications such as microprocessor chip manufacturing operations. They are also used to power ultraviolet 15 purification equipment at fresh water pumping stations. See Tab 33 for details. 16 17

CA08104001E For more information, visit: www.eaton.com/consultants 1.2-16 Power Distribution Systems Designing a Distribution System August 2017 Sheet 01 022

Additional Drawings, The 310.15(B) (3) from the National The equipment ground sizes are per i Electrical Code defines the Allowable NEC Table 250.122 based on the trip Schedules and Ampacities of Insulated Conductors rating of the overcurrent device pro- Specifications rated 0-90 degrees C. While details of tecting the phase and neutral conduc- ii this table are included in the reference tors. Note that they do not take voltage While a Power System One-Line is the section of this chapter, it should drop into consideration. basis for defining the interrelation- be noted that Listed Distribution 1 ships between the various types of Equipment is provided with Table 1.2-1. Ampacity of CU Conductors distribution equipment, there is often terminations rated at 75 °C. Conductor Ampacity (Copper) more information that needs to be Conductor Amperes Conductor Amperes 2 conveyed. From a pragmatic standpoint, this Sjze at 75 ºC Size at 75 ºC means that the equipment could be Because the end loads and the fed from conductors rated at either 14 15 3/0 200 3 conductors feeding them are the basis 60 °C or 75 °C. Derating would be 12 20 4/0 230 for proper selection and application required for the conductor ampacity 10 30 250 255 of the circuit breakers, a valuable step at 60 °C making it less practical. It also 8 50 300 285 in the selection process is developing means that the equipment could be 4 6 65 350 310 a schedule. fed from 90 °C conductors, but only if applied at the 75 °C ratings due to the 4 85 400 335 5 The overcurrent protection of many limitations of the equipment ratings. 3 100 500 380 loads, such as motors and distribution 2 115 600 420 transformers, must conform to the The following tables are adjusted in 1 130 700 460 requirements of Articles 240, 430 and accordance with NEC 240.4(D) to show 6 450 of the National Electrical Code. the actual allowable ampacities of 1/0 150 750 475 Particular consideration needs to copper and aluminum conductors 2/0 175 1000 545 7 be given to the length and type of terminating in electrical distribution conductors that will need to connect assemblies. Table 1.2-2. Ampacity of AL Conductors the distribution equipment. Conductor Ampacity (Aluminum) A schedule based on the allowable 8 Conductor Amperes Conductor Amperes As cable length increases, so does its ampacity of copper conductors in Size at 75 ºC Size at 75 ºC resistance in the circuit leading to a Table 1.2-1 is shown in Figure 1.2-19. It drop in the voltage at the end of the includes the relevant requirements for 14 — 3/0 155 9 conductor run feeding the loads. Cable secondary unit substation “SUS-F1A” 12 15 4/0 180 lengths exceeding 100 feet generally shown on the One-Line. This schedule 10 25 250 205 outlines the breaker frame sizes, trip need to be upsized to offset for voltage 8 40 300 230 10 drop concerns. settings and particulars of the trip units required. 6 50 350 250 Cable length, size and the raceway they 4 65 400 270 11 are installed in, also have an impact on It also annotates the names for the 375500310 breakers as well as their circuit the impedance of the conductor in the 2 90 600 340 circuit. Greater impedance helps to nameplate designations. The cable 12 reduce the available short circuit at the sizes and quantities are determined 1 100 700 375 terminals of the distribution equipment by utilizing the tables in the NEC, 1/0 120 750 385 or end load. (as condensed into Ta b l e 1. 2 - 1 ). 2/0 135 1000 445 13 SECONDARY UNIT SUBSTATION "SUS-F1A" 14 4000A, 480/277VAC, 3-PH, 4W, 85kA Rated Switchgear and Circuit Breakers BUS Structure Breaker Trip Poles, N bar Conduit Conduit Cable Entry Position Location Cell # Name Frame Size Trip Size Function connection Circuit Nameplate Feeder Size Quantity Size into Unit Substation 15 1C MB-F1A 4000 4000 LSG + ZSI MAIN BREAKER "MB-F1A" Close Coupled 2A DF1A 800 600 LSIG + ZSI 3N SPARE Future OVERHEAD 2B DF2A 800 600 LSIG + ZSI 3N DSB-DF2A (2) sets (4)#350MCM +(1)#1G 2 3" UNDERGROUND 2C DF-3A 1600 1600 LSIG + ZSI 3 MCC-DF3A (4) sets (3)#600MCM + (1)#4/0G 4 4" UNDERGROUND 16 2D DF-4A 1600 1600 LSIG + ZSI 3N DSB-DF4A (4) sets (3)#600MCM + (1)#4/0G 4 4" UNDERGROUND 3A DF-5A 800 600 LSIG + ZSI 3N SPARE Future OVERHEAD 3B DF6A 800 800 LSIG + ZSI 3N PP-DF6A (2) sets (4)#600MCM + (1)#1/0G 2 3.5" UNDERGROUND 3C DF7A 800 400 LSIG + ZSI 3N IFS-DF7A (1) set (4)#600MCM + (1)#3G 1 3.5" UNDERGROUND 3D DF8A 800 600 LSIG + ZSI 3 XFMR-DF8A (2) sets (4)#350MCM +(1)#1G 2 3" UNDERGROUND

17 SUS - F1A 4A DF9A 800 600 LSIG + ZSI 3N SPARE Future OVERHEAD 4B DF10A 800 400 LSIG + ZSI 3N SPARE Future OVERHEAD 4C DF11A 800 500 LSIG + ZSI 3N SPARE Future OVERHEAD 4D DF12A 800 500 LSIG + ZSI 3 UPS1-INPUT-DF12A (2) sets (3)#250MCM +(1)#2G 2 2" UNDERGROUND 18 5C LTA 4000 4000 LSG + ZSI 3N TIE CB "LTA" 4000A Busway OVERHEAD

Note 1: Looking at the front of the Unit Substation; Right of the Main Breaker is BUS 1. The TIE Breaker is on the far Right of the Lineup and connects to Switchgear "SUS-F1B" Through 4000A Busway 19 Figure 1.2-19. Unit Substation Cable Entry Position 20

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.2-17 August 2017 Designing a Distribution System Sheet 01 023

In order to provide an effective ground On other occasions, the room does not There is an expectation that further fault path as required by 250.4(A)(5) have enough height to accommodate advances will enable the potential to i and 250.4(B)(4) of the 2014 NEC, standard equipment. In these cases, integrate maintenance, spare parts upsizing of the equipment ground special reduced height switchboards and actual performance data into conductors are required by Article or switchgear may be provided. these BIM models. Eaton offers a suite ii 250.122(B) “when the ungrounded of BIM component models ranging conductors are increased in size from While this equipment may not be from automatic transfer switches to the minimum size that has a sufficient documented as standard, Eaton can panelboards and switchboards that 1 ampacity for the intended installation”. provide assistance in developing are available from the Eaton website. a reduced height alternative solution. Larger manufactured to order switch- In these cases, “wire-type equipment gear BIM models are available from 2 grounding conductors, where installed, As design and drafting tools have evolved, the push to include 3D your local Eaton application engineer shall be increased in size proportionally or sales office. according to the circular mil area of the drawings has subsequently evolved 3 ungrounded conductors”. into an enhanced technology called Building Information Modeling (BIM). When developing schedules, it is BIM drawings include the 3D aspect but important to remember that conductor also include the capability to assign 4 sizing is also impacted by the derating equipment performance parameters tables for ambient temperature and interdependencies. This permits and conductor fill when installed architects and construction firms to 5 in raceways. be alerted to potential “collisions” between incoming/outgoing conduits There are a number of ways to create and other potential obstructions such 6 cable schedules, the most common of as existing conduits/busduct, HVAC which is to name the conductor as is duct or plumbing in the space above shown on the medium-voltage portion or below the equipment. 7 of the One-Line on Page 1.2-4. Schedules are most often used to 8 define requirements for low-voltage TOP VIEW switchboards and panelboards. They 36.00 30.00 may also be utilized to enumerate the 9 various automatic transfer switches AIRWAY and the cables connecting them to the 30.00 OUTGOING CONDUIT AREA normal and emergency sources as 10 well as the end load. Figure 1.2-21. BIM 3D Model Top View Other drawings that are necessary FRONT VIEW 11 to produce the installation package PANEL PA3 are floor plans that include room dimensions, equipment locations PRIMARY MCB allocated within the space, appropriate 12 clearances per code requirements and means of egress from the area where 13 the equipment is located. 90.00 These drawings have been done 14 primarily in 2D CAD programs with 225 KVA boxes showing equipment dimensions on the floorplan. A front view of the 15 equipment is also used to detail the CONTACTOR elevation requirements. Equipment & RELAY COMPARTMENT occasionally requires top-hats or pullboxes that add height above the 16 switchboard or switchgear. 17 Figure 1.2-20. Equipment Floorplan and Elevation 18

CA08104001E For more information, visit: www.eaton.com/consultants 1.2-18 Power Distribution Systems Designing a Distribution System August 2017 Sheet 01 024

Power System Voltages The 2014 National Electrical Code has Excessively high megawatt loads such i ushered in a change to the definition as those required by large wastewater The System One-Line on Page 1.2-4, of low voltage. The NEC elevated the treatment plants or complex process shows an Incoming utility primary maximum voltage threshold for this facilities like petrochemical refining ii service feeding different types of category from 600 V maximum to will typically exceed the utility’s infra- distribution equipment at each of the 1000 V maximum. This was done to structure to serve the end customer various utilization voltages necessary accommodate the growing solar at low-voltage. In these instances, a 1 to power the actual loads. market where voltages up to 1000 V medium voltage service at 34.5, 33 kV, are becoming more commonplace. 26.4 kV, 13.8 kV, 13.2 kV, 12.47 kV or The One-Line illustrates a number of 4.16 kV will be mandated. Extremely 2 voltage transformations and is a good In general, the voltage classes above large loads may even involve a utility example of the types of choices and medium voltage are utilized for trans- interconnect at the 69 kV or high challenges a power systems design mission of bulk power from generating voltage level. 3 engineer faces today. stations to the utilities substations that transform it to the distribution voltage The System One-Line on Page 1.2-4 is used on their system. an example of a power system for a 4 Voltage Classifications hypothetical college campus with a A power system design engineer design load over 8 megawatts at a ANSI and IEEE® standards define should attempt to familiarize them- 0.8 power factor. This would require a various voltage classifications for selves with the application of all Utility service of over 400 A at 13.8 kV. 5 single-phase and three-phase systems. equipment available in the various The terminology used divides voltage voltage classes. This is particularly The most common service voltage classes into: true if they are involved in designing arrangements are in the low-voltage 6 industrial facilities or campus arrange- range (<600 Vac). Normal residential ■ Low voltage ments that may be served by a utility services are at 240/120 three-wire, ■ Medium voltage at medium or high voltage. (two phases each at 240 and a Neutral 7 ■ High voltage Conductor). Connection from each ■ Extra-high voltage Incoming Service Voltage 240 V phase to neutral provides 120 V 8 ■ Ultra-high voltage for the lighting and plug loads. When designing a new power A three-phase, four-wire low-voltage Table 1.2-1 presents the nominal system distribution system, the engineer voltages for these classifications. service is generally provided for 9 needs to be knowledgeable of the commercial customers. It includes Table 1.2-1. Standard Nominal System local utility requirements including a neutral and may be provided at Voltages and Voltage Ranges the service voltage that is available to 208/120 Vac wye, 240/120 Vac wye or 10 (From IEEE Standard 141-1993) be provided for their client. Meeting 480 /277 Vac wye. Voltage Nominal System Voltage with the utility’s customer service Class representative responsible for the Typical applications for the commercial 11 Three-Wire Four-Wire installation site, early in the design category of three-phase low-voltage Low 240/120 208Y/120 process, can help set expectations services are small commercial voltage 240 240/120 for both parties and avoid subsequent buildings, department stores, office 12 480 480Y/277 delays. buildings, kindergarten through 600 — 12th grade schools and light Medium 2400 4160Y/2400 Most utilities will require a load letter manufacturing facilities. 13 voltage 4160 8320Y/4800 when requesting a new service or 4800 12000Y/6930 upgrade to an existing utility service. There are a number of other older 6900 12470Y/7200 The letter must include calculated service configurations utilized in rural 13,200 13200Y/7620 values for the types of continuous locations such as Delta Hi Leg. These 14 13,800 13800Y/7970 23,000 20780Y/12000 and non-continuous loads that will were used as an inexpensive way to 34,500 22860Y/13200 be served. supply 240 V three-phase and 240 V or 15 46,000 24940Y/14400 120 V single-phase from a single-pole 69,000 34500Y/19920 Article 220 of the NEC covers branch- mount transformer. High 115, 0 0 0 — circuit, feeder and service calculations. voltage 138,000 — It also includes references to other As a general rule, the serving utility 16 161,000 — articles that pertain to specific types will offer a basic service option that is 230,000 — of installations requiring special outlined in the tariff documents that Extra-high 345,000 — calculation considerations. have been approved by the governing 17 voltage 500,000 — authority or agency that regulates the 765,000 — The determination of the utility utility. This basic service option is one Ultra-high 1,100,000 — service voltage is driven by a that minimizes the utility costs and 18 voltage combination of factors including best accommodates their system the engineers initial load letter, requirements. prevailing utility standards and the 19 type of facility being served.

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.2-19 August 2017 Designing a Distribution System Sheet 01 025

The utility may alternately offer to upcharge the client for extending or APPLICATION ZONES OF ARTICLE 230 - SERVICES PARTS I - VII & ASSOCIATED APPLICABLE NEC ARTICLES i reinforcing cable connections to a UTILITY OWNED POLE MOUNT UTILITY OWNED PADMOUNT TRANSFORMER location on their overhead or under- TRANSFORMER OR UNDERGROUND DISTRIBUTION ground grid where they can supply the Part II - Overhead Service Conductors Part III - Underground Service Conductors ii service the user is requesting. In major 230.24 - Clearances 230.32 - Depth of Burial & Protection cities where the serving utility utilizes Service Head Terminal Box, Meter or Other Enclosure Part IV - Service Entrance Conductors underground spot networks, the 1 Part V - Service Equipment General Utility option to select a voltage other than Meter Article 250 - Grounding & Bonding that available is either limited or Part VI - Service Equipment Disconnecting Means 1000 A & Above Main CB at extremely expensive. Part VII - Service Equipment Overcurrent Protection 2 480/277 Vac to be Provided with Utility metering requirements vary 230-95 - Ground Fault Protection of Equipment Equipment Ground Fault Protection from one serving entity to another Article 408 - Switchboards, Switchgear & Panelboards 3 and are more complex for medium- Article 240 - Overcurrent Protection voltage switchgear used as service Articles 215 & 225 - Feeders equipment. Articles 210 & 225 - Branch Circuits 75 kVa 480–208/120 V 4 HVAC Commercial low-voltage utility Distribution Distribution Lighting metering (<600 V) is more common Panel Panel Panelboard and includes standardized designs 5 that can be provided in various low- voltage switchboard and drawout Figure 1.2-22. Application Zones of 2014 NEC Articles Related to Incoming Utility Services 6 switchgear configurations. (Metering These include application of the Space allocation should be considered compartments for switchboards grounding electrode conductor in when laying out equipment in a service that meet individual utility design Section 250.50 to its sizing in accor- room. Both low- and medium-voltage 7 requirements are shown in Tab 21). dance with Table 250.66. Requirements utility metering typically adds an for bonding of service equipment additional equipment structure, or Incoming Service begins in Section 250.90. Sizing of structures, to an incoming service 8 the main bonding jumper and system lineup. These are used to accommo- Considerations bonding jumper are also covered in date the current transformers and Table 250.102(C)(1). potential taps or voltage transformers Article 230 of the National Electrical 9 necessary for the external utility Code: “covers service conductors Note: A more in-depth discussion of revenue meter to calculate usage. and equipment for the protection grounding and equipment ground fault 10 of services and their installation protection can be found in Section 1.5 of Article 110 of the NEC covers a broad requirements”. Figure 1.2-22 provides this Tab 1 document. range of requirements for electrical the scope of pertinent references that installations. It includes provisions The NEC Article 230 does not specifi- 11 apply to incoming service equipment. that govern the construction and cally require that electrical service These range from conductor types spatial requirements for egress, rooms be fire rated rooms or that from overhead service utility drops to clearances and working space in sprinklers be provided. However, 12 underground utility feeds and their rooms containing electrical distribu- survivability requirements for fire proper installation. tion and service equipment. pump disconnects in local building Parts V, VI and VII of Article 230 spell code requirements, in addition to Table 1.2-2 includes combined tables 13 out the common requirements for NEC Article 450 or additional utility from NEC Article 110, showing the low-voltage service equipment specifications may require fire rated minimum “depth of the working <1000 Vac. These parts cover locations rooms, particularly if medium-voltage space in the direction of live parts” 14 permitted, various marking require- service is being supplied. required in front and behind medium- ments including Section 230.66 that voltage equipment and low-voltage requires service equipment be listed equipment. 15 and marked as Suitable for Use as Service Equipment, (SUSE). Also Table 1.2-2. NEC Minimum Depth of Clear Working Space at Equipment included is Section 230.71, which limits Minimum Depth of Clear Working Space at Electrical Equipment 16 the number of incoming main service Combined NEC Tables 110.26 (A) & 110.34 (A) disconnects to a maximum of six. Nominal (Phase) Ty p i c a l Condition 1 Condition 2 Condition 3 to Ground Voltage System Live Parts to Live Parts to Live Parts to 17 Section 230.95 of this Article requires Voltage Ungrounded Grounded Live Parts equipment ground fault protection Surfaces Surfaces for service disconnect(s) 1000 A Feet Feet Feet 18 and above when applied on solidly grounded wye services, where the 0–150 V 208/120 V 3 ft 3 ft 3 ft 151–600 V 480/277 V 3 ft 3 ft 6 in 4 ft phase to ground voltage exceeds 150 V. 601–2500 V 4160 V 3 ft 4 ft 5 ft 19 Article 250 of the NEC contains the 2501–9000 V 13,800 V 4 ft 5 ft 6 ft requirements for grounding and 9001–25,000 V 34,500 V 5 ft 6 ft 9 ft 20 bonding of electrical systems. Specific NEC Definition of Live Parts: “Energized conductive Components.” details pertaining to grounding for NEC Definition of Energized: “Electrically Connected to, or is a source of voltage.” the incoming service equipment begin MV Transformers with Snubber Capacitors or MV EPR Cables holding a capacitive charge are considered “Live” until the voltage is bled off by grounding procedures. 21 at Section 250.24.

CA08104001E For more information, visit: www.eaton.com/consultants 1.2-20 Power Distribution Systems Designing a Distribution System August 2017 Sheet 01 026

Additional work space may need Utilization Voltage Selection In higher motor hp applications, a i to be allocated for OSHA required motor’s 4.16 kV utilization voltage grounding practices, prior to servicing Very large inductive loads such as may be the same as the 4.16 kV service deenergized medium-voltage equip- higher horsepower motors used on voltage. In these cases, the service ii ment. As an example, 6-foot-long HVAC chillers, sewage treatment equipment would need to feed insulated hot sticks are typically used pumps and in process or other power through cables or busway to to keep personnel at a safe distance, Industries can draw tremendous a medium-voltage starter or variable 1 while applying portable ground cables. amounts of power. Motors also frequency drive. (See Ta b 10 for This procedure is utilized to discharge inherently have high inrush currents more information.) any residual capacitive voltage present during full voltage starting, which can However, in installations where there 2 on cables terminating in a medium- cause a significant voltage dip on the are many long cable runs that are voltage transformer primary cable power system feeding it. As a result, feeding other large loads, the medium- compartment or in the rear cable many utilities have limitations on the voltage distribution may have a higher 3 compartment of medium-voltage maximum horsepower motor that service voltage such as 13.8 kV. In this switchgear. can be line started directly from case, the service voltage would need their system. 4 to be stepped-down to the 4.16 kV To limit the impact of this phenomena, utilization voltage through a primary a variety of techniques can be used unit substation transformer as 5 to reduce the motor's starting inrush illustrated by the System One-Line current. These generally involve the on Page 1.2-4. See Ta b 1 3 for use of electromechanical or solid- further details. state reduced voltage starters. Variable 6 Conversely, small end loads, short frequency drives in both low and runs and a high percentage of lighting medium voltage are also available and/or receptacle loads would favor as shown on the System One-Line 7 lower utilization voltages such as on Page 1.2-4. See Components 208 Y/120 V. If the incoming service of a Power System section for was at 13.8 kV, as noted in the previous further details. 8 example, secondary unit substations, As renewable energy or cogeneration Voltage Recommendations pad-mounted transformers or unitized 9 are added, power systems are power centers could be used to step- becoming more complex and so too is by Motor Horsepower down to the 208 Y/120 V utilization their service interface for utility power. Some factors affecting the selection voltage required. See Tabs 14 and 15 10 Many Public Service Commissions of motor operating voltage include: for details. have adopted Standard Interface Requirements (SIR) for Distributed ■ Motor, motor starter and cable This approach is often used to reduce Energy Resources (DER) based on first cost or offset voltage drop issues on multi 11 building sites such as college or IEEE 1547. These are intended to ■ Motor, motor starter and cable hospital campuses. It is also used protect the utility system from user- installation cost in large single building sites like 12 owned generation back-feeding into ■ Motor and cable losses a fault or dead cable on the utility grid. distribution warehouses and high ■ Motor availability rise “skyscraper” buildings. Utilities may have their own specifica- ■ Voltage drop 13 Note: Section 1.3 of this document tions and tariffs for the interconnection ■ Qualifications of the building illustrates a number of power system of this Dispersed or Distributed operating staff; and many more designs that improve reliability and Generation (DG). These include uptime during maintenance or service 14 capacity limitations and/or the addition The following table is based in part outages. Among these schemes are a of charges for the “spinning reserves” on the above factors and experience. variety of configurations showing medium- they must keep on hand, should the Because all the factors affecting the voltage sources feeding substation or 15 user’s DG assets fail or load increase. selection are rarely known, it is only pad-mounted transformers that step it an approximate guideline. down to the appropriate low voltage for Consequently, the design engineer end load utilization. 16 must be aware that special relaying Table 1.2-3. Selection of Motor Horsepower protection may need to be included Ratings as a Function of System Voltage A problem can arise, however, when a in the design. Also, additional analysis Motor Voltage Motor System low-voltage service is the only utility 17 of the utility tariffs and rate structures (Volts) hp Range Voltage service option and cable distances may be necessary to validate the between the incoming service and the 460 up to 500 480 utilization loads are great. In these projected payback of participation in 2300 250 to 2000 2400 18 peak demand reduction programs 4000 250 to 3000 4160 instances, a practical way to offset for the voltage drop to the end utilization using owner-supplied generation. 4600 250 to 3000 4800 13,200 above 2000 13,800 loads is the use of low-voltage 19 busway in lieu of cable. See Ta b 2 4 for details. 20

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.2-21 August 2017 Designing a Distribution System Sheet 01 027

Another technique to address voltage Low-Voltage Utilization The National Electrical Code permits drop concerns for long cable runs is voltage up to 300 V to ground on i to use a step-up and step-down With most low-voltage services, the circuits supplying permanently installed transformer arrangement. service voltage is the same as the electric discharge lamp fixtures, provided utilization voltage. However, when the luminaires do not have an integral ii To accomplish this, a step-up trans- the engineer is faced with a decision manual switch and are mounted at former is added after the low-voltage between 208Y/120 V and 480Y/277 V least 8 ft (2.4 m) above the floor. service. The transformer primary is secondary distribution for commercial This permits a three-phase, four-wire, 1 configured in a delta and is fed by the and institutional buildings, the choice solidly grounded 480Y/277 V system grounded and bonded low-voltage depends on several factors. The most to supply directly all of the fluorescent incoming utility service. The step-up important of these are the size and and high-intensity discharge (HID) 2 transformer wye secondary is often at types of loads (motors, fluorescent lighting in a building at 277 V, as well medium voltage, typically at 4.16 kV, lighting, incandescent lighting, as motors at 480 V. with the transformers wye secondary receptacles) and length of feeders. 3 grounded. In general, power system designs with Technical Factors HVAC equipment with a significant A 4.16 kV delta primary step-down The principal advantage of the use of quantity of motors, predominantly higher secondary voltages in buildings 4 transformer is then located near the fluorescent lighting loads, and long served load and has its wye secondary is that for a given load, less current feeders, will tend to make 480Y/277 V means smaller conductors and lower grounded in accordance with NEC more economical. Article 250.30 to create a separately voltage drop. Also, a given conductor 5 derived system. This step-down Industrial installations with large size can supply a large load at the transformer’s secondary voltage may motor loads are almost always 480 V same voltage drop in volts, but a lower be the same as the incoming service, or resistance grounded, wye systems percentage voltage drop because of 6 it may be at higher utilization voltage. (see further discussion on grounding the higher supply voltage. Fewer or in Section 1.6). smaller circuits can be used to transmit Caution must be taken when selecting the power from the service entrance 7 the step-up transformers to be used Practical Factors point to the final distribution points. in this type of application. Step-up Because most low-voltage distribution Smaller conductors can be used in transformers, particularly designs equipment available is rated for up to many branch circuits supplying 8 that are not optimized for step-up 600 V, and conductors are insulated for power loads, and a reduction in the purposes, such as a reverse-fed 600 V, the installation of 480 V systems number of lighting branch circuits is standard transformer, exhibit extremely uses the same techniques and is usually possible. 9 high inrush during energization. essentially no more difficult, costly It is easier to keep voltage drops within Unless the step-up transformers are or hazardous than for 208 V systems. acceptable limits on 480 V circuits than 10 specifically wound for low inrush, the The major difference is that an arc on 208 V circuits. When 120 V loads are magnetizing current during initial of 120 V to ground tends to be self- supplied from a 480 V system through energization, may exceed the 6X make extinguishing, while an arc of 277 V step-down transformers, voltage drop 11 capabilities of a low-voltage fused to ground tends to be self-sustaining in the 480 V supply conductors can bolted pressure switch. This can result and likely to cause severe damage. be compensated for by the tap adjust- in a condition where a portion of the For this reason, Article 230.95 of the ments on the transformer, resulting 12 switch contact surface can weld before National Electrical Code requires in full 120 V output. Because these full engagement. The current passing ground fault protection of equipment transformers are usually located close through the smaller contact area will on grounded wye services of more to the 120 V loads, secondary voltage 13 then eventually cause the switch to than 150 V to ground, but not exceeding drop should not be a problem. If it is, overheat and fail. 600 V phase-to-phase (for practical taps may be used to compensate by raising the voltage at the transformer. 14 Many step-up transformer applications purpose, 480Y/277 V services), for any involve a 208 Vac incoming service service disconnecting means rated The interrupting ratings of circuit stepping this voltage up to the 1000 A or more. breakers and fuses at 480 V have 15 utilization voltage of 480 Vac for HVAC Article 215.10 of the NEC extends this increased considerably in recent motor loads in a building. The design equipment ground fault requirement years, and protective devices are now engineer must be aware of some to feeder conductors and clarifies available for any required fault duty 16 potential pitfalls and plan ahead when the need for equipment ground fault at 480 V. In addition, many of these involved in this type of application. protection for 1000 A and above, protective devices are current limiting, and can be used to protect down- Larger step-up transformers offer feeder circuit protective devices on 17 the 480/277 Vac secondary of trans- stream equipment against these fewer transformer voltage taps, if high fault currents. any at all. They also exhibit poor formers. Article 210.13 has been voltage regulation when experiencing added to the 2014 NEC, essentially 18 transient shock loads, such as motors recognizing the same need for starting. When designing power equipment ground fault protection systems utilizing step-up transformers on 1000 A branch circuits being fed 19 to feed motor loads, a Motor Starting from the 480/277 Vac secondary Analysis should be performed to of transformers. ensure that the motors will start and 20 operate as intended. 21

CA08104001E For more information, visit: www.eaton.com/consultants 1.2-22 Power Distribution Systems Designing a Distribution System August 2017 Sheet 01 028

Economic Factors i Utilization equipment suitable for principal loads in most buildings is available for either 480 V or 208 V Elevator ii systems. Three-phase motors and Panel their controls can be obtained for Typical either voltage, and for a given 1 horsepower are less costly at 480 V. LED lighting as well as earlier Typical Emergency technologies including fluorescent, HVAC Lighting Panel 2 Panel (Typical Every HID and high pressure sodium can Third Floor) all be applied in either 480 V or 208 V systems. However, in almost all cases, 3 480Y/277 V 208Y/120 V Typical the installed equipment will have a Panel Panel lower total cost at the higher voltage. Dry Type Transformer 480Δ-208Y/120 V 4 (Typical Every Floor) HVAC Busway Emergency Elevator Feeder Riser Lighting Riser 5 Riser

Building and Typical Typical Miscellaneous 6 Loads Typical

7 Typical Typical Spare 8 1111 1 11

Automatic 4000 A 1 Transfer Switch 9 Main CB Gen. CB Utility Emergency CTs Metering or Standby 10 PTs Generator Utility 4000A at 480Y/277V Service 100,000A Available Fault Current 11 Figure 1.2-23. Typical Power Distribution and Riser Diagram for a Commercial Office Building 1 Include ground fault trip. 12

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.3-1 August 2017 Types of Systems Sheet 01 029

Types of Systems This makes it possible for the utility Additionally, a fault on the Service to minimize the installed transformer Switchgear or Switchboards low- i In many cases, power is supplied by capacity. However, if capacity require- voltage bus will cause the main the utility to a building at the utilization ments grow, the voltage regulation overcurrent protective device to voltage. In these cases, the distribution and efficiency of this system may be operate, interrupting service to all ii of power within the building is achieved poor because of the low-voltage loads. Service cannot be restored through the use of a simple radial feeders and single source. Typically, until the necessary repairs have been distribution system. the cost of the low-voltage feeder made. A fault on a low-voltage feeder 1 circuits and their associated circuit circuit will interrupt service to all the Simple Radial System breakers are high when the feeders loads supplied by that feeder. are long and the peak demand is 2 In a conventional low-voltage radial above 1000 kVA. An engineer needs to plan ahead for system, the utility owns the pole- these contingencies by incorporating mounted or pad-mounted transformers Where a utility’s distribution system is backup power plans during the initial 3 that step their distribution voltage down fed by overhead cables, the likelihood design of the power system. Resiliency from medium voltage to the utilization of an outage due to a storm, such as from storms, floods and other natural voltage, typically 480/277 Vac or 208/ a hurricane or blizzard, increases disasters can be accomplished with 4 120 Vac. In these cases, the service dramatically. Wind or ice formation the addition of permanently installed equipment is generally a low-voltage can cause tree branches to fall on standby generation, or by including main distribution switchgear or switch- these suspended cables, causing an a provision in the incoming Service 5 board. Specific requirements for service unplanned power outage. The failure equipment for the connection of a entrance equipment may be found in of pole-mounted utility transformers portable roll-up temporary generator. NEC Article 230, Services. can result in an outage lasting a day Note: See Generator and Generator 6 or more. Systems in Section 1.7 for further Low-voltage feeder circuits are run details. from the switchboard or switchgear assemblies to panelboards that are 7 located closer to their respective loads as shown in Figure 1.3-1. Each feeder is Utility Medium-Voltage 8 connected to the switchgear or switch- Distribution board bus through a circuit breaker or other overcurrent protective device. A relatively small number of circuits are Utility Owned 9 Utility Pole or Padmount used to distribute power to the loads. Meter Transformer Because the entire load is served from 10 a single source, full advantage can be 480/277 Vac (VT’s or Tap by Utility) Service Entrance taken of the diversity among the loads. (CT’s by Utility) Equipment 11

13 75 kVA 480–208/120 V HVAC 14 Distribution Distribution Lighting Panel Panel Panelboard 15

Figure 1.3-1. Low-Voltage Radial System 16

CA08104001E For more information, visit: www.eaton.com/consultants 1.3-2 Power Distribution Systems Types of Systems August 2017 Sheet 01 030

Figure 1.3-2 shows a typical incoming It is important to consider the ground- If the three-phase generator neutral i service switchboard with the addition ing of the generator neutral when using is brought back through the transfer of a key interlocked generator breaker. automatic transfer switches in power switches and grounded at the service In this design, the breaker pair shares system design. If the generator neutral entrance, a three-pole transfer switch ii a single key that can only be used to is grounded at the generator, a sepa- with solid neutral should be provided. close one breaker at a time. This rately derived system is created. This arrangement ensures against parallel- requires the use of four-pole transfer Note: See Automatic Transfer Switches in Ta b 2 5 for details. 1 ing with the utility but requires manual switches for a three-phase system. intervention in the event of an outage. 2 In a typical standby generation arrangement, automatic transfer Utility switches are used to feed either Nor- Medium-Voltage Distribution 3 mal utility power or an alternate generator source of backup power to the critical loads. The transfer switches Utility Owned Utility Pole or Padmount G 4 sense the loss of power from the Nor- Meter Transformer mal source and send a run command to the generator to start. 480/277 Vac (VT’s or Tap by Utility) 5 Service Entrance Once the generator is running, the Equipment (CT’s by Utility) transfer switches sense that voltage is available and automatically open K1 K1 6 the Normal contactor and close the Generator contactor. When the Normal source returns, the transfer switch 7 opens the Generator contactor and closes the Normal source contactor. 8 The location and type of the transfer 75 kVA 480–208/120 V switches depends on the Utility and HVAC the overall design intent. Transfer 9 switches can be Service Entrance Distribution Distribution Lighting Panel Panel Panelboard Rated and used as the main Service Disconnect feeding all the loads 10 downstream. See Figure 1.3-3. Figure 1.3-2. Typical Incoming Service Switchboard Transfer switches can be also be incor- Note: See Roll-Up Generator Switchboard Connections in Ta b 2 1. 11 porated into the service switchboard as an integral part of the assembly. Alternately, they can be located down- Typical Transfer Switch Installation 12 stream of the incoming service and Typical Transfer Switch Installation Rated for Service Entrance applied only to the individual loads Utility Service Utility Service 13 they are feeding. This approach of isolating only those critical loads that must function during a power 14 outage can reduce the generator kVA Service Service necessary. This can reduce space and Disconnect Disconnect cost requirements. G G Generator ATS 15 Generator ATS Breaker Breaker

16 Load Load

17 Figure 1.3-3. Main Service Disconnect Feeding Downstream

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.3-3 August 2017 Types of Systems Sheet 01 031

In cases where the utility service Each secondary unit substation is an are reduced, voltage regulation is voltage is at some voltage higher assembled unit consisting of a three- improved, feeder circuit costs are i than the utilization voltage within the phase, liquid-filled or air-cooled reduced substantially, and large low- building, the system design engineer transformer, an integrally connected voltage feeder circuit breakers are has a choice of a number of types primary fused switch, and low-voltage eliminated. In many cases the inter- ii of systems that may be used. This switchgear or switchboard with circuit rupting duty imposed on the load discussion covers several major types breakers or fused switches. Circuits circuit breakers is reduced. of distribution systems and practical are run to the loads from these low- 1 modifications of them. voltage protective devices. This modern form of the simple radial system will usually be lower in initial 1. Simple medium-voltage radial Because each transformer is located investment than most other types of 2 within a specific load area, it must primary distribution systems for build- 2. Loop-primary system— have sufficient capacity to carry the ings in which the peak load is above radial secondary system peak load of that area. Consequently, 1000 kVA. A fault on a primary feeder 3 3. Primary selective system— if any diversity exists among the load circuit or in one transformer will cause secondary radial system area, this modified primary radial an outage to only those secondary system requires more transformer loads served by that feeder or trans- 4 4. Two-source primary— capacity than the basic form of the former. In the case of a primary main secondary selective system simple radial system. However, bus fault or a utility service outage, because power is distributed to the service is interrupted to all loads until 5. Sparing transformer system 5 load areas at a primary voltage, losses the trouble is eliminated. 6. Simple spot network 6 7. Medium-voltage distribution system design Primary Fused Switch In those cases where the customer 7 Transformer receives his supply from the primary system and owns the primary switch and transformer along with the 600V Class 8 Switchboard secondary low-voltage switchboard or switchgear, the equipment may take the form of a separate primary switch, 9 separate transformer, and separate Distribution Dry-Type low-voltage switchgear or switch- Transformer board. This equipment may be 10 combined in the form of an outdoor Distribution MCC Distribution Lighting pad-mounted transformer with Panel Panel Panelboard internal primary fused switch and 11 secondary main breaker feeding an indoor switchboard. Figure 1.3-4. Simple Radial System 12 Another alternative would be a secondary unit substation where the primary fused switch, transformer and 13 secondary switchgear or switchboard 52 Primary Main Breaker are designed and installed as a close- coupled single assembly. 14 A modern and improved form of the 52 52 52 52 52 52 Primary Feeder Breakers conventional simple medium-voltage 15 radial system distributes power at a primary voltage. The voltage is stepped down to utilization level in the several 16 load areas within the building typically through secondary unit substation transformers. The transformers are 17 usually connected to their associated load bus through a circuit breaker, as Secondary Unit shown in Figure 1.3-5. Primary Substation 18 Cables 19 Figure 1.3-5. Primary and Secondary Simple Radial System 20

CA08104001E For more information, visit: www.eaton.com/consultants 1.3-4 Power Distribution Systems Types of Systems August 2017 Sheet 01 032

Reducing the number of transformers 2. Loop Primary System— utilizing three on-off switches or a i per primary feeder by adding more four-position sectionalizing switch and primary feeder circuits will improve Radial Secondary System vacuum fault interrupter (VFI) internal the flexibility and service continuity This system consists of one or more to the transformer saving cost and ii of this system; the ultimate being one “PRIMARY LOOPS” with two or more reducing footprint. secondary unit substation per primary transformers connected on the loop. feeder circuit. This of course increases This system is typically most effective When pad-mounted compartmental- 1 the investment in the system but when two services are available from ized transformers are used, they are minimizes the extent of an outage the utility as shown in Figure 1.3-6. Each furnished with loop-feed oil-immersed resulting from a transformer or primary loop is operated such that one gang-operated load break sectionalizing 2 primary feeder fault. of the loop sectionalizing switches is switches and Bay-O-Net expulsion fuses kept open to prevent parallel operation in series with partial range back-up Primary connections from one secondary of the sources. current-limiting fuses. By operating the 3 unit substation to the next secondary appropriate sectionalizing switches, it is unit substation can be made with When secondary unit substations are possible to disconnect any section of “double” lugs on the unit substation used, each transformer may have its the loop conductors from the rest of 4 primary switch as shown, or with load own duplex (2-load break switches with the system. In addition, it is possible break or non-load break separable load side bus connection) sectionalizing to disconnect any transformer from connectors made in manholes or other switches and primary load break fused the loop. 5 locations. See Eaton’s Cooper Power™ switch as shown in Figure 1.3-7 or series Molded Rubber Medium Voltage Connectors on Eaton's website 6 for more details. Depending on the load kVA connected to each primary circuit and if no ground Primary Main Breaker 1 52 52 Primary Main Breaker 2 7 fault protection is desired for either the primary feeder conductors and trans- 52 8 formers connected to that feeder or Tie the main bus, the primary main and/or 52 52 Breaker 52 52 Loop Feeder Breaker feeder breakers may be changed to 9 primary fused switches. This will sig- Loop A nificantly reduce the first cost, but also Loop B decrease the level of conductor and 10 equipment protection. Thus, should NC NO NC NC a fault or overload condition occur, Fault Sensors downtime increases significantly and 11 higher costs associated with increased damage levels and the need for fuse replacement is typically encountered. 12 In addition, if only one primary fuse on a circuit opens, the secondary loads are then single phased, causing damage to 13 low-voltage motors. Another approach to reducing costs is to eliminate the primary feeder NC NC NO NC NC NC 14 breakers completely, and use a single primary main breaker or fused switch for protection of a single primary 15 feeder circuit with all secondary unit substations supplied from this circuit. Although this system results in less ini- 16 tial equipment cost, system reliability is reduced drastically because a single fault in any part of the primary conductor 17 would cause an outage to all loads Secondary Unit Substations Consisting of: within the facility. Duplex Primary Switches/Fused Primary Switches/ 18 Transformer and Secondary Main Feeder Breakers Figure 1.3-6. Loop Primary—Radial Secondary System 19

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.3-5 August 2017 Types of Systems Sheet 01 033

Loop Loop Primary Metal-Clad i Feeder Feeder Switchgear Lineup Load Break 52 52 Primary Main Breaker Loop Switches ii Bus A 52 Bus B

52 52 52 52 Primary Feeder Breaker 1

Fused Feeder A1 Feeder B1 Feeder B2 Disconnect To Other 2 Switch Feeder A2 Substations NO 3

NC 4 NO Typical Secondary Unit Substation Duplex Primary Switch/Fuses NC Transformer/600V Class 5 Figure 1.3-7. Secondary Unit Substation Secondary Switchgear Loop Switching NO 6

Main Source Alternate Source NC 3-Position 7 Selector Switch Figure 1.3-10. Basic Primary Selective—Radial Secondary System Vacuum Fault 8 Interrupter (VFI) A key interlocking scheme is normally When a primary feeder conductor fault recommended to prevent closing all occurs, the associated loop feeder sectionalizing devices in the loop. Each breaker opens and interrupts service primary loop sectionalizing switch and to all loads up to the normally open 9 the feeder breakers to the loop are primary loop load break switch interlocked such that to be closed they (typically half of the loads). Once it is require a key (which is held captive determined which section of primary 10 until the switch or breaker is opened) cable has been faulted, the loop and one less key than the number of sectionalizing switches on each key interlock cylinders is furnished. side of the faulted conductor can be 11 Figure 1.3-8. VFI / Selector Switch An extra key is provided to defeat the opened, the loop sectionalizing switch Combination interlock under qualified supervision. that had been previously left open can 12 In addition, the two primary main then be closed to all secondary unit breakers, which are normally closed, substations while the faulted conduc- and primary tie breaker, which is tor is replaced. If the fault should occur Loop Feeder Loop Feeder 13 normally open, are either mechanically in a conductor directly on the load side or electrically interlocked to prevent of one of the loop feeder breakers, the paralleling the incoming source lines. loop feeder breaker is kept open after 14 4-Position For slightly added cost, an automatic tripping and the next load side loop Partial Range T-Blade throw-over scheme can be added sectionalizing switch manually opened Current-Limiting Fuse Sectionalizing Load-Break between the two main breakers and so that the faulted conductor can be 15 Bay-O-Net Switch tie breaker. During the more common sectionalized and replaced. Expulsion Fuse event of a utility outage, the automatic Note: Under this condition, all secondary transfer scheme provides significantly unit substations are supplied through the 16 reduced power outage time. other loop feeder circuit breaker, and thus all conductors around the loop must be The system in Figure 1.3-6 has higher sized to carry the entire load connected to 17 costs than in Figure 1.3-5, but offers the loop. Where separable load break or increased reliability and quick restora- non-load break connectors are used, they tion of service when 1) a utility outage too must be sized to handle the entire occurs, 2) a primary feeder conductor load of the loop. Increasing the number 18 Figure 1.3-9. Pad-Mounted Transformer fault occurs, or 3) a transformer fault of primary loops (two loops shown in Loop Switching or overload occurs. Figure 1.3-10) will reduce the extent of the outage from a conductor fault, but will also 19 Should a utility outage occur on one of increase the system investment. the incoming lines, the associated primary main breaker is opened and the 20 tie breaker closed either manually or through an automatic transfer scheme. 21

CA08104001E For more information, visit: www.eaton.com/consultants 1.3-6 Power Distribution Systems Types of Systems August 2017 Sheet 01 034

When a transformer fault or overload transformer includes a fuse assembly This means limited cable space i occurs, the transformer primary fuses with fuses. Mechanical and/or key especially if double lugs are open, and the transformer primary interlocking is furnished such that furnished for each line as shown switch manually opened, disconnecting both switches cannot be closed at in Figure 1.3-10. The downside is that ii the transformer from the loop, and the same time (to prevent parallel should a faulted primary conductor leaving all other secondary unit operation) and interlocking such have to be changed, both lines would substation loads unaffected. that access to either switch or fuse have to be de-energized for safe 1 assembly cannot be obtained unless changing of the faulted conductors. A basic primary loop system that both switches are opened. uses a single primary feeder breaker A second alternative is utilizing a 2 connected directly to two loop feeder three-position selector switch internal switches which in turn then feed the to the transformer, allowing only Primary loop is shown in Figure 1.3-11. In this Feeders one primary feeder to be connected to 3 basic system, the loop may be normally the transformer at a time without the operated with one of the loop section- need for any interlocking. The selector Load Break alizing switches open as described Switches switch is rated for load-breaking. If 4 above or with all loop sectionalizing overcurrent protection is also required, switches closed. If a fault occurs in the a vacuum fault interrupter (VFI), also basic primary loop system, the single internal to the transformer, may be loop feeder breaker trips, and secondary utilized, reducing floor space. 5 Fuses loads are lost until the faulted conductor is found and eliminated from the loop In Figure 1.3-10 when a primary 6 by opening the appropriate loop feeder fault occurs, the associated sectionalizing switches and then feeder breaker opens and the reclosing the breaker. transformers normally supplied from the faulted feeder are out of service. 7 Then manually, each primary switch connected to the faulted line must be 8 opened and then the alternate line Figure 1.3-12. Duplex Fused Switch in primary switch can be closed connect- 52 Two Structures ing the transformer to the live feeder, thus restoring service to all loads. 9 Loop A Loop A One alternate to the duplex switch arrangement, a non-load break selector Note that each of the primary circuit switch mechanically interlocked with conductors for Feeder A1 and B1 must be sized to handle the sum of the loads 10 In cases where only one primary line a load break fused switch can be used is available, the use of a single primary as shown in Figure 1.3-13. The non- normally connected to both A1 and B1. breaker provides the loop connections load break selector switch is physically Similar sizing of Feeders A2 and B2, to the loads as shown here. 11 located in the rear of the load break etc., is required. Figure 1.3-11. Single Primary Feeder— fused switch, thus only requiring one If a fault occurs in one transformer, Loop System structure and a lower cost and floor the associated primary fuses blow 12 space savings over the duplex and interrupt the service to just 3. Primary Selective System— arrangement. The non-load break the load served by that transformer. switch is mechanically interlocked to Secondary Radial System Service cannot be restored to the loads 13 prevent its operation unless the load normally served by the faulted The primary selective—secondary break switch is opened. The main transformer until the transformer radial system, as shown in disadvantage of the selector switch is is repaired or replaced. 14 Figure 1.3-10, differs from those that conductors from both circuits are previously described in that it employs terminated in the same structure. Cost of the primary selective— at least two primary feeder circuits in secondary radial system is greater 15 each load area. It is designed so that than that of the simple primary radial when one primary circuit is out of ser- Primary system of Figure 1.3-4 because of the Feeders vice, the remaining feeder or feeders additional primary main breakers, tie 16 have sufficient capacity to carry the breaker, two-sources, increased number total load. Half of the transformers are Non-Load Break of feeder breakers, the use of primary- normally connected to each of the two Selector Switches duplex or selector switches, and the Inter- 17 feeders. When a fault occurs on one of greater amount of primary feeder lock Load Break the primary feeders, only half of the Disconnect cable required. load in the building is dropped. The benefits from the reduction in 18 Fuses Duplex fused switches as shown the amount of load lost when a in Figure 1.3-10 and detailed in primary feeder is faulted, plus the 19 Figure 1.3-12 may be utilized for this quick restoration of service to all or type of system. Each duplex fused most of the loads, may more than switch consists of two load break offset the greater cost. 20 three-pole switches each in their own separate structure, connected together by bus bars on the load side. Typically, 21 the load break switch closest to the Figure 1.3-13. Fused Selector Switch in One Structure

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.3-7 August 2017 Types of Systems Sheet 01 035

Having two sources allows for either This means each primary feeder The double-ended unit substation manual or automatic transfer of the conductor must be sized to carry the arrangement can be used in conjunction i two primary main breakers and tie load on both sides of all the secondary with any of the previous systems breaker should one of the sources buses it is serving under secondary discussed, which involve two primary become unavailable. emergency transfer If the loss of sources. Although not recommended, ii voltage was due to a failure of one of if allowed by the utility, momentary The primary selective-secondary radial the transformers in the double-ended re-transfer of loads to the restored system, however, may be less costly unit substation, then the associated source may be made closed transition 1 or more costly than a primary loop— primary fuses would open taking only (anti-parallel interlock schemes would secondary radial system of Figure 1.3-6 the failed transformer out of service, have to be defeated) for either the depending on the physical location and then only the secondary loads primary or secondary systems. Under 2 of the transformers. It also offers normally served by the faulted this condition, all equipment interrupt- comparable downtime and reliability. transformer would have to be ing and momentary ratings should be The cost of conductors for the types of transferred to the opposite transformer. suitable for the fault current available 3 systems may vary depending on the from both sources. location of the transformers and loads In either of the above emergency within the facility. The cost differences conditions, the in-service transformer For double-ended unit substations 4 of the conductors may offset cost of of a double-ended unit substation equipped with ground fault systems the primary switching equipment. would have to have the capability of special consideration to transformer serving the loads on both sides of the neutral grounding and equipment 5 4. Two-Source Primary— tie breaker. For this reason, transform- operation should be made—see Secondary Selective System ers used in this application must have “Grounding” and “Ground Fault equal kVA ratings on each side of the Protection” in Section 1.6. Where 6 This system uses the same principle double-ended unit substation. The two single-ended unit substations of duplicate sources from the power transformers are sized so the normal are connected together by busway supply point using two primary main operating maximum load on each or external tie conductors, it is 7 breakers and a primary tie breaker. transformer is typically about 2/3 base recommended that a tie breaker The two primary main breakers and nameplate kVA rating. be furnished at each end of the tie primary tie breaker being either conductors. The second tie breaker 8 manually or electrically interlocked Typically these transformers are provides a means to isolate the to prevent closing all three at the same furnished with fan-cooling and/or interconnection between the two time and paralleling the sources. Upon lower than normal temperature rise single-ended substations for 9 loss of voltage on one source, a manual such that under emergency conditions maintenance or servicing purposes. or automatic transfer to the alternate they can continuously carry the source line may be used to restore maximum load on both sides of the 10 power to all primary loads. secondary tie breaker. Because of this spare transformer capacity, the voltage Each transformer secondary is regulation provided by the double- 11 arranged in a typical double-ended ended unit substation system under unit substation arrangement as shown normal conditions is better than that in Figure 1.3-14. The two secondary of the systems previously discussed. main breakers and secondary tie . 12 breaker of each unit substation are again either mechanically or electrically interlocked to prevent parallel operation. 13 Upon loss of secondary source voltage 52 52 Primary Main Breakers on one side, manual or automatic 52 transfer may be used to transfer the 14 loads to the other side, thus restoring 52 52 52 52 Primary Feeder Breakers power to all secondary loads. 15 This arrangement permits quick To Other Substations To Other Substations restoration of service to all loads when a primary feeder or transformer fault Typical 16 occurs by opening the associated Double-Ended Unit secondary main and closing the Substation secondary tie breaker. If the loss 17 of secondary voltage has occurred because of a primary feeder fault with the associated primary feeder breaker 18 opening, then all secondary loads normally served by the faulted feeder would have to be transferred to the 19 opposite primary feeder. Primary Fused Switch Transformer Tie Breaker Secondary Main Breaker 20 Figure 1.3-14. Two-Source Primary—Secondary Selective System 21

CA08104001E For more information, visit: www.eaton.com/consultants 1.3-8 Power Distribution Systems Types of Systems August 2017 Sheet 01 036

5. Sparing Transformer System The sparing transformer system In facilities without qualified electrical i operates as follows: power operators, an open transition The sparing transformer system concept with key interlocking is often a came into use as an alternative to the ■ All main breakers, including prudent design. ii capital cost intensive double-ended the sparing main breaker, are secondary unit substation distribution normally closed; the tie breakers Note: Each pair of “main breaker/tie breaker” system (see Two-Source Primary— are normally open key cylinders should be uniquely keyed to 1 Secondary Selective System). It essen- ■ Once a transformer (or primary prevent any paralleled source operations. tially replaces double-ended substations cable or primary switch/fuse) fails, Careful sizing of these transformers with single-ended substations and one the associated secondary main as well as careful specification of the or more “sparing” transformer substa- breaker is opened. The associated 2 transformers is required for reliability. tions all interconnected on a common tie breaker is then closed, which Low temperature rise specified with secondary bus—see Figure 1.3-15. restores power to the single-ended continuous overload capacity or substation bus 3 Generally no more than three to five upgraded types of transformers single-ended substations are on a ■ Schemes that require the main to should be considered. sparing loop. be opened before the tie is closed 4 (“open transition”), and that allow One disadvantage to this system is The essence of this design philosophy any tie to be closed before the the external secondary tie system, is that conservatively designed and substation main is opened, see Figure 1.3-15. As shown, all single- 5 loaded transformers are highly reliable (“closed transition”) are possible ended substations are tied together electrical devices and rarely fail. There- on the secondary with a tie busway or fore, this design provides a single com- With a closed transition scheme, it is cable system. Location of substations 6 mon backup transformer for a group of common to add a timer function that is therefore limited because of voltage transformers in lieu of a backup trans- opens the tie breaker unless either drop and cost considerations. former for each and every transformer. main breaker is opened within a 7 This system design still maintains a time interval. Routing of busway, if used, must be high degree of continuity of service. carefully layed out. It should also be This closed transition allows power noted, that a tie busway or cable fault 8 Referring to Figure 1.3-15, it is apparent to be transferred to the sparing will essentially prevent the use of the that the sparing concept backs up transformer without interruption, such sparing transformer until it is repaired. primary switch and primary cable as for routine maintenance, and then Commonly, the single-ended substa- 9 failure as well. Restoration of lost or back to the substation. This closed tions and the sparing transformer failed utility power is accomplished transition transfer has an advantage in must be clustered. This can also be similarly to primary selective scheme some facilities; however, appropriate an advantage, as more kVA can be 10 previously discussed. It is therefore interrupting capacities and bus bracing supported from a more compact important to use an automatic throw- must be specified suitable for the space layout. over system in a two source lineup momentary parallel operation. 11 of primary switchgear to restore utility power as discussed in the “Two-Source Primary” scheme—see Figure 1.3-14. 12 A major advantage of the sparing transformer system is the typically lower total base kVA of transformation. K K K 13 In a double-ended substation design, each transformer must be rated to carry the sum of the loads of two 14 busses and usually requires the addition of cooling fans to accomplish Sparing Transformer this rating. In the “sparing” concept, 15 each transformer carries only its own load, which is typically not a fan-cooled rating. In addition to first cost savings, K K 16 there is a side benefit of reduced equipment space.

17 Typical Secondary Busway Loop

K K 19 Typical Single-Ended Substation

20 Figure 1.3-15. Sparing Transformer System 21

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.3-9 August 2017 Types of Systems Sheet 01 037

6. Simple Spot Network Systems The purpose of the network protector system design with similar spare is to protect the integrity of the capacity. This occurs in many radial i The ac secondary network system network bus voltage and the loads systems because more and smaller is the system that has been used for served from it against transformer feeders are often used in order to many years to distribute electric power and primary feeder faults by quickly minimize the extent of any outage ii in the high-density, downtown areas disconnecting the defective feeder- when a primary fault event occurs. of cities, usually in the form of utility transformer pair from the network grids. Modifications of this type of when backfeed occurs. In spot networks, when a fault occurs 1 system make it applicable to serve on a primary feeder or in a transformer, loads within buildings. The simple spot network system the fault is isolated from the system resembles the secondary-selective through the automatic tripping of the 2 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 3 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 4 interrupting service to any load. bus, as shown in Figure 1.3-16, 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 5 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- minimum interruption in service to tion to the loads. The chief purpose of the network bus other loads on the network. In addition normally closed ties is to provide for 6 to flexibility and service reliability, the The paralleled transformers supplying the sharing of loads and a balancing secondary network system provides each load bus will normally carry equal of load currents for each primary exceptionally uniform and good load currents, whereas equal loading service and transformer regardless of 7 voltage regulation, and its high of the two separate transformers the condition of the primary services. efficiency materially reduces the supplying a substation in the costs of system losses. secondary-selective radial system is Also, the ties provide a means for 8 difficult to obtain. The interrupting isolating and sectionalizing ground Three major differences between the duty imposed on the outgoing feeder fault events within the switchgear 9 network system and the simple radial breakers in the network will be greater network bus, thereby saving a portion system account for the outstanding with the spot network system. of the loads from service interruptions, advantages of the network. First, yet isolating the faulted portion for a network protector is connected in The optimum size and number of corrective action. 10 the secondary leads of each network primary feeders can be used in the transformer in place of, or in addition spot network system because the The use of spot network systems to, the secondary main breaker, as loss of any primary feeder and its provides users with several important 11 shown in Figure 1.3-16. Also, the associated transformers does not advantages. First, they save trans- secondaries of each transformer in result in the loss of any load even former capacity. Spot networks permit a given location (spot) are connected for an instant. In spite of the spare equal loading of transformers under 12 together by a switchgear or ring bus capacity usually supplied in network all conditions. Also, networks yield from which the loads are served over systems, savings in primary switch- lower system losses and greatly short radial feeder circuits. Finally, the gear and secondary switchgear costs improve voltage conditions. 13 primary supply has sufficient capacity often result when compared to a radial to carry the entire building load without overloading when any one primary 14 feeder is out of service. Typical Feeder A network protector is a specially Primary Circuit 15 designed heavy-duty air power breaker, To Other spring close with electrical motor-charged Networks Network Transformer mechanism, with a network relay to 16 control the status of the protector Network Protector (tripped or closed). Fuses 17 The network relay is usually a solid- Optional Main, 50/51 state microprocessor-based component Relaying and/or Network Disconnect Tie Tie integrated into the protector enclosure Drawout 18 that functions to automatically close Low-Voltage Switchgear the protector only when the voltage LV Feeder NC NC conditions are such that its associated 19 transformer will supply power to the Customer Customer Customer secondary network loads. It also serves Loads Loads Loads to automatically open the protector 20 when power flows from the secondary Figure 1.3-16. Three-Source Spot Network to the network transformer. 21

CA08104001E For more information, visit: www.eaton.com/consultants 1.3-10 Power Distribution Systems Types of Systems August 2017 Sheet 01 038

The voltage regulation on a network 7. Medium-Voltage Distribution Retransfer to the “Normal” can be i system is such that both lights and closed transition subject to the approval power can be fed from the same load System Design of the utility. Closed transition momen- bus. Much larger motors can be started A. Single Bus, Figure 1.3-17 tarily (5–10 cycles) parallels both ii across-the-line than on a simple radial utility sources. Caution: when both system. This can result in simplified The sources (utility and/or generator(s)) sources are paralleled, the fault current motor control and permits the use of are connected to a single bus. All feeders available on the load side of the main 1 relatively large low voltage motors with are connected to the same bus. device is the sum of the available fault their less expensive control. This configuration is the simplest current from each source plus the motor fault contribution. It is recommended Finally, network systems provide a system; however, outage of the utility 2 results in total outage. that the short-circuit ratings of the greater degree of flexibility in adding bus, feeder breakers and all load side future loads; they can be connected to Normally the generator does not have equipment are rated for the increased 3 the closest spot network bus. adequate capacity for the entire load. available fault current. Spot network systems are economical A properly relayed system equipped with load shedding, automatic voltage/ If the utility requires open transfer, the for buildings that have heavy concen- disconnection of motors from the bus 4 trations of loads covering small areas, frequency control may be able to maintain partial system operation. must be ensured by means of suitable with considerable distance between time delay on reclosing as well as 5 areas, and light loads within the Any future addition of breaker sections supervision of the bus voltage and its distances separating the concentrated to the bus will require a shutdown of phase with respect to the incoming loads. They are commonly used in the bus, because there is no tie breaker. source voltage hospitals, high rise office buildings, 6 institutional buildings or laboratories This busing scheme does not preclude where a high degree of service reliabil- the use of cogeneration, but requires ity is required from the utility sources. Utility the use of sophisticated automatic syn- 7 Spot network systems are especially chronizing and synchronism checking economical where three or more G controls, in addition to the previously primary feeders are available. mentioned load shedding, automatic 8 frequency and voltage controls. Principally, this is due to supplying each load bus through three or This configuration is more expensive 9 more transformers and the reduction than the scheme shown in Figure 1.3-17, in spare cable and transformer 52 52 but service restoration is quicker. Again, capacity required. a utility outage results in total outage to 10 Main Bus the load until transfer occurs. Extension They are also economical when of the bus or adding breakers requires compared to two transformer double- a shutdown of the bus. 11 ended substations with normally opened tie breakers. If paralleling sources, reverse current, 52 reverse power and other appropriate 12 Emergency power should be connected relaying protection should be added to network loads downstream from as requested by the utility. the network, or upstream at primary One of Several Feeders 13 voltage, not at the network bus itself. Figure 1.3-17. Single Bus Utility #1 Utility #2 B. Single Bus with Two Sources from 14 the Utility, Figure 1.3-18 Same as the single bus, except that Normal Standby 15 two utility sources are available. This system is operated normally with the main breaker to one source open. 16 Upon loss of the normal service, the transfer to the standby normally open (NO) breaker can be automatic 52 NC 52 NO 17 or manual. Automatic transfer is preferred for rapid service restoration especially in unattended stations. 18 Loads Figure 1.3-18. Single Bus with Two-Sources 19

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.3-11 August 2017 Types of Systems Sheet 01 039

C. Multiple Sources with Tie Breaker, In Figure 1.3-20, closing of the tie Summary Figure 1.3-19 and Figure 1.3-20 breaker following the opening of a The medium-voltage system configu- i This configuration is similar to the main breaker can be manual or auto- rations shown are based on using configuration shown in Figure 1.3-18. It matic. However, because a bus can metal-clad drawout switchgear. The differs significantly in that both utility be fed through two tie breakers, the service continuity required from ii sources normally carry the loads and control scheme should be designed electrical systems makes the use of to make the selection. also by the incorporation of a normally single-source systems impractical. 1 open tie breaker. The outage to the The third tie breaker allows any bus system load for a utility outage is In the design of a modern medium- to be fed from any utility source. voltage system, the engineer should: limited to half of the system. Again, 2 the closing of the tie breaker can be Caution for Figures 1.3-18, 1.3-19 and 1. Design a system as simple as manual or automatic. The statements 1.3-20: If continuous paralleling of possible. made for the retransfer of the configu- sources is planned, reverse current, 2. Limit an outage to as small a 3 ration shown in Figure 1.3-18 apply to reverse power and other appropriate portion of the system as possible. this scheme also. relaying protection should be added. When both sources are paralleled for 3. Provide means for expanding the 4 any amount of time, the fault current system without major shutdowns. Utility #1 Utility #2 available on the load side of the main device is the sum of the available 4. Design a protective relaying 5 fault current from each source plus system so that only the faulted the motor fault contribution. It is part is removed from service, required that bus bracing, feeder and damage to it is minimized 6 breakers and all load side equipment consistent with selectivity. is rated for the increased available 52 NC 52 NC 5. Specify and apply all equipment fault current. within its published ratings and 7 NO national standards pertaining to Bus #1 Bus #2 the equipment and its installation. 52 8

Utility #1 Utility #2 Utility #3 52 52 9

10 Load Load

Figure 1.3-19. Two-Source Utility with 52NC 52 NC 52 NC 11 Tie Breaker NO NO If looped or primary selective Bus #1 Bus #2 Bus #3 12 distribution system for the loads 52 52 is used, the buses can be extended without a shutdown by closing the tie 13 breaker and transferring the loads to 52 NO 52 Typical Feeder 52 52 52 NO the other bus. This configuration is more expensive Tie Busway 14 than the configuration shown in Figure 1.3-18. The system is not limited Figure 1.3-20. Triple-Ended Arrangement to two buses only. Another advantage 15 is that the design may incorporate momentary paralleling of buses on retransfer after the failed line has been 16 restored to prevent another outage. See the Caution for Figures 1.3-18, 1.3-19 and 1.3-20. 17 18

CA08104001E For more information, visit: www.eaton.com/consultants 1.3-12 Power Distribution Systems August 2017 Sheet 01 040

This page intentionally left blank. i ii

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.4-1 August 2017 Power System Analysis Sheet 01 041

Systems Analysis ■ Circuit breaker duty—identify The following additional studies asymmetrical fault current based should be considered depending i A major consideration in the design on X/R ratio upon the type and complexity of the of a distribution system is to ensure ■ Protective device coordination— distribution system, the type of facility that it provides the required quality determine characteristics and set- and the type of loads to be connected ii of service to the various loads. This tings of medium voltage protective to the system: includes: serving each load under relays and fuses, and entire low ■ Harmonic analysis normal conditions, under abnormal voltage circuit breaker and fuse 1 ■ conditions and providing the desired coordination Transient stability ■ protection to service and system ■ Load flow—simulate normal and Insulation coordination apparatus so that interruptions of abnormal load conditions of system ■ Grounding study 2 service are minimized. voltages, power factor, line and ■ Switching transient transformer loadings Under normal conditions, the The Power Systems Engineering Team 3 ■ Motor starting—identify system important technical factors include within Eaton’s Electrical Services & voltages, motor terminal voltage, voltage profile, losses, load flow, Systems division can provide any motor accelerating torque, and effects of motor starting, service of the system studies discussed in 4 motor accelerating time when continuity and reliability. The prime this section. considerations under faulted starting large motors conditions are apparatus protection, Short-circuit calculations define 5 fault isolation service continuity and Short-Circuit Currents— momentary and steady-state fault of course personnel safety. currents for specific points in the General 6 During the system preliminary electrical system. This information is planning stage, before selection of used to select protective devices and The amount of current available in the distribution apparatus, several to determine required equipment bus a short-circuit fault is determined by 7 distribution systems should be bracing and withstand levels. These the capacity of the system voltage analyzed and evaluated, including calculations are generated for both sources and the impedances of the both economic and technical factors. normal, emergency and alternative system, including the fault. Voltage 8 During this stage, if system size system configurations. sources include the power supply or complexity warrant, it may be (utility or on-site generation) plus all Computer software programs can appropriate to provide a thorough rotating machines connected to the identify the fault current at any bus 9 review of each system under both system at the time of the fault, and in the distribution system under any normal and abnormal conditions. are not connected through power number of scenarios of source and load conversion equipment such as This type of dynamic analysis is combinations. It is often necessary to variable frequency drives. 10 typically done using Computer evaluate the distribution system in all Simulation Software. Selection of the possible operating states of sources A fault may be either an arcing or components such as circuit breakers, and loads to understand available fault bolted fault. In an arcing fault, part of 11 cables, transformers, equipment currents in all possible states. The the circuit voltage is consumed across motors and generators are entered results of these calculations permit the arc and the total fault current is into a power flow one-line of the optimizing service to the loads while somewhat smaller than for a bolted 12 system. Changes to these variables, properly applying distribution appara- fault. The bolted fault condition results including the type of breaker as well as tus within their intended limits. in the highest fault magnitude fault its trip unit settings, the size and length currents, and therefore is the value 13 Articles 110.21(B) and 110.24 of 2014 of conductors, the hp of motors and sought in the fault calculations. National Electrical Code (NEC) have kVA of transformers and generators, increased the field-applied available Basically, the short-circuit current is can be adjusted to reflect the impact 14 fault current marking requirements for determined by applying Ohm’s Law this will have on the short-circuit electrical equipment. Article 110.24(A) to an equivalent circuit consisting energy available at various points in states: “Service equipment in other of a constant voltage source and a the power distribution system. 15 than dwelling units shall be legibly time- varying impedance. A time- The principal types of computer marked in the field with the maximum varying impedance is used in order programs used to provide system available fault current. The field mark- to account for the changes in the 16 studies include: ing(s) shall include the date the fault- effective voltages of the rotating current calculation was performed and machines during the fault. ■ Short circuit—identify three-phase be of sufficient durability to withstand In an AC system, the resulting short- 17 and line-to-ground fault currents the environment involved.” Article and system impedances circuit current starts out higher in 110.24(B) then takes this a step further magnitude than the final steady-state ■ Arc flash—calculates arc flash stating: “When modifications to the value and asymmetrical (due to the 18 energy levels, which leads to electrical installation occur that affect DC offset) about the X-axis. The the proper selection of personal the maximum available fault current at current then decays toward a lower protective equipment (PPE) the service, the maximum available symmetrical steady-state value. 19 fault current shall be verified or recalculated as necessary. The required field marking(s) in 110.24(A) shall be 20 adjusted to reflect the new level of maximum available fault current.” 21

CA08104001E For more information, visit: www.eaton.com/consultants 1.4-2 Power Distribution Systems Power System Analysis August 2017 Sheet 01 042

The time-varying characteristic of Synchronous reactance (Xd), which The electric network that determines i the impedance accounts for the determines fault current after steady- the short-circuit current consists of an symmetrical decay in current. The state condition is reached. It has no AC driving voltage equal to the pre-fault ratio of the reactive and resistive effect as far as short-circuit calculations system voltage and an impedance ii components (X/R ratio) accounts are concerned, but is useful in the corresponding to that observed when for the DC decay, see Figure 1.4-1. determination of relay settings. looking back into the system from the The fault current consists of an fault location. 1 exponentially decreasing direct- Transformer impedance, in percent, is current component superimposed defined as that percent of rated primary In industrial medium- and high-voltage upon a decaying alternating-current. voltage that must be applied to the work, it is generally satisfactory to 2 transformer to produce rated current regard reactance as the entire imped- The rate of decay of both the DC and flowing in the secondary, with the ance; resistance may be neglected. AC components depends upon the secondary shorted through zero However, this is normally permissible 3 ratio of reactance to resistance (X/R) resistance. It is important to note that only if the X/R ratio of the medium of the circuit. The greater this ratio, the transformer percent impedance is voltage system is equal to or more the longer the current remains higher a per-unit value typically expressed on than 25. 4 than the steady-state value that it the base kVA rating of the transformer. would eventually reach. Therefore, it is not necessary to calcu- In low-voltage (1000 V and below) late maximum fault current produced calculations, it is usually worthwhile to 5 The total fault current is not symmetrical at the fan-cooled rating or the higher attempt greater accuracy by including with respect to the time-axis because temperature rise kVA ratings because resistance with reactance in dealing of the direct-current component, hence the per-unit impedance at those kVA with impedance. It is for this reason, 6 it is called asymmetrical current. The ratings increases by the same ratio, plus ease of manipulating the various DC component depends on the point making the fault current calculation impedances of cables and buses and on the voltage wave at which results the same.Therefore, assuming transformers of the low-voltage 7 the fault is initiated. the primary voltage can be sustained circuits, that computer studies are (generally referred to as an infinite recommended before final selection of See Figure 1.4-2 for multiplying factors apparatus and system arrangements. that relate the rms asymmetrical value or unlimited supply), the maximum 8 of total current to the rms symmetrical current a transformer can deliver to When evaluating the adequacy value, and the peak asymmetrical a fault condition is the quantity of of short-circuit ratings of medium value of total current to the rms (100 divided by percent impedance) voltage circuit breakers and fuses, 9 symmetrical value. times the transformer rated secondary both the rms symmetrical value and current. Limiting the power source asymmetrical value of the short-circuit The AC component is not constant fault capacity to the transformer current should be determined. 10 if rotating machines are connected primary will thereby reduce the to the system because the impedance maximum fault current from the For low-voltage circuit breakers and of this apparatus is not constant. The transformer secondary. fuses, the rms symmetrical value 11 rapid variation of motor and generator should be determined along with impedance is due to these factors: either: the X/R ratio of the fault at the device or the asymmetrical Subtransient reactance (Xd ), deter- short-circuit current. 12 mines fault current during the first cycle, and after about 6 cycles this value increases to the transient 13 Total Current—A Wholly Offset reactance. It is used for the calculation Asymmetrical Alternating Wave of the momentary interrupting and/or 3.0 14 momentary withstand duties of rms Value of Total Current equipment and/or system. 2.5 Alternating Component - Symmetrical Wave Transient reactance (X ), which d 2.0 rms Value of 15 determines fault current after about Alternating Component 6 cycles and this value in 1/2 to 1.5 2 seconds increases to the value of

16 a lues the synchronous reactance. It is used 1.0 in the setting of the phase overcurrent 17 relays of generators and medium- 0.5 voltage circuit breakers. 1 2 34 0

18 S ca le o f Curent V 0.5

19 –1.0 Direct Component—The Axis –1.5 of Symmetrical Wave Time in Cycles of a 60 Hz Wave 20 –2.0

21 Figure 1.4-1. Structure of an Asymmetrical Current Wave

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.4-3 August 2017 Power System Analysis Sheet 01 043

Fault Current Waveform Relationships i The following Figure 1.4-2 describes Based on a 60 Hz system and t = 1/2 cycle the relationship between fault (ANSI/IEEE C37.13.2015) 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 2.1 1.7 RMS MAXIMUM ASYMMETRICAL 14 N F O TI 2.0 1.6 IPLICA 15 1.9 1.5 MULT

1.8 PEAK ACTOR 1.4 16 TION F 1.7 1.3 TIPLICA 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 1.4-2. Relation of X/R Ratio to Multiplication Factor 21

CA08104001E For more information, visit: www.eaton.com/consultants 1.4-4 Power Distribution Systems Power System Analysis August 2017 Sheet 01 044

Fault Current Calculations To determine the motor contribution Medium-Voltage Motors i during the first half-cycle fault current, If known, use actual values otherwise The calculation of asymmetrical when individual motor horsepower use the values indicated for the same currents is a laborious procedure since load is known, the subtransient type of motor. ii the degree of asymmetry is not the reactances found in the IEEE Red Book same on all three phases. It is common should be used in the calculations. practice for medium voltage systems, Calculation Methods For motors fed through adjustable 1 to calculate the rms symmetrical fault The following pages describe various frequency drives or solid-state soft current, with the assumption being methods of calculating short-circuit starters, there is no contribution to made that the DC component has currents for both medium- and low- fault current, unless 1) they have an 2 decayed to zero, and then apply a multi- voltage systems. A summary of internal run contactor or 2) they have plying factor to obtain the first half- the types of methods and types of a bypass contactor. cycle rms asymmetrical current, which calculations is as follows: 3 is called the “momentary current.” When the motor load is not known, ■ Medium-voltage the following assumptions generally For medium-voltage systems (defined switchgear—exact are made. The following percentage by IEEE as greater than 1000 V up to method...... Page 1.4-5 4 estimates are based on design load or 69,000 V) the multiplying factor is ■ transformer nameplate rating, when Medium-voltage established by NEMA® and ANSI known. switchgear—quick 5 standards depending upon the check table ...... Page 1.4-8 operating speed of the breaker. 208Y/120 V Systems ■ Medium-voltage 6 For low-voltage systems, short-circuit ■ Assume 50% lighting and 50% switchgear study software usually calculates the motor load Example 1—verify ratings of breakers . . . . Page 1.4-9 symmetrical fault current and the or 7 faulted system X/R ratio using UL ■ Medium-voltage and ANSI guidelines. If the X/R ratio ■ Assume motor feedback contribu- switchgear is within the standard (lower than the tion of twice full load current of Example 2—verify 8 breaker test X/R ratio), and the breaker transformer ratings of breakers interrupting current is under the with rotating symmetrical fault value, the breaker or loads...... Page 1.4-10 9 is properly rated. 240/480/600 V Three-Phase, Three-Wire or ■ Medium-voltage switchgear Example 3 If the X/R ratio is higher than UL or Four-Wire Systems —verify ratings of ANSI standards, the study applies a ■ Assume 100% motor load breakers with 10 multiplying factor to the symmetrical generators ...... Page 1.4-11 calculated value (based on the or ■ Medium-voltage X/R value of the system fault) and ■ 11 Assume motors 25% synchronous fuses—exact method . . Page 1.4-11 compares that value to the breaker and 75% induction symmetrical value to assess if it is ■ Power breakers— properly rated. or asymmetry 12 derating factors ...... Page 1.4-12 In the past, especially using manual ■ Assume motor feedback contribu- ■ Molded-case calculations, a multiplying factor of tion of four times full load current breakers—asymmetry 1.35 (based on the use of an X/R ratio of transformer 13 derating factors ...... Page 1.4-13 of 6.6 representing a source short- circuit power factor of 15%) was used 480Y/277 V Systems in Commercial Buildings ■ Short-circuit 14 to calculate the asymmetrical current. ■ Assume 50% induction motor load calculations— short cut method These values take into account that or medium voltage breakers are rated for a system ...... Page 1.4-14 15 on maximum asymmetry and low ■ Assume motor feedback contribu- ■ Short-circuit voltage breakers are rated average tion of two times full load current calculations—short asymmetry. of transformer or source cut method for 16 end of cable ...... Page 1.4-16 ■ Short-circuit currents— chart of transformers 17 300–3750 kVA...... Page 1.11-9

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.4-5 August 2017 Power System Analysis Sheet 01 045

Fault Current Calculations Ultimately, as vacuum circuit breakers For example, consider the following case: became more and more prevalent in i for Specific Equipment— the industry, the IEEE C37.06-2000 Assume a 12.47 kV system with Exact Method standard was published to recognize 20,000 A symmetrical available. In both MVA and K = 1 rated breakers. order to determine if an Eaton Type ii 150 VCP-W 500 vacuum breaker is The purpose of the fault current calcu- suitable for this application, check lations is to determine the fault current The following is a review of the the following: at the location of a circuit breaker, fuse meaning of the ratings. (See Ta b 5 , 1 Section 5.4.) or other fault interrupting device in From Table 5.4-1B in Tab 5, Section 5.4 order to select a device adequate for the The Rated Maximum Voltage under column “Rated Maximum calculated fault current or to check the Voltage” V = 15 kV, under column 2 thermal and momentary ratings of non- This designates the upper limit of design and operation of a circuit “Rated short-circuit Current” I = 18 kA, interrupting devices. When the devices “Rated Voltage Range Factor” K = 1.3. to be used are ANSI-rated devices, the breaker. For example, a circuit breaker 3 with a 4.76 kV rated maximum voltage fault current must be calculated and the Test 1 for V/Vo x I or 15 kV/12.47 kV x 18 device selected as per ANSI standards. cannot be used in a 4.8 kV system. kA = 21.65; also check K x I (which K-Rated Voltage Factor is shown in the column headed 4 The calculation of available fault current “Maximum Symmetrical Interrupting and system X/R rating is also used to The rated voltage divided by this factor Capability”) or 1.3 x 18 kA = 23.4 kA. verify adequate busbar bracing and determines the system kV a breaker can Because both of these numbers are 5 momentary withstand ratings of be applied up to the short-circuit kVA greater than the available system fault devices such as contactors. rating calculated by the formula current of 20,000 A, the breaker is acceptable (assumes the breaker’s 6 Medium-Voltage VCP-W 3 Rated SC Current  Rated Max. Voltage momentary and fault close rating is Metal-Clad Switchgear Note: Interrupting capabilities of some of also acceptable). MVA breaker ratings first originated today’s vacuum breakers may have K=1, Note: If the system available fault current 7 many years ago to describe the whereby the interrupting current is constant were 22,000 A symmetrical, this breaker preferred ratings of air-magnetic circuit across its entire operating range. could not be used even though the breakers that had published short- “Maximum Symmetrical Interrupting 8 Rated Short-Circuit Current circuit current interruption ratings Capability” is greater than 22,000 because Test 1 calculation is not satisfied. based on their rated maximum For K = 1 breakers, this is the symmetri- voltage. These breakers, however, cal current that a breaker can interrupt 9 across it's operational range. With For approximate calculations, Table 1.4-1 could achieve higher interruption provides typical values of % reactance ratings at lower operating voltages MVA rated breakers (K >1), this is the symmetrical rms value of current (X) and X/R values for various rotating 10 until the maximum interruption equipment and transformers. For sim- rating was exceeded. that the breaker can interrupt at rated maximum voltage. For example, with plification purposes, the transformer The ratio of these two interruption an Eaton 50 VCP-W 250 circuit breaker, impedance (Z) has been assumed to be 11 ratings is called rated voltage range it should be noted that the product primarily reactance (X). In addition, the indicator (K). The rated voltage range 3 x 4.76 x 29,000 = 239,092 kVA is less resistance (R) for these simplified cal- indicator, K, is greater than 1 for MVA than the nominal 250,000 kVA listed. culations has been ignored. For detailed 12 rated breakers. For example, an Eaton This rating (29,000 A) is also the base calculations, the values from the IEEE Red Book Standard 141, for rotating 150 VCP-W 500, (15 kV – 500 MVA rated quantity that all the “related” capabili- machines, and ANSI C57 and/or C37 breaker with a K=1.30 rating has a ties are referred to. for transformers should be used. 13 published interruption rating of 18 kA Maximum Symmetrical Interrupting at 15 kV, but has a maximum interrup- Capability tion rating of 23 kA (18 kA x 1.30) at 14 11.5 kV (15 kV divided by 1.30). With K=1 breakers, the short-time withstand current and the maximum As new vacuum interrupting symmetrical interrupting current 15 technologies were developed, are equal to the rated symmetrical scientists discovered that reducing interrupting current. For MVA rated the operating voltage did not increase breakers (K >1), this is expressed 16 the short-circuit current interrupting in rms symmetrical amperes or capability of new interrupters. In fact, kiloamperes and is K x I rated; as the operating voltage is reduced, 1.24 x 29,000 = 35,960 rounded 17 the short-circuit current interrupting to 36 kA. capability changes only little. There- This is the rms symmetrical current fore the MVA (K >1.0) basis of rating that the breaker can interrupt down to 18 no longer accurately reflected the true a voltage equal to maximum rated interrupting characteristics of the voltage divided by K (for example, newer circuit breaker designs. 4.76/1.24 = 3.85). If this breaker is 19 applied in a system rated at 2.4 kV, the calculated fault current must be less than 36 kA. 20

CA08104001E For more information, visit: www.eaton.com/consultants 1.4-6 Power Distribution Systems Power System Analysis August 2017 Sheet 01 046

Table 1.4-1. Reactance X The Close and Latch Capability i System Reactance X Used for Typical Values and Range K = 1 and K >1 breakers also differ in Component Short-Circuit Close and Latch on Component Base the calculations for the breaker's close Duty (Momentary) % Reactance X/R Ratio and latch rating. With K = 1 breakers, ii this is a calculated peak value using Two-pole turbo generator X X 9 (7–14) 80 (40–120) Four-pole turbo generator X X 15 (12–17) 80 (40–120) 2.6 x the breaker’s symmetrical interrupting rating. For MVA rated 1 Hydro generator with damper wedges X X 20 (13–32) 30 (10–60) and synchronous condensers breakers (K >1), this is also a related quantity expressed in rms asymmetri- Hydro generator without damper windings 0.75X 0.75X 16 (16–50) 30 (10–60) cal amperes by 1.6 x maximum 2 All synchronous motors 1.5X 1.0X 20 (13–35) 30 (10–60) symmetrical interrupting capability. Induction motors above 1000 hp, 1800 rpm 1.5X 1.0X 17 (15–25) 30 (15–40) For example, 1.6 x 36 = 57.6 or 58 kA, and above 250 hp, 3600 rpm or 1.6 K x rated short-circuit current. 3 All other induction motors 50 hp and above 3.0X 1.2X 17 (15–25) 15 (2–40) Induction motors below 50 hp and Neglect Neglect — — Another way of expressing the close all single-phase motors and latch rating is in terms of the peak 4 Distribution system from remote XX As specified 15 (5–15) current, which is the instantaneous transformers or calculated value of the current at the crest. ANSI Current limiting reactors X X As specified 80 (40–120) Standard C37.09 indicates that the ratio 5 or calculated of the peak to rms asymmetrical value Transformers for any asymmetry of 100% to 20% (percent asymmetry is defined as the ONAN to 10 MVA, 69 kV X X 8.0 18 (7–24) 6 ratio of DC component of the fault in ONAN to 10 MVA, above 69 kV X X 8.0 to 10.5 18 (7–24) Depends on per unit to 2 ) varies not more than OFAF 12–30 MVA X X 20 (7–30) primary ±2% from a ratio of 1.69. Therefore, the 7 OFAF 40–100 MVA X X windings BIL 38 (32–44) close and latch current expressed in rating terms of the peak amperes is = 1.6 x 1.69 x K x rated short-circuit current. 8 Table 1.4-2. Typical System X/R Ratio Range (for Estimating Purposes) Type of Circuit X/R Range In the calculation of faults for the purposes of breaker selection, the 9 Remote generation through other types of circuits such as transformers rated 10 MVA 15 or less rotating machine impedances specified or smaller for each three-phase bank, transmission lines, distribution feeders, etc. in ANSI Standard C37.010 Article 5.4.1 Remote generation connected through transformer rated 10 MVA to 100 MVA 15–40 should be used. The value of the for each three-phase bank, where the transformers provide 90% or more impedances and their X/R ratios 10 of the total equivalent impedance to the fault point should be obtained from the equipment Remote generation connected through transformers rated 100 MVA or larger 30–50 for each three-phase bank where the transformers provide 90% or more manufacturer. At initial short-circuit 11 of the total equivalent impedance to the fault point studies, data from manufacturers is Synchronous machines connected through transformers rated 25–100 MVA 30–50 not available. Typical values of imped- for each three-phase bank ances and their X/R ratios are given 12 Synchronous machines connected through transformers rated 100 MVA and larger 40–60 in Table 1.4-1. Synchronous machines connected directly to the bus or through reactors 40–120 The ANSI Standard C37.010 allows the use of the X values only in determin- 13 ing the E/X value of a fault current. The R values are used to determine the 14 X/R ratio, in order to apply the proper multiplying factor, to account for the total fault clearing time, asymmetry, 15 and decrement of the fault current.

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.4-7 August 2017 Power System Analysis Sheet 01 047

The steps in the calculation of fault Step 5: Reduce the resistance network reactance external to the generation currents and breaker selection are to an equivalent resistance. Call this is 1.5 times or more than the subtran- i described hereinafter: resistance RI. The above calculations sient reactance of the generation on of XI and RI may be calculated by a common base. Also use Figure 1.4-5 Step 1: Collect the X and R data of the several computer programs. where the fault is supplied by a ii circuit elements. Convert to a common utility only. kVA and voltage base. If the reactances Step 6: Calculate the E/XI value, where and resistances are given either in E is the prefault value of the voltage at Step 9: Interrupting duty short-circuit 1 ohms or per unit on a different voltage the point of fault nominally assumed current = E/XI x MFx = E/X2. or kVA base, all should be changed 1.0 pu. to the same kVA and voltage base. This X Step 10: Construct the sequence Step 7: Determine X/R = ------I as (positive, negative and zero) networks 2 caution does not apply where R the base voltages are the same as previously calculated. I properly connected for the type of fault the transformation ratio. under consideration. Use the Step 8: Go to the proper curve for X values required by ANSI Standard 3 Step 2: Construct the sequence the type of fault under consideration C37.010 for the “Close and Latch” networks and connect properly for (three-phase, phase-to-phase, phase- duty value of the short-circuit current. the type of fault under consideration. to-ground), type of breaker at the loca- 4 Use the X values required by ANSI tion (2, 3, 5 or 8 cycles), and contact Step 11: Reduce the network to an Standard C37.010 for the “interrupting” parting time to determine the multi- equivalent reactance. Call the reac- duty value of the short-circuit current. plier to the calculated E/XI. tance X. Calculate E/X x 1.6 if the 5 breaker close and latch capability is Step 3: Reduce the reactance network See Figures 1.4-3, 1.4-4 and 1.4-5 for given in rms amperes or E/X x 2.7 if to an equivalent reactance. Call this 5-cycle breaker multiplying factors. the breaker close and latch capability 6 reactance X . I Use Figure 1.4-5 if the short circuit is is given in peak or crest amperes. fed predominantly from generators Step 4: Set up the same network for removed from the fault by two or resistance values. 7 more transformations or the per unit

130 130 130 8

120 120 120

8 9 7 5

110 110 4 110 6 3

5 10 8

6 10 100 100 100 4 4 3 90 90 90 3 11

80 80 80 E 12 70 70 70 TIM G

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 13 PARTIN

50 PARTIN 50 50 ACT 14 40 40 40 CONT

CONTACT 30 30 30 15 5-CYCLE 5-CYCLE 5-CYCLE BREAKER BREAKER BREAKER 20 20 20 16

10 10 10 17 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 Multiplying Factors for E / X Amperes Multiplying Factors for E / X Amperes Multiplying Factors for E / X Amperes 18 Figure 1.4-3. Three-phase Fault Multiplying Figure 1.4-4. Line-to-Ground Fault Multiplying Figure 1.4-5. Three-phase and Line-to-Ground 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 19

CA08104001E For more information, visit: www.eaton.com/consultants 1.4-8 Power Distribution Systems Power System Analysis August 2017 Sheet 01 048

Step 12: Select a breaker whose: Application Above 3,300 ft (1,000 m) i Application Quick Check Table a. Maximum voltage rating exceeds The rated one-minute power frequency For application of circuit breakers in a the operating voltage of the system: withstand voltage, the impulse with- radial system supplied from a single stand voltage, the continuous current ii source transformer, short-circuit duty E Vmax rating, and the maximum voltage rating b. ------I ------ KI was determined using E/X amperes X V must be multiplied by the appropriate 2 o and 1.0 multiplying factor for X/R ratio correction factors below to obtain 1 of 15 or less and 1.25 multiplying See Table 6.0-1, Ta b 6 . modified ratings that must equal or factor for X/R ratios in the range of exceed the application requirements. 15 to 40. Refer to Table 1.4-4 below. 2 Where: Note: For assemblies containing vacuum I = Rated short-circuit current breakers at high altitudes, system voltage is not derated. 3 Vmax = Rated maximum voltage of the breaker Note: Intermediate values may be obtained by interpolation. V = Actual system voltage 4 o KI = Maximum symmetrical Table 1.4-3. Altitude Derating interrupting capacity Altitude in Correction Factor Feet (Meters) Current Voltage 5 c. E/X x 1.6 m rms closing and latching capability of the breaker 3300 (1006) (and below) 1.0 0 1.0 0 5000 (1524) 0.99 0.95 6 and/or 10,000 (3048) 0.96 0.80 m E/X x 2.7 Crest closing and Table 1.4-4. Application Quick Check Table latching capability of the breaker. 7 Source Operating Voltage The ANSI standards do not require the Transformer kV inclusion of resistances in the calcula- MVA Rating 8 tion of the required interrupting and Motor Load 2.4 4.16 6.6 12 13.8 close and latch capabilities. Thus the 100% 0% calculated values are conservative. 9 However, when the capabilities of 1 1.5 1.5 2 50VCP-W250 existing switchgear are investigated, 2 2.5 12 kA 50VCP-W250 150VCP-W500 150VCP-W500 150VCP-W500 the resistances should be included. 10 2.5 3 10.1 kA 23 kA 22.5 kA 19.6 kA For single line-to-ground faults, the 3 3.75 symmetrical interrupting capability 3.75 5 50VCP-W250 11 is 1.15 x the symmetrical interrupting 5 7. 5 36 kA 50VCP-W250 7. 5 10 50VCP-W350 33.2 kA capability at any operating voltage, 1 but not to exceed the maximum 10 10 49 kA 1 12 symmetrical capability of the breaker. 10 12 12 15 50VCP-W350 75VCP-W500 ANSI C37 provides further guidance for 46.9 kA 41.3 kA 13 medium voltage breaker application. 15 20 1 Reclosing Duty 20 20 Breaker Type and 150VCP-W750 150VCP-W750 symmetrical interrupting capacity 35 kA 30.4 kA ANSI Standard C37.010 indicates the 25 14 30 at the operating voltage reduction factors to use when circuit 1 breakers are used as reclosers. Eaton 50 150VCP-W1000 150VCP-W1000 VCP-W breakers are listed at 100% 46.3 kA 40.2 kA 15 1 rating factor for reclosing. Transformer impedance 6.5% or more, all other transformer impedances are 5.5% or more. 16

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.4-9 August 2017 Power System Analysis Sheet 01 049

Application of K >1 Breakers on a Symmetrical Current Rating Basis For Three-Phase Fault E i I  ----- Example 1—Fault Calculations 3-Phase X Given a circuit breaker interrupting and momentary rating in the table below, where X is ohms per phase and E is ii verify the adequacy of the ratings for a system without motor loads, as shown. the highest typical line-to-neutral Table 1.4-5. Short-Circuit Duty operating voltage or Ty p e V Max. Three-Phase Symmetrical Interrupting Capability Close and Latch or 1 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 ------(29) = 33.2 kA I 3 2 4.16 1 where X is per unit reactance LG symmetrical interrupting capability IB is base current — 36 kA 1.15 (33.2) = 38.2 kA I2 3 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 symmetrical interrupting capability Kl. 4 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 motor contribution to short circuit. 5 X System   9 (is less than 15) On 13.8 kV System, 3.75 MVA Base R 13.8 kV 6 3.75 MVA would use 1.0 multiplying factor for Z ==------0.01 pu or 1% 375 MVA short-circuit duty, therefore, short- X = 15 circuit duty is 8.6 kA sym. for three- 7 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 Available For Line-to-Ground Fault 8 Z 1 1 ------R 0.066% 3IB 2 266 15.03 3E ------X ILG  ------ 9 ------+ 1 2X + X 2X + X 2 1 0 1 0 13.8 kV R For this system, X0 is the zero sequence reactance of the transformer, which 10 3750 kVA X X ==-----R 15 (0.066) = .99% is equal to the transformer positive R sequence reactance and X1 is the posi- 11 Transformer Standard 5.5% Impedance tive sequence reactance of the system. has a ±7.5% Manufacturing Tolerance Therefore, 4.16 kV 12 5.50 Standard Impedance 3(0.52) –0.41 (–7.5% Tolerance) ILG 9.1 kA Sym. Transformer Z = 2(0.0604)+ 0.0505 50VPC-W250 5.09% 13 Using 1.0 multiplying factor (see Table 1.4-6), short-circuit duty = 9.1 kA Sym. LG (I2) 14 Answer

Figure 1.4-6. Example 1—One-Line Diagram The 50VCP-W250 breaker capabilities 15 exceed the duty requirements and From transformer losses per unit or may be applied. percent R is calculated 16 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% 3750 kVA the application. If we assume unlimited 17 24,200 Watts Load Losses short circuit available at 13.8 kV and that Trans. Z = X 2 2 2 2 Transformer X=== Z – R (5.09) – (0.65) 25.91– 0.42 25.48 18 IB 0.52 Then I ------9.5 kA Sym. 3-Phase X 0.055 X = 5.05% 19 X/R ratio 15 or less multiplying factor X R X/R is 1.0 for short-circuit duty. 13.8 kV System 0.99% 0.066% 15 20 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 or 0.0604 pu 0.00716 pu 9.5 x 1.6 kA = 15.2 kA (I3). 21

CA08104001E For more information, visit: www.eaton.com/consultants 1.4-10 Power Distribution Systems Power System Analysis August 2017 Sheet 01 050

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

XR X/R 3 13.8 kV System 0.628 (6.9) X = = 0.015 0.015 0.001 15 X X 21 (13.8) = 25 = 35 R R 4 Transformer 0.055 0.0055 10 2 3 197A FL 173A FL Total Source Transformer 0.070 pu 0.0065 pu 11 X''d = 20% X''d = 25% 5 3000 hp Synchronous Motor (0.628) 3000 hp X = 0.20 = 0.638 pu at 7.5 MVA Base 2500 hp 6 0.197 1.0 PF Syn. Ind. 2500 hp Ind. Motor 7 X = 0.25 (0.628) = 0.908 pu at 7.5 MVA Base 0.173 Figure 1.4-7. Example 2—One-Line Diagram

Source of Interrupting Momentary X X (1) 1 8 E IB 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 I1 Source Transformer = 8.971 = 8.971 11 = 157 9 Table 1.4-6. Multiplying Factor for E/X 0.070 0.070 0.070 0.628 0.628 25 Amperes (ANSI C37) I 3000 hp Syn. Motor = 0.656 = 0.984 25 = 39 2 (1.5) 0.638 0.638 0.638 System Type VCP-W Vacuum 10 0.628 0.628 35 X/R Circuit Breaker I3 2500 hp Ind. Motor = 0.461 = 0.691 35 = 39 Rated Interrupting Time, 5-Cycle (1.5) 0.908 0.908 0.908 Ty p e o f Fa u l t I3F = 10.088 10.647 Total 1/R = 235 11 or 10.1 kA x 1.6 Ratio Three- LG Three-Phase 17.0 kA Momentary Duty Phase and LG Source of Short Circuit 12 IB 0.628 Local Remote Total X ==------=0.062 I3F 10.1 1 1.0 0 1.0 0 1.0 0 1 13 15 1.0 0 1.0 0 1.0 0 X System ----- = 0.062 (235) = 14.5 is a Multiplying Factor of 1.0 from Table 1.4-6 20 1.0 0 1.02 1.05 R 25 1.0 0 1.06 1.10 30 1.04 1.10 1.13 14 Table 1.4-7. Short-Circuit Duty = 10.1 kA 36 1.06 1.14 1.17 40 1.08 1.16 1.22 Breaker V Three-Phase Symmetrical Interrupting Capability Close and Latch 45 1.12 1.19 1.25 Ty p e Max. at V Max. Max. KI at 6.9 kV Oper. Voltage or Momentary 15 50 1.13 1.22 1.27 55 1.14 1.25 1.30 75VCP-W500 8.25 kV 33 kA 41 kA 8.25 (33) = 39.5 kA 66 kA 60 1.16 1.26 1.32 6.9 16 65 1.17 1.28 1.33 150VCP-W500 15 kV 18 kA 23 kA 15 (18) (39.1) = 23 kA 37 kA 70 1.19 1.29 1.35 6.9 75 1.20 1.30 1.36 (But not to exceed KI) 17 80 1.21 1.31 1.37 85 — — 1.38 Answer 90 1.22 1.32 1.39 18 95 — — 1.40 Either breaker could be properly 100 1.23 1.33 1.41 applied, but price will make the type 100 1.24 1.34 1.42 150VCP-W500 the more economical 120 1.24 1.35 1.43 selection. 19 130 1.24 1.35 1.43 1 Where system X/R ratio is 15 or less, the 20 multiplying factor is 1.0.

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.4-11 August 2017 Power System Analysis Sheet 01 051

Example 3—Fault Calculations Medium-Voltage Fuses— i Check breaker application or generator bus for the system of generators shown. Fault Calculations Each generator is 7.5 MVA, 4.16 kV 1040 A full load, I = 1.04 kA B There are two basic types of medium ii Sub transient reactance Xd” = 11% or, X = 0.11 pu voltage fuses. The following definitions are taken from ANSI Standard C37.40. X Gen ----- ratio is 30 R Expulsion Fuse (Unit) 1 A vented fuse (unit) in which the 1 1 1 1 3 1 1 1 1 3 expulsion effect of the gases produced        and       2 by internal arcing, either alone or aided XS X X X X RS R R R R by other mechanisms, results in current interruption. 3 X X R XS ----- X or XS ----- and RS ---- Therefore, System ------Gen ----- 30 Current-Limiting Fuse (Unit) 3 3 R R R S A fuse unit that, when its current- responsive element is melted by a 4 Since generator neutral grounding reactors are used to limit the ILG to I3-phase or below, we need only check the I short-circuit duty. current within the fuse’s specified 3 current-limiting range, abruptly 5 introduces a high resistance to I I I 31B 3(1.04) B B B ------reduce current magnitude and IBPhase  ------+++------28.4 kA Symmetrical E/X amperes X X X X 0.11 duration, resulting in subsequent 6 current interruption. X System ----- of 30 is a Multiplying Factor of 1.04 from Table 1.4-6. R There are two classes of fuses; power and distribution. They are 7 Short-circuit duty is 28.4 (1.04) = 29.5 kA Symmetrical distinguished from each other by the current ratings and minimum Three-Phase Symmetrical Interrupting Capability melting type characteristics. 8 Breaker Type V Max. at V Max. Max. KI at 4.16 kV Oper. Voltage The current-limiting ability of a 50VCP-W250 4.76 kV 29 kA 36 kA 4.76 (29) = 33.2 kA 4.16 current-limiting fuse is specified by 9 its threshold ratio, peak let-through current and I2t characteristics. Answer 10 The 50VCP-W250 breaker could be applied. The use of a specific generator circuit Interrupting Ratings of Fuses breaker such as the Eaton VCP-WG should also be investigated. Modern fuses are rated in amperes rms symmetrical. They also have a 11 listed asymmetrical rms rating that is 1.6 x the symmetrical rating. Refer to ANSI/IEEE C37.48 for fuse 12 interrupting duty guidelines. Calculation of the Fuse Required 13 Interrupting Rating: Step 1—Convert the fault from G1 G2 G3 the utility to percent or per unit on 14 a convenient voltage and kVA base. Step 2—Collect the X and R data of all 15 the other circuit elements and convert to a percent or per unit on a convenient kVA and voltage base same as 16 4.16 kV that used in Step 1. Use the substran- sient X and R for all generators and motors. 17 Step 3—Construct the sequence networks using reactances and connect 18 properly for the type of fault under consideration and reduce to a single Figure 1.4-8. Example 3—One-Line Diagram equivalent reactance. 19

CA08104001E For more information, visit: www.eaton.com/consultants 1.4-12 Power Distribution Systems Power System Analysis August 2017 Sheet 01 052

Step 4—Construct the sequence Low-Voltage Power Circuit The multiplying factor MF can be i networks using resistances and calculated by the formula: connect properly for the type of Breakers—Fault Calculations –  X/R fault under consideration and reduce 2 1 2.718 ii to a single equivalent resistance. The steps for calculating the fault MF   current for the selection of a low 2.29 Step 5—Calculate the E/XI value, voltage power circuit breaker are If the X/R of system feeding the 1 where E is the prefault value of the the same as those used for medium breaker is not known, use X/R = 15. voltage at the point of fault normally voltage circuit breakers except that assumed 1.0 in pu. For three-phase where the connected loads to the low For fused breakers by the formula: 2 faults E/XI is the fault current to be voltage bus includes induction and used in determining the required synchronous motor loads. 12  2.718–2  X/R MF   interrupting capability of the fuse. 1.25 3 The assumption is made that in Note: It is not necessary to calculate a 208Y/120 V systems the contribution If the X/R of the system feeding the single phase-to-phase fault current. This from motors is two times the full load breaker is not known, use X/R = 20. current is very nearly3 /2 x three-phase current of the step-down transformer. 4 fault. The line-to-ground fault may exceed This corresponds to an assumed 50% Refer to Ta b l e 1. 4 - 8 for the standard the three-phase fault for fuses located in motor aggregate impedance on a kVA ranges of X/R and power factors used in generating stations with solidly grounded base equal to the transformer kVA testing and rating low voltage breakers. 5 neutral generators, or in delta-wye transformers with the wye solidly grounded, rating or 50% motor load. Refer to Ta b l e 1. 4 - 9 for the circuit where the sum of the positive and negative breaker interrupting rating derating For 480 V, 480Y/277 V and 600 V sys- factors to be used when the calculated sequence impedances on the high voltage tems, the assumption is made that the 6 side (delta) is smaller than the impedance of X/R ratio or power factor at the point the transformer. contribution from the motors is four the breaker is to be applied in the times the full load current of the step- power distribution system falls outside 7 For single line-to-ground fault: down transformer, which corresponds of the X/R or power factors used in test- to an assumed 25% aggregate motor X  X (+) ++X (–) X (0) ing and rating the circuit breakers. The I I I I impedance on a kVA base equal to derating factors shown in Table 1.4-9 8 the transformer kVA rating or 100% are the inverse of the MF (multiplying E motor load. factors) calculated above. These derat- If  ------ 3 XI In low voltage systems that contain ing factors are applied to the nameplate 9 generators, the subtransient reactance interrupting rating of the breaker to Step 6—Select a fuse whose should be used. indicate the device’s interrupting published interrupting rating capacity at the elevated X/R ratio. 10 exceeds the calculated fault current. The X/R ratio is calculated in the same manner as that for medium-voltage Figure 1.4-2 should be used where circuit breakers. If the X/R at the point 11 older fuses asymmetrically rated are of fault is greater than 6.6, a multiply- involved. ing factor (MF) must be applied. 12 The voltage rating of power fuses used The calculated symmetrical amperes on three-phase systems should equal should be multiplied by the multiply- or exceed the maximum line-to-line ing factor (MF) and compared to the 13 voltage rating of the system. Current nameplate rating to ensure the breaker limiting fuses for three-phase systems is applied within its rating. should be so applied that the fuse 14 voltage rating is equal to or less than 1.41 x nominal system voltage. 15

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.4-13 August 2017 Power System Analysis Sheet 01 053

Molded-Case Breakers and Low-Voltage Circuit Breaker i Insulated Case Circuit Interrupting Derating Factors Breakers—Fault Calculations Refer to Table 1.4-8 for the standard Established standard values include ii 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 1.4-9 for Table 1.4-8. Standard Test Power Factors circuit breakers. The calculated fault 1 the circuit breaker interrupting rating Interrupting Power Factor X/R Test current times the MF must be less than de-rating factors to be used when the Rating in kA Te s t R a n ge Range the breaker interrupting capacity. calculated X/R ratio or power factor Molded-Case Circuit Breaker Because molded case breakers are 2 at the point the breaker is to be applied tested at lower X/R ratios, the MFs are 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 different than those for low voltage outside of the Table 1.4-8 X/R or power Over 20 0.15–0.20 6.6–4.9 power circuit breakers. 3 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 Normally the short-circuit power factor 4 MF  ------For distribution systems where the X or X/R ratio of a distribution system 1 calculated short-circuit current X/R –    need not be considered in applying 1+ 2.718 R1 ratio differs from the standard values low voltage circuit breakers. This is 5 given in the above table, circuit breaker because the ratings established in X1 /R1 = test X/R value interrupting rating derating factors from the applicable standard are based Table 1.4-9 table should be applied. 6 X /R = X/R at point where breaker on power factor values that amply 2 2 is applied cover most applications. 7 Table 1.4-9. Circuit Breaker Interrupting Rating Derating Factors % P.F. X/R Interrupting Rating Molded Case or Insulated Case Power Circuit Breaker 8 >10 kA m m L / = 10 kA / = 20 kA 20 kA Unfused Fused 9 50 1.73 1.000 1.000 1.0 0 0 1.0 0 0 1.000 30 3.18 0.847 1.000 1.0 0 0 1.0 0 0 1.000 25 3.87 0.805 0.950 1.0 0 0 1.0 0 0 1.000 10 20 4.90 0.762 0.899 1.0 0 0 1.0 0 0 1.000 15 6.59 0.718 0.847 0.942 1.0 0 0 0.939 12 8.27 0.691 0.815 0.907 0.962 0.898 11 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 7 14.25 0.645 0.761 0.847 0.899 0.827 12 5 19.97 0.627 0.740 0.823 0.874 0.797 Note: These are derating factors applied to the breaker and are the inverse of MF. 13

CA08104001E For more information, visit: www.eaton.com/consultants 1.4-14 Power Distribution Systems Power System Analysis August 2017 Sheet 01 054

i Short-Circuit Calculations Determination of Short-Circuit Current ii Note 1: Transformer impedance generally relates to self-ventilated rating (e.g., with ONAN/ONAF/OFAF transformer use OA base). Note 2: kV refers to line-to-line voltage in kilovolts. Note 3: Z refers to line-to-neutral impedance of system to fault where R + jX = Z. 1 Note 4: When totaling the components of system Z, arithmetic combining of impedances as “ohms Z”. “per unit Z”. etc., is considered a 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).

2 1. Select convenient kVA base for system to 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 3 one kVA base to another: 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) 5 (b) % impedance = % Z =  kV 2 10 (% impedance)kV 2 (10) (c) Ohms impedance =  6 kVA base

4. Change power-source impedance to per unit (a) —if utility fault capacity given in kVA 7 or percent impedance on kVA base as selected for this study: kVA base in study Per-unit impedance = pu Z = ------power-source kVA fault capacity 8 (b) —if utility fault capacity given in rms symmetrical short circuit amperes

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

5. Change motor rating to kVA: (a) —motor kVA —3 (kV) (I) where I = motor nameplate full-load amperes 10 (b) —if 1.0 power factor synchronous motorkVA = (0.8) (hp) (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 12 (b) Per unit ISC =  puZ

13 (c) rms Symmetrical current = ISC = (pu ISC) (IBase Amperes) Three-phase KVA base Single-phase kVA base (d) rms Symmetrical current = Amperes = ------or ------14 puZ 3 kV puZ kV (Three-phase kVA base) (100) Single-phase kVA base (100) (e) = ------or ------(%Z)3 kV (%Z) kV (kV) (1000) 15 (g) = ------3 (ohms Z) kVA base (kVA base) (100) kV 2 1000 7. Determine symmetrical short-circuit kVA: (a) Symmetrical short-circuit kVA = ------==------16 puZ %Z ohms Z 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 18 unit (i.e., 3 x 75 kVA = 225 kVA, Z = 2%). (c) —from single-phase transformer—see Page 1.4-16.

19 (a) —synchronous motor—5 times motor full load current (impedance 20%) 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: 20 —on 208Y/120 V systems—2.0 times transformer full-load current —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) 21 —In industrial plants, 4.0 times transformer full-load current (100% motor load)

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.4-15 August 2017 Power System Analysis Sheet 01 055

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 3 Switchboard Fault 1000 kV A 5.75% 480V Cables 4 Cable Fault Switchboard Fault

F1 Zm 5 Zu 0.002 pu Zm 1.00 pu Zm 1.00 pu 1.00 pu 100 ft (30m) 3–350 kcmil Cable Z in Steel Conduit c 6 ABC 0.0575 pu Zc 0.027 pu Zc 0.027 pu 0.027 pu Switchboard Fault Zequiv Mixed Load—Motors and Lighting F1 Each Feeder—100 ft (30m) of 3–350 kcmil 7 Cable in Steel Conduit Feeding Lighting and Zc 0.027 pu 250 kVA of Motors Cable Fault F2 F2 8 Cable Fault Combining Series Impedances: ZTOTAL = Z1 + Z2 + ... +Zn C. Conductor impedance from Ta b l e 1. 11- 6 . 1 1 1 1 Combining Parallel Impedances: = + + ... 9 Conductors: 3–350 kcmil copper, single Z Z Z Z conductors Circuit length: 100 ft TOTAL 1 2 n (30 m), in steel (magnetic) conduit 10 Impedance 0.0777 pu Z = 0.0617 ohms/ 1,000 ft (304.8 m). 0.0595 pu 0.342 pu 0.0507 pu Z = 0.00617 ohms (100 circuit feet) Es TOT F1 F1 11 D. Fault current calculations (combining 0.027 pu 0.027 pu impedances arithmetically, using approximate “Short Cut” method—see Note 4, F2 12 Page 1.4-14)

Equation 13 Step (See) Calculation 1 – Select 1000 kVA as most convenient base, since all data except utility source is on secondary of 1000 kVA transformer. 14 kVA base 1000 24(a)Zu Utility per unit impedance Z == ------==------0.002 pu pu utility fault kVA 500.000 15 %Z 5.75 33(a)ZT Transformer per unit impedance = Z ==------=0.0575 pu pu 100 100

4 4(a) and Z Motor contribution per unit impedance = Z = kVA base ==1000 1.00 pu 16 m pu ------9(c) 4 x motor kVA 4 x 250

53(a)Zc Cable impedance in ohms (see above) = 0.00619 ohms 17 (ohms)(kVA base) (0.00619)(1000) Cable impedance per unit = Z ===------0.027pu pu 2 2 (kV) (1000) (0.480) (1000) 18

66(d)F1 Total impedance to switchboard fault = 0.0507 pu (see diagram above) 3-phase kVA base 1000 Symmetrical short circuit current at switchboard fault =  == 23,720 amperes rms 19 Z 3 kV 0.0507 3 0.480 pu 76(d)F2 Total impedance to cable fault = 0.0777 pu (see diagram above) 20 3-phase kVA base 1000 Symmetrical short circuit current at cable fault =  == 15, 480 amperes rms Z 3 kV 0.0777 3 0.480 pu 21 Figure 1.4-9. Example Number 1

CA08104001E For more information, visit: www.eaton.com/consultants 1.4-16 Power Distribution Systems Power System Analysis August 2017 Sheet 01 056

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

ii A. System Diagram Deriving Transformer R and X: R = 0.1498 Z X 480 V Three-Phase Switchboard Bus at 50,000 A Symmetrical, X/R = 6.6 {X = 0.9887 Z   6.6 X = 6.6 R 1 R 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 2 { Z R =  R = 0.1498Z 6.6753 75 kVA Single-Phase 480–120/240 V; Z = 2.8%, R = 1.64%, X = 2.27% 3 X = 6.6R X = 0.9887Z

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

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

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

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

RTotal = 0.02371 XTotal = 0.02958 RTotal = 0.03191 XTotal = 0.03408 F F F F 8 1 1 2 2 D. Impedance and Fault Current Calculations—75 kVA Base Note: To account for the outgoing and return paths of single-phase circuits (conductors, 9 systems, etc.) use twice the three-phase values of R and X. 75 Z 0.0018 (From Page 1.4-14 R = 2 (0.1498 x Z ) = 0.00054 pu Syst    pu Syst SYST 10 3 0.480  50,000 Formula 4(b) ) XSyst = 2 (0.9887 x ZSYST) = 0.00356 pu ohms kVA Base 0.0104 75 Z =  (From Page 1.4-14 R = 2  = 0.00677 pu Cond 2 Cond 2 11 kV  1000 Formula 3(a) ) 0.48  1000 0.0051 75 X = 2  = 0.00332 pu Cond 2 0.48  1000 1.64 12 Full-winding of Transformer (75 kVA Base) R =  = 0.0164 pu Tfmr 100 2.27 X =  = 0.0277 pu 13 Tfmr 100 1.64 Half-winding of Transformer (75 kVA Base) R = 1.5  = 0.0246 pu Tfmr 100 14 2.27 X = 1.2  = 0.0272 pu Tfmr 100

2 2 15 Impedance to Fault F1—Full Winding Z = 0.02371 + 0.02958 = 0.03791 pu 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 16 Short circuit current F2 = 75 ÷ (0.04669 x 0.120 kV) = 13,386 A Symmetrical Figure 1.4-10. Example Number 2 17 Shortcut Method—End of Cable 277 V/30,000 A = 0.00923 ohms Next, 277 V/0.01196 ohms = 23,160 A (source impedance) rms at load side of conductors This method uses the approximation 18 of adding Zs instead of the accurate Conductor ohms for 500 kcmil X 30,000 A available method of Rs and Xs. conductor from Ta b l e 1. 11- 6 in magnetic conduit is 0.00551 ohms For Example: For a 480/277 V system 100 ft (30 m) 19 per 100 ft (30 m). For 100 ft (30 m) and 2–500 kcmil per phase with 30,000 A symmetrical available two conductors per phase we have: at the line side of a conductor run of XIf = 23,160 A 20 100 ft (30 m) of 2–500 kcmil per phase 0.00551/2 = 0.00273 ohms (conductor and neutral, the approximate fault current impedance) Figure 1.4-11. Short-Circuit Diagram 21 at the load side end of the conductors Add source and conductor impedance or can be calculated as follows. 0.00923 + 0.00273 = 0.01196 total ohms

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.4-17 August 2017 Power System Analysis Sheet 01 057

Determining X and R Values Voltage Drop Considerations Voltage variation in such areas should be held to 2 or 3% under motor-starting i from Transformer Loss Data The first consideration for voltage or other transient conditions. drop is that under the steady-state Method 1: conditions of normal load, the voltage Computer Equipment: With the ii Given a 500 kVA, 5.5% Z transformer at the utilization equipment must be proliferation of data-processing and with 9000W total loss; 1700W no-load adequate. Fine-print notes in the NEC computer- or microprocessor-controlled loss; 7300W load loss and primary recommend sizing feeders and branch manufacturing, the sensitivity of 1 voltage of 480 V. circuits so that the maximum voltage computers to voltage has become an drop in either does not exceed 3%, important consideration. Severe dips of Watts Load Loss = 3 x (I2 x R) with the total voltage drop for feeders short duration can cause a computer 2 and branch circuits not to exceed 5%, to “crash”—shut down completely, 2 500 for efficiency of operation. (Fine print and other voltage transients caused 3    R= 7300 W 3 0.480 notes in the NEC are not mandatory.) by starting and stopping motors can 3 cause data-processing errors. While R = 0.0067 ohms Local energy codes as well as the voltage drops must be held to a mini- standards for high performance mum, in many cases computers will 0.0067 500 green buildings should be referenced 4 %R = = 1.46% require special power-conditioning 2 10 0.48 to determine any additional project equipment to operate properly. related voltage drop requirements. 2 2 5 %X = 5.5 – 1.46 = 5.30% Industrial Plants: Where large motors In addition to steady-state conditions, exist, and unit substation transformers voltage drop under transient condi- Method 2: are relatively limited in capacity, tions, with sudden high-current, short- 6 Using same values above. voltage dips of as much as 20% may time loads, must be considered. The be permissible if they do not occur too 2 most common loads of this type are I R Losses frequently. Lighting is often supplied %R =  motor inrush currents during starting. 7 10 kVA from separate transformers, and is These loads cause a voltage dip on minimally affected by voltage dips in 7300 the system as a result of the voltage  = 1.46 the power systems. However, it is 10 500 drop in conductors, transformers and usually best to limit dips to between 8 generators under the high current. 2 2 5 and 10% at most. %X= 5.5 – 1.46 = 5.30% This voltage dip can have numerous adverse effects on equipment in the One critical consideration is that 9 system, and equipment and conduc- a large voltage dip can cause a How to Estimate Short-Circuit tors must be designed and sized to dropout (opening) of magnetic Currents at Transformer Secondaries: minimize these problems. In many motor contactors and control relays. 10 cases, reduced-voltage starting of The actual dropout voltage varies Method 1: motors to reduce inrush current considerably among starters of To obtain three-phase rms symmetrical will be necessary. different manufacturers. 11 short-circuit current available at transformer secondary terminals, Recommended Limits of The only standard that exists is that of use the formula: NEMA, which states that a starter must 12 Voltage Variation not drop out at 85% of its nominal coil 100 I = I  ------General Illumination: Flicker in voltage, allowing only a 15% dip. SC FLC %Z incandescent lighting from voltage While most starters will tolerate con- 13 where %Z is the transformer impedance dip can be severe; lumen output drops siderably more voltage dip before in percent, from Ta b l e s 1. 11- 6 through about three times as much as the dropping out, limiting dip to 15% is the 1.11-11, Page 1.11-11. voltage dips. That is, a 10% drop in only way to ensure continuity of oper- 14 voltage will result in a 30% drop in ation in all cases. This is the maximum three-phase sym- light output. While the lumen output X-Ray Equipment: Medical x-ray and metrical bolted-fault current, assuming drop in fluorescent lamps is roughly 15 similar diagnostic equipment, such as sustained primary voltage during fault, proportional to voltage drop, if the CAT-scanners, are extremely sensitive i.e., an infinite or unlimited primary voltage dips about 25%, the lamp will to low voltage. They present a small, power source (zero source impedance). go out momentarily and then restrike. 16 Because the power source must steady load to the system until the always have some impedance, this For high-intensity discharge (HID) instant the x-ray tube is “fired.” This is a conservative value; actual fault lamps such as mercury vapor, high- presents a brief but extremely high 17 current will be somewhat less. pressure sodium or metal halide, if the instantaneous momentary load. lamp goes out because of an excessive In some modern x-ray equipment, Note: This will not include motor short- voltage dip, it will not restrike until it the firing is repeated rapidly to 18 circuit contribution. has cooled. This will require several create multiple images. The voltage minutes. These lighting flicker effects regulation must be maintained within Method 2: can be annoying, and in the case of the manufacturer’s limits, usually 2 to 19 Refer to Ta b l e 1. 7- 7 in the Reference HID lamps, sometimes serious. section, and use appropriate row of 3%, under these momentary loads, data based on transformer kVA and In areas where close work is being to ensure proper x-ray exposure. 20 primary short-circuit current available. done, such as drafting rooms, precision This will yield more accurate results assembly plants, and the like, even and allow for including motor short- a slight variation, if repeated, can be 21 circuit contribution. very annoying, and reduce efficiency.

CA08104001E For more information, visit: www.eaton.com/consultants 1.4-18 Power Distribution Systems Power System Analysis August 2017 Sheet 01 058

Motor Starting Engine Generator Systems In other words, a NEMA design C motor i With an engine generator as the with an autotransformer would have a Motor inrush on starting must be limited starting torque of approximately full- to minimize voltage dips. Ta b l e 1. 4 - 10 source of power, the type of starter that will limit the inrush depends on load (see Ta b l e 1. 4 - 10 ) whereas the ii on the next page will help select the NEMA design D motor under the same proper type of motor starter for various the characteristics of the generator. Although automatic voltage regulators conditions would have a starting torque motors, and to select generators of of approximately 1-1/2 times full-load. 1 adequate size to limit voltage dip. are usually used with all AC engine- See Ta b 2 9 for additional data on generators, the initial dip in voltage is Note: If a resistance starter were used for reduced voltage motor starting. caused by the inherent regulation of the same motor terminal voltage, the the generator and occurs too rapidly starting torque would be the same as that 2 Utility Systems for the voltage regulator to respond. obtained with autotransformer type, but the Where the power is supplied by a utility It will occur whether or not a regulator starting current would be higher, as shown. network, the motor inrush can be is installed. 3 Shortcut Method assumed to be small compared to the Consequently, the percent of initial system capacity, and voltage at the voltage drop depends on the ratio of The last column in Ta b l e 1. 4 - 10 has 4 source can be assumed to be constant the starting kVA taken by the motor to been worked out to simplify checking. during motor starting. Voltage dips the generator capacity, the inherent The figures were obtained by using resulting from motor starting can be regulation of the generator, the the formula above and assuming 5 calculated on the basis of the voltage power-factor of the load thrown on 1 kVA generator capacity and 1% drop in the conductors between the the generator, and the percentage voltage drop. power source and the motor resulting load carried by the generator. 6 from the inrush current. Example: A standard 80% power-factor engine- Assuming a project having a Where the utility system is limited, the type generator (which would be 1000 kVA generator, where the 7 utility will often specify the maximum used where power is to be supplied voltage variation must not exceed permissible inrush current or the to motor loads) has an inherent 10%. Can a 75 hp, 1750 rpm, 220 V, maximum hp motor they will permit regulation of approximately 40% three-phase, squirrel-cage motor be 8 to be started across-the-line. from no-load to full-load. This means started without objectionable lamp Transformer Considerations that a 50% variation in load would flicker (or 10% voltage drop)? cause approximately 20% variation If the power source is a transformer, in voltage (50% x 40% = 20%). From tables in the circuit protective 9 and the inrush kVA or current of the devices reference section, the full-load motor being started is a small portion Assume that a 100 kVA, 80% PF amperes of this size and type of motor of the full-rated kVA or current of the engine-type generator is supplying is 158 A. To convert to same basis as 10 transformer, the transformer voltage dip the power and that the voltage drop the last column, 158 A must be divided will be small and may be ignored. As should not exceed 10%. Can a 7-1/2 hp, by the generator capacity and % the motor inrush becomes a significant 220 V, 1750 rpm, three-phase, squirrel- voltage drop, or: 11 percentage of the transformer full-load cage motor be started without rating, an estimate of the transformer exceeding this voltage drop? 158 = 0.0158 A per kVA voltage drop must be added to the 1000 x 10 per 1% voltage drop 12 Starting current (%F.L.) = conductor voltage drop to obtain the Checking against the table, 0.0158 falls total voltage drop to the motor. Percent voltage drop gen. kVA  1000 within the 0.0170–0.0146 range for a  13 Accurate voltage drop calculation F.L. amperes volts  3  reg. of gen. NEMA A with an autotransformer would be complex and depend upon starter. This indicates that a general- transformer and conductor resistance, From the nameplate data on the motor, purpose motor with autotransformer 14 reactance and impedance, as well as the full-load amperes of a 7-1/2 hp. starting can be used. motor inrush current and power factor. 220 V, 1750 rpm, three-phase, squirrel- Note: Designers may obtain calculated However, an approximation can be cage motor is 19.0 A. Therefore: information from engine generator 15 made on the basis of the low power- manufacturers. factor motor inrush current (30–40%) Starting current (%F.L.) = and impedance of the transformer. 10 100  1000 The calculation results in conservative 16   3.45 or 345%. results. The engineer should provide 19.0 220 3 0.40    to the engine-generator vendor the For example, if a 480 V transformer From Table 1.4-10, a NEMA design C or starting kVA of all motors connected 17 has an impedance of 5%, and the NEMA design B motor with an autotrans- to the generator and their starting motor inrush current is 25% of the former starter gives approximately this sequence. The engineer should also transformer full-load current (FLC), starting ratio. It could also be obtained specify the maximum allowable drop. 18 then the worst case voltage drop will from a properly set solid-state adjust- The engineer should request that the be 0.25 x 5%, or 1.25%. able reduced voltage starter. engine-generator vendor consider the proper generator size when closed- 19 The allowable motor inrush current is The choice will depend upon the transition autotransformer reduced determined by the total permissible torque requirements of the load voltage starters, and soft-start solid- voltage drop in transformer and since the use of an autotransformer state starter are used; so the most 20 conductors. starter reduces the starting torque in economical method of installation direct proportion to the reduction in is obtained. 21 starting current.

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.4-19 August 2017 Power System Analysis Sheet 01 059

Table 1.4-10. 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. Voltage Drop Formulas If the receiving end voltage, load current and power factor 7 (PF) are known. Approximate Method 2 2 8 Voltage Drop EVD = ERcos + IR + ERsin + IX – ER E = IR cos + IX sin VD ER is the receiving end voltage. 9 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 10 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 11 are known. R or 2 2 E = E ++IR cos IX sin – E – IX cos – IR sin 12 VD S S 2 2 2 ZMVAR E E += ------– 2ZMVA cos– where: R S 2 S S ES 13 EVD = Voltage drop, line-to-neutral, volts where: ES = Source voltage, line-to-neutral, volts 14 ER = Receiving line-line voltage in kV I = Line (Load) current, amperes ES = Sending line-line voltage in kV R = Circuit (branch, feeder) resistance, ohms 15 MVAR = Receiving three-phase mVA X = Circuit (branch, feeder) reactance, ohms MVAS = Sending three-phase mVA cos = Power factor of load, decimal 16 Z = Impedance between and receiving ends sin = Reactive factor of load, decimal  = The angle of impedance Z 17 R = Receiving end PF S = Sending end PF, positive when lagging 18

CA08104001E For more information, visit: www.eaton.com/consultants 1.4-20 Power Distribution Systems Power System Analysis August 2017 Sheet 01 060

Voltage Drop Table 1.4-11. Temperature Correction Factors To select minimum conductor size: i for Voltage Drop 1. Determine maximum desired Voltage Drop Tables Conductor Percent Correction voltage drop, in volts. Size Power Factors % ii Note: Busway voltage drop tables are 2. Divide voltage drop by 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. 1 Tables for calculating voltage drop for No. 2 to 3/0 5.0 4.2 3.7 3.5 3.2 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, 2 for type of conductor, conduit and appear on Page 1.4-13. These tables Calculations power factor. Read conductor size give voltage drop per ampere per for that value. 3 100 ft (30 m) of circuit length. The To calculate voltage drop: 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 4 regardless of the number of conductors. get ampere-feet. Circuit length is molded case breakers and fusible 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 5 conditions: rating. 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 6 value in tables. Result is voltage A three-phase, four-wire lighting 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 7 and high power factors. Actual Example: 90% PF. It is desired to use aluminum 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 8 sizes and lower power factors. fed by three 2/0 copper conductors in voltage drop to 2% phase-to-phase? 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 9 three-phase, four-wire 60 Hz in the feeder? What is the percentage voltage drop? 2. 4.16 = 0.0000951 circuits. For other circuits, multiply 175 250 10 voltage drop given in the tables by 1. 124 A x 150 ft (46 m) = 18,600 A-ft the following correction factors: 3. 0.0000951 100= 0.00951 2. Divided by 100 = 186 11 Three-phase, four-wire, 4. In table, under aluminum conduc- 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 12 Single-phase, three-wire, 186 x 0.0187 = 3.48 V drop 0.0091. Conductor required is 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 13 4. Conclusion: 0.76% voltage drop voltage drop would be excessive.) 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 14 used for conductor temperatures voltage drop of 3% or less on a between 60 °C and 90 °C with feeder is acceptable.) reasonable accuracy (within ±5%). 15 However, correction factors in Table 1.4-11 can be applied if desired. The values in the table are 16 in percent of total voltage drop. For conductor temperature of 60 °C– 17 SUBTRACT the percentage from Table 1.4-11. For conductor temperature of 90 °C– 18 ADD the percentage from Table 1.4-11.

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.4-21 August 2017 Power System Analysis Sheet 01 061

Table 1.4-12. Voltage Drop—Volts per Ampere per 100 Feet (30 m); Three-Phase, Phase-to-Phase Conductor Size Magnetic Conduit (Steel) Nonmagnetic Conduit (Aluminum or Nonmetallic) i AWG Load Power Factor, % Load Power Factor, % or kcmil 60 70 80 90 100 60 70 80 90 100 ii Copper Conductors 14 0.3390 0.3910 0.4430 0.4940 0.5410 0.3370 0.3900 0.4410 0.4930 0.5410 12 0.2170 0.2490 0.2810 0.3130 0.3410 0.2150 0.2480 0.2800 0.3120 0.3410 1 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 6 0.0595 0.0670 0.0742 0.0809 0.0850 0.0579 0.0656 0.0730 0.0800 0.0849 2 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 1/0 0.0198 0.0211 0.0222 0.0229 0.0213 0.0183 0.0198 0.0211 0.0220 0.0211 3 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 4/0 0.0130 0.0134 0.0136 0.0133 0.0109 0.0116 0.0121 0.0124 0.0124 0.0107 4 250 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 350 0.0104 0.0104 0.0102 0.0096 0.0069 0.0090 0.0091 0.0091 0.0087 0.0066 5 500 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 750 0.0084 0.0081 0.0077 0.0069 0.0040 0.0069 0.0067 0.0064 0.0058 0.0035 6 1000 0.0080 0.0077 0.0072 0.0063 0.0035 0.0064 0.0062 0.0058 0.0052 0.0029 Aluminum Conductors 12 0.3296 0.3811 0.4349 0.4848 0.5330 0.3312 0.3802 0.4328 0.4848 0.5331 7 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 6 0.0898 0.1018 0.1142 0.1254 0.1349 0.0887 0.1011 0.1127 0.1249 0.1361 8 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 1 0.0332 0.0357 0.0396 0.0423 0.0428 0.0318 0.0349 0.0391 0.0411 0.0428 9 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 4/0 0.0172 0.0174 0.0179 0.0177 0.0170 0.0152 0.0159 0.0171 0.0179 0.0172 10 250 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 350 0.0130 0.0133 0.0128 0.0131 0.0100 0.0122 0.0123 0.0119 0.0120 0.0101 11 500 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 750 0.0095 0.0094 0.0090 0.0084 0.0056 0.0081 0.0080 0.0078 0.0072 0.0051 12 1000 0.0085 0.0082 0.0078 0.0071 0.0043 0.0069 0.0068 0.0065 0.0058 0.0038 13

CA08104001E For more information, visit: www.eaton.com/consultants 1.4-22 Power Distribution Systems August 2017 Sheet 01 062

This page intentionally left blank. i ii

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.5-1 August 2017 System Protection Considerations Sheet 01 063

Overcurrent Protection To study and accomplish ■ Understanding of operating charac- coordination requires: teristics and available adjustments i and Coordination of each protective device ■ A one-line diagram, the roadmap ■ Overcurrents in a power distribution of the power distribution system, Any special overcurrent protection ii system can occur as a result of both showing all protective devices and requirements including utility normal (motor starting, transformer the major or important distribution limitations; refer to Figure 1.5-1 inrush, etc.) and abnormal (overloads, and utilization apparatus To ensure complete coordination, the 1 ground fault, line-to-line fault, etc.) ■ Identification of desired degrees time-trip characteristics of all devices conditions. In either case, the funda- of power continuity or criticality of in series should be plotted on a single mental purposes of current-sensing loads throughout system sheet of standard log-log paper. 2 protective devices are to detect the ■ Definition of operating-current Devices of different-voltage systems abnormal overcurrent and with proper characteristics (normal, peak, can be plotted on the same sheet by coordination, to operate selectively starting) of each utilization circuit converting their current scales, using 3 to protect equipment, property the voltage ratios, to the same voltage- and personnel while minimizing the ■ Equipment damage or withstand characteristics basis. Such a coordination plot is outage of the remainder of the system. shown in Figure 1.5-1. 4 ■ Calculation of maximum short- With the increase in electric power circuit currents (and ground fault consumption over the past few decades, currents if ground fault protection 5 dependence on the continued supply of is included) available at each this power has also increased so that the protective device location direct costs of power outages have risen significantly. Power outages can create 6 dangerous and unsafe conditions as a SCALE X 100 = CURRENT IN AMPERES AT 480V result of failure of lighting, elevators,

.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 1000 1000 7 ventilation, fire pumps, security 900 900 800 4.16 kV 250 MVA 800 700 700 systems, communications systems, 600 600 and the like. In addition, economic loss 500 500 from outages can be extremely high 400 400 8 300 B 300 as a result of computer downtime, or, A D especially in industrial process plants, 200 200 C 9 interruption of production. D 100 250A 100 90 90 80 1000 80 Protective equipment must be 70 70 60 kVA 4,160V Δ adjusted and maintained in order 5.75% 60 10 50 480/277V 50 to function properly when an over- 40 40 ANSI Three-Phase 19,600A current occurs. Coordination, however, 30 Thru Fault 30 Protection Curve begins during power system design 20 (More Than 10 in C 1,600A 20 11 with the knowledgeable analysis and Lifetime) 24,400A selection and application of each over- 10 B 10 9 600A 9 current protective device in the series 8 8 12 7 7 M TIME IN SECONDS circuit from the power source(s) to 6 6 5 5 20,000A each load apparatus. 4 4

3 3 13 The objective of coordination is to A 175A 2 B C 2

localize the overcurrent disturbance TIME IN SECONDS so that the protective device closest 14 1 1 to the fault on the power-source side .9 .9 .8 100 hp – .8 .7 M 124A FLC .7 has the first chance to operate. Each .6 .6 preceding protective device upstream .5 .5 15 .4 X = Available fault current .4 toward the power source should be including motor .3 contribution. .3 capable, within its designed settings Ground of current and time, to provide backup .2 Fault Trip .2 C 16 and de-energize the circuit if the fault .1 .1 persists. Sensitivity of coordination is .09 .09 .08 .08 .07 .07 the degree to which the protective Transformer 17 .06 B .06 devices can minimize the damage .05 Inrush .05 to the faulted equipment. .04 .04 .03 .03 A 18 .02 .02 M a x. Three-Ph se 4.16 kV F a ult 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 19 100 200 300 400 500 600 700 800 9 00 1000 2000 3000 4000 5000 6000 7000 8000 9 000 10,000 SCALE X 100 = CURRENT IN AMPERES AT 480V

Figure 1.5-1. Time-Current Characteristic Curves for Typical Power Distribution System 20 Protective Devices Coordination Analysis 21

CA08104001E For more information, visit: www.eaton.com/consultants 1.5-2 Power Distribution Systems System Protection Considerations August 2017 Sheet 01 064 Protection and Coordination

In this manner, primary fuses and However, the primary (high voltage) If perfect coordination is not feasible, i circuit breaker relays on the primary side fault is the same as if the secondary then lack of coordination should be side of a substation transformer can fault was a three-phase fault. limited to the smallest part of the system. be coordinated with the low voltage ii breakers. Transformer damage points, Therefore in coordination studies, the Application data is available for all based on ANSI standards, and low knee of the short-time pickup setting protective equipment to permit systems voltage cable heating limits can also on the secondary breaker should be to be designed for adequate overcurrent 1 be plotted on this set of curves to multiplied by protection and coordination. ensure that apparatus limitations are ■ For circuit breakers of all types, time- 1 or 1.1547 not exceeded. 0.866 current curves permit selection of 2 instantaneous and inverse-time trips Ground-fault curves may also be before it is compared to the minimum ■ For more complex circuit breakers, included in the coordination study melting time of the upstream primary with solid-state trip units, trip curves 3 if ground-fault protection is provided, fuse curve. In the example shown, include long- and short-time delays, but care must be used in interpreting the knee is at 4000 A 30 sec., and the as well as ground-fault tripping, their meaning. 30-sec. trip time should be compared to with a wide range of settings and 4 the MMT (minimum melt time) of the Standard definitions have been features to provide selectivity and fuse curve at 4000 x 1.1547 = 4619 A. established for overcurrent protective coordination devices covering ratings, operation In this case, there is adequate clearance 5 to the fuse curve. ■ For current-limiting circuit breakers, and application systems. Referring fuses, and circuit breakers with to Figure 1.5-1, the Single Line In the example shown, the ANSI integral fuses, not only are time- 6 Diagram references the below three-phase through fault transformer current characteristic curves defined equipment. protection curve must be multiplied available, but also data on current- M—Motor (100 hp). Dashed line shows by 0.577 and replotted in order to limiting performance and protection 7 initial inrush current, starting current determine the protection given by for downstream devices the primary for a single line to ground during 9-sec. acceleration, and drop to In a fully rated system, all circuit 124 A normal running current, all well fault in the secondary. 8 breakers must have an interrupting below CBA trip curve. Maximum 480 V three-phase fault capacity adequate for the maximum A—CB (175 A) coordinates selectively indicated on the horizontal current axis. available fault current at their point of 9 with motor M on starting and running application. All breakers are equipped Maximum 4160 V three-phase fault with long-time-delay (and possibly and with all upstream devices, except indicated, converted to 480 V basis. that CB B will trip first on low level short delay) and instantaneous over- ground faults. 4160 current trip devices. A main breaker 10 I I   480V 4160V 480 may have short time-delay tripping to B—CB (600 A) coordinates selectively allow a feeder breaker to isolate the 11 with all upstream and downstream The ANSI protection curves are fault while power is maintained to all devices, except will trip before A on specified in ANSI C57.109 for liquid- the remaining feeders. limited ground faults, since A has no filled transformers and C57.12.59 for ground fault trips. dry-type transformers. A selective or fully coordinated system 12 permits maximum service continuity. C—Main CB (1600 A) coordinates Illustrative examples such as shown The tripping characteristics of each selectively with all downstream here start the coordination study from overcurrent device in the system must 13 devices and with primary fuse D, the lowest rated device proceeding be selected and set so that the breaker for all faults on load side of CB. upstream. In practice, the setting or nearest the fault opens to isolate the faulted circuit, while all other breakers D—Primary fuse (250 A, 4160 V) coor- rating of the utility’s protective device 14 remain closed, continuing power to dinates selectively with all secondary sets the upper limit. Even in cases the entire unfaulted part of the system. protective devices. Curve converted to where the customer owns the medium voltage or higher distribution system, 15 480 V basis. Clears transformer inrush The 2014 edition of the National point (12 x FLC for 0.1 sec.), indicating the setting or rating of the lowest set protective device at the source deter- Electrical Code contains specific that fuse will not blow on inrush. requirements for designing certain Fuse is underneath right-half of ANSI mines the settings of the downstream 16 devices and the coordination. circuits with selective coordination. three-phase withstand curve, indicating Article 100 defines selective coordina- fuse will protect transformer for high- Therefore the coordination study tion: Coordination (Selective), the 17 magnitude faults up to ANSI rating. should start at the present setting following definition: “Localization of an overcurrent condition to restrict Delta-wye transformer secondary or rating of the upstream device and outages to the circuit or equipment side short circuit is not reflected to work toward the lowest rated device. If 18 affected, accomplished by the selec- the primary by the following relation this procedure results in unacceptable tion and installation of overcurrent for L-L and L-G faults. settings, the setting or rating of the upstream device should be reviewed. protective devices and their ratings or 19 settings for the full range of available VS Where the utility is the sole source, I   I overcurrents, from overload to the P V S they should be consulted. Where the P owner has its own medium or higher maximum available fault current, 20 voltage distribution, the settings or and for the full range of overcurrent For line-to-line fault, the secondary ratings of all upstream devices should protective device opening times (low voltage) side fault current is be checked. associated with those overcurrents.” 21 0.866 x I three-phase fault current.

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.5-3 August 2017 System Protection Considerations Sheet 01 065 Protection and Coordination

Article 620.62 (elevators, dumbwaiters, In general for systems such as shown B. Devices Rated 800 A or Less. The escalators, moving walks, wheelchair in Figure 1.5-1: next higher standard overcurrent i lifts, and stairway chair lifts) requires device rating (above the ampacity “Where more than one driving machine 1. The settings or ratings of the of the conductors being protected) disconnecting means is supplied by a transformer primary side fuse shall be permitted to be used, ii single feeder, the overcurrent protective and main breaker must not provided all of the following devices in each disconnecting means exceed the settings allowed by conditions are met. shall be selectively coordinated with NEC Article 450. 1 any other supply side overcurrent 1. The conductors being protected 2. At 12 x IFL the minimum melting protective device.” A similar require- are not part of a branch circuit time characteristic of the fuse supplying more than one receptacle ment under Article 700.28 is as follows; should be higher than 0.1 second. 2 “Emergency system(s) overcurrent for cord-and-plug-connected devices shall be selectively coordinated 3. The primary fuse should be to the portable loads. with all supply side overcurrent left of the transformer damage 2. The ampacity of the conductors 3 protective devices.” Article 701.27 curve as much as possible. The does not correspond with the states that “Legally required standby correction factor for a single line- standard ampere rating of a fuse or system(s) overcurrent devices shall be to-ground factor must be applied a circuit breaker without overload 4 selectively coordinated with all supply to the damage curve. trip adjustments above its rating side overcurrent devices.” 4. The setting of the short-time delay (but that shall be permitted to have 5 Exception: Selective coordination element must be checked against other trip or rating adjustments). shall not be required between two the fuse Minimum Melt Time 3. The next higher standard rating overcurrent devices located in series (MMT) after it is corrected for selected does not exceed 800 A. 6 if no loads are connected in parallel line-to-line faults. with the downstream device. C. Overcurrent Devices Rated Over 5. The maximum fault current must 800 A. Where the overcurrent 7 In addition, for healthcare facilities, be indicated at the load side of device is rated over 800 A, the Article 517.26, Application of Other each protective device. ampacity of the conductors it Articles requires that “The life safety 6. The setting of a feeder protective protects shall be equal to or branch of the essential electrical 8 device must comply with Article greater than the rating of the system shall meet the requirements 240 and Article 430 of the NEC. overcurrent device as defined in of Article 700, except as amended by It also must allow the starting Section 240.6. 9 Article 517.“ and acceleration of the largest D. Small Conductors. Unless All Overcurrent Protective Devices motor on the feeder while carrying specifically permitted in 240.4(E) must have an interrupting capacity all the other loads on the feeder. or 240.4(G), the overcurrent 10 not less than the maximum available protection shall not exceed 15 A Protection of Conductors (Excerpts short-circuit current at their point for 14 AWG, 20 A for 12 AWG, and 11 of application. A selective system from NFPA 70-2014, Article 240.4) 30 A for 10 AWG copper; or 15 A is a fully rated system with tripping Conductors, other than flexible cords for 12 AWG and 25 A for 10 AWG devices chosen and adjusted to aluminum and copper-clad provide the desired selectivity. and fixture wires, shall be protected 12 against overcurrent in accordance with aluminum after any correction The tripping characteristics of each their ampacities as specified in Section factors for ambient temperature overcurrent device should not over- 310.15, unless otherwise permitted or and number of conductors have 13 lap, but should maintain a minimum required in 240.4 (A) through (G). been applied. time interval for devices in series (to A. Power Loss Hazard. Conductor E. Tap Conductors. Tap conductors allow for normal operating tolerances) shall be permitted to be protected 14 at all current values. Generally, a overload protection shall not be required where the interruption of against overcurrent in accordance maximum of four low voltage circuit with the following: breakers can be operated selectively the circuit would create a hazard, 15 in series, with the feeder or branch such as in a material handling 1. 210.19(A)(3) and (A)(4) Household breaker downstream furthest from magnet circuit or fire pump circuit. Ranges and Cooking Appliances the source. Short-circuit protection shall be and Other Loads. 16 provided. Specify true rms sensing devices in 2. 240.5(B)(2) Fixture Wire. order to avoid false trips due to rapid Note: FPN See NFPA 20-2013, standard for the Installation of Stationary Pumps 3. 240.21 Location in Circuit. 17 currents or spikes. Specify tripping for Fire Protection. elements with I2t or I4t feature for 4. 368.17(B) Reduction in Ampacity improved coordination with other Size of Busway. 18 devices having I2t or I4t characteristics and fuses. 5. 368.17(C) Feeder or Branch Circuits (busway taps). 19 6. 430.53(D) Single Motor Taps. 20

CA08104001E For more information, visit: www.eaton.com/consultants 1.5-4 Power Distribution Systems System Protection Considerations August 2017 Sheet 01 066 Protection and Coordination

Circuit Breaker Cable The maximum allowable settings are: For low-voltage systems with high- i 1200 A pickup, 1 second or less trip magnitude available short-circuit Temperature Ratings delay at currents of 3000 A or greater. currents, common in urban areas and UL listed circuit breakers rated 125 A or large industrial installations, several ii less shall be marked as being suitable The characteristics of the ground-fault solutions are available: for 60 ºC (140 ºF), 75 ºC (167 ºF) only or trip elements create coordination 60/75 ºC (140/167 ºF) wire. All Eaton problems with downstream devices ■ High interrupting molded-case 1 breakers rated 125 A or less are marked not equipped with ground fault breakers 60/75 ºC (140/167 ºF). All UL listed circuit protection. The National Electrical ■ Current-limiting circuit breakers breakers rated over 125 A are suitable Code exempts fire pumps and or current-limiting fuses 2 for 75 ºC conductors. continuous industrial processes ■ Limiters integral with molded-case from this requirement. circuit breakers (TRI-PAC®) Conductors rated for higher tempera- 3 tures may be used, but must not be The NEC has addressed the concern ■ MDS-L power circuit breakers loaded to carry more current than the that the impedance added by a with integral current-limiting 75 ºC ampacity of that size conductor step-up, step-down or isolation fuses or MDS-X without current- 4 for equipment marked or rated 75 ºC transformer causes the primary limiting fuses or the 60 ºC ampacity of that size side ground fault protection to be desensitized to faults on its secondary To provide current limiting, these conductor for equipment marked or devices must clear the fault completely rated 60 ºC. However, when applying side. Consequently, Article 215.10 5 clarifies the need for equipment within the first half-cycle, limiting the derated factors, so long as the actual peak current (I ) and heat energy (I2t) load does not exceed the lower of the ground fault protection on 1000 A p and above 480 Vac feeder circuit let-through to considerably less than 6 derated ampacity or the 75 ºC or 60 ºC what would have occurred without ampacity that applies. disconnects on the secondary of these transformers. Article 210.13 has the device. 7 Zone Selective Interlocking been added to the 2014 NEC, which For a fully fusible system, rule-of- recognized the same need for branch thumb fuse ratios or more accurate Trip elements equipped with zone circuits being fed by transformers, I2t curves can be used to provide selective interlocking, trip without as for feeder circuits outlined in selectivity and coordination. For fuse- 8 intentional time delay unless a Article 215.10. breaker combinations, the fuse should restraint signal is received from be selected (coordinated) so as to a protective device downstream. It is recommended that in solidly permit the breaker to handle those 9 Breakers equipped with this feature grounded 480/277 V systems where overloads and faults within its capacity; reduce the damage at the point of main breakers are specified to be the fuse should operate before or fault if the fault occurs at a location equipped with ground fault trip elements with the current breaker only on large 10 within the zone of protection. that the feeder breakers be specified to be equipped with ground fault trip faults, approaching the current The upstream breaker upon receipt elements as well. interrupting capacity of the breaker, 11 of the restraint signal will not trip until to minimize fuse blowing. its time-delay setting times out. If the Suggested Ground Fault Settings The three-pole FDCE breakers include breaker immediately downstream of the a Digitrip 310+ electronic trip unit fault does not open, then after timing For the main devices: 12 and are available in three models out, the upstream breaker will trip. A ground fault pickup setting equal covering loads from 15 A through to 20–30% of the main breaker rating 225 A. Optional equipment ground 13 Breakers equipped with ground fault but not to exceed 1200 A, and a time fault allows the designer to extend trip elements should also be specified delay equal to the delay of the short- protection to smaller loads that are to include zone interlocking for the time element, but not to exceed more likely to cause a ground fault 14 ground fault trip element. 1 second. trip, such as motors or lighting. Zone Ground Fault Protection For the feeder ground fault setting: Selective Interlocking is also available to ensure coordinated tripping with 15 Article 230.95 of NEC requires ground- A setting equal to 20–30% of the feeder upstream breakers. fault protection of equipment shall be ampacity and a time delay to coordinate with the setting of the main (at least provided for solidly grounded wye The Series G high performance, 6 cycles below the main). 16 electrical services of more than 150 V current-limiting circuit breaker series to ground, but not exceeding 600 V If the desire to selectively coordinate offers interrupting ratings to 200 kA. phase-to-phase for each service ground fault devices results in settings Frames are EGC, JGC and LGU. 17 disconnect rated 1000 A or more. that do not offer adequate damage The rating of the service disconnect protection against arcing single line- 18 shall be considered to be the rating ground faults, the design engineer of the largest fuse that can be installed should decide between coordination or the highest continuous current trip and damage limitation. 19 setting for which the actual overcurrent device installed in a circuit breaker is rated or can be adjusted. 20

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.5-5 August 2017 System Protection Considerations Sheet 01 067 Protection and Coordination

Any of these current-limiting devices— The 2014 National Electrical Code Arc Flash Considerations fuses, fused breakers or current-limit- (NEC) included new marking require- i ing breakers—cannot only clear these ments for electrical equipment. The Arcflash Reduction Maintenance large faults safely, but also will limit Article 110.24 applies to service System™ is available on power circuit 2 breakers, insulated-case circuit breakers the Ip and I t let-through significantly equipment in other than dwelling ii to prevent damage to apparatus units and mandates that they “shall and molded-case circuit breakers. The downstream, extending their zone be legibly marked in the field with the trip units have maintenance settings of of protection. Without the current maximum available fault current. 2.5 to 4 times the current setting. These 1 limitation of the upstream device, The field marking(s) shall include the breakers deliver faster clearing times the fault current could exceed the date the fault-current calculation than standard instantaneous trip withstand capability of the down- was performed and be of sufficient by eliminating the microprocessor 2 stream equipment. durability to withstand the environ- processing latencies. This system ment involved.” Article 110.24 (B) is superior to simply reducing the Underwriters Laboratories tests requires that: “When modifications instantaneous setting and results in 3 and lists these series combinations. to the electrical installation occur arc energy reduction that can allow Application information is available for that affect the maximum available for reduced PPE, improving worker combinations that have been tested fault current at the service, the dexterity and mobility. The system can 4 ® and UL -listed for safe operation. maximum available fault current also include a remote activation switch with status indicator. Protective devices in electrical shall be verified or recalculated as distribution systems may be properly necessary. The required field NEC 2014 240.87 requires Arc Energy 5 coordinated when the systems are marking(s) in 110.24 (A) shall be Reduction “Where the highest continu- designed and built, but that is no adjusted to reflect the new level of ous current trip setting for which the guarantee that they will remain maximum available fault current.” actual overcurrent device installed 6 coordinated. System changes and Consequently, periodic study of in a circuit breaker is rated or can be additions, plus power source changes, protective-device settings and adjusted is 1200 A or higher, 240.87(A) 7 frequently modify the protection ratings is as important for safety and (B) shall apply. requirements, sometimes causing loss and preventing power outages of coordination and even increasing A. Documentation shall be available as is periodic maintenance of the to those authorized to design, 8 fault currents beyond the ratings of distribution system. some devices. install, operate or inspect the installation as to the location In addition, NFPA 70E 130.3 requires 9 the study be reviewed periodically, of the circuit breaker(s). but not less than every 5 years, to B. Method to Reduce Clearing account for changes in the electrical Time. One of the following or 10 distribution system that could affect approved equivalent means the original arc-flash analysis. shall be provided: 1. Zone-selective interlocking 11 2. Differential relaying 12 3. Energy-reducing maintenance switching with local status indicator 13 4. Energy-reducing active arc flash mitigation system 14 5. An approved equivalent means” 15

CA08104001E For more information, visit: www.eaton.com/consultants 1.5-6 Power Distribution Systems August 2017 Sheet 01 068

This page intentionally left blank. i ii

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.6-1 August 2017 Grounding/Ground Fault Protection Sheet 01 069

Grounding such an object while grounded could The equipment grounding system be seriously injured or killed. In addi- must be bonded to the grounding i Grounding encompasses several tion, current flow from the accidental electrode at the source or service; different but interrelated aspects of grounding of an energized part of the however, it may be also connected electrical distribution system design system could generate sufficient heat to ground at many other points. ii and construction, all of which are (often with arcing) to start a fire. This will not cause problems with essential to the safety and proper the safe operation of the electrical To prevent the establishment of operation of the system and equip- distribution system. 1 such unsafe potential difference ment supplied by it. Among these requires that: Where computers, data processing, are: equipment grounding, system or microprocessor-based industrial grounding, static and lightning ■ 2 The equipment grounding process control systems are installed, protection, and connection to earth conductor provide a return path the equipment grounding system must as a reference (zero) potential. for ground fault currents of be designed to minimize interference 3 sufficiently low impedance to with their proper operation. Often, 1. Equipment Grounding prevent unsafe voltage drop isolated grounding of this equipment, Equipment grounding is essential ■ The equipment grounding or isolated electrical supply systems are 4 to safety of personnel. Its function is conductor be large enough to required to protect microprocessors to ensure that all exposed noncurrent- carry the maximum ground fault from power system “noise” that does carrying metallic parts of all structures current, without burning off, for not in any way affect motors or other 5 and equipment in or near the electrical sufficient time to permit protective electrical equipment. distribution system are at the same devices (ground fault relays, circuit potential, and that this is the zero breakers, fuses) to clear the fault Such systems must use single-point 6 reference potential of the earth. ground concept to minimize “noise” The grounded conductor of the system and still meet the NEC requirements. Equipment grounding is required (usually the neutral conductor), although Any separate isolated ground mat must by both the National Electrical Code grounded at the source, must not be be tied to the rest of the facility ground 7 (Article 250) and the National Electrical used for equipment grounding. mat system for NEC compliance. Safety Code regardless of how the power system is grounded. Equipment The equipment grounding conductor 2. System Grounding 8 grounding also provides a return path may be the metallic conduit or raceway System grounding connects the for ground fault currents, permitting of the wiring system, or a separate electrical supply, from the utility, from protective devices to operate. equipment grounding conductor, 9 run with the circuit conductors, as transformer secondary windings, or Accidental contact of an energized permitted by NEC. If a separate from a generator, to ground. A system conductor of the system with an equipment grounding conductor is can be solidly grounded (no intentional 10 improperly grounded noncurrent- used, it may be bare or insulated; if impedance to ground), impedance carrying metallic part of the system insulated, the insulation must be green, grounded (through a resistance or (such as a motor frame or panelboard green with yellow stripe or green tape. reactance), or ungrounded (with no 11 enclosure) would raise the potential of Conductors with green insulation may intentional connection to ground. the metal object above ground poten- not be used for any purpose other than tial. Any person coming in contact with for equipment grounding. 12 3. Medium-Voltage System: Grounding 13 Table 1.6-1. Features of Ungrounded and Grounded Systems (from ANSI C62.92) Description A B C D E Ungrounded Solidly Grounded Reactance Grounded Resistance Grounded Resonant Grounded 14 (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 15 ground current higher than three-phase reduced below one-half Petersen coil is short short circuit current or one-third of values circuited for relay purposes for solid grounding when it may compare with 16 solidly 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 made satisfactory by use if used at receiving end if used at receiving end single line-to-ground faults 17 of high-speed breakers of system of system unless neutralizer is short circuited to isolate fault by relays 18 (4) Relaying Difficult Satisfactory Satisfactory Satisfactory Requires special provisions but can be made satisfactory 19 (5) Arcing Likely Unlikely Possible if reactance Unlikely Unlikely grounds is excessive (6) Localizing Effect of fault transmitted Effect of faults localized to Effect of faults localized to Effect of faults transmitted Effect of faults transmitted faults as excess voltage on system or part of system system or part of system as excess voltage on as excess voltage on sound 20 sound phases to all where they occur where they occur unless sound phases to all phases to all parts of parts of conductively reactance is quite high parts of conductively conductively connected connected network connected network network 21

CA08104001E For more information, visit: www.eaton.com/consultants 1.6-2 Power Distribution Systems Grounding/Ground Fault Protection August 2017 Sheet 01 070

Table 1.6-1. Features of Ungrounded and Grounded Systems (Continued) i Description A B C D E Ungrounded Solidly Grounded Reactance Grounded Resistance Grounded Resonant Grounded (7) Double faults Likely Likely Unlikely unless reactance Unlikely unless resistance Seem to be more likely but ii is quite high and insulation is quite high and insulation conclusive information weak weak not available (8) Lightning Ungrounded neutral Highest efficiency and If reactance is very high Arresters for ungrounded, Ungrounded neutral 1 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 sacrifice be applied at sacrifice in and efficiency applied at sacrifice in cost in cost and efficiency cost and efficiency and efficiency 2 (9) Telephone Will usually be low except Will be greatest in Will be reduced from Will be reduced from Will be low in magnitude interference in cases of double faults magnitude due to higher solidly grounded values solidly grounded values except in cases of double or electrostatic induction fault currents but can be faults or series resonance 3 with neutral displaced but quickly cleared particularly at harmonic frequencies, duration may be great with high speed breakers but duration may be great (10) Radio May be quite high during Minimum Greater than for Greater than for solidly May be high during faults 4 interference faults or when neutral solidly grounded, grounded, when faults is displayed when faults occur 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 5 of interconnected line is in about 60 to 80 percent low and require isolation of faults from system in increasing 6 percentages as length becomes greater (12) Adaptability to Cannot be interconnected Satisfactory indefinitely Satisfactory indefinitely Satisfactory with solidly- Cannot be interconnected 7 interconnection unless interconnecting with reactance-grounded with solidly-grounded or reactance-grounded unless interconnected system is ungrounded or systems systems systems with proper system is resonant isolating transformers attention to relaying grounded or isolating are used transformers are used. 8 Requires coordination between interconnected systems in neutralizer 9 settings (13) Circuit Interrupting capacity Same interrupting Interrupting capacity Interrupting capacity Interrupting capacity breakers determined by three-phase capacity as required for determined by three-phase determined by three-phase determined by three-phase conditions three-phase short circuit fault conditions fault conditions fault conditions 10 will practically always be satisfactory (14) Operating Ordinarily simple but Simple Simple Simple Taps on neutralizers must 11 procedure possibility of double faults be changed when major introduces complication system switching is in times of trouble performed and difficulty may arise in intercon- 12 nected systems. Difficult to tell where faults are located 13 (15) Total cost High, unless conditions Lowest Intermediate Intermediate Highest unless the arc are such that arc tends to suppressing characteristic extinguish itself, when is relied on to eliminate transmission circuits may transmission circuits when 14 be eliminated, reducing it may be lowest for the total cost particular types of service

15 Because the method of grounding The aforementioned definition is With selective ground fault isolation affects the voltage rise of the unfaulted of significance in medium-voltage the fault current should be at least 60% phases above ground, ANSI C62.92 distribution systems with long lines of the three-phase current at the point 16 classifies systems from the point of and with grounded sources removed of fault. Damage to cable shields must view of grounding in terms of a during light load periods so that in be checked. Although this fact is not coefficient of grounding some locations in the system the a problem except in small cables, it is a 17 Highest Power Frequency X0/X1, R0/X1 may exceed the defining good idea to supplement the cable rms Line – Ground Voltage limits. Other standards (cable and shields returns of ground fault current COG = ------18 rms Line – Line Voltage at Fault lightning arrester) allow the use of to prevent damage, by installing an Location with the Fault Removed 100% rated cables and arresters equipment grounding conductor. selected on the basis of an effectively This same standard also defines grounded system only where the The burdens on the current transformers 19 systems as effectively grounded when criteria in the above are met. In must be checked also (for saturation COG is less than or equal to 0.8. Such effectively grounded system the line- considerations), where residually a system would have X /X less than 0 1 to-ground fault current is high and connected ground relays are used or equal to 3.0 and R /X less than 20 0 1 there is no significant voltage rise in and the current transformers supply or equal to 1.0. Any other grounding the unfaulted phases. current to phase relays and meters. means that does not satisfy these 21 conditions at any point in a system is not effectively grounded.

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.6-3 August 2017 Grounding/Ground Fault Protection Sheet 01 071

If ground sensor current transformers should not be limited to less than the Grounding Point (zero sequence type) are used they current transformers rating of the The most commonly used grounding i must be of high burden capacity. source. This rule will provide sensitive point is the neutral of the system. differential protection for wye-connected Table 1.6-2 taken from ANSI-C62.92 This may be a neutral point created generators and transformers against by means of a zigzag or a wye-broken ii indicates the characteristics of the line-to-ground faults near the neutral. various methods of grounding. delta grounding transformer in a Of course, if the installation of ground system that was operating as an 1 Reactance Grounding fault differential protection is feasible, ungrounded delta system. It is generally used in the grounding or ground sensor current transformers In general, it is a good practice that all of the neutrals of generators directly are used, sensitive differential relaying source neutrals be grounded with the 2 connected to the distribution system in resistance grounded system with same grounding impedance magnitude. bus, in order to limit the line-to-ground greater fault limitation is feasible. However, neutrals should not be tied fault to somewhat less than the In general, ground sensor current together to a single resistor. Where 3 three-phase fault at the generator transformers (zero sequence) do not one of the medium-voltage sources is terminals. If the reactor is so sized, have high burden capacity. the utility, their consent for impedance in all probability the system will grounding must be obtained. 4 remain effectively grounded. Resistance grounded systems limit the circulating currents of triplen The neutral impedance must have a Resistance Grounded harmonics and limit the damage at voltage rating at least equal to the rated 5 Medium-voltage systems in general the point of fault. This method of line-to-neutral voltage class of the should be low resistance grounded. grounding is not suitable for line-to- system. It must have at least a 10-second The ground fault is typically limited to neutral connection of loads. rating equal to the maximum future line- 6 about 200–400 A but less than 1000 A On medium-voltage systems, 100% to-ground fault current and a continuous (a cable shield consideration). With a cable insulation is rated for phase-to- rating to accommodate the triplen properly sized resistor and relaying neutral voltage. If continued operation harmonics that may be present. 7 application, selective fault isolation with one phase faulted to ground is is feasible. The fault limit provided desired, increased insulation thickness 4. Low-Voltage System: Grounding has a bearing on whether residually is required. For 100% insulation, fault Solidly grounded three-phase 8 connected relays are used or ground clearance is recommended within systems (Figure 1.6-1) are usually sensor current transformers are used one minute; for 133% insulation, one wye-connected, with the neutral point for ground fault relaying. hour is acceptable; for indefinite grounded. Less common is the 9 In general, where residually connected operation, as long as necessary, “red-leg” or high-leg delta, a 240 V ground relays are used (51N), the 173% insulation is required. system supplied by some utilities with fault current at each grounded source one winding center-tapped to provide 10 120 V to ground for lighting. This Table 1.6-2. Characteristics of Grounding 240 V, three-phase, four-wire system 11 Grounding Classes Ratios of Symmetrical Percent Fault Per Unit Transient is used where 120 V lighting load is and Means Component Parameters 1 Current LG Voltage small compared to 240 V power load, because the installation is low in cost 2 3 X0/X1 R0/X1 R0/X0 to the utility. 12 A. Effectively ➃ 1. Effective 0-3 0-1 — >60 m2 2. Very effective 0-1 0-0.1 — >95 <1.5 Phase A 13 B. Noneffectively Phase B 1. Inductance • • • N a. Low inductance 3-10 0-1 — >25 <2.3 Phase C b. High inductance >10 — <2 <25 m2.73 8 • 14 2. Resistance • Neutral a. Low resistance 0-10 — Š2 <25 <2.5 b. High resistance — >100 m(-1) <1 m2.73 Grounded Wye 15 3. Inductance and resistance >10 — >2 <10 m2.73 5 m 4. Resonant — — <1 2.73 • Phase B 5. Ungrounded/capacitance y 6 m 9 a. Range A to -40 — — <8 3 Phase C 16 79 • • • b. Range B -40 to 0 — — >8 >3 Phase A 1 Values of the coefficient of grounding (expressed as a percentage of maximum phase-to-phase • Neutral voltage) corresponding to various combinations of these ratios are shown in the ANSI C62.92 17 Appendix figures. Coefficient of grounding affects the selection of arrester ratings. Center-Tapped (High-Leg) Delta 2 Ground-fault current in percentage of the three-phase short-circuit value. 3 Transient line-to-ground voltage, following the sudden initiation of a fault in per unit of the crest Phase A 18 of the prefault line-to-ground operating voltage for a simple, linear circuit. • 4 In linear circuits, Class A1 limits the fundamental line-to-ground voltage on an unfaulted phase to • • Phase B 138% of the prefault voltage; Class A2 to less than 110%. • Phase C 19 5 See ANSI 62.92 para. 7.3 and precautions given in application sections. 6 Usual isolated neutral (ungrounded) system for which the zero-sequence reactance is capacitive (negative). Corner-Grounded Delta 7 Same as NOTE (6) and refer to ANSI 62.92 para. 7.4. Each case should be treated on its own merit. 20 8 Under restriking arcing ground fault conditions (e.g., vacuum breaker interrupter operation), Figure 1.6-1. Solidly Grounded Systems this value can approach 500%. 9 Under arcing ground fault conditions, this value can easily reach 700%, but is essentially unlimited. 21

CA08104001E For more information, visit: www.eaton.com/consultants 1.6-4 Power Distribution Systems Grounding/Ground Fault Protection August 2017 Sheet 01 072

A corner-grounded three-phase delta Most transformer-supplied systems These faults are usually arcing and i system is sometimes found, with are either solidly grounded or resis- can cause severe damage if at least one phase grounded to stabilize all tance grounded. Generator neutrals one of the grounds is not cleared voltages to ground. Better solutions are often grounded through a reactor, immediately. If the second circuit is ii are available for new installations. to limit ground fault (zero sequence) remote, enough current may not currents to values the generator can flow to cause protection to operate. Ungrounded systems (Figure 1.6-2) withstand. This can leave high voltages and 1 can be either wye or delta, although stray currents on structures and the ungrounded delta system is far Selecting the Low-Voltage System jeopardize personnel. more common. Grounding Method 2 There is no one “best” distribution In general, where loads will be system for all applications. In choosing connected line-to-neutral, solidly • Phase A among solidly grounded, resistance grounded systems are used. High 3 grounded, or ungrounded power resistance grounded systems are • • Phase B used as substitutes for ungrounded Phase C distribution, the characteristics of the systems where high system Ungrounded Delta system must be weighed against the 4 requirements of power loads, lighting availability is required. Phase A loads, continuity of service, safety With one phase grounded, the voltage • • Phase B and cost. to ground of the other two phases • N 5 rises 73%, to full phase-to-phase • Phase C Under ground fault conditions, each system behaves very differently: voltage. In low-voltage systems this Ungrounded Wye is not important, since conductors 6 ■ A solidly grounded system produces are insulated for 600 V. Figure 1.6-2. Ungrounded Systems high fault currents, usually with A low-voltage resistance grounded Resistance-grounded systems arcing, and the faulted circuit must 7 be cleared on the first fault within system is normally grounded so that (Figure 1.6-3) are simplest with a the single line-to-ground fault current wye connection, grounding the neutral a fraction of a second to minimize damage exceeds the capacitive charging 8 point directly through the resistor. current of the system. If data for the ■ An ungrounded system will pass Delta systems can be grounded by charging current is not available, use limited current into the first ground means of a zig-zag or other grounding 40–50 ohm resistor in the neutral fault—only the charging current 9 transformer. Wye broken delta of the transformer. transformer banks may also be used. of the system, caused by the distributed capacitance to ground In commercial and institutional 10 of the system wiring and equip- installations, such as office buildings, Phase A ment. In low-voltage systems, shopping centers, schools and hospitals, • Phase B • • this is rarely more than 1 or 2 A lighting loads are often 50% or more N of the total load. In addition, a feeder 11 R Phase C Therefore, on first ground fault, an • outage on first ground fault is seldom ungrounded system can continue in crucial—even in hospitals, that have service, making it desirable where emergency power in critical areas. For 12 Resistance-Grounded Wye power outages cannot be tolerated. these reasons, a solidly grounded wye However, if the ground fault is distribution, with the neutral used for Phase A intermittent, sputtering or arcing, a • • lighting circuits, is usually the most 13 high voltage—as much as 6 to 8 times economical, effective and convenient • • • Phase B phase voltage—can be built up across Phase C design. In some instances, it is an • the system capacitance, from the • NEC requirement. 14 phase conductors to ground. N • In industrial installations, the effect R • Similar high voltages can occur as a of a shutdown caused by a single 15 result of resonance between system ground fault could be disastrous. An capacitance and the inductances of interrupted process could cause the Delta With Derived Neutral Resistance- transformers and motors in the loss of all the materials involved, often 16 Grounded Using Zig-Zag Transformer system. However, the phase-to-phase ruin the process equipment itself, and voltage is not affected. This high sometimes create extremely danger- Figure 1.6-3. Resistance-Grounded Systems transient phase-to-ground voltage ous situations for operating personnel. 17 These arrangements create a derived can puncture insulation at weak neutral point, which can be either points, such as motor windings, and On the other hand, lighting is usually solidly or impedance-grounded. If the is a frequent cause of multiple motor only a small fraction of the total 18 grounding transformer has sufficient failures on ungrounded systems. industrial electrical load. Conse- capacity, the neutral created can be quently, a solidly grounded neutral Locating a first fault on an ungrounded solidly grounded and used as part of circuit conductor is not imperative. system can be difficult. If, before the 19 a three-phase, four-wire system. When required, a neutral to feed the first fault is cleared, a second ground lighting loads can be obtained from fault occurs on a different phase, even inexpensive lighting transformers. 20 on a different, remote feeder, it is a high-current phase-to-ground-to- phase fault. 21

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.6-5 August 2017 Grounding/Ground Fault Protection Sheet 01 073

Because of the ability to continue in system, the voltage drop across Overcurrent protection is designed operation with one ground fault on the arc can be from 70 to 140 V. The to protect conductors and equipment i the system, many existing industrial resulting ground fault current is against currents that exceed their plants use ungrounded delta distribu- rarely enough to cause the phase ampacity or rating under prescribed tion. Today, new installations can have overcurrent protection device to open time values. An overcurrent can result ii all the advantages of service continuity instantaneously and prevent damage. from an overload, short circuit or (high of the ungrounded delta, yet minimize level) ground fault condition. the problems of the system, such Sometimes, the ground fault is below 1 as the difficulty of locating the first the trip setting of the protective device When currents flow outside the normal ground fault, risk of damage from a and it does not trip at all until the fault current path to ground, supplementary second ground fault, and damage escalates and extensive damage is ground fault protection equipment will 2 transient overvoltages. done. For these reasons, low level be required to sense low-level ground ground protection devices with mini- fault currents and initiate the protection A high-resistance grounded wye mum time delay settings are required required. Normal phase overcurrent 3 distribution can continue in operation to rapidly clear ground faults. This is protection devices provide no protection with a ground fault on the system emphasized by the NEC requirement against low-level ground faults. and will not develop transient that a ground fault relay on a service 4 overvoltages. shall have a maximum delay of one There are three basic means of sensing second for faults of 3000 A or more. ground faults. The most simple and And, because the ground point is direct method is the ground return established, locating a ground fault is The NEC (Sec. 230.95) requires that method as illustrated in Figure 1.6-4. 5 less difficult than on an ungrounded ground fault protection, set at no more This sensing method is based on the fact system especially when a “pulsing than 1200 A, be provided for each that all currents supplied by a trans- contactor” design is applied. When service disconnecting means rated former must return to that transformer. 6 combined with sensitive ground-fault 1000 A or more on solidly grounded protection, damage from a second wye services of more than 150 V to Main ground fault can be nearly eliminated. ground, but not exceeding 600 V 7 phase-to-phase. Practically, this makes Ungrounded delta systems can be Neutral ground fault protection mandatory Service converted to high-resistance grounded on 480Y/277 V services, but not on Transformer 8 Sensor GFR systems, using a zig-zag or other 208Y/120 V services. Typical grounding transformer to derive a Ground Bus Feeder neutral, with similar benefits, see On a 208 V system, the voltage to 9 Ta b 3 6 . While the majority of ground is 120 V. If a ground fault Main Bonding Jumper manufacturing plants use solidly occurs, the arc goes out at current zero, Typical Grounding Equipment 4W Load grounded systems, in many instances, and the voltage to ground is often too Electrode Grounding 10 the high-resistance grounded distribu- low to cause it to restrike. Therefore, Conductor Conductor tion will be the most advantageous. arcing ground faults on 208 V systems tend to be self-extinguishing. Figure 1.6-4. Ground Return Sensing Method 11 Ground Fault Protection On a 480 V system, with 277 V to When an energized conductor faults A ground fault normally occurs in one ground, restrike usually takes place to grounded metal, the fault current 12 of two ways: by accidental contact of after current zero, and the arc tends to returns along the ground return path to an energized conductor with normally be self-sustaining, causing severe and the neutral of the source transformer. grounded metal, or as a result of increasing damage, until the fault is This path includes the main bonding 13 an insulation failure of an energized cleared by a protective device. jumper as shown in Figure 1.6-4. conductor. When an insulation failure occurs, the energized conductor The NEC requires ground fault service A current sensor on this conductor 14 contacts normally noncurrent-carrying disconnecting means rated 1000 A or (which can be a conventional bar-type grounded metal, which is bonded to higher. This protection works so fast or window type CT) will respond to or part of the equipment grounding that for ground faults on feeders, or ground fault currents only. Normal 15 conductor. even branch circuits, it will often open neutral currents resulting from the service disconnect before the feeder unbalanced loads will return along In a solidly grounded system, the fault or branch circuit overcurrent device can the neutral conductor and will not be 16 current returns to the source primarily operate. This is highly undesirable, and detected by the ground return sensor. along the equipment grounding in the NEC (230.95), an informational This is an inexpensive method of sensing conductors, with a small part using note states that “additional ground fault ground faults where protection per 17 parallel paths such as building steel or protective equipment may be needed NEC (230.95) is desired. For it to piping. If the ground return impedance on feeders and branch circuits where operate properly, the neutral must be was as low as that of the circuit maximum continuity of electric service grounded in only one place as indicated 18 conductors, ground fault currents is necessary.” would be high, and the normal phase in Figure 1.6-4. In many installations, overcurrent protection would clear Unless it is acceptable to disconnect the servicing utility grounds the neutral them with little damage. the entire service on a ground fault at the transformer and additional 19 almost anywhere in the system, such grounding is required in the service Unfortunately, the impedance of the additional stages of ground fault equipment per NEC (250.24(A)(2)). ground return path is usually higher, protection must be provided. At 20 the fault itself is usually arcing and the least two stages of protection are impedance of the arc further reduces mandatory in healthcare facilities the fault current. In a 480Y/277 V (NEC Sec. 517.17). 21

CA08104001E For more information, visit: www.eaton.com/consultants 1.6-6 Power Distribution Systems Grounding/Ground Fault Protection August 2017 Sheet 01 074

In such cases, and others including This method of sensing ground faults As with the zero sequence sensing i multiple source with multiple, inter- can be employed on the main discon- method, the resultant residual sensor connected neutral ground points, nect where protection per NEC (230.95) output to the ground fault relay or residual or zero sequence ground is desired. It can also be easily employed integral ground fault tripping circuit ii sensing methods should be employed. in multi-tier systems where additional will be zero if all currents flow only levels of ground fault protection are in the circuit conductors. Should a A second method of detecting ground desired for added service continuity. ground fault occur, the current from 1 faults involves the use of a zero Additional grounding points may be the faulted conductor will return along sequence sensing method, as illus- employed upstream of the sensor, the ground path, rather than on the but not on the load side. trated in Figure 1.6-5. This sensing other circuit conductors, and the resid- method requires a single specially 2 Ground fault protection employing ual sum of the sensor outputs will not designed sensor, either of a toroidal ground return or zero sequence be zero. When the level of ground fault or rectangular shaped configuration. sensing methods can be accomplished current exceeds the pre-set current 3 This core balance current transformer by the use of separate ground fault and time delay settings, a ground surrounds all the phase and neutral relays (GFRs) and disconnects fault tripping action will be initiated. conductors in a typical three-phase, equipped with standard shunt trip 4 four-wire distribution system. devices. Alternately, it can be done This method of sensing ground faults by circuit breakers using electronic can be economically applied on main This sensing method is based on the trip units with integral ground fault service disconnects where circuit break- 5 fact that the vectorial sum of the phase protection using external connections ers with integral ground fault protection and neutral currents in any distribution from sensors arranged for this mode are provided. It can be used in protec- circuit will equal zero unless a ground of sensing. In some cases, a reliable tion schemes per NEC (230.95) or in 6 fault condition exists downstream from source of control power is needed. multi-tier schemes where additional the sensor. All currents that flow only levels of ground fault protection are in the circuit conductors, including The third basic method of detecting ground faults involves the use of desired for added service continuity. balanced or unbalanced phase-to-phase Additional grounding points may be 7 and phase-to-neutral normal or fault multiple current sensors connected in a residual sensing method as illus- employed upstream of the residual currents, and harmonic currents, will sensors, but not on the load side. result in zero sensor output. trated in Figure 1.6-6. This is a very 8 common sensing method used with Both the zero sequence and However, should any conductor circuit breakers equipped with elec- residual sensing methods have 9 become grounded, the fault current tronic trip units, current sensors and been commonly referred to as will return along the ground path— integral ground fault protection. The “vectorial summation” methods. not the normal circuit conductors. three-phase sensors are required for Consequently, the sensor will have an normal phase overcurrent protection. Most distribution systems can use 10 unbalanced magnetic flux condition. Ground fault sensing is obtained with either of the three sensing methods The ground fault relay will sense the the addition of an identically rated exclusively or a combination of the unbalance and provide a trip signal to sensor mounted on the neutral. sensing methods depending upon 11 the breaker. the complexity of the system and In a residual sensing scheme, the the degree of service continuity and relationship of the polarity markings Zero Alternate selective coordination desired. 12 Sequence Sensor —as noted by the “X” on each sensor— Different methods will be required Sensor Location is critical. Because the vectorial sum of Main depending upon the number of supply the currents in all the conductors will sources, and the number and location 13 total zero under normal, non-ground of system grounding points. faulted conditions, it is imperative Neutral that proper polarity connections are As an example, one of the more 14 employed to reflect this condition. frequently used systems where GFR Typical continuity of service to critical loads Feeder is a factor is the dual source system

Sensor illustrated in Figure 1.6-7. This system 15 Residual Polarity Typical Sensors uses tie-point grounding as permitted 4W Load Marks Main under NEC Sec. 250.24(A)(3). The use 16 Figure 1.6-5. Zero Sequence Sensing Method of this grounding method is limited to services that are dual fed (double-

Zero sequence sensors are available Neutral ended) in a common enclosure or 17 with various window openings for grouped together in separate enclo- circuits with small or large conductors, Typical sures, employing a secondary tie. and even with large rectangular win- GFR Feeder 18 dows to fit over bus bars or multiple large size conductors in parallel. Some Typical sensors have split cores for installation 4W Load 19 over existing conductors without disturbing the connections. Figure 1.6-6. Residual Sensing Method 20

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.6-7 August 2017 Grounding/Ground Fault Protection Sheet 01 075

This scheme uses individual sensors connected in ground return fashion. Power Power i Under tie breaker closed operating Transformer Transformer conditions, either the M1 sensor or M2 sensor could see neutral unbalance Neutral Sensor Neutral Sensor ii currents and possibly initiate an Main Main Bkr. Main Bkr. 52-1 Tie Bkr. Main Bkr. 52-2 Bkr. improper tripping operation. However, 52-1 52-T 52-2 with the polarity arrangements of ØA, ØB, ØC ØA, ØB, ØC 1 these two sensors along with the tie Neutral Neutral Neutral Sensor breaker auxiliary switch (T/a) and Tie Bkr. 52-T ( )B5 interconnections as shown, this Typical ( )B5 Typical 2 4-Wire ( )B4 ( )B4 52-T 52-T 4-Wire possibility is eliminated. Feeder Feeder TN a TG a M2N M1G M2G M1N Selective ground fault tripping 33- 3 coordination between the tie breaker 4-Wire 52-T 4-Wire B5 B4 B4 B5 B4 B5 Load Load and the two main circuit breakers is Digitrip Digitrip Digitrip achieved by pre-set current pickup and B4 B5 Main Bkr. Main Bkr. Main Bkr. B4 B5 4 time delay settings between devices Digitrip 52-1 52-T 52-2 Digitrip GFR/1, GFR/2 and GFR/T. Figure 1.6-7. Dual Source System—Single Point Grounding 5 The advantages of increased service Note: This GF scheme requires trip units to be set to source ground sensing. continuity offered by this system can only be effectively used if additional levels of ground fault protection are 6 added on each downstream feeder. Power Power Some users prefer individual grounding Transformer Transformer of the transformer neutrals. In such 7 cases, a partial differential ground fault scheme should be used for the mains X X and tie breaker. X Neutral Neutral X 8 Sensor Main Sensor Main An example of a residual partial differ- Main Breaker 52-1 Breaker 52-2 Main Breaker Breaker 9 ential scheme is shown in Figure 1.6-8. 52-1 52-2 The scheme typically relies upon the vector sum of at least two neutral Phase A, Tie Breaker Phase A, sensors in combination with each Phase B, 52-T Phase B, 10 breakers’ three-phase sensors. To Phase C Phase C Neutral Neutral reduce the complexity of the drawing, X each of the breakers’ three-phase Neutral Sensor X 11 Tie Breaker 52-T sensors have not been shown. It is X X Typical X Typical X absolutely critical that the sensors’ Four-Wire Four-Wire i p Un t polarities are supplied as shown, the Feeder i p Un t 52-1 52-T 52-2 Feeder 12 Tr neutral sensor ratings of the mains and Tr a a a tie are the same, and that there are no other grounds on the neutral bus Four-Wire Load Four-Wire Load 13 made downstream of points shown. Trip Unit Trip Unit Trip Unit Main Breaker Tie Breaker Main Breaker An infinite number of ground fault 52-1 52-T 52-2 14 protection schemes can be developed depending upon the number of alternate Figure 1.6-8. Dual Source System—Multiple Point Grounding sources, the number of grounding points To maintain maximum service continu- The use of GFRs (or circuit breakers 15 and system interconnections involved. ity, more than two levels (zones) of with integral ground fault protection) Depending upon the individual system ground fault protection will be that incorporate Zone Selective configuration, either mode of sensing required, so that ground fault outages Interlocking, allows a coordinated 16 or a combination of all types may be can be localized and service interrup- response in a system by operating in employed to accomplish the desired tion minimized. To obtain selectivity a time delayed mode for ground faults end results. between different levels of ground occurring most remote from the 17 The NEC (230.95) limits the maximum fault relays, time delay settings should source. This time delayed mode is setting of the ground fault protection be employed with the GFR furthest only actuated when the GFR protecting 18 used on service equipment to 1200 A downstream having the minimum the zone containing the fault sends a (and timed tripping at 3000 A for one time delay. This will allow the GFR restraining signal to the upstream second). In order to prevent tripping nearest the fault to operate first. GFRs. The absence of a restraining signal from a downstream GFR is an 19 of the main service disconnect on a With several levels of protection, this downstream feeder ground fault, indication to the next upstream GFR will reduce the level of protection for that a ground fault is within its zone ground fault protection must be faults within the upstream GFR zones. 20 provided on all the feeders. of protection and it will operate Zone interlocking was developed for instantaneously to clear the fault with GFRs to overcome this problem. minimum damage and maximum service continuity. 21

CA08104001E For more information, visit: www.eaton.com/consultants 1.6-8 Power Distribution Systems Grounding/Ground Fault Protection August 2017 Sheet 01 076

This operating mode permits all GFRs Further Information These supplemental grounding i to operate instantaneously for a fault ■ PRSC-4E—System Neutral Ground- electrodes include: the effectively within their zone and still provide ing and Ground Fault Protection grounded metal frame of the building, complete selectivity between zones. (ABB Publication) a concrete-encased electrode, a copper conductor ground ring encircling the ii ■ PB 2.2—NEMA Application Guide The National Electrical Manufacturers building, or a made electrode such as for Ground Fault Protective Devices Association (NEMA) states, in their one or more driven ground rods or for Equipment 1 application guide for ground fault a buried plate. Where any of these protection, that zone interlocking is ■ IEEE Standard 142—Grounding of electrodes are present, they must be necessary to minimize damage from Industrial and Commercial Power bonded together into one grounding 2 ground faults. A two-wire connection Systems (Green Book) electrode system. is required to carry the restraining ■ IEEE Emerald Book (Standard 1100) signal from the GFRs in one zone to One of the most effective grounding ■ UL 96A, Installation Requirements the GFRs in the next zone. electrodes is the concrete-encased 3 for Lightning Protection Systems electrode, sometimes called the Ufer Circuit breakers with integral ground Lightning and Surge Protection ground, named after the man who 4 fault protection and standard circuit developed it. It consists of at least breakers with shunt trips activated Physical protection of buildings 20 ft (6 m) of steel reinforcing bars or by the ground fault relay are ideal for from direct damage from lightning rods not less than 1/2 inches (12.7 mm) 5 ground fault protection. Eaton’s is beyond the scope of this section. in diameter, or at least 20 ft (6 m) of Pringle Bolted Pressure Type fused Requirements will vary with geographic bare copper conductor, size No. 4 AWG switches have an optional integral location, building type and environ- or larger, encased in at least 2 inches 6 ground fault protection relay and meet ment, and many other factors (see (50.8 mm) of concrete. It must be UL Class 1 requirements to open safely IEEE/ANSI Standard 142, Grounding located within and near the bottom of on faults up to 12 times their rating. of Industrial and Commercial Power a concrete foundation or footing that 7 Eaton’s Shunt Trip Safety Switches Systems). Any lightning protection is in direct contact with the earth. Tests have passed Class 1 ground fault system must be grounded, and the have shown this electrode to provide a testing and include an integral shunt lightning protection ground must be low-resistance earth ground even in 8 trip mechanism that can be field wired bonded to the electrical equipment poor soil conditions. to an external ground fault relay. grounding system. The electrical distribution system and Power distribution systems differ 9 Grounding Electrodes equipment ground must be connected widely from each other, depending to this grounding electrode system by upon the requirements of each end At some point, the equipment and a grounding electrode conductor. All 10 user’s facility type and application. A system grounds must be connected other grounding electrodes, such power system design professional to the earth by means of a grounding as those for the lightning protection needs to carefully evaluate total system electrode system. system, the telephone system, overcurrent protection, including 11 Outdoor substations usually use a television antenna and cable TV ground fault currents, to meet these system grounds, and computer needs. Experienced and knowledgeable ground grid, consisting of a number of ground rods driven into the earth systems, must be bonded to this engineers have to consider the impact grounding electrode system. 12 on all power sources (utility and on-site and bonded together by buried copper generation), the effects of outages and conductors. The required grounding There are many books written the cost impact of downtime, as well as electrode system for a building is about the design and application of 13 safety for people and equipment from spelled out in NEC Article 250. grounding systems. For those diligent arc flash hazards, when balancing The preferred grounding electrode engineers seeking more information, 14 enhanced protection schemes against is a metal underground water pipe the following publications are initial equipment cost. They must apply in direct contact with the earth for at recommended reading: protective devices, analyzing the least 10 ft (3 m). However, because ■ time-current characteristics and fault Soares Book on Grounding and 15 underground water piping is often Bonding, 2014 NEC. IAEI 12th interrupting capacity, as well as plastic outside the building, or may selectivity and coordination methods Edition by International Association later be replaced by plastic piping, of Electrical Inspectors to provide the most safe and cost- the NEC requires this electrode to be 16 ■ McGraw Hill’s National Electrical effective distribution system. supplemented by and bonded to at Code 2014 Grounding & Earthing least one other grounding electrode. 17 Handbook

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.6-9 August 2017 Grounding/Ground Fault Protection Sheet 01 077

Medium-Voltage Equipment Surge Recognizing that distribution system Surge Protection Recommendations Protection Considerations can be subject to voltage transients 1. For circuits exposed to lightning, i caused by lighting or switching, the surge arresters should be applied Transformers industry has developed standards to in line with Industry standard provide guidelines for surge protection practices. ii If the voltage withstand/BIL rating of of electrical equipment. Those guide- the transformer is less than that of the lines should be used in design and 2. Transformers—Because each switchgear feeding the transformer, protection of electrical distribution installation is unique, a variety 1 surge protection is recommended at systems independent of the circuit of different factors can impact the transformer terminals, in line with breaker interrupting medium. The how the various electrical established practices. In addition, industry standards are: components interact as a system 2 consideration should be given to using (i.e.,: transformer type and MVA surge arresters and/or surge capacitors ANSI C62 rating, system impedances, for transformers having equal or Guides and Standards for Surge the Manufacturer’s Vacuum 3 greater withstand/BIL ratings than Protection Interrupter Current Chop Rating, that of the switchgear feeding the etc.). Consequently, there is no transformer for distribution systems IEEE 242—Buff Book IEEE Recommended Practice for singular answer for all situations. 4 where reflected voltage waves and/or The optimum application of resonant conditions may occur. Protection and Coordination of Industrial and Commercial Power snubbers may require Typically incoming voltage surges are Systems recommendations from a 5 reflected at the transformer primary switching transient study. IEEE 141—Red Book terminals, resulting in voltages at the Typical rules of thumb are: ends of the transformer primary Recommended Practice for 6 terminals/windings of up to two times Electric Power Distribution for a. Close-coupled to medium- Industrial Plants the incoming voltage wave. System voltage primary breaker: 7 capacitance and inductance values IEEE C37.20.2 Provide transients surge combined with the transformer Standards for Metal-Clad Switchgear protection, such as Surge impedance values can cause resonant Arrester in parallel with RC conditions resulting in amplified Eaton’s medium-voltage metal-clad Snubber. The surge protection 8 reflected waves. Surge arresters/ and metal-enclosed switchgear that device selected should be capacitors when required, should uses vacuum circuit breakers is applied located and connected at the 9 be located as close to the transformer over a broad range of circuits. It is one transformer primary terminals primary terminals as practical. of the many types of equipment in the or it can be located inside the total distribution system. Whenever a switchgear and connected on Where concerns exist for transformer switching device is opened or closed, the transformer side of the 10 failures or life reduction due to certain interactions of the power primary breaker. switching transients, Eaton’s system elements with the switching Cooper Transformer Group offers b. Cable-connected to medium- 11 device can cause high frequency voltage voltage primary breaker: an environmentally friendly oil-filled transients in the system. hardened transformer solution. See Provide transient surge White Paper WP202001 and Brochure Due to the wide range of applications protection, such as surge 12 B210-10035 on Eaton/Cooper website and variety of ratings used for different arrester in parallel with RC for details. elements in the power systems, a Snubber for transformers given circuit may or may not require connected by cables with 13 Motors surge protection. Therefore, Eaton lengths up to 150 feet. The Surge capacitors and, where does not include surge protection as surge protection device should appropriate, surge arresters should standard with its metal-clad or metal- be located and connected at the 14 be applied at the motor terminals. enclosed medium-voltage switchgear. transformer terminals. Surge protection is generally not Generators The system designer must specify needed for transformers with 15 Surge capacitors and station class the optional type and extent of surge lightning impulse withstand surge arresters should be properly protection necessary, depending on ratings equal to that of the applied at the machine terminals. the individual circuit characteristics switchgear and connected to 16 and cost considerations. Because the switchgear by cables at Surge Protection transformers have both high initial least 150 feet or longer. For installation and replacement costs, transformers with lower BIL, 17 Eaton’s VacClad-W metal-clad switch- the specifying engineer should provide surge arrester in parallel gear is applied over a broad range of consider commissioning an optional with RC Snubber. circuits, and is one of the many types study. These switching transient c. When special transient resis- 18 of equipment in the total system. The studies and their associated distribution system can be subject to tant transformer designs are recommendations can be provided used, RC snubbers may not be voltage transients caused by lighting by Eaton’s Engineering Services & 19 or switching surges. required for power transformer Systems group (EESS). protection. However, they The following are Eaton’s recommenda- may be needed for instrument 20 tions for surge protection of medium- transformer protection. voltage equipment. Please note these recommendations are valid when using 21 Eaton’s vacuum breakers only.

CA08104001E For more information, visit: www.eaton.com/consultants 1.6-10 Power Distribution Systems Grounding/Ground Fault Protection August 2017 Sheet 01 078

RC Snubber to dampen internal Types of Surge Protection Devices B. Low Resistance Grounded Sys- i transformer resonance: tems (systems grounded through Generally surge protective devices resistor rated for 10 seconds): The natural frequency of transformer should be located as closely as possible Arrester 10-second MCOV capability ii windings can under some circumstances to the circuit component(s) that require at 60 ºC, which is obtained from be excited to resonate. Transformer protection from the transients, and manufacturer’s data, should be windings in resonance can produce connected directly to the terminals of equal to 1.05 x VLL, where VLL is 1 elevated internal voltages that produce the component with conductors that nominal line-to-line service voltage, insulation damage or failure. An RC are as short and flat as possible to and 1.05 factor allows for +5% Snubber applied at the transformer minimize the inductance. It is also voltage variation above the 2 terminals as indicated above can important that surge protection devices nominal voltage. dampen internal winding resonance should be properly grounded for and prevent the production of damag- effectively shunting high frequency C. Ungrounded or Systems 3 ing elevated internal voltages. This is transients to ground. Grounded through impedance typically required where rectifiers, UPS other than a 10-second resistor: or similar electronic equipment is on Surge Arresters Arrester MCOV rating should be Modern metal-oxide surge arresters 4 the transformer secondary. equal to 1.05 x VLL/T, where VLL are recommended as this design and T are as defined above. 3. Arc-Furnace Transformers— ensures better performance and high 5 Provide Surge Arrester in parallel reliability of surge protection schemes. Refer to Table 1.6-3 for recommended with RC Snubber at the trans- Manufacturer’s technical data must be ratings for metal-oxide surge arresters former terminals. consulted for correct application of a that are sized in accordance with the given type of surge arrester. above guidelines, when located in 6 4. Motors—Provide Surge Arrester Eaton’s switchgear. in parallel with RC Snubber at the Many manufacturer’s published motor terminals. For those motors arrester MCOV (maximum continuous Surge Capacitors 7 using VFDs, surge protection operating voltage) ratings are based Metal-oxide surge arresters limit the should be applied and precede on 40 ºC or 45 ºC ambient temperature. magnitude of prospective surge over- the VFD devices as well. 8 In general, the following guidelines are voltage, but are ineffective in control- 5. Generators—Provide station class recommended for arrester selections, ling its rate of rise. Specially designed Surge Arrester in parallel with RC when installed inside Eaton’s medium- surge capacitors with low internal Snubber at the generator terminals. voltage switchgear: inductance are used to limit the rate of 9 rise of this surge overvoltage to protect 6. Capacitor Switching—No surge A. Solidly Grounded Systems: turn-to-turn insulation. Recommended protection is required. Make sure Arrester MCOV rating should be values for surge capacitors are: 0.5 µf 10 that the capacitor’s lightning equal to 1.05 x VLL/(1.732 x T), on 5 and 7.5 kV, 0.25 µf on 15 kV, and impulse withstand rating is equal where VLL is nominal line-to-line 0.13 µf on systems operating at 24 kV to that of the switchgear. service voltage, 1.05 factor allows and higher. 11 for +5% voltage variation above 7. Shunt Reactor Switching— the nominal voltage according Provide Surge Arrester in parallel to ANSI C84.1, and T is derating 12 with RC Snubber at the reactor factor to allow for operation at terminals. 55 ºC switchgear ambient, which should be obtained from the 13 8. Motor Starting Reactors or Reduced arrester manufacturer for the type Voltage Auto-Transformers— of arrester under consideration. Provide Surge Arrester in parallel Typical values of T are: 0.946 to 1.0. 14 with RC Snubber at the reactor or RVAT terminals. 9. Switching Underground Cables— 15 Surge protection should be properly applied as determined 16 by a switching transient study.

19 Figure 1.6-9. Surge Protection Devices 20

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.6-11 August 2017 Grounding/Ground Fault Protection Sheet 01 079

RC Snubber Under high frequency transient Better protection: An RC Snubber A RC Snubber device consists of a conditions, the capacitor offers in parallel with Surge Arrester for i non-inductive resistor R sized to match very low impedance, thus effectively protection from high frequency surge impedance of the load cables, “inserting” the resistor R and ZnO transients and voltage peaks. in the power system as a cable ii typically 20 to 30 ohms, and connected Best protection: RC Snubber with in series with a Surge Capacitor C. The terminating network, thus minimizing reflection of the steep wave-fronts of surge suppressor, plus proper surge Surge Capacitor is typically sized to be arrester preceding it where needed 0.15 to 0.25 microfarad. Under normal the voltage transients and prevents 1 voltage doubling of the traveling for protection against lightning. The operating conditions, impedance of RC Snubber with surge suppressor the capacitor is very high, effectively wave. The ZnO element limits the peak voltage magnitudes. provides protection from high 2 “isolating” the resistor R from the frequency voltage transients and system at normal power frequencies, The combined effects of R, ZnO, limits peak magnitude of the transient and minimizing heat dissipation during and capacitor of this device provides to 1 to 2 PU. A surge arrester provides 3 normal operation. optimum protection against high protection from higher voltage peaks Under high frequency transient frequency transients by absorbing, resulting from lightning surges. conditions, the capacitor offers very damping, and by limiting the peak Note that special design liquid-filled 4 low impedance, thus effectively amplitude of the voltage wave-fronts. and dry-type transformers are avail- “inserting” the resistor R in the power Please note that this suppressor is able that do not require the addition system as a cable terminating resistor, not a lightning protection device. If of RC Snubbers to mitigate switching 5 thus minimizing reflection of the steep lightning can occur or be induced in the transients. wave-fronts of the voltage transients electrical system, a properly rated and and prevents voltage doubling of the applied surge arrester must precede Further Information 6 traveling wave. The RC Snubber this device. ■ IEEE/ANSI Standard 142—Grounding provides protection against high Industrial and Commercial Power frequency transients by absorbing Surge Protection Summary Systems (Green Book) 7 and damping the transients. Minimum protection: Surge Arrester ■ IEEE Standard 241—Electric Power for protection from high overvoltage Systems in Commercial Buildings An RC Snubber is most effective in peaks, or Surge Capacitor for (Gray Book) 8 mitigating fast-rising transient volt- protection from fast-rising transient. ages, and in attenuating reflections ■ IEEE Standard 141—Electric Power Please note that the surge arresters and resonances before they have a Distribution for Industrial Plants or surge capacitor alone may not 9 chance to build up, but does not limit (Red Book) provide adequate surge protection the peak magnitude of the transient. from escalating voltages caused by Therefore, the RC Snubber alone may circuit resonance. Note that when 10 not provide adequate protection. To applying surge capacitors on both limit peak magnitude of the transient, sides of a circuit breaker, the surge application of a surge arrester should capacitor on one side of the breaker 11 also be considered. must be an RC Snubber or RC Snubber RC Snubber with Surge Suppressor with surge suppressor, to mitigate 12 This type of device consists of parallel possible virtual current chopping. combination of Resistor (R) and Zinc Good protection: Surge arrester in Oxide Voltage Suppressor (ZnO), parallel with surge capacitor for 13 connected in series with a Surge protection from high overvoltage peaks Capacitor. The resistor R is sized to and fast rising transient. This option match the surge impedance of the load may not provide adequate surge 14 cables, typically 20 to 30 ohms. The protection from escalating voltages ZnO is a gapless metal-oxide nonlinear caused by circuit resonance. When arrester, set to trigger at 1 to 2 PU applying surge capacitors on both 15 voltage, where 1 PU = 1.412*(VL- L /1.732). sides of a circuit breaker, the surge The Surge Capacitor is typically sized to capacitor on one side of the breaker be 0.15 to 0.25 microfarad. As with RC must be an RC Snubber or RC Snubber 16 Snubber, under normal operating with surge suppressor, to mitigate conditions, impedance of the capacitor possible virtual current chopping. is very high, effectively “isolating” the 17 resistor R and ZnO from the system at normal power frequencies, and minimizing heat dissipation during 18 normal operation. 19

CA08104001E For more information, visit: www.eaton.com/consultants 1.6-12 Power Distribution Systems Grounding/Ground Fault Protection August 2017 Sheet 01 080

Table 1.6-3. Surge Arrester Selections—Recommended Ratings i Service Distribution Class Arresters Station Class Arresters 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 ii Arrester Ratings kV Arrester Ratings kV Nominal MCOV Nominal MCOV Nominal MCOV Nominal MCOV Nominal MCOV Nominal MCOV 1 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 3.30 3 2.55 3 2.55 6 5.10 3 2.55 3 2.55 6 5.10 2 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 4.80 6 5.10 6 5.10 9 7.65 6 5.10 6 5.10 9 7.65 3 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 7.20 6 5.10 6 5.10 10 8.40 6 5.10 9 7.65 10 8.40 4 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 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 5 12.00 10 8.40 10 8.40 18 15.30 10 8.40 12 10.20 18 15.30 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 6 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 18.00 15 12.70 15 12.70 27 22.00 15 12.70 18 15.30 27 22.00 7 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 22.86 18 15.30 21 17.00 — — 18 15.30 24 19.50 36 29.00 8 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 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 9 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 38.00 30 24.40 — — — — 30 24.40 36 29.00 — — 10

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.7-1 August 2017 Typical Components of a Power System Sheet 01 081

Typical Power System Because the majority of medium- and Power Equipment Losses low-voltage switchgear is mounted i Components indoors, they are typically provided Table 1.7-1. Power Equipment Losses in NEMA 1A enclosures. In these Equipment Watts The System One-line on Page 1.2-4, applications, ventilation openings are Loss ii illustrates schematically the various normally provided to allow heat to Medium-Voltage Switchgear (Indoor, 5 and 15 kV) types of power distribution equipment escape from the enclosures. Where that an engineer will encounter during 1200 A breaker 600 required, optional dust screens and 2000 A breaker 1400 1 the design of a power system. It is gasketing can be provided. 3000 A breaker 2100 important to consider the various 4000 A breaker 3700 physical attributes of the various pieces Many indoor applications are in base- Medium-Voltage Switchgear (Indoor, 5 and 15 kV) 2 of electrical equipment that will be ments or areas where condensation 600 A unfused switch 500 utilized as well as the constraints that on the ceiling may leak on top of the 1200 A unfused switch 750 will be encountered in their application. switchgear. Additional concerns may 100 A CL fuses 840 3 arise where sprinklers are provided Medium-Voltage Starters (Indoor, 5 kV) Electrical equipment that distributes above the switchgear or alternately, power has a heat loss due to the 400 A starter FVNR 600 on the floor above. Eaton can provide 800 A starter FVNR 1000 4 impedance and/or resistance of its “sprinkler resistant” low-voltage conductors. This heat is radiated into 600 A fused switch 500 switchgear or low- and medium- 1200 A fused switch 800 the electrical room where the equip- voltage switchgear with a drip hood. ment is placed and must be removed Low-Voltage Switchgear (Indoor, 480 V) 5 to ensure excess heat does not cause For outdoor environments, this equip- 800 A breaker 400 failures. Table 1.7-1 provides heat loss 1600 A breaker 1000 ment may be mounted in a NEMA 3R 2000 A breaker 1500 in watts for typical power distribution drip-proof enclosure. Where equipment 6 equipment that may be used in the 3200 A breaker 2400 is located outdoors, the humidity in the 4000 A breaker 3000 sizing of HVAC equipment. air may condense during evening 5000 A breaker 4700 7 hours, resulting in water droplets fall- Fuse limiters—800 A CB 200 As indicated on the one-line, a ing on the bus bars in the equipment. number of distribution components, Fuse limiters—1600 A CB 500 Under these circumstances, an optional Fuse limiters—2000 A CB 750 are provided with a description of the space heater may be provided and 8 physical structure in which they are to Fuse truck—3200 A CB 3600 wired to a thermostat or humidistat Fuse truck—4000 A CB 4500 be enclosed. The National Electrical for control. Manufacturers Association (NEMA) Structures—3200 A 4000 9 Structures—4000 A 5000 has developed a set of standards to Because many countries around Structures—5000 A 7000 ensure the consistent application the world refer to International High resistance grounding 1200 performance of enclosures. Electrotechnical Commission 10 standards (IEC), designers should Panelboards (Indoor, 480 V) As an example, the panelboard shown reference Ta b l e 1. 7- 5 to determine the 225 A, 42 circuit 300 in Figure 1.2-2 is called out as being appropriate alternate enclosure rating. Low-Voltage Busway (Indoor, Copper, 480 V) 11 NEMA 4X. Ta b l e 1. 7- 2 and Table 1.7-3, show the various performance data 800 A 44 per foot 1200 A 60 per foot for these enclosures in indoor and 1350 A 66 per foot 12 outdoor applications respectively. 1600 A 72 per foot Ta b l e 1. 7- 4 covers enclosures to be 2000 A 91 per foot installed in explosive or hazardous 2500 A 103 per foot 13 environments. 3200 A 144 per foot 4000 A 182 per foot 5000 A 203 per foot 14 Motor Control Centers (Indoor, 480 V) NEMA Size 1 starter 39 NEMA Size 2 starter 56 15 NEMA Size 3 starter 92 NEMA Size 4 starter 124 NEMA Size 5 starter 244 16 Structures 200 Adjustable Frequency Drives (Indoor, 480 V) 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

CA08104001E For more information, visit: www.eaton.com/consultants 1.7-2 Power Distribution Systems Typical Components of a Power System August 2017 Sheet 01 082

Enclosures i The following are reproduced from NEMA 250. ii Table 1.7-2. Comparison of Specific Applications of Enclosures for Indoor Nonhazardous Locations Provides a Degree of Protection Against the Enclosure Type Following Environmental Conditions 1 1 2 1 4 4X 5 6 6P 12 12K 13

1 Incidental contact with the enclosed equipment ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ Falling dirt ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ Falling liquids and light splashing ■ ■ ■ ■ ■ ■ ■ ■ ■ 2 Circulating dust, lint, fibers and flyings 2 ■ ■ ■ ■ ■ ■ ■ Settling airborne dust, lint, fibers and flyings 2 ■ ■ ■ ■ ■ ■ ■ ■ Hosedown and splashing water ■ ■ ■ ■ Oil and coolant seepage ■■■ 3 Oil or coolant spraying and splashing ■ Corrosive agents ■■ Occasional temporary submersion ■■ 4 Occasional prolonged submersion ■ 1 These enclosures may be ventilated. 2 These fibers and flying are nonhazardous materials and are not considered the Class III type ignitable fibers or combustible flyings. For Class III type 5 ignitable fibers or combustible flyings, see the National Electrical Code, Article 500.

Table 1.7-3. Comparison of Specific Applications of Enclosures for Outdoor Nonhazardous Locations 6 Provides a Degree of Protection Against the Enclosure Type Following Environmental Conditions 33R 3 3S 4 4X 6 6P 7 Incidental contact with the enclosed equipment ■ ■ ■ ■ ■ ■ ■ Rain, snow and sleet 4 ■ ■ ■ ■ ■ ■ ■ Sleet 5 ■ Windblown dust ■■■■ ■ ■ 8 Hosedown ■ ■ ■ ■ Corrosive agents ■ ■ Occasional temporary submersion ■■ 9 Occasional prolonged submersion ■ 3 These enclosures may be ventilated. 4 External operating mechanisms are not required to be operable when the enclosure is ice covered. 10 5 External operating mechanisms are operable when the enclosure is ice covered.

Table 1.7-4. Comparison of Specific Applications of Enclosures for Indoor Hazardous Locations 11 Provides a Degree of Protection Against Class Enclosure Types Enclosure Type Atmospheres Typically Containing 7 and 8, Class I Groups 6 9, Class II Groups 6 (For Complete Listing, See NFPA 497M) 12 ABCDEFG10 Acetylene I ■ Hydrogen, manufactured gas I ■ diethyl ether, ethylene, cyclopropane I ■ 13 Gasoline, hexane, butane, naphtha, propane, acetone, toluene, isoprene I ■ Metal dust II ■ 14 Carbon black, coal dust, coke dust II ■ Flour, starch, grain dust II ■ Fibers, flyings 7 III ■ 15 Methane with or without coal dust MSHA ■ 6 For Class III type ignitable fibers or combustible flyings, see the National Electrical Code, Article 500. 7 Due to the characteristics of the gas, vapor or dust, a product suitable for one class or group may not be suitable for another class or group unless so 16 marked on the product. Note: If the installation is outdoors and/or additional protection is required by Tables 1.7-2 and 1.7-3, a combination-type enclosure is required. 17

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.7-3 August 2017 Typical Components of a Power System Sheet 01 083

Table 1.7-5. Conversion of NEMA Enclosure Type Ratings to IEC 60529 Enclosure Classification Designations (IP) (From NEMA Publication 250) (Cannot be Used to Convert IEC Classification Designations to NEMA Type Ratings) i

EXAMPLE OF TABLE USE An IEC IP45 Enclosure Rating is specified. What NEMA Type Enclosures meet and exceed the IP45 rating? 6 Referencing the first character, 4, in the IP rating and the row designated “IP4–” in the leftmost column in the 7 table; the blocks in Column “A” for NEMA Types 3, 3S, 4, 4X, 5, 6, 6P, 12, 12K and 13 are shaded. These NEMA ratings meet and exceed the IEC protection requirements against access to hazardous parts and solid foreign objects. Referencing the second character, 5, in the IP rating and the row designated “IP–5” in the rightmost 8 column in the table; the blocks in Column “B” for NEMA Types 3, 3S, 4, 4X, 6 and 6P are shaded. These NEMA ratings meet and exceed the IEC requirements for protection against the ingress of water. The absence of shading in Column “B” beneath the “NEMA Enclosure Type 5” indicates that Type 5 does not meet the IP45 protection 9 requirements against the ingress of water. Likewise, the absence of shading in Column “B” for NEMA Type 12, 12K and 13 enclosures indicates that these enclosures do not meet the IP45 requirements for protection against the ingressof water. Only Types 3, 3S, 4, 4X, 6 and 6P have both Column “A” in the “IP4–” row and Column “B” 10 in the “IP–5” row shaded and could be used in an IP45 application. The NEMA Enclosure Type 3 not only meets the IP45 Enclosure Rating, but also exceeds the IEC requirements 11 because the NEMA Type requires an outdoor corrosion test; a gasket aging test; a dust test; an external icing test; and no water penetration in the rain test. Slight differences exist between the IEC and NEMA test methods, but the IEC rating permits the penetration of water if “it does not deposit on insulation parts, or reach live parts.” 12 The IEC rating does not require a corrosion test; gasket aging test; dust test or external icing test. Because the NEMA ratings include additional test requirements, this table cannot be used to select IP Designations for NEMA rated enclosure specifications. 13 IEC 60529 specifies that an enclosure shall only be designated with a stated degree of protection indicated by the first characteristic numeral if it also complies with all lower degrees of protection. Furthermore, IEC 60529 14 states that an enclosure shall only be designated with a degreeof protection indicated by the second characteristic numeral if it also complies with all lower degrees of protection up to and including the secondcharacteristic numeral 6. An enclosure designated with a second characteristic numeral 7 or 8 only is considered unsuitable 15 for exposure to water jets (designated by second characteristic numeral 5 or 6) and need not comply with requirements for numeral 5 or 6 unless it is dual coded. Because the IEC protection requirements become more stringent with increasing IP character value up through 6, once a NEMA Type rating meets the requirements for 16 an IP designation up through 6, it will also meet the requirements for all lower IP designations. This is apparent from the shaded areas shown in the table. 17

CA08104001E For more information, visit: www.eaton.com/consultants 1.7-4 Power Distribution Systems Typical Components of a Power System August 2017 Sheet 01 084

Transformers Transformers were the key component For example, a 300 kVA three-phase i in the growth of alternating current power transformer has 5% impedance The work of early electrical pioneer (AC) distribution systems over whereas higher kVA transformers have Michael Faraday, in documenting the the direct current (DC) alternative 5.75%. See Ta b l e 1. 7- 7 for information ii principal of electro-magnetic induction, promoted by Thomas Edison. on transformer secondary FLA ratings led to a discovery that voltage flowing and short-circuit current available. NEMA has worked through the years through a coil wrapped around a donut to standardize transformer primary Because there are a number of 1 shaped piece of iron could induce a and secondary full load amperes categories with the ANSI C57 family, voltage in a second coil of wire also (FLA). Ta b l e 1. 7- 6 is a compilation of the design engineer needs to pinpoint wrapped around the iron. This various transformers kVA and primary the transformer design type. When 2 discovery was key to Faraday’s work voltages along with their primary FLA. designing systems involving different in 1831 and became the basis for types of transformers such as larger others in the development of Transformers are designed with a fluid-filled units like the 7500 kVA 3 transformer technology. specific number of primary versus (7.5 MVA) unit “T1” shown in secondary winding turns. These are While Sebastian Ferranti and others Figure 1.2-2 on Page 1.2-4, the a ratio of the primary voltage to the continued to develop and patent impedance can be 6.5% or greater. 4 secondary voltage. Each winding transformer technology, it was a has a specific amount of resistance, Ta b l e 1. 7- 8 through Table 1.7-12 demonstration of a power transformer however, when first energized, acts provide further information on the during 1884 in Turin, Italy that caught 5 like a short circuit drawing a high impedances and electrical characteris- the attention of George Westinghouse. inrush current that falls off as the tics of various styles of transformers. In 1885, Westinghouse purchased the core material magnetizes. This Note that smaller dry-type distribution American rights to manufacture the 6 combination of electrical properties transformers may not have uniform transformer developed by Lucien is termed impedance. impedances across various manufac- Gaulard and John Gibbs. turers due to design characteristics 7 Dry-type power transformers that meet In subsequent years, William and construction tolerances. the ANSI C57 standard follow a specific Stanley, Jr., Westinghouse’s chief requirement for impedance based on Eaton markets dry-type distribution engineer, would alter the Gaulard and 8 their kVA rating and type. Lower transformers (see Section 19), Gibbs design by changing the series impedances allow more secondary secondary substation transformers coil arrangement to a parallel coil short-circuit current to flow versus in liquid and dry configurations design. Stanley also developed the 9 higher impedance versions. (see Section 14), liquid and dry net- “E” coil using laminated stamped steel work transformers (see Section 18), core pieces. Both of these innovations tamper-proof pad-mounted, liquid improved the transformer by stabiliz- 10 filled transformers (see Section 17), ing its regulation as well as improving and liquid-filled and dry-type primary its manufacturability and efficiency. substation transformers (see Section 11 13). The features of each type of transformer are explained with the 12 individual sections of this guide. Table 1.7-6. Transformer Full-Load Current, Three-Phase, Self-Cooled Ratings Voltage, Line-to-Line 13 kVA 208 240 480 600 2400 4160 7200 12,000 12,470 13,200 13,800 22,900 34,400

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 14 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 1.26 112-1/2 312 271 135 108 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 15 225 625 541 271 217 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 5.04 500 1388 1203 601 481 120 69.4 40.1 24.1 23.1 21.9 20.9 12.6 8.39 16 750 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 1500 4164 3608 1804 1443 361 208 120 72.2 69.4 65.6 62.8 37.8 25.2 17 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 3750 — — 4511 3608 902 520 301 180 174 164 157 94.5 62.9 18 5000 — — — 4811 1203 694 401 241 231 219 209 126 83.9 7500 — — — — 1804 1041 601 361 347 328 314 189 126 10,000 — — — — 2406 1388 802 481 463 437 418 252 168 19

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.7-5 August 2017 Typical Components of a Power System Sheet 01 085

Table 1.7-7. 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

CA08104001E For more information, visit: www.eaton.com/consultants 1.7-6 Power Distribution Systems Typical Components of a Power System August 2017 Sheet 01 086

Approximate Impedance Data Table 1.7-11. 15 kV Class Primary— Table 1.7-13. 600V Primary Class Three-Phase i Dry-Type Substation Transformers DOE 2016 Energy-Efficient Dry-Type Table 1.7-8. 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 ii kVA Liquid-Filled 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 1 45 — — 1000 5.75 2.16 5.33 2.47 45 3.80 2.60 2.77 0.94 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 2 112.5 — 3.4 2500 5.75 1.74 5.48 3.15 150 3.02 2.64 1.46 1.81 150 — 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 3 500 5.75 1.44 5.57 3.87 500 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 4 1500 5.75 0.87 5.68 6.51 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 5 3000 — 5.75 150 3.34 3.05 1.37 2.23 3750 — 6.00 Table 1.7-12. 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 6 1 Values are typical. For guaranteed values, 80 °C Rise Copper 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 7 Table 1.7-9. 15 kV Class Primary— 45 1.70 1.16 1.25 0.93 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 8 150 2.89 2.65 1.15 2.31 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 9 150 5.00 1.88 4.63 2.47 225 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 10 750 5.75 1.41 5.57 3.96 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 11 2000 5.75 0.93 5.67 6.10 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 12 Table 1.7-10. DOE 2016 Transformer 225 4.90 4.73 1.28 3.69 Efficiencies—Medium-Voltage Three-Phase 300 4.80 4.65 1.21 3.85 Distribution Transformers 1 13 80 °C Rise Aluminum kVA % Efficiency 15 4.19 2.94 2.98 0.99 Liquid- Dry Transformers 30 2.50 1.76 1.78 0.99 14 Filled 45 2.43 2.01 1.37 1.46 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 15 98.65 97.5 97.18 — 225 3.35 3.20 0.99 3.23 30 98.83 97.9 97.63 — 45 98.92 98.1 97.86 — 16 75 99.03 98.33 98.13 — 112 . 5 99.11 98.52 98.36 — 150 99.16 98.65 98.51 — 17 225 99.23 98.82 98.69 98.57 300 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 18 1000 99.43 99.28 99.2 99.11 1500 99.48 99.37 99.3 99.21 2000 99.51 99.43 99.36 99.28 19 2500 99.53 99.47 99.41 99.33 1 Based on transformer operating at 50% of 20 nameplate base kVA.

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.7-7 August 2017 Typical Components of a Power System Sheet 01 087

Transformer Loss Data Transformer losses for various At 0% load: loading can be estimated in the 1800 watts i Data for the following calculations can following manner. The no load watt be found in Section 14—Secondary losses of the transformer are due to At 50% load: Unit Substations. magnetization and are present 1800 watts + (13,300)(0.5)2 = ii Transformer Losses at Reduced Loads whenever the transformer is 1800 watts + 3325 watts = 5125 watts energized. The load watt losses are Information on losses based on actual the difference between the no load At 100% load: 1 transformer test data can be obtained watt losses and the full load watt 1800 watts + 13,300 watts = 15,100 watts from the manufacturer. Transformer losses. The load watt losses are manufacturers provide no load watt At 110% load: proportional to I2R and can be 2 losses and total watt losses in accor- estimated to vary with the transformer 1800 watts + (13,300)(1.1)2 = dance with ANSI standards. The load by the square of the load current. 1800 watts + 16,093 watts = 17,893 watts calculated difference between the 3 no load losses and the total losses For example, the approximate watts Because transformer losses vary are typically described as the load loss data for a 1000 kVA oil-filled between designs and manufacturers, losses. Although transformer coils substation transformer is shown in additional losses such as from 4 are manufactured with either aluminum the table as having 1800 watts no cooling fans can be ignored for or copper conductors, the industry load losses and 15,100 watts full load these approximations. has sometimes referred to these load losses, so the load losses are approxi- Note: 1 watthour = 3.413 Btu. 5 losses as the “copper losses.” mately 13,300 watts (15,100–1800). The transformer losses can be calculated for various loads as follows. 6

CA08104001E For more information, visit: www.eaton.com/consultants 1.7-8 Power Distribution Systems Typical Components of a Power System August 2017 Sheet 01 088

Table 1.7-7. Three-Phase Transformer Winding Connections i Phasor Notes Diagram ii DELTA-DELTA Connection 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 1 Diagram:

2 H1 H3 X1 X3

Angular Displacement (Degrees): 0

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

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.7-9 August 2017 Typical Components of a Power System Sheet 01 089

Sound Levels Area Consideration Because values given in Table 1.7-9 In determining permissible sound lev- are in general higher than those given i Sound Levels of Electrical Equipment els within a building, it is necessary to in Ta b l e 1. 7- 8 , the difference must be for Offices, Hospitals, Schools and consider how the rooms are to be used attenuated by distance and by proper Similar Buildings and what levels may be objectionable use of materials in the design of ii Insurance underwriters and building to occupants of the building. The the building. It may appear that a owners require that the electrical ambient sound level values given in transformer is noisy because the level apparatus be installed for maximum Ta b l e 1. 7- 8 are representative average in the room where it is located is high. 1 safety and minimum impact on normal values and may be used as a guide in Two transformers of the same sound functioning of the property. Architects determining suitable building levels. output in the same room increase the should take particular care with the sound level in the room approximately 2 The decrease in sound level varies at designs for hospitals, schools and 3 dB, and three transformers by about an approximate rate of 6 dB for each similar buildings to keep the sound 5 dB, etc. A good engineer needs to doubling of the distance from the perception of such equipment as consider these factors while designing 3 source of sound to the listener. For motors, blowers and transformers the electrical rooms and allocating example, if the level 6 ft (1.8 m) from to a minimum. locations for the transformers. a transformer is 50 dB, the level at a 4 Even though transformers are distance of 12 ft (3.7 m) would be 44 dB In many buildings, floors between relatively quiet, resonant conditions and at 24 ft (7.3 m) the level decreases different levels can act like the sound may exist near the equipment, which to 38 dB, etc. However, this rule applies board in a piano. In these cases, 5 will amplify their normal 120 Hz hum. only to equipment in large areas sounds due to structure-transmitted Therefore, it is important that consid- equivalent to an out-of-door installation, vibrations originating from the trans- eration be given to the reduction of with no nearby reflecting surfaces. former are lowered by mounting the 6 amplitude and to the absorption of transformers on vibration dampeners Table 1.7-8. Typical Sound Levels energy at this frequency. This problem or isolators. There are a number of begins in the designing stages of Description Average different sound vibration isolating 7 the equipment and the building. Decibel materials that may be used with Level (dB) good results. There are two points worthy of Radio, recording and TV studios 25–30 8 consideration: Dry-type power transformers are often Theatres and music rooms 30–35 built with an isolator mounted between Hospitals, auditoriums and churches 35–40 ■ What sound levels are desired in the the transformer support and case 9 normally occupied rooms of this Classrooms and lecture rooms 35–40 members. The natural period of the Apartments and hotels 35–45 building? Private offices and conference rooms 40–45 core and coil structure when mounted ■ on vibration dampeners is about 10% To effect this, what sound level in Stores 45–55 10 the equipment room and what type Residence (radio, TV off) of the fundamental frequency. The of associated acoustical treatment and small offices 53 reduction in the transmitted vibration will give the most economical Medium office (3 to 10 desks) 58 is approximately 98%. 11 installation overall? Residence (radio, TV on) 60 Large store (5 or more clerks) 61 If the floor or beams beneath the A relatively high sound level in the Factory office 61 transformer are light and flexible, 12 equipment room does not indicate Large office 64 the isolator must be softer or have an abnormal condition within the Average factory 70 improved characteristics in order to apparatus. However, absorption may Average street 80 keep the transmitted vibrations to be necessary if sound originating in a minimum. (Enclosure covers 13 an unoccupied equipment room is Transformer Sound Levels and ventilating louvers are often objectionable outside the room. Transformers emit a continuous improperly tightened or gasketed 14 Furthermore, added absorption 120 Hz hum with harmonics when and their vibration can produce material usually is desirable if sound connected to 60 Hz circuits. The unnecessary noise.) is magnified due to reflections. fundamental frequency is the “hum” The building structure will assist the 15 that annoys people primarily because dampeners if the transformer is While some sound reduction or of its continuous nature. For purposes attenuation takes place as the sound mounted above heavy floor members of reference, sound measuring or if mounted on a heavy floor slab. 16 waves travel through building walls, instruments convert the different the remainder may be reflected in Positioning of the transformer in frequencies to 1000 Hz and a 40 dB relation to walls and other reflecting various directions, resulting in a level. Transformer sound levels based build-up or apparent higher levels. surfaces has a great effect on reflected 17 on NEMA publication TR-1 are listed noise and resonances. Often, placing This is especially true if resonance in Ta b l e 1. 7- 9 . occurs because of room dimensions the transformer at an angle to the or material characteristics. wall, rather than parallel to it, will 18 reduce noise. Electrical connections to a substation 19 transformer should be made with flexible braid or conductors; connections to an individually 20 mounted transformer should be in flexible conduit. 21

CA08104001E For more information, visit: www.eaton.com/consultants 1.7-10 Power Distribution Systems Typical Components of a Power System August 2017 Sheet 01 090

Table 1.7-9. Maximum Average Sound Levels i for Medium-Voltage Transformers—Decibels kVA Liquid-Filled Transformers Dry-Type Transformers Self-Cooled Forced-Air Self-Cooled Forced-Air ii Rating (OA) Cooled Rating (FA) Rating (AA) Cooled Rating (FA)

300 55 — 58 67 1 500 56 — 60 67 750 57 67 64 67 1000 58 67 64 67 1500 60 67 65 68 2 2000 61 67 66 69 2500 62 67 68 71 3000 63 67 68 71 3 3750 64 67 70 73 5000 65 67 71 73 6000 66 68 72 74 4 7500 67 69 73 75 10,000 68 70 — 76 5

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.7-11 August 2017 Typical Components of a Power System Sheet 01 091

Motor Protection Table 1.7-10. Motor Circuit Protector (MCP), Circuit Breaker and Fusible Switch Selection Guide i Consistent with the 2014 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 1.7-12 Power Distribution Systems Typical Components of a Power System August 2017 Sheet 01 092

Table 1.7-11. 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.

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.7-13 August 2017 Typical Components of a Power System Sheet 01 093

Generators and The other requirements for grounded Types of Generators systems were renumbered to accom- i Generator Systems modate the 250.30(A)(2) change. Generators can be either synchronous 250.30(B)(3)—Ungrounded Systems— or asynchronous. Asynchronous was added and this language requires generators are also referred to as ii a supply-side bonding jumper to be induction generators. The construction installed from the source of a sepa- is essentially the same as an induction rately derived system to the first dis- motor. It has a squirrel-cage rotor and 1 connecting means in accordance with wound stator. An induction generator 250.30(A)(2). Another new require- is a motor driven above its designed ment, 250.30(C)—Outdoor Source— synchronous speed thus generating 2 was added that requires a grounding power. It will operate as a motor if it electrode connection at the source is running below synchronous speed. Typical Diesel Genset—Caterpillar location when the separately derived The induction generator does not have 3 system is located outside of the build- Introduction an exciter and must operate in parallel ing or the structure being supplied. with the utility or another source. The The selection and application 4 Article 445.19—Generators Supplying induction generator requires VARs from of generators into the electrical an external source for it to generate distribution system will depend on Multiple Loads—was also revised to require that the generator have power. The induction generator the particular application. There are operates at a slip frequency so its 5 many factors to consider, including overcurrent protection per 240.15(A) when using individual enclosures output frequency is automatically code requirements, environmental locked in with the utility's frequency. constraints, fuel sources, control tapped from a single feeder. 6 complexity, utility requirements and Article 517.17(B)—Feeder Ground Fault An induction generator is a popular load requirements. The healthcare Protection (Healthcare Facilities)—now choice for use when designing requirements for legally required allows, but does not require, multiple cogeneration systems, where it will 7 emergency standby generation levels of Ground Fault Protection operate in parallel with the utility. systems are described starting Equipment (GFPE) upstream of the This type of generator offers certain on Page 1.8-1. transfer switch when the choice is advantages over a synchronous 8 generator. For example, voltage and Systems described in this section are made to provide GFPE on the alternate power source (i.e., generator). frequency are controlled by the utility; applicable to healthcare requirements, thus voltage and frequency regulators 9 as well as other facilities that may Article 701.6(D)—Signals (Legally are not required. In addition, the require a high degree of reliability. Required Standby Systems)—now generator construction offers high The electrical supply for data centers, requires ground fault indication for reliability and little maintenance. 10 financial institutions, telecommunica- legally required standby systems of Also, a minimum of protective relays tions, government and public more than 150 V to ground and OCPDs and controls are required. Its major utilities also require high reliability. rated 1000 A or more. disadvantages are that it requires 11 Threats of disaster or terror attacks VARs from the system and it normally have prompted many facilities to Types of Engines cannot operate as a standby/ require complete self-sufficiency for emergency generator. 12 continuous operation. Many generator sets are relatively small in size, typically ranging from Synchronous generators, however, NEC Changes Related to several kilowatts to several megawatts. are the most common. Their output is 13 These units are often required to come determined by their field and governor Generator Systems online and operate quickly. They need controls. Varying the current in the Article 250.30—Grounding Separately to have the capacity to run for an DC field windings controls the voltage 14 Derived AC Systems—was completely extended period of time. output. The frequency is controlled rewritten for clarity and for usability in by the speed of rotation. The torque The internal combustion engine is an the 2011 NEC. Most notably, the term applied to the generator shaft by excellent choice as the prime mover 15 equipment bonding jumper was the driving engine controls the power for the majority of these applications. changed to supply-side bonding jumper output. In this manner, the synchro- Diesel-fueled engines are the most (see 250.30(A)(2)). This was necessary nous generator offers precise control common, but other fuels used include 16 to ensure proper identification and over the power it can generate. In natural gas, digester gas, landfill gas, installation of bonding conductors cogeneration applications, it can be propane, biodiesel, crude oil, steam within or on the supply side of service used to improve the power factor of and others. 17 equipment and between the source of a the system. separately derived system and the first Some campuses and industrial facilities disconnecting means. use and produce steam for heating and 18 other processes. These facilities may find it economically feasible to produce electricity as a byproduct of the steam 19 production. These installations would typically be classified as a cogeneration facility producing a fairly constant 20 power output and operating in parallel with the electric utility system. 21

CA08104001E For more information, visit: www.eaton.com/consultants 1.7-14 Power Distribution Systems Typical Components of a Power System August 2017 Sheet 01 094

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 1.7-2 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 frequency for load sharing. They may This is typically referred to as an switches. The generators and the also require multiple levels of load emergency standby generator utility are never continuously shedding and/or load restoration 2 system. Figure 1.7-1 shows a single connected together in this scheme. schemes to match generation capacity. standby generator, utility source Multiple Generators Operating in and a transfer switch. Multiple generators may be required 3 to meet the load requirements Parallel with Utility System In this case, the load is either supplied (N system). Generators may be The third type of system is either one from the utility or the generator. The applied in an N+1 or a 2N system with a single or multiple generators 4 generator and the utility are never for improved system reliability. that operate in parallel with the utility continuously connected together. This system. Figure 1.7-3 shows two simple radial system has few require- generators and a utility source feeding

5 ments for protection and control. It also Utility a switchgear lineup feeding multiple has the least impact on the complete G1 G2 loads. This system typically requires electric power distribution system. generator capacity sufficient to carry 6 It should be noted that this type of the entire load or sophisticated load generator system improves overall Switchgear shedding schemes. This system will electrical reliability but does not require a complete and complex 7 provide the redundancy that some protection and control scheme. The facilities require if the generator fails ATS-1 ATS-2 electric utility may have very stringent to start or is out for maintenance. and costly protection requirements 8 for the system. IEEE standard 1547

Load 1 Load 2 describes the interconnection requirements for paralleling to the utility. 9 Utility G1 Figure 1.7-2. Multiple Isolated Set of Standby Generators Utility 10 G1 G2 In an N system, where N is the number of generators required to carry the 11 load; if a generator fails or is out for Switchgear maintenance, then the load may be dropped. This is unacceptable for most 12 ATS critical 24/7 operations. In an N + 1 system, N is the number of generators needed to carry the load and 1 is an extra generator for redundancy. If one 13 Load 1 Load 2 Load 3 Load generator fails to start or is out for maintenance, it will not affect the load. 14 Figure 1.7-3. Multiple Generators Operating Figure 1.7-1. Emergency Standby In a 2N system, there is complete 100% in Parallel with Utility System Generator System redundancy in the standby generation system such that the failure of one 15 complete set of generators will not affect the load. 16

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.7-15 August 2017 Typical Components of a Power System Sheet 01 095

Generator Fundamentals The application of generators adds An IEEE working group has studied the special protection requirements to practice of low resistance grounding i A generator consists of two primary the system. The size, voltage class, of medium-voltage generators within components, a prime mover and an importance and dollar investment the general industry. This “working alternator. The prime mover is the will influence the protection scheme group” found that, for internal generator ii energy source used to turn the rotor associated with the generator(s). The ground faults, the vast majority of the of the alternator. It is typically a mode of operation will influence the damage is done after the generator diesel combustion engine for most utility company’s interface protection breaker is tripped offline, and the field 1 emergency or standby systems. requirements. Paralleling with the and turbine are tripped. This is due to In cogeneration applications, the electric utility is the most complicated the stored energy in the generator flux prime mover may come from a steam of the utility inter-tie requirements. driven turbine or other source. On that takes several seconds to dissipate 2 IEEE ANSI 1547 provides recom- after the generator is tripped offline. diesel units, a governor and voltage mended practices. regulator are used to control the speed It is during this time that the low 3 and power output. Generator Grounding and Bonding resistance ground allows significant The alternator is typically a synchro- (Ref. NEC 2014, Article 250.30(A)(1) amounts of fault current to flow into nous machine driven by the prime the ground fault. Because the large 4 mover. A voltage regulator controls its and (2)) fault currents can damage the voltage output by adjusting the field. Generator grounding methods need generator’s winding, application of The output of a single generator or to be considered and may affect the an alternate protection method is 5 multiple paralleled generator sets is distribution equipment and ratings. desirable during this time period. controlled by these two inputs. The Generators may be connected in delta One of the solutions set forth by this alternator is designed to operate at a or wye, with wye being the most “working group” is a hybrid high 6 specified speed for the required output typical connection. A wye-connected resistance grounding (HHRG) scheme frequency, typically 60 or 50 Hz. The generator can be solidly grounded, as shown in Figure 1.7-4. voltage regulator and engine governor low impedance grounded, high In the HHRG scheme, the low 7 along with other systems define the impedance grounded or ungrounded. resistance ground (LRG) is quickly generator’s response to dynamic Section 1.4 discusses general ground- tripped offline when the generator load changes and motor starting ing schemes, benefits of each and protection senses the ground fault. 8 characteristics. protection considerations. The LRG is cleared at the same time Generators are rated in power and A solidly grounded generator may have that the generator breaker clears, 9 voltage output. Most generators are a lower zero sequence impedance than leaving the high resistance ground designed to operate at a 0.8 power its positive sequence impedance. In this portion connected to control the factor. For example, a 2000 kW case, the equipment will need to be rated transient overvoltages during the 10 generator at 277/480 V would have a for the larger available ground fault coast-down phase of the generator, kVA rating of 2500 kVA (2000 kW/ current. The generator’s neutral may thereby all but eliminating generator 08 pf) and a continuous··· current rating be connected to the system-neutral; if damage. 11 of 3007A2500 kVA 480V 3 . it is, the generator is not a separately derived system and a three-pole transfer Typical synchronous generators switch is used. for industrial and commercial 12 power systems range in size from If the generator’s neutral is bonded to 100–3000 kVA and from 208 V–13,800 V. ground separate from the system- Other ratings are available and these neutral, it is a separately derived 13 discussions are applicable to those system and a four-pole transfer switch ratings as well. is required or ground fault relays could misoperate and unbalanced neutral 14 Generators must be considered in the current may be carried on ground short-circuit and coordination study conductors. as they may greatly impact the rating 15 of the electrical distribution system. This is especially common on large installations with multiple generators HRG 16 and systems that parallel with the utility source. Short-circuit current 51G Gen R 59G contribution from a generator 86 17 typically ranges from 8 to 12 times LRGR Phase 87GN full load amperes. Relays 18

20 Figure 1.7-4. Hybrid High Resistance Grounding Scheme 21

CA08104001E For more information, visit: www.eaton.com/consultants 1.7-16 Power Distribution Systems Typical Components of a Power System August 2017 Sheet 01 096

Generator Controls During this time, the breakers for Generator Short-Circuit i the other generators are held open The engine generator set has controls and not permitted to close until Characteristics to maintain the output frequency certain conditions are met. Once ii (speed) and voltage. These controls the paralleling bus is energized, If a short circuit is applied directly to consist of a governor and voltage the remaining generators must the output terminals of a synchronous regulator. As loads change on the be synchronized to it before the generator, it will produce an extremely 1 system, the frequency and voltage generators can be paralleled. high current initially, gradually decaying will change. The speed control will to a steady-state value. This change then adjust the governor to correct Synchronization compares the voltage is represented by a varying reactive 2 for the load (kW) change. The phasor’s angle and magnitude. Both impedance. Three specific reactances voltage regulator will change the generators must be operating at the are used for short-circuit fault currents. field current to adjust the voltage same frequency and phase-matched They are: to the desired voltage value. These within typically 5 to 10 degrees with 3 ■ are the basic controls found on all each other. The voltage magnitude Subtransient reactance Xd”, which is synchronous generators. typically must be within 20 to 24%. used to determine the fault 4 current during the first 1 to 5 cycles Multiple generator systems require A synch-scope is typically supplied ■ Transient reactance Xd’, which is more sophisticated controls. Generators on paralleling gear. The synch-scope used to determine the fault current 5 are paralleled in a multi-generator displays the relative relationship during the next 5 to 200 cycles system and they must share the load. between voltage phasors on the ■ Synchronous reactance Xd”, which is These systems often have a load shed generator to be paralleled and used to determine the steady- state 6 scheme, which adds to the complexity. the bus. fault current Multiple generator schemes need a If the generator is running slower than The subtransient reactance Xd” will master controller to prevent units from the bus (less than 60 Hz) then the range from a minimum of approxi- 7 being connected out-of-phase. The needle on the scope will spin in the mately 9% for a two-pole, wound-rotor sequence of operation is to send a counterclockwise direction. If it is machine to approximately 32% for a start signal to all generators simulta- running faster, then it will rotate in low-speed, salient-pole, hydro-generator. 8 neously. The first unit up to frequency the clockwise direction. The greater The initial symmetrical fault current and voltage will be permitted to close the frequency difference, the faster can be as much as 12 times full its respective breaker and energize the is the rotation. It is important that the load current. 9 paralleling bus. generators are in phase before they are paralleled. Severe damage will Depending on the generator type, occur if generators are paralleled the zero sequence impedance may be 10 out-of-phase. less than the subtransient reactance and the ground fault current substantially higher than the three-phase 11 short-circuit current. For example, a 2500 kVA, 480/277 V, four-pole, 2/3 pitch standby generator has a 0.1411 12 per unit subtransient reactance Xd” and a 0.033 per unit zero sequence Xo reactance. The ground current is 13 approximately a third larger than the three-phase fault current. The ground fault current can be reduced to the 14 three-phase level by simply adding a small reactance between the generator neutral and ground while still being 15 considered solidly grounded. An electric power system analysis 16 must be performed based on the worst- case operating conditions. Typically this is when all sources are paralleled. 17 If the system can operate with both the utility supply and generators in parallel, then the equipment must be 18 rated for the combined fault current plus motor contribution. If the generator and utility will not be paralleled, then 19 both cases will need to be looked at independently and the worst case used for selecting the equipment ratings. 20

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.7-17 August 2017 Typical Components of a Power System Sheet 01 097

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. 1 The simplest is a single generator 3 system used to feed emergency Gen 51G 87 3 and/or standby loads. In this case, the generator is the only source 1 available when it is operating in the 51 Preferred 4 Location Gen emergency mode and must keep operating until the normal source 1 5 returns. 51G Figure 1.7-5 Part (A) shows minimum recommended protection for a single (A) (A) Single Isolated Generator on Low-Voltage System (B) 6 generator used as an emergency or (B) Multiple Isolated Generator on Medium-Voltage System standby system. Phase and ground time overcurrent protection (Device Figure 1.7-5. Typical Protective Relaying Scheme for Small Generators 7 51 and 51G) will provide protection for external faults. For medium-voltage generators, a voltage controlled time 8 overcurrent relay (Device 51V) is R recommended for the phase protection as it can be set more sensitive 9 than standard overcurrent relays and is less likely to false operate on 50/5A 87-1 normal overloads. 10

This scheme may not provide 50/5A 87-2 adequate protection for internal 11 generator faults when no other power source exists. Local generator 50/5A 87-3 controllers may offer additional 12 protection for voltage and frequency conditions outside the generator’s capabilities. 13 Figure 1.7-5 Part (B) shows the recommended protection for multiple, Gen isolated, medium-voltage, small 14 generators. Additional protection may be desired and could include 15 generator differential, reverse power, and loss of field protection. Differential protection (Device 87) can be accom- 16 plished with either a self-balancing set of CTs as in Figure 1.7-6 or with Figure 1.7-6. Self-Balancing Generator a percentage differential scheme as Differential Relay Scheme 17 in Figure 1.7-7 on Page 1.7-18. The percentage differential scheme offers the advantage of reducing the 18 possibility for false tripping due to CT saturation. The self-balancing scheme offers the advantages of 19 increased sensitivity, needing three current transformers in lieu of six, and the elimination of current transformer 20 external wiring from the generator location to the generator switchgear location. 21

CA08104001E For more information, visit: www.eaton.com/consultants 1.7-18 Power Distribution Systems Typical Components of a Power System August 2017 Sheet 01 098

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 approximately 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 52 7 machines beyond their capability and the entire system. 8

To Main Bus OC = Operating coil PC = Permissive coil 10 Figure 1.7-7. Generator Percentage Differential Relay (Phase Scheme) and Ground Differential Scheme Using a Directional Relay 11

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.7-19 August 2017 Typical Components of a Power System Sheet 01 099

Typical protection for larger generators is shown in Figure 1.7-8. 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. 1

Unbalanced loads, fault conditions 27/59 or open phasing will produce a 2 negative sequence current to flow. The unbalanced currents induce double system frequency currents in the 3 1 1 1 3 rotor, which quickly causes rotor 51V 40 32 46 overheating. Serious damage will occur to the generator if the unbalance 3 1 4 is allowed to persist. 87 87G 60 Other protection functions such as under/overvoltage (Device 27/59) could Voltage Regulator and 5 Metering Circuits be applied to any size generator. The 1 voltage regulator typically maintains 1 64 the output voltage within its desired 6 output range. This protection can 49 provide backup protection in case the voltage regulator fails. Under/over 7 Gen frequency protection (Device 81U/81O) E could be used for backup protection for the speed control. Sync check 8 relays (Device 25) are typically applied as a breaker permissive close function 9 where generators are paralleled. 51G Many modern protective relays are microprocessor-based and provide a 10 full complement of generator protection functions in a single package. The cost per protection function has been 11 drastically reduced such that it is Figure 1.7-8. Typical Protective Relaying Scheme for Large Generator feasible to provide more complete protection even to smaller generators. 12 IEEE ANSI 1547 provides recommended practices for utility inter-tie protection. 13 If the system has closed- transition or paralleling capability, additional protection may be required by the utility. 14 Typically, no additional protection is required if the generator is paralleled to the utility for a maximum of 15 100 msec or less. Systems that offer soft transfer, peak 16 shaving or co-generation will require additional utility inter-tie protection. The protection could include directional 17 overcurrent and power relays and even transfer trip schemes. Please consult your local utility for specific 18 requirements. 19

CA08104001E For more information, visit: www.eaton.com/consultants 1.7-20 Power Distribution Systems Typical Components of a Power System August 2017 Sheet 01 100

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 ii Many factors must be considered 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 1 generator set. The engine or prime 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 2 (frequency) control through the use standby rating of 2000 kW at 0.8 power chamber, resulting in a very responsive of an engine governor. factor (pf) and a continuous rating of engine-generator. 1825 kW at 0.8 pf. 3 The generator is sized to supply the A natural gas engine is challenged with kVA needed at startup and during The lower continuous rating is due to air-fuel flow dynamics and a much normal running operation. It also the additional hours of operation and more indirect path from the engine 4 provides voltage control through the higher load that the continuous genset governor (throttle actuator) and fuel use of a brushless exciter and voltage must carry. These additional require- delivery system (natural gas pressure regulator. Together the engine and ments put more stress on the engine regulator, fuel valve and actuator, 5 generator provide the energy and generator and therefore the rating carburetor mixer, aftercooler, intake necessary to supply electrical loads is decreased to maintain longevity of manifold) to the combustion chamber. in many different applications the equipment. This results in a less responsive encountered in today’s society. engine-generator. Diesel gensets 6 Different generator set manufacturers The generator set must be able to recover about twice as fast as natural use basically the same diesel genset gas gensets. supply the starting and running electrical rating definitions. These are 7 electrical load. It must be able to based on International Diesel Fuel For the actual calculations involved pick up and start all motor loads and Stop Power standards from organiza- for sizing a genset, there are readily low power factor loads, and recover tions like ISO, DIN and others. accessible computer software programs 8 without excessive voltage dip or that are available on the genset manu- ■ extended recovery time. Standby diesel genset rating— facturer’s Internet sites or from the Typically defined as supplying manufacturer’s dealers or distributors. 9 Nonlinear loads like variable frequency varying electrical loads for the drives, uninterruptible power supply These programs are used to quickly duration of a power outage with the and accurately size generator sets for (UPS) systems and switching power load normally connected to utility, 10 supplies also require attention because their application. The programs take genset operating <100 hours per into consideration the many different the SCR switching causes voltage year and no overload capability and current waveform distortion and parameters discussed above, including ■ 11 harmonics. The harmonics generate Prime plus 10 rating—Typically the size and type of the electrical loads additional heat in the generator wind- defined as supplying varying (resistive, inductive, SCR, etc.), reduced ings, and the generator may need to electrical loads for the duration voltage soft starting devices (RVSS), 12 be upsized to accommodate this. of a power outage with the load motor types, voltage, fuel type, site normally connected to utility, genset conditions, ambient conditions and The type of fuel (diesel, natural gas, operating <500 hours per year and other variables. propane, etc.) used is important as it is overload capability of 10% above its 13 a factor in determining generator set rating for 1 hour out of 12 The software will optimize the starting response to transient overloads. It is ■ Continuous rating—Typically sequences of the motors for the least 14 also necessary to determine the load defined as supplying unvarying amount of voltage dip and determine factor or average power consumption electrical loads (i.e., base loaded) the starting kVA needed from the of the generator set. This is typically for an unlimited time genset. It also provides transient response data, including voltage defined as the load (kW) x time ■ 15 Load management ratings—Apply dip magnitude and recovery duration. (hrs. while under that particular load) / to gensets in parallel operation with total running time. When this load If the transient response is unaccept- the utility or isolated/islanded from able, then design changes can be 16 factor or average power is taken into utility and these ratings vary in consideration with peak demand considered, including oversizing the usability from <200 hours per generator to handle the additional kvar requirements and the other operating year to unlimited usage 17 parameters mentioned above, the load, adding RVSS devices to reduce overall electrical rating of the genset Refer to generator set manufacturers the inrush current, improving system can be determined. for further definitions on load manage- power factor and other methods. ment ratings, load factor or average 18 Other items to consider include the The computer software programs are power consumption, peak demand quite flexible in that they allow changes unique installation, ambient, and site and how these ratings are typically requirements of the project. These to the many different variables and 19 applied. Even though there is some parameters to achieve an optimum will help to determine the physical standardization of these ratings across configuration of the overall system. design. The software calculates how the manufacturers, there also exists to minimize voltage dips and can 20 some uniqueness with regard to recommend using paralleled gensets how each manufacturer applies their vs. a single genset. generator sets. 21

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.7-21 August 2017 Typical Components of a Power System Sheet 01 101

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.) across the line 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 least 40% concrete inertia pad, etc.) inspection, etc…) ■ for six-pulse technology drives. ■ 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 ❑ 200 hp motor...... 195 A ❑ 100 hp motor ...... 98 A 13 ❑ 60 hp motor...... 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 1.7-9. 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 1.4-19 for further discussion 20 on generator loading and reduced voltage starting techniques for motors. 21

CA08104001E For more information, visit: www.eaton.com/consultants 1.7-22 Power Distribution Systems Typical Components of a Power System August 2017 Sheet 01 102

Capacitors and Power Factor ANSI Standard C37.06 (indoor oilless Low-Voltage Capacitor Switching i circuit breakers) indicates the preferred 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 ii Considerations careful attention should be paid to rating in excess of rated capacitor 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 1 Standard C37.04 Article 5.13 (for the and harmonic currents. The following 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: 2 ■ Capacitor selection method of calculation of the Fused and unfused switches . . . .165% ■ Where to install capacitors in a plant quantities covered by C37.06 Standard. distribution system Molded-case breaker or 3 Note that the definitions in C37.04 equivalent ...... 150% ■ Locating capacitors on reduced make the switching of two capacitors voltage and multi-speed starters banks in close proximity to the switch- Insulated-case breakers ...... 135% ■ Harmonic considerations gear bus a back-to-back mode of 4 Magnum DS power ■ switching. This classification requires Eliminating harmonic problems circuit breaker ...... 135% ■ National Electrical Code a definite purpose circuit breaker 5 requirements (breakers specifically designed for Contactors: capacitance switching). Open type...... 135% Medium-Voltage 6 We recommend that such application Enclosed type ...... 150% 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 7 severe operating duty for a circuit switching should include as applicable: 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). 8 fully charged. After interruption, when 2. Rated frequency. See Ta b 3 5 for switching device 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 9 maximum, the voltage that appears switching current. as indicated (above). The interrupting 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. 10 to-neutral voltage of the circuit. If a available at the point of capacitor 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 11 to the circuit constants on the supply capacitor switching current. ultimate kvar capacity of the rack or 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 12 the normal line-to-neutral voltage. 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. 13 side voltage, the voltage across the 8. Rated interrupting time. Refer to Tab 35 for recommended open contact is even higher. selection of capacitor switching 9. Rated capacitive current devices; recommended maximum 14 switching life. capacitor ratings for various motor types and voltages; and for required 10. Grounding of system and multipliers to determine capacitor kvar 15 capacitor bank. required for power factor correction. Load break interrupter switches are permitted by ANSI/IEEE Standard 16 C37.30 to switch capacitance, but they must have tested ratings for the purpose. 17 Refer to Ta b 8 Eaton Type MVS ratings.

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.7-23 August 2017 Typical Components of a Power System Sheet 01 103

Motor Power Factor % AR (amp reduction) is the percent To derate a capacitor used on a system reduction in line current due to the voltage lower than the capacitor i Correction capacitor. A capacitor located on the voltage rating, such as a 240 V motor side of the overload relay capacitor used on a 208 V system, See Ta b 3 5 containing suggested reduces line current through the relay. use the following formula: ii maximum capacitor ratings for Therefore, a different overload relay Actual kvar = induction motors switched with the and/or setting may be necessary. capacitor. The data is general in nature 2 The reduction in line current may be Applied Voltage 1 and representative of general purpose Nameplate kvar  ------determined by measuring line current 2 induction motors of standard design. with and without the capacitor or by Nameplate Voltage The preferable means to select capacitor calculation as follows: 2 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   available from the motor manufacturer. (Improved PF) COS 1 to COS 2, the formula is: 3 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 An important point to remember Capacitors cause a voltage rise. 4 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 may cause a motor-damaging over- kvar in Table 5 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 line. In addition, high transient torques motor ratings as follows: formula: 6 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  MVASC 7 reconnected to the line while rotating kvar = 1.7–1.4 of kvar listed and still generating a voltage of self- % AR= 1.8–1.35 of % AR listed excitation. Low-speed pump motors, MVAR is the capacitor rating and MVASC or motors with more than four poles, B. For standard 50 Hz motors is the system short-circuit capacity. 8 will typically exhibit low power factor operating at 50 Hz: With the introduction of variable speed and high FLA. kvar = 1.4–1.1 of kvar listed drives and other harmonic current 9 % AR= 1.4–1.05 of % AR listed Definitions generating loads, the capacitor impedance value determined must kvar—rating of the capacitor in C. For standard 60 Hz wound-rotor not be resonant with the inductive reactive kilovolt-amperes. This value motors: 10 reactances of the system. is approximately equal to the motor kvar = 1.1 of kvar listed no-load magnetizing kilovars. % AR= 1.05 of % AR listed 11 Note: For A, B, C, the larger multipliers apply for motors of higher speeds; i.e., 3600 rpm = 1.7 mult., 1800 rpm = 1.65 mult., etc. 12 13

CA08104001E For more information, visit: www.eaton.com/consultants 1.7-24 Power Distribution Systems Typical Components of a Power System August 2017 Sheet 01 104

BIL—Basic Impulse Levels Table 1.7-12. Metal-Clad Switchgear Table 1.7-15. Liquid-Immersed i Voltage and Insulation Levels Transformers Voltage and Basic ANSI standards define recommended (From IEEE Std. C37.20.2-2015) Lightning Impulse Insulation Levels (BIL) and required BIL levels for: Rated Maximum Impulse (From ANSI/IEEE C57.12.00) ii ■ Metal-clad switchgear Voltage (kV rms) Withstand (kV) Applica- Nominal BIL (typically vacuum breakers) tion System (kV Crest) 1 4.76 60 Voltage ■ Metal-enclosed switchgear 8.25 95 (kV rms) 1 (typically load interrupters, 15.0 95 switches) 27.0 125 Distribu- 1.2 30 — — — tion 2.5 45 — — — ■ 38.0 150 2 Pad-mounted and overhead 5.0 60 — — — distribution switchgear Table 1.7-13. Metal-Enclosed Switchgear 8.7 75 — — — ■ Liquid immersed transformers Voltage and Insulation Levels 15.0 95 — — — 3 ■ Dry-type transformers (From IEEE Std. C37.20.3-2013) 25.0 150 125 — — 34.5 200 150 125 — Rated Maximum Impulse Table 1.7-12 through Table 1.7-16 46.0 250 200 — — 4 contain those values. Voltage (kV rms) Withstand (kV) 69.0 350 250 — — 4.76 60 Power 1.2 45 30 — — 8.25 95 2.5 60 45 — — 5 15.0 95 5.0 75 60 — — 27.0 125 8.7 95 75 — — 38.0 150 15.0 110 95 — — 6 25.0 150 — — — Table 1.7-14. Pad Mounted and Overhead 34.5 200 — — — Distribution Switchgear, Voltage and 46.0 250 200 — — 7 Insulation Levels 69.0 350 250 — — Rated Maximum Impulse 115.0 550 450 350 — Voltage Level (kV rms) Withstand (kV) 138.0 650 550 450 — 161.0 750 650 550 — Pad Mount Switchgear (per IEEE C37.74-2014) 8 230.0 900 825 750 650 15.5 95 345.0 117 5 1050 900 — 27 125 500.0 1675 1550 1425 1300 9 38 150 765.0 2050 1925 1800 — Overhead Switchgear (per IEEE C37.60-2012) 1 BIL values in bold typeface are listed as 15 95 standard. Others listed are in common use. 10 15.5 110 27 125 Table 1.7-16. Dry-Type Transformers Voltage 38 150 and Basic Lightning Impulse Insulation 11 38 170 Levels (BIL)—From ANSI/IEEE C57.12.01-1998) Nominal BIL (kV Crest) 2 System 12 Voltage (kV rms)

1.2 — 10 20 30 13 2.5 — 20 30 45 5.0 — 30 45 60 8.7 — 45 60 95 14 15.0 — 60 95 110 25.0 95 3 110 125 150 34.5 — 125 3 150 200 15 2 BIL values in bold typeface are listed as standard. Others listed are in common use. Optional higher levels used where exposure to overvoltage occurs and higher protection 16 margins are required. 3 Lower levels where surge arrester protective devices can be applied with 17 lower spark-over levels.

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.8-1 August 2017 Typical Application by Facility Type Sheet 01 105

Healthcare Facilities In addition to NFPA guidelines, there All electrical power in a healthcare are additional standards documents facility is important, though some i Healthcare facilities are defined by important in the design of healthcare loads are not critical to the safe opera- NFPA (National Fire Protection Agency) power distribution systems and tion of the facility. These “non-essential” as “Buildings or portions of buildings accreditation of those facilities or “normal” loads include things such ii in which medical, dental, psychiatric, including: as general lighting, general lab equip- nursing, obstetrical, or surgical care ment, non-critical service equipment, ■ Joint Commission—Environment are provided.” Due to the critical nature patient care areas, etc. These loads are 1 of Care 2016 of the care being provided at these not required to be fed from an alternate facilities and their increasing depen- ■ Facility Guidelines Institute (FGI)— source of power. dence on electrical equipment for Guidelines for Design and 2 The electrical system requirements for preservation of life, healthcare facilities Construction of Hospitals and the essential electrical system (EES) have special requirements for the Outpatient Facilities—2014 vary according to the associated risk to design of their electrical distribution 3 These codes, standards and guidelines the patients, visitors and staff that systems. These requirements are represent the most industry recognized might occupy that space. NFPA 99 typically much more stringent than requirements for healthcare electrical assigns a risk category to each space commercial or industrial facilities. 4 design. However, the electrical design within the healthcare facility based on The following section summarizes engineer should consult with the the risk associated with a failure of the some of the unique requirements authorities having jurisdiction over power distribution system serving of healthcare facility design. 5 the local region for specific electrical that space. These risk categories are There are several agencies and organi- distribution requirements. summarized in Table 1.8-1. zations that develop requirements The risk category of the space within 6 for healthcare electrical distribution Healthcare Electrical System the healthcare facility determines system design. The following is a Requirements whether or not that space is required listing of some of the specific NFPA Healthcare electrical systems usually to be served by an Essential Electrical 7 (National Fire Protection Agency) consist of two parts: System (EES). If an EES is required standards that affect healthcare facility to serve the space, the risk category design and implementation: 1. Non-essential or normal also dictates whether the EES must 8 electrical system. ■ NFPA 37-2015—Standard for meet Type 1 or Type 2 requirements. Stationary Combustion Engines 2. Essential electrical system. Table 1.8-2 lists the associated 9 and Gas Turbines EES Type requirements for each ■ NFPA 70-2014—National risk category. Electrical Code 10 ■ NFPA 99-2015—Healthcare Facilities ■ NFPA 101-2015—Life Safety Code Table 1.8-1. Essential Electrical System (EES) Risk Categories Risk Category Failure of Such Equipment or System is Likely to Cause: 11 ■ NFPA 110-2016—Standard for Emergency and Standby Category 1 ...major injury or death of patients or caregivers… Power Systems Category 2 ...minor injury to patients or caregivers… 12 ■ NFPA 111-2016—Standard on Stored Category 3 ...patient discomfort… Electrical Energy Emergency and Category 4 ...no impact on patient care… Standby Power Systems 13 Table 1.8-2. Essential Electrical System (EES) Risk Category by Type Risk Category Essential Electrical System (EES) Type Example 14 Category 1 Type 1 Critical Care Space Category 2 Type 2 General Care Space Category 3 EES not required Basic Examination Space 15 Category 4 EES not required Waiting Room 16

CA08104001E For more information, visit: www.eaton.com/consultants 1.8-2 Power Distribution Systems Typical Application by Facility Type August 2017 Sheet 01 106

i Normal Source Normal Source Normal Source Emergency Power Supply

ii G

4 Non-Essential Loads Non-Essential Loads

Manual Transfer Switch

6 Equipment Life Safety Critical Delayed Automatic Transfer Switch Branch Branch Branch

Essential Electrical System 7 Automatic (Non-Delaying) Transfer Switch 8 Figure 1.8-1. Typical Large Hospital Electrical System—Type 1 Essential Electrical System 9 Type 1 Essential Electrical The transfer switches can be non- Table 1.8-3. Type 1 EES Applicable Codes delayed automatic, delayed automatic Description Standard Section Systems (EES) or manual transfer depending on the 10 Type 1 essential electrical systems requirements of the specific branch Sources NFPA 99 6.4.1 (EES) have the most stringent require- of the EES that they are feeding. It is Uses NFPA 99 6.4.1.1.8 ments for providing continuity of permissible to feed multiple branches Emergency NFPA 110 4.1 11 electrical service and will, therefore, or systems of the EES from a single Power Supply be the focus of this section. Type 1 automatic transfer switch provided Classification EES requirements meet or exceed that the maximum demand on the Distribution NFPA 99 6.4.2 12 the requirements for Type 2 facilities. EES does not exceed 150 kVA. This NEC 517.30 configuration is typically seen in General NFPA 99 6.4.2.2.1 Sources: Type 1 systems are required smaller healthcare facilities that NEC 517.25 thru 517.31 to have a minimum of two independent 13 must meet Type 1 EES requirements Life Safety NFPA 99 6.4.2.2.3 sources of electrical power—a normal (see Figure 1.8-3). Branch NEC 517.32 source that generally supplies the Critical NFPA 99 6.4.2.2.4 entire facility and one or more alter- Branch NEC 517.33 14 nate sources that supply power when Normal Source Equipment NFPA 99 6.4.2.2.5 the normal source is interrupted. The Branch NEC 517.34 alternate source(s) must be an on-site Wiring NFPA 99 6.4.2.2.6 15 Alternate generator driven by a prime mover NEC 517.30.(C) unless a generator(s) exists as the Source normal power source. In the case 16 where a generator(s) is used as the G normal source, it is permissible for the 17 alternate source to be a utility feed. Alternate source generators must be classified as Type 10, Class X, Level 1 18 gensets per NFPA 110 Tables 4.1(a) and 4.2(b) that are capable of providing power to the load in a maximum of Non-Essential Loads 19 10 seconds. Typically, the alternate sources of power are supplied to the Entire Essential loads through a series of automatic Electric System 20 and/or manual transfer switches (150 kVA or Less) (see Ta b 2 5 ). Figure 1.8-2. Small Healthcare Facility 21 Electrical System—Single EES Transfer Switch

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.8-3 August 2017 Typical Application by Facility Type Sheet 01 107

Essential Electrical System Branches: 3. Task illumination and selected The following equipment must be The Type 1 EES consists of three receptacles in the following arranged for delayed automatic or i separate branches capable of supply- patient care areas: infant manual transfer to the emergency ing power considered essential for life nurseries, medication prep power supply: safety and effective facility operation areas, pharmacy, selected ii during an interruption of the normal acute nursing areas, psychiatric 1. Select heating equipment. power source. They are the life safety bed areas, ward treatment 2. Select elevators. branch, critical branch and equipment rooms, nurses’ stations. 3. Supply, return and exhaust 1 branch. 4. Specialized patient care task ventilating systems for surgical, A. Life Safety Branch—supplies illumination, where needed. obstetrical, intensive care, 2 power for lighting, receptacles 5. Nurse call systems. coronary care, nurseries and emergency treatment areas. and equipment to perform the 6. Blood, bone and tissue banks. following functions: 4. Supply, return and exhaust 3 7. Telephone equipment rooms ventilating systems for airborne 1. Illumination of means of egress. and closets. infectious/isolation rooms, labs and 2. Exit signs and exit direction signs. 8. Task illumination, selected medical areas where hazardous 4 3. Alarms and alerting systems. receptacles and selected power materials are used. circuits for the following: general 5. Hyperbaric facilities. 4. Emergency communications care beds (at least one duplex 5 systems. receptacle), angiographic labs, 6. Hypobaric facilities. 5. Task illumination, battery cardiac catheterization labs, 7. Autoclaving equipment. chargers for battery powered coronary care units, hemodialysis 8. Controls for equipment listed above. 6 lighting, and select receptacles rooms, selected emergency at the generator. room treatment areas, human 9. Other selected equipment in kitchens, laundries, radiology 6. Elevator lighting control, physiology labs, intensive care 7 units, selected postoperative rooms and central refrigeration communication and signal as selected. systems. recovery rooms. 7. Automatic doors used for egress. 9. Additional circuits and single- Any loads served by the generator that 8 phase fraction motors as needed are not approved as outlined above as These are the only functions for effective facility operation. part of the essential electrical system permitted to be on the life safety must be connected through a separate 9 branch. Life safety branch equip- C. Equipment Branch—consists transfer switch. These transfer switches ment and wiring must be entirely of major electrical equipment must be configured such that the loads independent of all other loads necessary for patient care and will not cause the generator to overload 10 and branches of service. This Type 1 operation. and must be shed in the event the includes separation of raceways, generator enters an overload condition. boxes or cabinets. Power must be The equipment branch of the EES 11 supplied to the life safety branch that consists of large electrical Ground fault protection—per NFPA 70 from a non-delayed automatic equipment loads needed for NEC Article 230.95, ground fault transfer switch. patient care and basic healthcare protection is required on any feeder or 12 facility operation. Loads on the service disconnect 1000 A or larger on B. Critical Branch—supplies power for equipment system that are systems with line to ground voltages task illumination, fixed equipment, essential to generator operation of 150 V or greater and phase-to-phase 13 selected receptacles and selected are required to be fed by a non- voltages of 600 V or less. For healthcare power circuits for areas related to delayed automatic transfer switch. facilities (of any type), a second level patient care. The purpose of the of ground fault protection is required 14 critical branch is to provide power The following equipment must be to be on the next level of feeder to a limited number of receptacles arranged for delayed automatic downstream. and locations to reduce load transfer to the emergency power This second level of ground fault is 15 and minimize the chances of supply: fault conditions. only required for feeders that serve 1. Central suction systems for patient care areas and equipment 16 The transfer switch(es) feeding the medical and surgical functions. intended to support life. 100% critical branch must be automatic 2. Sump pumps and other selective coordination of the two type. They are permitted to have equipment required for the safe levels of ground fault protection 17 appropriate time delays that will operation of a major apparatus. must be achieved with a minimum follow the restoration of the life six-cycle separation between the 3. Compressed air systems for upstream and downstream device. safety branch, but should have medical and surgical functions. 18 power restored within 10 seconds As of the 2011 NEC, ground fault of normal source power loss. 4. Smoke control and stair pressurization systems. protection is allowed between the The critical branch provides power generator(s) and the EES transfer 19 to circuits serving the following 5. Kitchen hood supply and switch(es). However, NEC 517.17(B) areas and functions: exhaust systems, if required prohibits the installation of ground to operate during a fire. 20 1. Critical care areas. fault protection on the load side of a transfer switch feeding EES circuits 2. Isolated power systems in (see Figure 1.8-3—additional level of special environments. ground fault). 21

CA08104001E For more information, visit: www.eaton.com/consultants 1.8-4 Power Distribution Systems Typical Application by Facility Type August 2017 Sheet 01 108

i Normal Source Normal Source(s) G Generator Breakers are ii Typically Supplied with 480/277 V 480/277 V 480/277 V Ground Fault Alarm 1000 A Service 1000 A Service 1000 A Service Only. (NEC 700.27) GF GF GF 1 or Larger Entrance or Larger Entrance or Larger Entrance Ground Fault is Permitted Additional Level Between Generator 2 GFGFGF GFGF of Ground Fault GFGFGF GFGFGF and EES Transfer Protection Switches. (NEC 517.17 (B)) 3 Non-Essential Loads Non-Essential Loads 4

GF = Ground Fault Protection Required Additional Level of Ground Fault is not Permitted on Load Side of EES 5 Essential Electrical System Transfer Switches. (NEC 517.17(B)

Figure 1.8-3. Additional Level of Ground Fault Protection 6 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 ground per NEC 230.95. 7 Careful consideration should be used Wet procedure locations—A wet Electronic line isolation monitors (LIM) in applying ground fault protection procedure location in a healthcare are used to monitor and display leakage on the essential electrical system to facility is any patient care area that currents to ground. When leakage 8 prevent a ground fault that causes a is normally subject to wet conditions current thresholds are exceeded, visible trip of the normal source to also cause while patients are present. By default, and/or audible alarms are initiated to a trip on the emergency source. Such operating rooms are considered alert occupants of a possible hazardous 9 an event could result in complete power wet procedure locations unless a condition. This alarm occurs without loss of both normal and emergency risk assessment is performed to interrupting power to allow for the power sources and could not be show otherwise. Other examples of safe conclusion of critical procedures. 10 recovered until the source of the wet procedure locations might include ground fault was located and isolated anesthetizing locations, dialysis Table 1.8-5. Wet Procedure Location from the system. To prevent this locations, etc. (patient beds, toilets Applicable Codes 11 condition, NEC 700.27 removes the and sinks are not considered wet Description Standard Section ground fault protection requirement locations). These wet procedure General NFPA 99 6.3.2.2.8 for the emergency system source. locations require special protection NEC 517.20 12 Typically, the emergency system to guard against electric shock. The GFCI Protection NFPA 99 6.3.2.2.8.8 generator(s) are equipped with ground fault current in these areas ground fault alarms that do not must be limited to not exceed 5 mA. Isolated Power NFPA 99 6.3.2.2.9, 6.3.2.6 Systems NE 517.160 13 automatically disconnect power during a ground fault. Protection to patient and staff in wet procedure locations can be provided 14 Table 1.8-4. Ground Fault Protection through the use of GFCI outlets, GFCI Applicable Codes breakers or isolated power systems. Description Standard Section If GFCI protection is utilized, each 15 circuit must have a dedicated GFCI Services NEC 230.95 outlet or GFCI breaker. It is not Branch-Circuits NEC (see Article 210.13 permissible to use a single GFCI 100 Definition 16 for Applicability) device to protect multiple outlets. Feeders NEC 215.10 This limits interruption resulting Additional NFPA 99 6.3.2.5 from a ground fault to a single outlet. 17 Level NEC 517.17 Isolated power systems provide power Alternate NEC 700.27 to an area that is isolated from ground 18 Source NEC 701.26 (or ungrounded). This type of system limits the amount of current that flows to ground in the event of a single 19 line-to-ground fault and maintains circuit continuity. 20

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.8-5 August 2017 Typical Application by Facility Type Sheet 01 109

Maintenance and Testing Routine maintenance should be Paralleling Emergency Generators Regular maintenance and testing of performed on circuit breakers, transfer i the electrical distribution system in switches, switchgear, generator equip- Without Utility Paralleling a healthcare facility is necessary ment, etc. by trained professionals In many healthcare facilities (and other to ensure proper operation in an to ensure the most reliable electrical large facilities with critical loads), the ii emergency and, in some cases, to system possible. See Ta b 4 1 for Eaton’s demand for standby emergency power maintain government accreditation. Electrical Services & Systems (EESS), is large enough to require multiple Any healthcare facility receiving which provides engineers, trained generator sets to power all of the 1 Medicare or Medicaid reimbursement in development and execution of required essential electrical system from the government must be annual preventative maintenance (EES) loads. In these cases, it becomes accredited by the Joint Commission. procedures of healthcare facility more flexible and easier to operate the 2 electrical distribution systems. required multiple generators from a The Joint Commission has established single location using generator paral- a group of standards called the Table 1.8-6. Maintenance and Testing 3 Applicable Codes leling switchgear. Figure 1.8-4 shows Environment of Care, which must be an example of a typical one-line for a met for healthcare facility accredita- Description Standard Section paralleling switchgear lineup feeding tion. Included in these standards is the EES. 4 the regular testing of the emergency Grounding NFPA 99 6.3.3.1 (alternate) power system(s). Diesel- Essential NFPA 99 6.4.4.1 A typical abbreviated sequence of Electrical Joint Commission EC.2.1.4(d) powered EPS installations must be System Environment operation for a multiple emergency 5 tested monthly in accordance with of Care generator and ATS system follows. NFPA 110 Standard for Emergency and Generator NFPA 110 8.4 Note that other modes of operation Standby Power Systems. Generators such as generator demand priority 6 Transfer NFPA 110 8.3.5, 8.4.6 must be tested for a minimum of Switches and automated testing modes are 30 minutes under the criteria defined available but are not included below. Breakers NFPA 99 6.4.4.1.2.1 7 in NFPA 110. NFPA 110 8.4.7 (Reference Ta b 4 0 for complete detailed sequences of operation.) 8 Utility 9 Transformer Generators X = Number of Units

Utility G1 G2 Gx 10 Metering

Typical 11 Generator Breaker Service Main 12

Normal Bus Emergency Bus 13 Optional Optional Electrically Electrically Operated Stored Operated Energy Breakers 14 EF1 EF2 EFx Stored F1 F2 Fx Energy Breakers 15

16 Equipment Life Safety Critical Load Shed/Load ATS # 1 ATS # 2 ATS # X Add ATS Units Non-Essential Loads 17 Optional Closed EP1 EP2 Typical EPX Tr ansition Panelboards Paralleling of 18 Generators and Utility 19 Figure 1.8-4. Typical One-Line for a Paralleling Switchgear Lineup Feeding the Essential Electrical System (EES) 20

CA08104001E For more information, visit: www.eaton.com/consultants 1.8-6 Power Distribution Systems Typical Application by Facility Type August 2017 Sheet 01 110

1. Entering emergency mode b. As each automatic transfer Healthcare facilities are ideally suited i switch transfers back to utility to take advantage of these programs a. Upon loss of normal source, power, it removes its run request because they already have significant automatic transfer switches from the generator plant. on-site generation capabilities due to ii send generator control system the code requirements described. a run request. c. When the last automatic transfer switch has retransferred to Many healthcare facilities are taking b. All available generators are the utility and all run requests advantage of these utility incentives 1 started. The first generator up have been removed from the by adding generator capacity over to voltage and frequency is generator plant, all generator and above the NFPA requirements. closed to the bus. circuit breakers are opened. Figure 1.8-5 shows an example 2 one-line of a healthcare facility with c. Unsheddable loads and load d. The generators are allowed shed Priority 1 loads are pow- complete generator backup and to run for their programmed utility interconnect. 3 ered in less than 10 seconds. cool-down period. d. The remaining generators are e. The system is now back in NFPA 110 requirements state that the synchronized and paralleled automatic/standby mode. normal and emergency sources must 4 to the bus as they come up to be separated by a fire-rated wall. voltage and frequency. With Utility Paralleling The intent of this requirement is so that e. As additional generators are Today, many utilities are offering their a fire in one location cannot take out 5 paralleled to the emergency customers excellent financial incen- both sources of power. To meet this bus, load shed priority levels tives to use their on-site generation requirement, the paralleling switchgear are added, powering their capacity to remove load from the utility must be split into separate sections 6 associated loads. grid. These incentives are sometimes with a tie bus through a fire-rated wall. f. The system is now in referred to as limited interruptible For more information on generator emergency mode. rates (LIP). Under these incentives, paralleling switchgear, see Ta b 4 0 . 7 utilities will greatly reduce or eliminate 2. Exit from emergency mode kWhr or kW demand charges to their a. Automatic transfer switches customers with on-site generation 8 sense the utility source is within capabilities. In exchange, during times acceptable operational toler- of peak loading of the utility grid, the ances for a time duration set at utility can ask their LIP rate customers 9 the automatic transfer switch. to drop load from the grid by using their on-site generation capabilities. 10 Utility Fire-Rated Wall or Separation Barrier 11 Transformer Generators X = Number of Units

12 Utility G1 G2 Gx Metering Utility Closed Protective 13 Tr ansition Typical Relay Paralleling of Generator Generators and Breaker 14 Service Main Utility, Plus Soft Loading/ Unloading 15 Normal Bus Emergency Bus TIE Optional TIE Optional Electrically Operated Electrically Stored Energy 16 Field Installed Operated Breakers Cable or Busway Stored F1 F2 Fx EF1 EF2 EFx Energy 17 Breakers

18 Equipment Life Safety Critical Load Shed/ ATS # 1 ATS # 2 ATS # X Load Add 19 Non-Essential ATS Units Loads

20 EP1 EP2 EPX Typical Panelboards

21 Figure 1.8-5. Typical One-Line Healthcare Facility with Complete Generator Backup and Utility Interconnect

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.8-7 August 2017 Typical Application by Facility Type Sheet 01 111

Quick Connect Generator and i Load Bank Capabilities ii

Quick-Connect Double-Throw 7 Many facilities are increasing their resiliency by including quick connect capabilities for temporary roll-up Cam-Type Receptacle Sub-Assembly 8 generators. Quick-connect sections can be added to generator switchboards to Typical (1200 A) Generator Quick Connect Switchboard allow for the use of temporary roll-up 9 generators when permanent generators are out-of-service for maintenance and repair. The same quick-connect 10 device can also be used for convenient connection of a load bank for periodic testing of the permanent generators. 11 Another common application for generator quick-connect structures 12 is on the normal service. Having a quick-connect infrastructure in place provides the ability to restore some or 13 all normal system loads such as HVAC, chillers, etc. that can become crucial if there were a long-term utility outage. 14 The flexibility to quickly and safely connect a temporary generator to these normal system loads can help 15 resume more normal facility operation during an extended utility outage. See Ta b 2 1. 7 or additional 16 information on quick-connect switchboards up to 4000 A and Ta b 2 8 for quick-connect safety switches 17 up to 800 A. 18

CA08104001E For more information, visit: www.eaton.com/consultants 1.8-8 Power Distribution Systems August 2017 Sheet 01 112

This page intentionally left blank. i ii

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.9-1 August 2017 Power Quality Sheet 01 113 Power Quality

Power Quality Terms Defining the Problem Power Quality Terms Power quality problems can be Power disturbance: Any deviation i Technical Overview resolved in three ways: by reducing from the nominal value (or from some the variations in the power supply selected thresholds based on load Introduction (power disturbances), by improving tolerance) of the input ac power ii Sensitive electronic loads deployed the load equipment’s tolerance to those characteristics. today by users require strict require- variations, or by inserting some Total harmonic distortion or distortion ments for the quality of power delivered interface equipment (known as power 1 factor: The ratio of the root-mean- to loads. conditioning equipment) between the electrical supply and the sensitive square of the harmonic content to the For electronic equipment, power load(s) to improve the compatibility of root-mean-square of the fundamental 2 disturbances are defined in terms of the two. Practicality and cost usually quantity, expressed as a percentage amplitude and duration by the elec- determine the extent to which each of the fundamental. tronic equipment operating envelope. 3 option is used. Crest factor: Ratio between the Electronic loads may be damaged peak value (crest) and rms value of and disrupted, with shortened life Many methods are used to define a periodic waveform. expectancy, by these disturbances. power quality problems. For example, 4 one option is a thorough on-site Apparent (total) power factor: The The proliferation of computers, variable investigation, which includes inspecting ratio of the total power input in watts frequency motor drives, UPS systems wiring and grounding for errors, to the total volt-ampere input. 5 and other electronically controlled monitoring the power supply for equipment is placing a greater demand power disturbances, investigating Sag: An rms reduction in the ac on power producers for a disturbance- equipment sensitivity to power voltage, at the power frequency, for 6 free source of power. Not only do these disturbances, and determining the the duration from a half-cycle to a few types of equipment require quality load disruption and consequential seconds. An undervoltage would have power for proper operation; many effects (costs), if any. In this way, the a duration greater than several seconds. 7 times, these types of equipment are power quality problem can be defined, Interruption: The complete loss of also the sources of power disturbances alternative solutions developed, voltage for a time period. that corrupt the quality of power in a and optimal solution chosen. 8 given facility. Tr a n s i e n t : A sub-cycle disturbance Before applying power-conditioning in the ac waveform that is evidenced Power quality is defined according to equipment to solve power quality by a sharp brief discontinuity of the 9 IEEE Standard 1100 (Recommended problems, the site should be checked waveform. May be of either polarity Practice for Powering and Grounding for wiring and grounding problems. and may be additive to or subtractive Electronic Equipment) as the concept Often, correcting a relatively inexpen- from the nominal waveform. 10 of powering and grounding electronic sive wiring error, such as a loose equipment in a manner that is suitable connection or a reversed neutral Surge or impulse: See transient. to the operation of that equipment. and ground wire, can avoid a more 11 IEEE Standard 1159 (Recommended expensive power conditioning solution. Noise: Unwanted electrical signals Practice for Monitoring Electric Power that produce undesirable effects Quality) notes that “within the industry, Sometimes the investigative approach in the circuits of control systems 12 alternate definitions or interpretations is not viable, as the exact sensitivities in which they occur. of power quality have been used, of the load equipment may be reflecting different points of view.” unknown and difficult to determine. Common-mode noise: The noise 13 In other cases, monitoring for power voltage that appears equally and in In addressing power quality problems anomolies may be needed over an phase from each current-carrying at an existing site, or in the design extended period of time to capture conductor to ground. 14 stages of a new building, engineers infrequent disturbances. This added need to specify different services or Normal-mode noise: Noise signals time and expense can be impractical measurable between or among active mitigating technologies. The lowest in smaller installations. cost and highest value solution is circuit conductors feeding the subject 15 to selectively apply a combination It is important to remember that while load, but not between the equipment of different products and services the thorough on-site investigation grounding conductor or associated as follows: can identify and help solve observed signal reference structure and the active 16 problems on existing installations, for circuit conductors. ■ Power quality surveys, analysis a power systems engineer designing a and studies new facility, there is no site or equip- 17 ■ Power monitoring ment to investigate. Consequently, as ■ Grounding products and services in the prior instances cited, it is often 18 ■ Surge protection practical to implement power quality solutions to address common issues ■ Voltage regulation as a preemptive measure. Using well- ■ Harmonic solutions accepted practices, such as tiered levels 19 ■ Lightning protection (ground rods, of surge protection or UPS systems, hardware, etc.) an engineer can avoid or alleviate the 20 ■ Uninterruptible power supply (UPS) potential problems that poor power or motor-generator (M-G) set quality can cause on a power system. 21

CA08104001E For more information, visit: www.eaton.com/consultants 1.9-2 Power Distribution Systems Power Quality August 2017 Sheet 01 114 Power Quality

Methodology for Ensuring Effective The proliferation of communication The benefit of implementing cascaded i Power Quality to Electronic Loads and computer network systems network protection is shown in The power quality pyramid is an has increased the need for proper Figure 1.9-2. Combined, the two stages effective guide for addressing power grounding and wiring of ac and data/ of protection at the service entrance ii quality problems at an existing facility. communication lines. In addition to and branch panel locations reduce the The framework is also useful for reviewing ac grounding and bonding IEEE 62.41 recommended test wave specifying engineers who are practices, it is necessary to prevent (C3–20 kV, 10 kA) to less than 200 V 1 designing a new facility. ground loops from affecting the signal voltage, a harmless disturbance level reference point. for 120 V rated sensitive loads. Power quality starts with grounding 2 (the base of the pyramid) and then 2. Surge Protection If surge protection is only provided for moves upward to address the potential the building entrance feeder, the let- Surge protection devices (SPDs) are issues. This simple, yet proven through voltage will be approximately recommended as the next stage power 3 methodology, will provide the most 950 V in a 277/480 V system exposed quality solutions. NFPA, UL 96A, cost-effective approach. As we move to induced lightning surges. This IEEE Emerald Book and equipment higher up the pyramid, the cost per level of let-through voltage can cause manufacturers recommend the use 4 kVA of mitigating potential problems degradation or physical damage of of surge protectors. The SPDs are used increase and the quality of the power most electronic loads. to shunt short duration voltage increases (refer to Figure 1.9-1). 5 disturbances to ground, thereby Wherever possible, consultants, preventing the surge from affecting specifiers and application engineers electronic loads. When installed as should ensure similar loads are fed 6 part of the facility-wide design, SPDs from the same source. In this way, 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 7 The IEEE Emerald Book recommends example, motor loads, HVAC systems the use of a two-stage protection and other linear loads should be concept. For large surge currents, separated from the sensitive process 8 kVA Cost Per diversion is best accomplished in control and computer systems. two stages: the first diversion should be performed at the service entrance The most effective and economic 9 to the building. Then, any residual solution for protecting a large number 5. Uninterruptible Power Supply voltage resulting from the action of loads is to install parallel style SPDs (UPS, Gen. Sets, etc.) can be dealt with by a second at the building service entrance feeder 10 4. Harmonic Distortion protective device at the power and panelboard locations. These SPDs 3. Voltage Regulation panel of the computer room are either placed in parallel with the (or other critical loads). loads directly on the equipment 11 2. Surge Protection bus bars or externally by means of a 1. Grounding short cable. This reduces the cost of protection for multiple sensitive loads. 12 Figure 1.9-1. Power Quality Pyramid

1. Grounding Input—high energy 13 SPD transient disturbance; IEEE Category Grounding represents the foundation CP C3 Impulse 20,000V; 10,000A SPD 20,000V of a reliable power distribution 480V 120/208V 14 system. Grounding and wiring Computer or Best achievable problems can be the cause of up to Sensitive Loads performance with single SPD 80% of all power quality problems. Stage 1 Protection at main panel (950V, at Stage 1) All other forms of power quality (Service Entrance) Stage 2 Protection 15 (Branch Location) solutions are dependent upon good 800V grounding procedures. System Test Parameters: PEAK VOLTAGE IEEE C62.41[10] and C62.45 [10] 400V 16 test procedures using category; 0 480V main entrance panels; 25 uS 50 uS TIME (MICROSECONDS) 100 ft (30m) of three-phase wire; 17 480/208V distribution transformer; Two stage (cascade and 208V branch panel. approach) achieves best possible protection (less 18 = SPD than 200V at Stage 2) Figure 1.9-2. Cascaded System Protection 19

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.9-3 August 2017 Power Quality Sheet 01 115 Power Quality

The recommended system approach Advantages of the system approach are: By twisting the installation wires, the for installing SPDs is summarized in area between wires is reduced and the ■ i Figure 1.9-3. The lowest possible investment mutual inductance affect minimized. in mitigating equipment to protect a facility Increasing the diameter of the ii 1. ■ Building entrance SPDs protect installation wires is of negligible Identify Critical Loads the facility against large external benefit. Inductance is a “skin effect” transients, including lightning phenomenon and a function of wire 1 2. ■ SPDs are bi-directional and prevent circumference. Because only a Identify Non-Critical Loads transient and noise disturbances marginal reduction in inductance is from feeding back within a system achieved when the diameter of the 2 3. when installed at distribution or installation conductors is increased, Identify Noise and branch panels the use of large diameter wire results Disturbance Generating Loads ■ Two levels of protection safeguard in only minimal improvement 3 sensitive loads from physical (see Figure 1.9-5). 4. damage or operational upset Further benefits provided by integrated Review Internal Power Distribution Layout 4 Side-Mounted SPD vs. Integral SPD surge suppression designs are the elimination of field installation costs and 5. Directly connecting the surge the amount of expensive “outboard” Identify Facility Exposure to suppresser to the bus bar of electrical wall space taken up by side-mounted 5 Expected Levels of Disturbance distribution equipment results in SPD devices. the best possible level of protection. 6. Compared to side-mounted devices, Building Entrance Feeder Installation 6 Apply Mitigating Equipment to: connecting the SPD unit to the bus bar Considerations a) Service Entrance Main Panels eliminates the need for lead wires Installing an SPD device immediately b) Key Sub-Panels and reduces the let-through voltage after the switchgear or switchboard 7 c) Critical Loads up to 50% (see Figure 1.9-4). d) Data and Communication Lines main breaker is the optimal location Given that surges are high frequency for protecting against external disturbances such as lightning. When placed 8 Figure 1.9-3. System Approach for Installing SPDs disturbances, the inductance of the installation wiring increases the in this location, the disturbance is There may be specific single-phase let-through voltage of the protective “intercepted” by the SPD and reduced 9 critical loads within a facility that device. Figure 1.9-5 shows that to a minimum before reaching the require a higher level of protection. for every inch of lead length, the distribution and/or branch panel(s). In these instances, a series style SPD is best suited for protecting such loads. let-through voltage is increased by The use of a disconnect breaker 10 Application of the series style SPD an additional 15–25 V above the eliminates the need to de-energize involves wiring it in series with the manufacturers stated suppression the building entrance feeder equip- load it is feeding. performance. ment should the SPD fail or require 11 Lead length has the greatest effect on isolation for Megger testing. the actual level of protection realized. 12 Twisting of the installation wires is the second most important installation consideration. 13

208Y/120 Panelboard (integrated versus side mounted SPD) 14

1000 Side-Mounted SPD Device Side-Mounted SPD SPD Integrated (assuming 14-inch (355.6 mm) lead length to bus) 15 used for Retrofit into Panelboards, Applications Switchboards, MCCs 800 16 600

N SPD 400 17 Integrated SPD SPD (direct bus bar connection) 200 18 0 GRO UND GROUND Let-Throu g h Volt ag e a t Bus B r Surge Event 19 G –200 G –2.00 0.00 2.00 4.00 6.00 8.00 10.00 N \ Microseconds 20

Figure 1.9-4. Performance Comparison of Side-Mounted vs. Integrated SPD 21

CA08104001E For more information, visit: www.eaton.com/consultants 1.9-4 Power Distribution Systems Power Quality August 2017 Sheet 01 116 Power Quality

Reference Ta b 3 4 for detailed i Additional Let-Through Voltage Using IEEE C1(6000V, 3000A)[3] information on SPDs. Waveform (UL 1449 Test Wave)[12] 900 14 AWG 3. Voltage Regulation 800 209V (23%) 10 AWG ii 700 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 1 300 mitigating solutions are available 200 depending upon the load sensitivity, 100 2 0 fault duration/magnitude and the 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 1.9-5. The Effect of Installation Lead Length on Let-Through Voltage 1 occurrences of voltage regulation 4 Additional to UL 1449 ratings. problems. The captured data will allow 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 5 Larger suppressers rated at approxi- and downtime. 4. Harmonics Distortion mately 250 kA per phase should be Harmonics and Nonlinear Loads installed at the service entrance to Installing Dataline Surge Protection 6 survive high-energy surges associated Most facilities also have communica- In the past, most loads were primarily with lightning. tion lines that are potential sources linear in nature. Linear loads draw the for external surges. As identified by full sine wave of electric current at its 7 A 250 kA per phase surge rating allows the power quality pyramid, proper 60 cycle (Hz) fundamental frequency— for over a 25-year life expectancy grounding of communication lines is Figure 1.9-6 shows balance single- assuming an IEEE defined high essential for dependable operation. phase, linear loads. As the figure 8 exposure environment. Lower surge NEC Article 800 states that all data, shows, little or no current flows in rating devices may be used; however, power and cable lines be grounded the neutral conductor when the loads device reliability and long-term and bonded. are linear and balanced. 9 performance may be compromised. Power disturbances such as lightning The advent of nonlinear electronic For aerial structures, the 99.8 percentile can elevate the ground potential loads, where the ac voltage is 10 recorded lightning stroke current is between two communicating pieces converted to a dc voltage, altered the less than 220 kA. The magnitude of of electronic equipment with different way power was traditionally drawn surges conducted or induced into a ground references. The result is current from a normal ac sine wave. During 11 facility electrical distribution system is flowing through the data cable, causing the ac to dc conversion, power considerably lower given the presence component failure, terminal lock-up, electronic devices are switched on of multiple paths for the surge to travel data corruption and interference. during a fraction of each 1/2 cycle along. It is for this reason that IEEE causing voltage and current to be 12 C62.41 recommends the C3 (20 kV, NFPA 780 D—4.8 warns that “surge drawn in pulses to obtain the required 10 kA) test wave for testing SPDs suppression devices should be installed dc output. This deviation of voltage installed at building entrance feeders. on all wiring entering or leaving elec- and current from the normal sine wave 13 tronic equipment, usually power, data results in harmonics. SPDs with surge ratings greater than or communication wiring.” 250 kA are not required, however, It is important to note that the current 14 higher ratings are available and may Surge suppressers should be installed distortion caused by loads such as provide longer life. at both ends of a data or communica- rectifiers or switch mode power tion cable. In those situations where supplies causes the voltage distortion. 15 Installing Panelboard Surge one end of the cable is not connected That voltage distortion is caused by Protection Devices into an electronic circuit (e.g., contactor distorted currents flowing through an Smaller surge capacity SPDs (120 kA coil), protection on the electronic end impedance. The amount of voltage 16 per phase) are installed at branch only is required. distortion depends on: panelboards where power disturbances are of lower energy, but occur much To prevent the coupling or inducing of ■ System impedance 17 more frequently. This level of surge power disturbances into communication ■ Amount of distorted current current rating should result in a greater lines, the following should be avoided: Devices that can cause harmonic than 25-year life expectancy. ■ 18 Data cables should not be run over disturbances include rectifiers, When isolated ground systems are fluorescent lighting fixtures thrusters and switching power used, the SPD should be installed such ■ Data cables should not be in the supplies, all of which are nonlinear. 19 that any common mode surges are vicinity of electric motors Further, the proliferation of electronic shunted to the safety ground. ■ The right category cable should equipment such as computers, UPS be used to ensure transmission systems, variable speed drives, The use of a disconnect breaker is performance programmable logic controllers, and 20 optional. The additional let-through ■ Data cables must be grounded at the like: nonlinear loads have become voltage resulting from the increased a significant part of many installations. inductance caused by the disconnect both ends when communicating 21 switch is about 50–60 V. between buildings

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.9-5 August 2017 Power Quality Sheet 01 117 Power Quality

Other types of harmonic-producing and C-phase are in sequence with each Harmonic Issues loads include arcing devices (such as other. Meaning, the triplen harmonics i arc furnaces, welders and fluorescent present on the three phases add Harmonic currents may cause system losses that over burden the distribution lighting). together in the neutral, as shown in system. This electrical overloading may Figure 1.9-7, rather than cancel each ii contribute to preventing an existing Nonlinear load currents vary widely other out, as shown in Figure 1.9-6. electrical distribution system from from a sinusoidal wave shape; often Odd non-triplen harmonics are serving additional future loads. they are discontinuous pulses. This classified as “positive sequence” 1 means that nonlinear loads are or “negative sequence” and are the In general, harmonics present on extremely high in harmonic content. 1st, 5th, 7th, 11th, 13th, etc. a distribution system can have the following detrimental effects: 2 Triplen harmonics are the 3rd, 9th, In general, as the order of a harmonic 15th,...harmonics. Further, triplen gets higher, its amplitude becomes 1. Overheating of transformers and harmonics are the most damaging smaller as a percentage of the funda- rotating equipment. 3 to an electrical system because these mental frequency. harmonics on the A-phase, B-phase 2. Increased hysteresis losses. 3. Decreased kVA capacity. 4 60 Hz Fundamental 4. Overloading of neutral. 5. Unacceptable neutral-to-ground 5 A Phase voltages. 6. Distorted voltage and current 6 waveforms.

120º 7. Failed capacitor banks. Lagging 7 B Phase 8. Breakers and fuses tripping. 9. Double sized neutrals to defy the negative effects of triplen 8 harmonics. 120º In transformers, generators and Lagging 9 C Phase uninterruptible power supplies (UPS) systems, harmonics cause overheating and failure at loads below their ratings 10 because the harmonic currents cause Balance greater heating than standard 60 Hz Neutral Current current. This results from increased 11 eddy current losses, hysteresis losses in the iron cores, and conductor skin Figure 1.9-6. Balanced Neutral Current Equals Zero effects of the windings. In addition, 12 the harmonic currents acting on the impedance of the source cause 60 Hz Fundamental harmonics in the source voltage, which 13 3rd Harmonic is then applied to other loads such as motors, causing them to overheat. A Phase 14 The harmonics also complicate the application of capacitors for power factor correction. If, at a given harmonic 15 120º frequency, the capacitive impedance B Phase Lagging equals the system reactive impedance, the harmonic voltage and current can 16 reach dangerous magnitudes. At the same time, the harmonics create problems in the application of power 17 120º C Phase Lagging factor correction capacitors, they lower the actual power factor. The rotating meters used by the utilities for 18 watthour and various measurements do not detect the distortion component Neutral caused by the harmonics. Rectifiers Triplen 19 Current with diode front ends and large dc side à capacitor banks have displacement Phase Triplen Harmonics power factor of 90% to 95%. More 20 Added in the Neutral recent electronic meters are capable of metering the true kVA hours taken by the circuit. Figure 1.9-7. Single-Phase Loads with Triplen Harmonics 21

CA08104001E For more information, visit: www.eaton.com/consultants 1.9-6 Power Distribution Systems Power Quality August 2017 Sheet 01 118 Power Quality

Single-phase power supplies for Table 1.9-2. Low-Voltage System Classification When evaluating current distortion, i computer and fixture ballasts are and Distortion Limits for 480 V Systems it is important to understand the rich in third harmonics and their difference between THD (Total Class CAN DF odd multiples. Harmonic Distortion) and TDD (Total 2 ii Special application 10 16,400 3% Demand Distortion). THD is the Even with the phase currents perfectly General system 5 22,800 5% measured distortion on the actual balanced, the harmonic currents in Dedicated system 2 36,500 10% magnitude of current flowing at a 2 1 the neutral can total 173% of the Special systems are those where the rate given instant. This could be referred phase current. This has resulted in of change of voltage of the notch might to as a “sine wave quality factor” mistrigger an event. A is a measurement overheated neutrals. The Information N as it is a measure of the amount of Technology Industry Council (ITIC) of notch characteristics measured in 2 volt-microseconds, C is the impedance distortion at that given time, for that formerly known as CBEMA, recom- ratio of total impedance to impedance given magnitude of current. It can mends that neutrals in the supply to at common point in system. DF is be measured with a simple harmonic 3 electronic equipment be oversized distortion factor. current metering device. Current to at least 173% of the ampacity of THD is not utilized anywhere in the the phase conductors to prevent Table 1.9-3. Utility or Cogenerator Supply IEEE 519 standard. Instead, the IEEE Voltage Harmonic Limits 4 problems. ITIC also recommends 519 standard sets limits based on TDD, derating transformers, loading them Voltage 2.3–69 kV 69–138 kV >138 kV or Total Demand Distortion. TDD is a to no more than 50% to 70% of their Range calculated value based on the amount 5 nameplate kVA, based on a rule-of- of harmonic distortion related to the thumb calculation, to compensate Maximum 3.0% 1.5% 1.0% individual full load capacity of the electrical for harmonic heating effects. harmonic system. The formula for calculating 6 In spite of all the concerns they cause, Total 5.0% 2.5% 1.5% TDD is as follows: nonlinear loads will continue to harmonic distortion increase. Therefore, the systems that 7 supply them will have to be designed 22 2 2 TDD = I2 + I3 + I4 + I5 + … x 100 so that their adverse effects are greatly Vh Percentages are  x 100 for each ()I reduced. Ta b l e 1. 9 - 1 shows the typical L 8 harmonic V1 harmonic orders from a variety of The numerator of the formula is the harmonic generating sources. and square root of the sum of the current harmonics squared. This value is 9 Table 1.9-1. Source and Typical Harmonics V % = V222+ V + V + V 2 + … x 100 THD 2 3 4 5 divided by I , which is the full load Source Typical ()L 1 V rms Harmonics 1 capacity of the system. From this, you 10 can see that even heavily distorted 6-pulse rectifier 5, 7, 11, 13, 17, 19… currents (i.e., high current THD) that are 12-pulse rectifier 11, 13, 23, 25… It is important for the system designer only a small fraction of the capacity of 11 18-pulse rectifier 17, 19, 35, 37… to know the harmonic content of the the system will result in a low TDD. Switch-mode power utility’s supply voltage because it will supply 3, 5, 7, 9, 11, 13… affect the harmonic distortion of Harmonic Solutions Fluorescent lights 3, 5, 7, 9, 11, 13… the system. 12 Arcing devices 2, 3, 4, 5, 7… In spite of all the concerns nonlinear Transformer energization 2, 3, 4 Table 1.9-4. Current Distortion Limits for loads cause, these loads will continue 1 Generally, magnitude decreases as harmonic General Distribution Systems (120– 69,000 V) to increase. Therefore, the application 13 order increases. Maximum Harmonic Current Distortion in of nonlinear loads such as variable frequency drives (VFDs) and the Total Harmonic Distortion Percent of IL 14 Individual Harmonic Order (Odd Harmonics) systems that supply them will require Revised standard IEEE 519-2014 further scrutiny by the design profes- ISC/IL <11 11 17 23 35 TDD indicates the limits of current distortion < h < h < h < h sional. The use of “Clean Power” multi- 15 allowed at the PCC (Point of Common <17 <23 <35 pulse VFDs has become a common Coupling) point on the system where 3 approach so adverse harmonic effects the current distortion is calculated. <20 4.0 2.0 1.5 0.6 0.3 5.0 are greatly reduced. Table 1.9-5 and 20<50 7. 0 3.5 2.5 1.0 0.5 8.0 depicts many harmonic solutions along 16 The 2014 revision is more focused on 50<100 10.0 4.5 4.0 1.5 0.7 12.0 harmonic limits on the system over 100<1000 12.0 5.5 5.0 2.0 1.0 15.0 with their advantages and disadvantages. time. It now clearly indicates that the >1000 15.0 7. 0 6.0 2.5 1.4 20.0 Eaton’s Engineering Services & PCC is the point of connection to 3 17 All power generation equipment is limited Systems Group (EESS) can perform the utility. to these values of current distortion, regardless of actual I /I where: harmonic studies and recommend SC L solutions for harmonic problems. The standard now primarily addresses ISC = Maximum short-circuit current at PCC. 18 the harmonic limits of the supply volt- IL = Maximum demand load current age from the utility or cogenerators. (fundamental frequency component) at PCC. TDD = Total Demand Distortion. Even 19 harmonics are limited to 25% of the odd harmonic limits above. Current distortions that result in a dc offset, e.g., half-wave 20 converters, are not allowed.

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.9-7 August 2017 Power Quality Sheet 01 119 Power Quality

Table 1.9-5. Harmonic Solutions for Given Loads Load Solutions Advantages Disadvantages i Ty p e Drives and rectifiers— Line reactors ■ Inexpensive ■ May require additional compensation ii includes three-phase ■ For 6-pulse standard drive/rectifier, can UPS loads reduce harmonic current distortion from 80% down to about 35–40% 1 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 dc choke ■ Slightly better than ac line reactors ■ Not always an option for drives 2 for 5th and 7th harmonics ■ Less protection for input semiconductors 12-pulse convertor ■ 85% reduction versus standard ■ Cost difference approaches 18-pulse drive 6-pulse drives and blocking filters, which guarantee 3 IEEE 519 compliance Harmonic mitigating ■ Substantial (50–80%) reduction in harmonics ■ Harmonic cancellation highly dependent transformers/phase shifting when used in tandem on load balance 4 ■ Must have even multiples of matched loads Tuned filters ■ Bus connected—accommodates ■ Requires allocation analysis load diversity ■ Sized only to the requirements of that system; 5 ■ Provides PF correction must be resized if system changes Broadband filters ■ Makes 6-pulse into the equivalent ■ Higher cost of 18-pulse ■ Requires one filter per drive 6 18-pulse converter ■ Excellent harmonic control for drives ■ High cost above 100 hp ■ IEEE 519 compliant 7 ■ No issues when run from generator sources Active filters ■ Handles load/harmonic diversity ■ High cost ■ Complete solution up to 50th harmonic 8 Active front end ■ Excellent harmonic control ■ High cost ■ Four quadrant (regen) capability ■ High complexity ■ Can have system stability issues when run 9 from generator source Computers/ Neutral blocking filter ■ Eliminates the 3rd harmonic from load ■ High cost switch-mode ■ Relieves system capacity ■ May increase voltage distortion 10 power supplies ■ Possible energy savings Harmonic mitigating ■ 3rd harmonic recalculated back to the load ■ Requires fully rated circuits and 11 transformers ■ When used as phase-shifted transformers, oversized neutrals to the loads reduces other harmonics ■ Reduces voltage “flat-topping” Oversized neutral/derated ■ Tolerate harmonics rather than correct ■ Upstream and downstream equipment 12 transformer ■ Typically least expensive fully rated for harmonics K-rated transformer ■ Tolerate harmonics rather than correct ■ Does not reduce system harmonics 13 Fluorescent Harmonic mitigating ■ 3rd harmonic recalculated back to the load ■ Requires fully rated circuits and lighting transformers ■ When used as phase-shifted transformers, oversized neutrals to the loads reduces other harmonics 14 ■ Reduces voltage “flat-topping” 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 15 expensive than “system” solutions Welding/arcing Active filters ■ Fast response and broadband ■ High cost loads harmonic correction 16 ■ Reduces voltage flicker Tuned filters ■ SCR controlled tuned filters simulates ■ SCR controlled units are high cost an active filter response but fixed filters are reasonable 17 System Tuned filters ■ Provides PF correction ■ System analysis required to verify application. 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 18 transformers Active filters ■ Ideal solution and handles system diversity ■ Highest cost 19

CA08104001E For more information, visit: www.eaton.com/consultants 1.9-8 Power Distribution Systems Power Quality August 2017 Sheet 01 120

5. Uninterruptible Power Uninterruptible power supply (UPS) Rotary UPS Systems i systems have evolved to serve the Systems (UPS) needs of sensitive equipment and Typical Ratings The advent and evolution of solid-state can supply a stable source of electrical 300–3 MW maximum. ii semiconductors has resulted in a pro- power, or switch to backup to allow liferation of electronic computational for an orderly shutdown of the loads Typical Rotary Configurations devices that we come in contact with without appreciable loss of data or Rotary UPS systems are among the 1 on a daily basis. These machines all process. In the early days of main- oldest working systems developed rely on a narrow range of nominal frame computers, motor-generator to protect sensitive loads. Many of ac power in order to work properly. sets provide isolation and clean power these systems are complicated engine- 2 Indeed, many other types of equip- to the computers. They did not have generator sets coupled with high ment also require that the ac electrical deep reserves, but provided extensive inertial flywheels operated at relatively power source be at or close to nominal ride-through capability while other low rotational speeds. These legacy 3 voltage and frequency. Disturbances sources of power (usually standby types of hybrid UPS systems are not of the power translate into failed emergency engine generator sets) the focus of this discussion, because processes, lost data, decreased were brought online while the normal only one or two vendors continue to 4 efficiency and lost revenue. source of power was unstable or offer them. unavailable. The normal power source supplied by See Figure 1.9-8 for the modern high 5 the local utility or provider is typically UPS systems have evolved along the speed Rotary UPS systems discussed not stable enough over time to lines of rotary types and static types in this section of the guide. These continuously serve these loads with- of systems, and they come in many types of modern rotary UPS systems 6 out interruption. It is possible that a configurations, including hybrid are advanced, integrated designs facility outside a major metropolitan designs having characteristics of using scalable configurations of high- area served by the utility grid will both types. The discussion that speed flywheel, motor and generator in 7 experience outages of some nature follows attempts to compare and one compact UPS package. The new 15–20 times in one year. Certain contrast the two types of UPS rotary technologies have the potential outages are caused by the weather, systems, and give basic guidance to replace battery backup systems, or 8 and others by the failure of the utility on selection criteria. This discussion at least reduce the battery content supply system due to equipment will focus on the medium, large and for certain applications. The appeal failures or construction interruptions. very large UPS systems required by of rotary systems is the avoidance of 9 Some outages are only several cycles users who need more than 10 kVA of the purchase, maintenance and facility in duration, while others may be for clean reliable power. space required by dc battery based hours at a time. backup systems. Power Ratings of UPS Systems 10 In a broader sense, other problems exist in the area of power quality, and ■ Small UPS: Typically 300 VA to 10 kVA, High-Speed Rotary 11 many of those issues also contribute and sometimes as high as 18 kVA Concept of Operation to the failure of the supply to provide ■ Medium UPS: 10–60 kVA The modern rotary type of UPS that narrow range of power to these ■ Large UPS: 100–200 kVA units, and operation is understood by reviewing 12 sensitive loads. higher when units are paralleled the four topics below: startup mode, Power quality problems take the form ■ Very Large UPS: 200–2 MW normal operation mode, discharge of any of the following: power failure, units, and higher when units mode and recharge mode. 13 are paralleled power sag, power surge, undervoltage, Startup Mode overvoltage, line noise, frequency Each of these categories is arbitrary variations, switching transients and The UPS output is energized on because manufacturers have many 14 harmonic distortion. Regardless of the bypass as soon as power is applied different UPS offerings for the same reason for outages and power quality from the source to the system input. application. The choice of UPS type problems, the sensitive loads can not The UPS continues the startup and the configuration of UPS modules 15 function normally without a backup procedure automatically when the for a given application depends upon power source Additionally, in many front panel controls are placed into . many factors, including: cases, the loads must be isolated from the “Online” position. Internal UPS system checks are performed then 16 the instabilities of the utility supply ■ How many power quality problems the input contactor is closed. The static and power quality problems and given the UPS is expected to solve clean reliable power on a continuous disconnect switch is turned on and the 17 ■ How much future capacity is to be conduction angle is rapidly increased basis, or be able to switch over to purchased now for future loads reliable clean electrical power quickly. from zero to an angle that causes the ■ The nature of the sensitive loads dc bus voltage between the utility con- 18 and load wiring verter and the flywheel converter to ■ Which type of UPS system is reach approximately 650 V through the favored, rotary or static rectifying action of the freewheeling 19 ■ Choices of battery or dc storage diodes in the utility converter. As soon technology considered as this level of dc voltage is reached, the static disconnect turns on fully. 20 ■ A host of other application issues

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.9-9 August 2017 Power Quality Sheet 01 121

Static Bypass Option i It = Input Current Ir = Real Load Current Ic = Charging Current ii Ig = Voltage Regulation Current Bypass Contactor 1 Id = Ih + Ix + Ir It = Ir + Ic + Ig Input Static Disconnect Output Contactor Switch Line Inductor Contactor 2 Source Load Flywheel Converter Utility Converter Ic Inverter 3 Fuse Output Transformer

Ix dc Filter Inductor Ig Id = Output Current Field Coil ac 4 Ih = Harmonic Current Driver dc ac Ix = Reactive Load Current Ir = Real Load Current 5 Ih Integrated Motor/Flywheel/ and Generator 6 Figure 1.9-8. Typical-High Speed Modern Rotary UPS The next step involves the utility Once the flywheel reaches 60 rpm, The second component is charging 7 converter IGBTs to start firing, the flywheel inverter controls the current required by the flywheel to which allows the converter to act as a acceleration to keep currents below the keep the rotating mass fully charged at rectifier, a regulating voltage source maximum charging and the maximum rated rpm, or to recharge the rotating 8 and an active harmonic filter. As the input settings. The point that the fly- mass after a discharge. The power to IGBTs begin to operate, the dc bus wheel reaches 4000 rpm, the UPS is maintain full charge is low at 2 kW and is increased to a normal operating fully functional and capable of support- is accomplished by the IGBTs of the 9 voltage of approximately 800 V, and ing the load during a power quality flywheel converter gating to provide the output bus is transferred from event. flywheel acceleration continues small pulses of motoring current to bypass to the output of the power until the Flywheel reaches “full charge” he flywheel. This current can be 10 electronics module. The transfer from at 7700 rpm. The total time to complete much higher if fast recharge times bypass is completed when the output startup is less than 5 minutes. are selected. contactor is closed and the bypass 11 contactor opened in a make-before- Normal Operation Mode The final component of input current break manner. Once the UPS is started and the is the voltage regulation current, which flywheel is operating at greater than is usually a reactive current that 12 The firing of the SCRs in the static 4000 rpm, the UPS is in the normal circulates between the input and the disconnect switch is now changed so operating mode where it is regulating utility converter to regulate the output that each SCR in each phase is only output voltage and supplying reactive voltage. Leading reactive current 13 turned on during the half-cycle, which and harmonic currents required by the causes a voltage boost across the line permits real power to flow from the load. At the same time it cancels the inductor, and a lagging current causes utility supply to the UPS. This firing effect of load current harmonics on the a bucking voltage. By controlling the 14 pattern at the static disconnect switch UPS output voltage. utility converter to maintain nominal prevents power from the flywheel output voltage, just enough reactive from feeding backward into the Input current consists of three current flows through the line inductor 15 utility supply and ensures that all of components: real load current, to make up the difference between the the flywheel energy is available to charging current, and voltage input voltage and the output voltage. support the load. regulation current. Real current is 16 current that is in phase with the supply The load current consists of three Immediately after the output is voltage and supplies real power to components: the harmonic current transferred from bypass to the power the load. Real current flowing through required by the load, the reactive load 17 electronic module, the flywheel field is the line inductor causes a slight phase current, and the real current, which excited, which also provides magnetic shift of the current lagging the voltage does the work. The utility converter lift to unload the flywheel bearings. by 10 degrees and ensures that the supplies both the harmonic and 18 The flywheel inverter is turned on UPS can quickly transfer to bypass reactive currents. Because these and gradually increases frequency without causing unacceptable currents supply no net power to the at a constant rate to accelerate the switching transients. load, the flywheel supplies no energy 19 flywheel to approximately 60 rpm. for these currents. They circulate between the utility converter and the load. 20

CA08104001E For more information, visit: www.eaton.com/consultants 1.9-10 Power Distribution Systems Power Quality August 2017 Sheet 01 122

The power stage controls analyze the Recharge Mode High-Speed Rotary Advantages i harmonic current requirements of When input power is restored to ■ Addresses all power quality the load and set the firing angle of acceptable limits, the UPS synchronizes problems the inverter IGBTs to make the utility the output and input voltages, closes ■ Battery systems are not required converter a very low impedance source ii the input contactor and turns on the or used to any harmonic currents. Thus, static disconnect switch. The utility ■ No battery maintenance required nonlinear load currents are supplied converter then transfers power from ■ 1 almost entirely from the utility the flywheel to the input source by Unlimited discharge cycles converter with little effect on the linearly increasing the real input ■ 150-second recharge time available quality of the UPS output voltage current. The transfer time is program- ■ Wide range of operating tempera- 2 waveform and with almost no mable from 1 to 15 seconds. As soon tures can be accommodated transmission of load harmonics as the load power is completely (–20 ° to 40 °C) currents to the input of the UPS. 3 transferred to the input source, the ■ Small compact size and less floor Discharge Mode utility converter and flywheel converter space required (500 kW systems start to recharge the flywheel and takes 20 sq ft) The UPS senses the deviation of return to normal operation mode. ■ N+1 reliability available up to 4 the voltage or frequency beyond The flywheel recharge power is 900 kVA maximum programmed tolerances and quickly programmable between a slow and disconnects the supply source by fast rate. Using the fast rate results ■ No disposal issues 5 turning off the static disconnect switch in an increase of UPS input current High-Speed Rotary Disadvantages and opening the input contactor. The over nominal levels. disconnect occurs in less than one-half ■ Flywheel does not have deep 6 cycle. Then the utility converter starts Recharging the flywheel is accom- reserve capacity—rides through delivering power from the dc bus to plished by controlling the utility and for up to 13 seconds at 100% load the load, and the flywheel converter flywheel converter in a similar manner ■ Some enhanced flywheel systems 7 changes the firing point of its IGBTs as is used to maintain full charge in the may extend the ride through to to deliver power to the dc bus. The normal operation mode, however the 30 seconds at 100% load UPS maintains a clean output voltage IGBT gating points are changed to ■ Mechanical flywheel maintenance 8 within 3% or nominal voltage to the increase current into the flywheel. required every 2–3 years, and oil load when input power is lost. changes required every year 9 ■ Recharge fast rates require the input to be sized for 125% of nominal current 10 ■ Flywheels failures in field not understood ■ Requires vacuum pumps for 11 high-speed flywheels ■ Limited number of vendors 12 and experience

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.9-11 August 2017 Uninterruptible Power Systems (UPS) Sheet 01 123

Static UPS Systems Double Conversion Concept of Operation 5. The bypass circuit provides a The basic operation of the Double path for unregulated normal i Typical Ratings Conversion UPS is: power to be routed around the 20 kW to 1 MVA / 1 MW, and higher major electronic sub-assemblies when multiple units are paralleled. 1. Normal power is connected to of the UPS to the load so that ii the UPS input through the facility the load can continue to operate Typical Static UPS Configurations electrical distribution system. during maintenance, or if the UPS Static UPS systems modules are This usually involves two input electronics fails. The bypass static 1 available in three basic types of circuits that can either come from switch can switch to conducting configurations known as standby, line the same source or from separate mode in <1 millisecond. When the interactive and double conversion. sources such as utility and site UPS recognizes a requirement to 2 See Ta b 3 3 in this guide for details on generation. transfer to the bypass mode, it simultaneously turns the static all the UPS configurations available 2. The Rectifier/Charger function switch ON, the output breaker to 3 from Eaton. The lower power ratings converts the normal ac power OPEN, and the bypass breaker to are likely to be one of the first two to dc power to charge the battery CLOSE. The output breaker opens types of configurations, e.g., standby and power the inverter. The and the bypass breaker closes 4 or line interactive. Most medium or load is isolated from the normal in about 50 milliseconds. The large static UPS installations use the input source. double conversion technology in one restoration of normal conditions at or multiple module configurations, 3. The battery stores dc energy the UPS results in the automatic 5 i.e., or multiple UPS units in parallel. for use when input power to the restoration of the UPS module UPS fails. The amount of power powering the load through the Special UPS high-efficiency operating available from the dc battery rectifier/charger and inverter with 6 modes like Eco mode or ESS can system and time to discharge load isolation from power quality provide efficiency improvements to voltage is a function of the type of problems, and the opening of the over 99%, equating to less than 1% battery selected and the ampere- bypass circuit. 7 losses through the UPS. These modes hour sized used. Battery systems Static Double Conversion Advantages depend on the system operating with should be sized for no less than the static switch closed and power 5 minutes of clean power usage ■ Addresses all power quality 8 conversion sections suspended from a fully charged state, and, in problems (not off). Modern UPSs can instantly many cases, are sized to provide ■ Suitable for applications from revert to traditional double conversion more time on battery power. 5 kVA to over 2500 kVA 9 operation within 2 ms on detection of ■ Simple battery systems are any power anomaly. 4. The dc link connects the output sized for application of the rectifier/charger to the input 10 Figure 1.9-9 illustrates the one-line of the inverter and to the battery. ■ Long battery backup times and diagram of a simple single Double Typically the rectifier/charger is long life batteries are available Conversion UPS module. Brief sized slightly higher than 100% of ■ Higher reliability is available 11 explanations appear for the standby UPS output because it must power using redundant UPS modules and line interactive UPS systems the inverter and supply charger after the text explaining the Double power to the battery. 12 Conversion static UPS type of system. 13

Bypass Breaker (Optional) UPS Module 14

Bypass Static Switch 15 Source Load Normal Output Rectifier/Charger Inverter Breaker Breaker 16 ac dc dc ac 17 Battery Breaker 18 Battery 19 Figure 1.9-9. Typical Static UPS, Double Conversion Type with Battery Backup 20

CA08104001E For more information, visit: www.eaton.com/consultants 1.9-12 Power Distribution Systems Power Quality August 2017 Sheet 01 124

Static Double Conversion Disadvantages 3. The battery stores dc energy for Static Line Interactive UPS i ■ Battery systems, battery maintenance use by the inverter when input Concept of Operation and battery replacement are required power to the UPS fails. The The basic operation of the Line amount of power available from ■ Large space requirement for Interactive UPS is: the dc battery system and time to ii battery systems (higher life takes 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 80–200 sq ft depending upon the 1 the ampere-hour sized used. the static double conversion and 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 2 ■ Limited discharge cycles of load in parallel with a battery 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 3 for application the inverter and to the battery. usually terminates at a line Typically the rectifier/charger ■ Efficiencies are in the 90–97% inductor and the output of the is sized only to supply charger inductor is connected to the load ■ Bypass mode places load at risk power to the battery, and is 4 unless bypass has UPS backup in parallel with the battery and rated far lower than in the inverter/charger circuit. See ■ Redundancy of UPS modules double conversion UPS. Figure 1.9-11 for more details. results in higher costs 5 5. The bypass circuit provides a ■ Output faults are cleared by the 2. The traditional rectifier circuit direct connection of bypass source bypass circuit is eliminated and this results to the load. The load operates 6 ■ Output rating of the UPS is 150% in a smaller footprint and from unregulated power. The weight reduction. However, line ■ Battery disposal and safety bypass static switch can switch conditioning is compromised. issues exist to non-conducting mode in 7 <8 milliseconds. When the UPS 3. When the input power fails, the Standby UPS Concept of Operation recognizes the loss of normal battery/inverter charger circuit The basic operation of the Standby input power, it transfers to battery/ reverses power and supplies the 8 UPS is: inverter mode by simultaneously load with regulated power. 1. The Standby UPS topology is turning the Inverter ON and the static switch OFF. Static Line Interactive UPS Advantages 9 similar to the double conversion ■ Slight improvement of power type, but the operation of the UPS Static Standby UPS Advantages conditioning over standby is different in significant ways. ■ Lower costs than double conversion UPS systems Normal power is connected to 10 ■ the UPS input through the facility ■ Rectifier and charger are Small footprints and weights electrical distribution system. economically sized ■ Efficient design 11 This usually involves two input ■ Efficient design ■ Batteries are sized for the circuits that can come from one or ■ Batteries are sized for the application two sources such as utility and site application 12 generation. See Figure 1.9-10 Static Line Interactive UPS Disadvantages for details. Static Standby UPS Disadvantages ■ Impractical over 10 kVA ■ Impractical over 2 kVA ■ Not as good conditioning as 2. The rectifier/charger function 13 ■ double conversion converts the normal ac power to Little to no isolation of load from dc power to charge the battery power quality disturbances ■ Standby power is from battery alone 14 only, and does not simultaneously ■ Standby power is from battery alone ■ Battery systems, battery maintenance power the inverter. The load is ■ Battery systems, battery mainte- and battery replacement are required connected to the bypass source nance and battery replacement ■ Limited discharge cycles for the 15 through the bypass static switch. are required battery system The inverter is in the standby ■ Limited discharge cycles of ■ Narrow temperature range for mode ready to serve the load battery system application from battery power if the input 16 ■ Narrow temperature range for ■ power source fails. Battery disposal and safety application issues exist ■ Output faults are cleared by the 17 bypass circuit ■ Battery disposal and safety 18 issues exist

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.9-13 August 2017 Power Quality Sheet 01 125

UPS Module i

Bypass Static Switch ii

2 Source Load Rectifier/ Normal Charger Inverter Output Breaker Breaker 3 ac dc

dc ac 4 Battery Breaker 5

Battery 6

Figure 1.9-10. Typical Static UPS, Standby Type with Battery Backup 7 8 UPS Module 9

Source Load 10 Inductor 11

Bidirectional Inverter/Charger 12 dc 13 ac 14

Battery 15

16 Figure 1.9-11. Typical Static UPS, Line Interactive Type with Battery Backup 17

CA08104001E For more information, visit: www.eaton.com/consultants 1.9-14 Power Distribution Systems August 2017 Sheet 01 126

This page intentionally left blank. i ii

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.10-1 August 2017 Other Application Considerations Sheet 01 127 Seismic Requirements

Seismic Requirements i

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 requirements of the Uniform Building Code 4 (UBC) and California Building Code (CBC). These codes emphasize building design requirements. Electrical 5 equipment and distribution system components are considered attachments to the building. The entire 6 program has been updated to show compliance with the 2015 International Building Code (IBC) and the 2016 CBC 7 seismic requirements. Figure 1.10-1. Typical Earthquake Ground Motion Map for the United States A cooperative effort with the equip- International Building Code (IBC) California Building Code 8 ment user, the building designer and On December 9, 1994, the International The 2001 CBC was based upon the the equipment installer ensures that Code Council (ICC) was established 1997 UBC. In August of 2006, it was the equipment is correctly anchored as a nonprofit organization dedicated repealed by the California Building 9 such that it can withstand the effects to developing a single set of compre- Standards Commission (CBSC) and of an earthquake. Eaton’s electrical hensive and coordinated codes. The replaced by the 2007 CBC, California distribution and control equipment has ICC founders—the Building Officials Code of Regulations (CCR),Title 24, 10 been tested and seismically proven for and Code Administrators (BOCA), the Part 2 and used the 2006 IBC as the requirements in compliance with the International Conference of Building basis for the code. The 2016 CBC IBC and CBC. Over 100 different Officials (ICBO), and the Southern is based upon the 2015 IBC, with 11 assemblies representing essentially all Building Code Congress International amendments as deemed appropriate product lines have been successfully (SBCCI)—created the ICC in response by the CBSC. Eaton’s seismic tested and verified to 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 2016 CBC with The equipment maintained structural codes now in use in the U.S. The many of the distribution and control integrity and demonstrated the ability ICC offers a single, complete set of products having Seismic Certification 13 to function immediately after the construction codes without regional Pre-approval with the California Office seismic tests. A technical paper, limitations—the International of Statewide Health Planning and Earthquake Requirements and Eaton Building Code. Development (OSHPD). 14 Distribution and Control Equipment Seismic Capabilities (SA12501SE), Uniform Building Code (UBC) Process provides a detailed explanation 15 of the applicable seismic codes 1997 was the final year in which the According to Chapter 16 of the 2015 and Eaton’s equipment qualification UBC was published. It has since been IBC, structure design, the seismic program. The paper may be found replaced by the IBC. requirements of electrical equipment 16 at www.eaton.com/seismic. Type in buildings may be computed in two in SA12501SE in the document steps. The first step is to determine search field. the maximum ground motion to be 17 considered at the site. The second step is to evaluate the equipment mounting and attachments inside the building 18 or structure. These are then evaluated to determine appropriate seismic test requirements. The ground motion, 19 seismic requirements of the equipment, and the seismic response spectrum requirements are discussed on 20 Page 1.10-3, see Figure 1.10-3. 21

CA08104001E For more information, visit: www.eaton.com/consultants 1.10-2 Power Distribution Systems Other Application Considerations August 2017 Sheet 01 128 Seismic Requirements

Ground Motion As a result, the adjusted maximum According to the IBC and ASCE 7, the i considered earthquake spectral spectral acceleration (Sa) at periods The first step in the process is to response for 0.2 second short period less than 1.45 seconds may be com- determine the maximum considered (SMS) and at 1.0 second (SM1), adjusted puted by using the following formula: ii earthquake spectral response accelera- for site class effects, are determined tion at short periods of 0.2 seconds from the following equations: Sa = SDS (0.6 T/T0 + 0.4) (SS) and at a period of 1.0 second (S1). Where T is the period where Sa is 1 These values are determined from a SMS = Fa SS = 1.0 x 3.73 g = 3.73 g set of spectral acceleration maps being calculated: SM1 = Fv S1 = 1.5 x 1.389 g = 2.08 g (Figure 1.10-1) and include numerous Therefore, the acceleration at 2 contour lines indicating the severity ASCE 7 (American Society of Civil 0.0417 seconds (24 Hz), for example, of the earthquake requirements at a Engineers) provides a plot of the is equal to: particular location in the country. final shape of the design response Sa = 2.49 (0.6 ((0.0417/0.112) + 0.4) = 1.55 g 3 The spectral acceleration maps spectra of the seismic ground motion. indicate low to moderate seismic The plot is shown in Figure 1.10-2. The acceleration at 0.03 seconds requirements for the entire country, ASCE 7 is referenced throughout (33 Hz) is equal to: 4 with the exception of two particular the IBC as the source for numerous Sa = 2.49 (0.6 (0.3/0.112) + 0.4) = 1.40 g areas; the West Coast and the Midwest structural design criteria. 5 (the New Madrid area). The maps The design spectral acceleration curve At zero period (infinite frequency), indicate that the high seismic require- can now be computed. The peak spec- T = 0.0, the acceleration (ZPA) is ments in both regions, West Coast tral acceleration (SDS) and the spectral equal to: and Midwest, quickly decrease as one acceleration at 1.0 second (SD1) may 6 moves away from the fault area. Sa = 2.49 (0.6 (0.0/0.112) + 0.4) = now be computed from the following 0.996 g (ZPA) Therefore, the high requirements formulas in the code: are only limited to a relatively narrow The acceleration to frequency 7 S = 2/3 x S = 2/3 x 3.73 g = 2.49 g strip along the fault lines. Just a few DS MS relationship in the frequency range miles away from this strip, only a SD1 = 2/3 x SM1 = 2/3 x 2.08 g = 1.39 g of 1.0 Hz to TS is stated equal to: 8 small percentage of the maximum requirements are indicated. SDS, the peak spectral acceleration, Sa = SD1/T extends between the values of T and Assuming the worse condition, which 0 Where S is the acceleration at the T . T and T are defined in the codes a 9 is a site directly located near a fault, S 0 S T period. as follows: the maximum considered earthquake At 1.0 Hz (T=1.0) this equation yields spectral response acceleration at short T = 0.2 S /S = 0.2 x 1.39/2.49 = 0 D1 DS the following acceleration: 10 periods of 0.2 seconds (SS) is equal to 0.112 seconds (8.96 Hz) 285% gravity and at 1.0 second period S = 1.39/1 = 1.39 g T = S /S = 1.39/2.49 = a (S1) is 124% gravity. These numbers S D1 DS 11 are the maximum numbers for the 5.585 seconds (1.79 Hz) entire country. To help understand the 2015 IBC (and 12 (g) 2016 CBC) seismic parameters for a a specific building location, the link to SDS the US Geological Society is extremely SD1 13 Sa = helpful: http://earthquake.usgs.gov/ T research/hazmaps/design/

14 S T The program will allow one to enter the SD1 S = D1 L latitude and longitude of a location. The a T2 15 IBC (CBC) seismic parameters for that location will then be displayed. To determine the maximum considered

16 earthquake ground motion for most T0 TS 1.0 TL site classes (A through D), the code A cc eler a t i on S Spe c tur a l Response Period T (sec) introduces site coefficients, which 17 when applied against the location- Figure 1.10-2. Design Response Spectrum specific site class, produces the adjusted maximum considered 18 earthquake spectral response acceleration for the required site. The site coefficients are defined as 19 Fa at 0.2 seconds short period and FV at 1.0 second period. From the tables in the code, the highest adjust- 20 ing factor for SS is equal to 1.0 and the highest adjusting factor for S1 is 1.50. 21

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.10-3 August 2017 Other Application Considerations Sheet 01 129 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 ■ 1.39 g 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 1.10-3. 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 1.10-3. Design Response Spectrum adequate to stop the peak spectral 11 acceleration at 8.96 Hz. There are other ASCE 7—Seismic Demands on Rp = Component response modifica- contour line combinations that will Non-Structural Components 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 ASCE 7 provides a formula for consider all combinations. However, computing the seismic requirements Ip = Component importance factor that a study of the spectral acceleration of electrical and mechanical equipment is either 1.0 or 1.5. 13 maps indicates that all variations with inside a building or a structure. The Z = Highest point of equipment in a high magnitude of contour lines could formula is designed for evaluating the building relative to grade elevation. very well be enveloped by a factor equipment attachment to the equip- 14 of 1.25. Therefore, T0 is recomputed ment foundations. The seismic loads h = Average roof height of building as follows: are defined as: relative to grade elevation. 15 T0 = 0.2 SD1/(SDS x 1.25) = 0.2 x 1.39/ Fp = 0.4 ap SDS Wp (1 + 2 Z/h)/(Rp/Ip) The following parameters produce the (2.49 x 1.25) = 0.089 seconds (11.20 Hz) maximum required force: Where: Eaton ensures maximum certification ■ Z is taken equal to h (equipment 16 by requiring peak acceleration during Fp = Seismic design force imposed on roof) at the component’s center of gravity testing to extend to 12 Hz. ■ I is taken equal to 1.5 (C.G.) and distributed relative to p 17 component mass distribution. ■ ap is taken equal to 2.5 ■ Rp is taken equal to 2.5 a = Component amplification factor p ■ S is equal to 2.49 g as indicated 18 that varies from 1.00 to 2.50. DS in the previous section S = Ground level spectral DS The acceleration (F /W ) at the C.G. acceleration, short period. p p 19 of the equipment is then computed Wp = Component operating weight. equal to: 20 Acceleration = Fp/Wp = 0.4 x 2.5 x 2.49 g (1 + 2) / (2.5/1.5) = 4.482 g 21

CA08104001E For more information, visit: www.eaton.com/consultants 1.10-4 Power Distribution Systems Other Application Considerations August 2017 Sheet 01 130 Seismic Requirements

For equipment on (or below) grade, i the acceleration at the equipment C.G. Required Response Spectrum is then computed equal to: 10 ii Acceleration = Fp/Wp = 0.4 x 2.5 x 2.49 g (1 + 0) / (2.5 /1.5) = 1.49 g It is impractical to attempt to measure 1 the actual acceleration of the C.G. of a piece of equipment under seismic test. 1 The seismic response at the middle of 2 base mounted equipment close to its

C.G. is at least 50% higher than the Acceleration (g) floor input at the equipment natural 3 frequency. The base accelerations associated with the accelerations of 0.1 FP/WP at the C.G. of the equipment 4 could then be computed as 4.48 /1.5 1 10 100 = 2.99 g. It is the equipment base input Frequency (Hz) acceleration that is measured and Eaton Seismic IBC 2015/CBC 2016 5 documented during seismic testing and is the acceleration value shown on Eaton’s seismic certificates. 6 Figure 1.10-4. Required Response Spectrum Curve Final Combined Requirements 7 To better compare all seismic levels and determine the final envelope 100% vs. 120% seismic requirements, the 2016 CBC 10 8 and 2015 IBC for California are plotted in Figure 1.10-4. All curves are plotted at 5% damping. An envelopment of the 9 seismic levels in the frequency range of 3.2 Hz to 100 Hz is also shown. This level is taken as Eaton’s generic 10 seismic test requirements for all 1 certifications. Eaton performed additional seismic test runs on the Acceleration (g) 11 equipment at approximately 120% of the generic enveloping seismic requirements (see Figure 1.10-5). Eaton 12 has established this methodology 0.1 to provide additional margin to 1 10 100 accommodate potential changes Frequency (Hz) 13 with the spectral maps, thus eliminating the need for additional testing. Eaton 100% Seismic Envelope Eation 120% Seismic Envelope

14 Figure 1.10-5. Eaton Test Required Response Spectrum Curve 15

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.10-5 August 2017 Other Application Considerations Sheet 01 131 Seismic Requirements

Product Specific Test Summaries i Table 1.10-6. Distribution Equipment Tested and Seismically Proven Against Requirements within IBC 2015 ii Note: For most current information, see www.eaton.com/seismic. Eaton Equipment 1 MV Metal-Clad Switchgear, VacClad-W MV Metal-Enclosed Switchgear: 2 MEF Front Access MV Metal-Enclosed Switchgear; MVS, MEB MV Motor Starters: Ampgard 3 MV Variable Frequency Drives (VFD) MV Busway: Non-Segregated Unitized Power Centers 4 Spot Network Equipment LV Metal-Enclosed Drawout Switchgear: 5 Magnum LV Busway LV Motor Control Centers (MCC) 6 Switchboards Panelboards Dry-Type Distribution Transformers (DTDT) 7 Transfer Switch Equipment Enclosed Molded-Case Circuit Breakers 8 Safety Switches Elevator Control Enclosed Motor Starters & Contactors 9 Variable Frequency Drives (VFD) Uninterruptible Power Supplies (UPS) 10 CAT Generator Paralleling Switchgear Resistance Grounding Systems IEC Equipment 11 Solar Systems Interconnect Equipment Fire Pump Controllers 12 Residential/Light Commercial Metering & Distribution

Note: See www.eaton.com/seismic for 13 current seismic certificates. 14 Figure 1.10-6. Sample Seismic Certificate 15

CA08104001E For more information, visit: www.eaton.com/consultants 1.10-6 Power Distribution Systems Other Application Considerations August 2017 Sheet 01 132 Seismic Requirements

Additional Design and Note: Eaton recommends that designers Energy Conservation i confirm with the manufacturer if the Installation Considerations seismic certification supplied with the Because of the greatly increased cost When installing electrical distribution equipment is based on: of electrical power, designers must ii and control equipment, consideration consider the efficiency of electrical must be given as to how the methods 1. ACTUAL shaker table test as distribution systems, and design for employed will affect seismic forces required by the IBC and CBC. energy conservation. In the past, 1 imposed on the equipment, equipment especially in commercial buildings, 2. The seismic certificate and test design was for lowest first cost, mounting surface, and conduits data clearly state if the equipment entering the equipment. because energy was inexpensive. 2 was tested as free-standing— Today, even in the speculative office Eaton recommends that when specify- anchored at the bottom of the building, operating costs are so high ing a brand of electrical distribution equipment to the shaker table. that energy-conserving designs can 3 and control equipment, the designer 3. Structure attached, that is, justify their higher initial cost with a references the installation manuals of anchored at the center of gravity rapid payback and continuing savings. that manufacturer to ascertain that the (C.G.) or at the TOP of the equip- The leading standard for energy 4 requirements can be met through the ment to a simulated wall on the conservation is ASHRAE 90.1 (latest design and construction process. shaker table. is 2016) and International Energy Conservation Code (IECC) as adopted For Eaton electrical distribution and Stand-Alone or Free-Standing Equipment by the International Building Code (IBC). 5 control products, the seismic installa- If stand-alone or free-standing, then tion guides for essentially all product There are four major sources of this may require that additional width lines can be found at our Web site: electrical energy conservation in space be allowed at each end of the 6 http://www.eaton.com/seismic. a commercial building: 1) Lighting equipment for additional seismic Systems, 2) Motors and controls, bracing supplied by the manufacturer. Electrical designers must work closely 3) Transformers, 4) HVAC system. 7 with the structural or civil engineers Additional thought must be given to for a seismic qualified installation. The lighting system must take the clearances around the equipment advantage of the newest equipment to rigid structural edifices. Space must 8 Consideration must be given to the and techniques. New light sources, be allowed for the differing motions of type of material providing anchorage familiar light sources with higher the equipment and the structure, so for the electrical equipment. efficiencies, solid-state ballasts with that they do not collide during a seis- 9 dimming controls, use of daylight, If steel, factors such as thickness or mic event and damage one another. gauge, attachment via bolts or welding, environmental design, efficient and the size and type of hardware Note: If the equipment is installed as stand- luminaires, computerized or 10 must be considered. alone or free-standing, with additional programmed control, and the like, seismic bracing at each end and not are some of the methods that can If concrete, the depth, the PSI, the type attached to the structure as tested, and yet, increase the efficiency of lighting 11 of re-enforcing bars used, as well as it is fitted tightly against a structural wall, systems. They add up to providing the diameter and embedment of then this would be an incorrect installation for the application of the seismic certificate. the necessary amount of light, with the anchorage all must be considered. desired color rendition, from the most 12 efficient sources, where and when it is The designer must also give consider- Furthermore, if conduits are to be needed, and not providing light where ation if the equipment will be secured installed overhead into the equipment, or when it is not necessary. 13 to the wall, versus stand-alone or does the design call for flexible conduits free-standing, which requires the of sufficient length to allow for the The installation of energy-efficient equipment to withstand the highest conflicting motion of the equipment lighting provides the best payback 14 level of seismic forces. Top cable and the structure during a seismic event for the lowest initial investment and entry should be avoided for large so as to not damage the conductors should be considered the first step in enclosures, as accommodation for contained therein, and the terminations a facility energy reduction program. 15 cable/conduit flexibility will need to points within the equipment. be designed into the system. Motors and controls are another cause Structure Attached Equipment of wasted energy that can be reduced. 16 For a manufacturer to simply state The designer must work closely New, energy-efficient motor designs “Seismic Certified” or “Seismic with the structural engineer if the are available using more and better Qualified” does not tell the designer equipment is to be attached to the core steel, and larger windings. if the equipment is appropriate for structure to ascertain that the internal 17 the intended installation. wall re-enforcement of the structure, type of anchor, and depth of embed- 18 ment is sufficient to secure the equipment so that the equipment, conduits and structure move at or 19 near the same frequency.

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.10-7 August 2017 Other Application Considerations Sheet 01 133 Seismic Requirements

For any motor operating 10 or The U.S. Department of Energy (DOE) HVAC systems have traditionally been more hours per day, the use of has established energy efficiency very wasteful of energy, often being i energy-efficient types is strongly standards that manufacturers of designed for lowest first cost. This, recommended. These motors have a distribution transformers must too, is changing. For example, reheat premium cost of about 20% more comply with since 2007. As of systems are being replaced by variable ii than standard motors. Depending on January 1, 2016, the DOE standard air volume systems, resulting in equal loading, hours of use and the cost of CFR Title 10 Chapter II Part 431 comfort with substantial increases in energy, the additional initial cost could (in Appendix A of Subpart K 2016) efficiency. While the electrical engineer 1 be repaid in energy saved within a few requires increased minimum operat- has little influence on the design of the months, and it rarely takes more than ing efficiencies for each distribution HVAC system, he/she can specify that two years. Because, over the life of a transformer size at a loading equal to all motors with continuous or long duty 2 motor, the cost of energy to operate it is 35% of the transformer full load kVA. cycles are specified as energy-efficient many times the cost of the motor itself, The 35% loading value in the NEMA types, and that the variable-air-volume any motor with many hours of use standard reflects field studies fans do not use inlet vanes or outlet 3 should be of the energy-efficient type. conducted by the U.S. Department dampers, but are driven by variable- of Energy, which showed that dry-type speed drives. Where a motor drives a load with transformers installed in commercial 4 variable output requirements such facilities are typically loaded at an Variable speed drives can often be as a centrifugal pump or a large fan, average of 35% of their full load desirable on centrifugal compressor customary practice has been to run the capacity over a 24-hour time period. units as well. Because some of these 5 motor at constant speed, and to throttle Figure 1.10-7 compares losses for requirements will be in HVAC the pump output or use inlet vanes or both low temperature rise TP-1 specifications, it is important for outlet dampers on the fan. This is highly and DOE 2016 transformers using the energy-conscious electrical 6 inefficient and wasteful of energy. In a 75 kVA design. engineer to work closely with the order to achieve maximum energy HVAC engineer at the design stage efficiency in these applications, solid- to ensure that these systems are as 7 state variable frequency, variable speed energy efficient as possible. drives for AC induction motors are available as a reliable and relatively 8 inexpensive option. Using a variable- Former TP-1 Versus NEW DOE 2016 Transformer Loss Comparison speed drive, the throttling valves, for 75 kVA Copper Wound 80C, 115C and 150C Temperature Rated Designs inlet vanes or output dampers can be 3500 9 eliminated, saving their initial cost and energy over the life of the system. An 3000 2903 additional benefit of both energy- 10 efficient motors and variable speed 2557 drives used to control the speed of 2500 2346 2146 variable torque loads, such as centrifu- 2075 11 gal fans and pumps, is that the motors 2000 1848 1837 operate at reduced temperatures, 1753 1612 1640 1615 1519 resulting in increased motor life. 1426 12

Watts Losses 1407 1500 1333 1238 1202 1508 Transformers have inherent losses. 1104 1040 1334 Transformers, like motors, are designed 911 1000 1127 13 for lower losses by using more and 976 857 838 better core materials, larger conductors, 759 666 500 598 etc., and this results in increased initial 360 545 300 14 256 cost. Because the 480 V to 208Y/120 V 193 stepdown transformers in an office 0 building are usually energized 24 hours 0% 25% 35% 50% 75% 100% 15 a day, savings from lower losses can Percentage of Load be substantial, and should be consid- DOE 2016 Efficient 150C TP-1 Efficient 150C DOE 2016 Efficient 115C ered in all transformer specifications. TP-1 Efficient 115C TP-1 Efficient 80C 16 One method of obtaining reduced DOE 2016 Efficient 80C losses is to specify Premium Efficiency Figure 1.10-7. Former TP-1 NEW DOE 2016 Transformer Loss Comparison for 75 kVA Copper Wound transformers with no more than 80 °C 17 (or sometimes 115 °C) average winding temperature rise at full load. These transformers generate less heat than 18 standard 150 °C rise transformers, resulting in lower HVAC operating costs to remove the heat in areas 19 where they are located. 20

CA08104001E For more information, visit: www.eaton.com/consultants 1.10-8 Power Distribution Systems Application Considerations August 2017 Sheet 01 134

Building Control Systems Increasingly, advanced signaling is Prime Power i being implemented utilizing sensors DER can be used for generating prime In order to obtain the maximum that communicate wirelessly to benefit from these energy-saving power or for cogeneration. Prime power gateways that connect them back to concerns a system that is electrically ii lighting, power and HVAC systems, the master control system. The newest they must be controlled to perform separated from the electrical grid. systems are using fiber optic cables Prime power is generated at remote their functions most efficiently. as the Ethernet backbone to carry Constant monitoring would be sites where commercial electrical 1 tremendous quantities of data, free power is not available. required for manual operation but from electromagnetic interference is impractical and not cost-effective back to the master control system and Cogeneration 2 given the skilled labor rates of facilities auxiliary building systems. While the engineering personnel. In order to actual method used will depend on Cogeneration is another outgrowth of ensure optimum energy performance, the type, number and complexity the high cost of energy. Cogeneration 3 some form of automatic control of functions to be performed, the is the production of electric power con- is required. commonality of exchanging data at the currently with the production of steam, hot water and similar energy uses. The The simplest of these energy-saving Ethernet level is a prime consideration electric power can be the main prod- 4 controls is a time clock to turn various in the selection of equipment that will uct, and steam or hot water the systems on and off. Where flexible need to be integrated into the overall byproduct, as in most commercial control is required, programmable system. Eaton offers a variety of installations, or the steam or hot water 5 controllers may be used. These metering, protection and control can be the most required product, range from simple devices, similar devices that can be used as local Web and electric power a byproduct, as to multi-function time clocks, to fully servers as well as to communicate in many industrial installations. In 6 programmable, microprocessor-based over Ethernet LANs by BACnet/IP some industries, cogeneration has devices that run dedicated software to or Modbus TCP to other master been common practice for many control specific loads or processes. control systems. 7 years, but until recently it has not For complete control of all building Because building design and control been economically feasible for most systems, building management for maximum energy saving is commercial installations. 8 systems (BMS) with specialized important and complex, and This has been changed by the high software can be used. Computers can frequently involves many functions cost of purchased energy, plus federal not only control lighting and HVAC and several systems, it is necessary and state policies incentivizing public 9 systems, and provide peak demand for the design engineer to make a utilities to purchase any excess power control to minimize the cost of energy, thorough building and environmental generated by the cogeneration plant. but they can perform many other study, and to weigh the costs and In many cases, practical commercial 10 functions. Fire detection and alarm advantages of many systems. The cogeneration systems have been built systems that generally have their own result of good design and planning that provide some or all of the electric dedicated control system can report can be economical, efficient operation. power required, plus hot water, steam, 11 back information to the BMS System. Poor design can be wasteful and and sometimes steam absorption-type Other auxiliary systems, such as extremely costly. air conditioning. Such cogeneration elevator control and various aspects systems are now operating success- 12 of access and intrusion control, often Distributed Energy Resources fully in hospitals, shopping centers, have the capability to be integrated Distributed energy resources (DER) high-rise apartment buildings and to share information with the BMS. are increasingly becoming prominent even commercial office buildings. 13 Other building systems, such as sources of electric power. Distributed closed-circuit television monitoring, energy resources are usually small-to- Where a cogeneration system is being are increasingly sharing data and medium sources of electric generation, considered, the electrical distribution 14 bandwidth over the same Ethernet either from renewable or non-renew- system becomes more complex. backbone with the building manage- able sources. Sources include: The interface with the utility company ment computer system. is critical, requiring careful relaying 15 ■ Photovoltaic (PV) systems to protect both the utility and the The time clocks, programmable (solar systems) cogeneration system. Many utilities controllers and computers can ■ Energy storage systems (battery) have stringent requirements that obtain data from external sensors 16 ■ must be incorporated into the and control the lighting, motors and Wind system. Proper generator control other equipment by means of hard ■ Fossil-fueled (diesel, natural gas, and protection is necessary, as well. wiring-separate wires to and from landfill gas, coal-bed methane) 17 An on-site electrical generating plant each piece of equipment. In the more generators (reciprocating engines) tied to an electrical utility requires a complex systems, this would result ■ Gas-fired turbines (natural gas, sophisticated engineering design, in a tremendous number of control 18 landfill gas, coal-bed methane) interconnection application and wires, so other methods are frequently ■ Water-powered (hydro) system impact studies. used. A single pair of wires, with ■ Fuel cells 19 electronic digital multiplexing, can control or obtain data from many ■ Microturbines different points. ■ Wave power 20 ■ Coal-fired boilers Distributed energy resources may also 21 be termed alternative energy resources.

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.10-9 August 2017 Application Considerations Sheet 01 135

Utilities require that when the For installation in/on/for existing Seek the solar module data sheet for protective device at their substation structures and sites, it is advised a list of standard test condition (STC) i opens that the device connecting a that, at the minimum, pre-design data, temperature coefficients, and any cogenerator to the utility open also. and construction tests be performed special module-related information to This is often accomplished by Transfer for existing power-quality issues, determine the low-temperature open ii Trip Systems utilizing dedicated fiber water drainage and the utility circuit voltage. The prevailing industry optic connectivity and local multiplex- feeder/transformer. practice, requires the use of the site’s ing equipment. Extreme Annual Mean Minimum 1 Additionally, electrical distribution Design Dry Bulb Temperature data, This can add considerable cost and panel ratings ampacity and short- available in the ASHRAE Handbook. complexity to the design as well as circuit ratings must be sufficient for Code requires that the resulting 2 reoccuring monthly charges to pay the planned solar system, and the maximum voltage (Voc) when added for the use of the dedicated fiber. necessary arc flash studies be in the “string of modules” be under performed. Connection to the utility One reason for these complex maximum system voltage. Record low 3 is always preceded by a utility inter- temperatures provide an indication of Transfer Trip arrangements is that connect agreement (application) most cogenerators are connected to system performance when tempera- process. Successful approval is tures drop to these levels. Power 4 feeders serving other customers. typically required for the available Utilities desire to reclose the feeder Xpert Solar inverters are designed to solar incentives and programs offered 1000 Vdc and 1500 Vdc standards. after a transient fault is cleared. by the utility, municipality, state, and 5 Reclosing in most cases will damage various federal agencies and depart- High Temperature Equation the cogenerator if it had remained ments. State, and IRS tax incentives connected to their system. Once the maximum number of require well-documented records. modules per string is established, 6 Islanding is another reason why the Solar systems, while low maintenance, the minimum number of modules per utility insists on the disconnection of do require periodic service. The solar string needs to be calculated. Here, the cogenerator. Islanding is the event modules need to be washed-clean on more site-related aspects come into 7 that after a fault in the utility’s system a regular basis and electrical termina- play, as the voltage of solar modules is cleared by the operation of the tions require initial and annual checks. decreases with increasing tempera- protective devices, a part of the Cooling system filters are periodic ture. The modules’ (photovoltaic cell) 8 system may continue to be supplied maintenance items, with the re-fresh temperature is influenced by the by cogeneration. Such a condition is rate dependent upon typical and ambient temperature, reflected 9 dangerous to the utility’s operation unusual circumstances. sun-loads from nearby structures, during restoration work. parapet walls, roof-coatings, etc. Solar systems installed near other new Major cogenerators are connected to construction where dust is generated Air-flow above and behind the solar 10 the subtransmission or the transmission (e.g., grading, paving) or agricultural modules affect the cell temperature. system of a utility. Major cogenerators environments may require additional The accepted industry standards to have buy-sell agreements. In such solar-system checks and services. add to the module heating are listed 11 cases, utilities will use a trip transfer Planning for such contingencies is below. Unusual mounting systems scheme to trip the cogenerator breaker. the business of solar-system design, may adjust these figures, and it is best construction and on-going operation. to seek assistance in establishing and 12 Guidelines that are given in IEEE 1547 planning such installations. and IEEE P2030 are starting points, Performance-based incentives but the entire design should be require verifiable metering, often ■ 15–20 °C for ground or pole 13 coordinated with the utility. by registered/approved independent mounted solar systems third parties. Such monitoring periods ■ 20–25 °C for roof-top solar systems are typically for 60 or more months. PV System Design Considerations mounted at inclined angles 14 Successful photovoltaic (PV) design It is generally wise to involve engineer- (offers improved air-flow behind and construction is a complex multi- ing design firms that specialize in the modules) discipline endeavor. Proper planning complete solar systems “turn-key” ■ 25–30 °C for roof-top solar systems 15 includes site survey and solar site calculations, drawings, construction mounted flat, yet at least 6.00 inches assessment for maximizing the sun’s management and procurement. (152.4 mm) above the roof surface energy harvesting for solar module 16 selection, and for updating the The following equations are the basis Vmp_min = Vmp + (temp-differential x electrical/mechanical design and of all solar system layout and design. temp-coefficient-of-Vmp) construction to the latest code and Low Temperature Equation The temp-differential in this case 17 local constraints, including fire Voc_max = Voc + (temp-differential x includes the above temperature marshal and seismic regulations. temp-coefficient-of-Voc) “adders.” The Vmp and related Professionally prepared bid, permit, temperature coefficients are listed 18 construction and as-built drawings The temp-differential is the difference on the solar module’s data sheets. must be required and maintained. between the standard module rating at 25 °C and the low temperature. 19 The voltage (Voc) will rise with temperatures under 25 °C. 20

CA08104001E For more information, visit: www.eaton.com/consultants 1.10-10 Power Distribution Systems Application Considerations August 2017 Sheet 01 136

While the code doesn’t indicate the All wiring from emergency source to Where the emergency or standby i high temperature to use (i.e., because emergency loads must be kept separate source, such as an engine generator it is an equipment application issue), from all other wiring and equipment, or separate service, has capacity to the industry standard is to evaluate the in its own distribution and raceway supply the entire system, the transfer ii ASHRAE 2% high temperature figures, system, except in transfer equipment scheme can be either a full-capacity coupled to known location differences. enclosures and similar locations. automatic transfer switch, or, less Record high temperatures provide costly but equally effective, normal 1 an indication of system performance The most common power source for and emergency main circuit breakers, when climatic condition reaches large emergency loads is an engine- electrically interlocked such that on these levels. generator set, but the NEC also permits failure of the normal supply the 2 the emergency supply (subject to emergency supply is connected to the Beyond the damaging temperature local code requirements) to be storage load. However, if the emergency or affects on photovoltaic module Vmp batteries, uninterruptible power standby source does not have capacity 3 voltage levels, voltage drop in PV supplies, a separate emergency for the full load, as is usually the conductors under such conditions also service, or a connection to the service case, such a scheme would require need to be calculated and evaluated, ahead of the normal service discon- automatic disconnection of the 4 beyond normal temperatures. The necting means. Unit equipment for nonessential loads before transfer. inverter only uses (knows) the Vmp emergency illumination, with a voltage at the inverter, not at the rechargeable battery, a charger to A simpler and more economical 5 PV modules. keep it at full capacity when normal approach is a separate emergency power is on, one or more lamps, and bus, supplied through an automatic Increasing grid voltages also puts a a relay to connect the battery to the transfer switch, to feed all critical 6 constraint on the minimum Vmp lamps on loss of normal power, is loads. The transfer switch connects voltage at the DC input stage. also permitted. this bus to the normal supply, in To ensure the full MPPT range without normal operation. On failure of the Because of the critical nature of normal supply, the engine-generator 7 power-clipping (reduced power output), emergency power, ground fault prudent PV system designs shall con- is started, and when it is up to speed protection is not required. It is the automatic switch transfers the sider the PV array’s Vmp voltage drop considered preferable to risk arcing 8 to the point of the inverter connection, emergency loads to this source. On damage, rather than to disconnect return of the normal source, manual or ambient temperatures and the PV the emergency supply completely. For system installation type’s effects on automatic retransfer of the emergency 9 emergency power, ground fault alarm loads can take place. Vmp, solar module miss-match and is required by NEC 700.5(D) to indicate tolerance variations, degradation of a ground fault in solidly grounded Peak Shaving 10 solar modules over time (solar system wye emergency systems of more than life), etc. Typical Vmp design values, 150 V to ground and circuit-protective Many installations now have based upon known and expected devices rated 1000 A or more. emergency or standby generators. conditions are 5–10% over the In the past, they were required for 11 minimum MPPT tracking voltage. Legally required standby systems, as hospitals and similar locations, but Reference NEC 2017 Section 690 and required by the governmental agency not common in office buildings or 691, Solar Photovoltaic Systems. having jurisdiction, are intended to shopping centers. However, many 12 supply power to selected loads, other costly and unfortunate experiences Emergency Power than those classed as emergency during utility blackouts in recent years 13 Most areas have requirements systems, on loss of normal power. have led to the more frequent installa- for emergency and standby power These are usually loads not essential tion of engine generators in commer- systems. The National Electrical Code to human safety, but loss of which cial and institutional systems for safety does not specifically call for any could create hazards or hamper and for supplying important loads. 14 rescue or fire-fighting operations. emergency or standby power, but Industrial plants, especially in process does have requirements for those NEC requirements are similar to those industries, usually have some form 15 systems when they are legally for emergency systems, except that of alternate power source to prevent mandated and classed as emergency wiring may occupy the same distribu- extremely costly shutdowns. These (Article 700), legally required standby tion and raceway system as the standby generating systems are 16 (Article 701) by municipal, state, normal wiring if desired. Optional critical when needed, but they are federal or other codes, or by any standby systems are those not legally needed only infrequently. They governmental agency having jurisdic- required, and are intended to protect represent a large capital investment. 17 tion. Optional standby systems, not private business or property where To be sure that their power will be legally required, are also covered in life safety does not depend on available when required, they should the NEC (Article 702). performance of the system. Optional be tested periodically under load. 18 Emergency systems are intended to systems can be treated as part of the supply power and illumination essen- normal building wiring system. Both tial for safety to human life, when the legally required and optional standby 19 normal supply fails. NEC requirements systems should be installed in such are stringent, requiring periodic testing a manner that they will be fully avail- under load and automatic transfer to able on loss of normal power. It is 20 emergency power supply on loss of preferable to isolate these systems normal supply. See Figure 1.10-8. as much as possible, even though not required by code. 21

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.10-11 August 2017 Application Considerations Sheet 01 137

Utility i 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. ii G1 G2 G3 G4 Paralleling Switchgear with Distribution 1 Revenue Metering HMI Touchscreen 2 52G1 52G2 52G3 52G4 Main D1 D2 D3 D4 3 Service 4

6 ATS1 N ENENENEATS2 ATS3 ATS4 To Normal To Emergency Distribution Circuits Circuits 7

EDP1 EDP2 EDP3 EDP4 8

Optional Remote PC with Software 9 LP1 BP1 LP2 BP2 LP3 BP3 LP4 BP4 10 Figure 1.10-8. Typical Emergency Power System

The cost of electric energy has risen The engine-generator must be It is important that the electrical sys- 11 to new high levels in recent years, and selected to withstand the required tem designer providing a substantial utilities bill on the basis not only of duty cycle. The simplest of these source of emergency and standby power consumed, but also on the schemes transfer specific loads to the power investigate the possibility of 12 basis of peak demand over a small generator. More complex schemes using it for peak shaving, and even interval. As a result, a new use for operate the generator in parallel with of partial utility company financing. in-house generating capacity has the normal utility supply. The savings Frequently, substantial savings in 13 developed. Utilities measure demand in demand charges can reduce the cost power costs can be realized for a charges on the basis of the maximum of owning the emergency generator small additional outlay in distribution demand for electricity in any given equipment. and control equipment. 14 specific period (typically 15 or 30 minutes) during the month. Some In some instances, utilities with little Peak shaving equipment operating in utilities have a demand “ratchet clause” reserve capacity have helped finance parallel with the utility are subject to the 15 that will continue demand charges on the cost of some larger customer- comments made under cogeneration a given peak demand for a full year, owned generating equipment. In as to separation from the utility under unless a higher peak results in even return, the customer agrees to take fault conditions. 16 higher charges. One large load, coming some or all of his load off the utility on at a peak time, can create higher system and on to his own generator at electric demand charges for a year. the request of the utility (with varying 17 limitations) when the utility load Obviously, reducing the peak demand approaches capacity. can result in considerable savings in 18 the cost of electrical energy. For those In some cases, the customer’s installations with engine generators generator is paralleled with the utility for emergency use, modern control to help supply the peak utility loads, 19 systems (computers or programmable with the utility buying the supplied controllers) can monitor the peak power. Some utilities have been able demand, and start the engine-generator to delay large capital expenditures for 20 to supply part of the demand as it additional generating capacity by such arrangements. approaches a preset peak value. 21

CA08104001E For more information, visit: www.eaton.com/consultants 1.10-12 Power Distribution Systems August 2017 Sheet 01 138

This page intentionally left blank. i ii

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.11-1 August 2017 Reference Data Sheet 01 139

Codes and Standards a number of other testing laboratories A design engineer should conform have been recognized and accepted. to all applicable codes, and require i 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 of books (the “color book” series) on wherever possible, and to meet ii 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 buildings, emergency power systems, be followed to a great extent. In 1 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 ANSI standards. They are excellent quality required. The design goal 2 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 electrical distribution system. 3 as New York and Chicago, have their own electrical codes, basically similar Professional Organizations to the NEC. The designer must deter- American National Standards Institute National Electrical Manufacturers 4 mine which code applies in the area (ANSI) Association (NEMA) of a specific project. Headquarters: 1300 North 17th Street 5 The Occupational Safety and Health Suite 900 Act (OSHA) of 1970 sets uniform 1899 L Street, NW Arlington, VA 22209 national requirements for safety in the 11t h F l oo r 703-841-3200 6 workplace—anywhere that people are Washington, DC 20036 www.nema.org employed. Originally OSHA adopted 202-293-8020 the 1971 NEC as rules for electrical Operations: National Fire Protection Association 7 safety. As the NEC was amended every 25 West 43rd Street (NFPA) three years, the involved process for 4th Floor 1 Batterymarch Park modifying a federal law such as OSHA New York, NY 10036 Quincy, MA 02169-7471 8 made it impossible for the act to adopt 212-642-4900 617-770-3000 each new code revision. To avoid this problem, the OSHA administration www.ansi.org www.nfpa.org 9 in 1981 adopted its own code, a condensed 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 Headquarters: was amended to adopt this code, 847-272-8800 based on NFPA Standard 70E, Part 1, 3 Park Avenue 11 which is now federal law. 17th Floor www.ul.com New York, NY 10016-5997 The NEC is a minimum safety 212-419-7900 International Code Council (ICC) 12 standard. Efficient and adequate 500 New Jersey Avenue, NW design usually requires not just Operations: 6th Floor meeting, but often exceeding NEC 445 and 501 Hoes Lane Washington, DC 20001 13 requirements to provide an effective, Piscataway, NJ 08854-4141 1-888-422-7233 reliable, economical electrical system. 732-981-0060 www.iccsafe.org Many equipment standards have been www.ieee.org 14 established by the National Electrical The American Institute of Architects (AIA) Manufacturers’ Association (NEMA) International Association of Electrical 1735 New York Avenue, NW and the American National Standards Inspectors (IAEI) Washington, DC 20006-5292 15 Institute (ANSI). Underwriters 901 Waterfall Way 1-800 242-3837 Suite 602 Laboratories (UL) has standards that www.aia.org equipment must meet before UL will Richardson, TX 75080-7702 16 list or label it. Most jurisdictions and 972-235-1455 OSHA require that where equipment listed as safe by a recognized labora- www.iaei.org 17 tory is available, unlisted equipment may not be used. UL is by far the most widely accepted national laboratory, 18 although Factory Mutual Insurance Company lists some equipment, and 19

CA08104001E For more information, visit: www.eaton.com/consultants 1.11-2 Power Distribution Systems Reference Data August 2017 Sheet 01 140

Table 1.11-1. Selected IEEE Device Numbers for Switchgear Apparatus i Device Function Definition Typical Number Uses ii 2 Time-delay starting or closing relay A device that functions to give a desired amount Used for providing a time-delay for 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 1 48, 62 and 79 described later. 6 Starting circuit breaker A device whose principal function is to connect — a machine to its source of starting voltage. 2 19 Starting to running transition timer A device that operates to initiate or cause the Used to transfer a reduced voltage automatic transfer of a machine from the starting starter from starting to running. to the running power connection. 3 21 Distance relay A device that functions when the circuit — admittance, impedance or reactance increases or decreases beyond predetermined limits. 4 23 Temperature control device A device that functions to raise or to lower the Used as a thermostat to control temperature of a machine or other apparatus, or space heaters in outdoor equipment. of any medium, when its temperature falls below 5 or rises above, a predetermined level. 24 Volts per hertz relay A device that operates when the ratio of voltage ETR-5000 transformer protective relays, to frequency is above a preset value or is below EGR-5000 generator protective relay. a different preset value. The relay may have any 6 combination of instantaneous or time delayed characteristics. 25 Synchronizing or synchronism check device A device that operates when two AC circuits are In a closed transition breaker 7 within the desired limits of frequency, phase angle transfer, a 25 relay is used to ensure or voltage, to permit or cause the paralleling of two-sources are synchronized before these two circuits. paralleling. Eaton EDR-5000 feeder 8 protective relays, EGR-5000 generator protective relay. 27 Undervoltage relay A device which functions on a given value of Used to protect a motor or other devices undervoltage. from a sustained under-voltage and/or 9 initiate an automatic transfer when a primary source of power is lost. Eaton EDR feeder protective relay, EMR-4000/ 10 EMR-5000 motor protective relays, ETR-5000 transformer protective relay, EGR-5000 generator protective relay. 11 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. also be arranged to perform a lockout function. Typically, a mechanical “drop” type 12 annunciator panel is used. 32 Directional power relay A relay that functions on a desired value of power Used to prevent reverse power from flow in a given direction, or upon reverse power feeding an upstream fault. Often 13 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 EDR-5000 feeder protective relay, EMR-4000/ 14 EMR-5000 motor protective relays, ETR-5000 transformer protective relay, EGR-5000 generator protective relay. 33 Position switch A device that makes or breaks contact when the Used to indicate the position of a 15 main device or piece of apparatus, which has no drawout circuit breaker (TOC switch). device function number, reaches a given point. 34 Master sequence device A device such as a motor-operated multi-contact — 16 switch, or the equivalent, or a programmable device, that establishes or determines the operating sequence of the major devices in equipment 17 during starting and stopping, or during sequential switching operations. 37 Undercurrent or underpower relay A relay that functions when the current or power Eaton EMR-3000, EMR-4000, EMR-5000 18 flow decreases below a predetermined value. motor protective relays. 38 Bearing protective device A device that functions on excessive bearing — temperature, or on other abnormal mechanical conditions, such as undue wear, which may 19 eventually result in excessive bearing temperature. 40 Field relay A device that functions on a given or abnormally EGR-5000 generator protective relay. high or low value or failure of machine field current, 20 or on an excessive value of the reactive component of armature current in an AC machine indicating abnormally high or low field excitation. 21

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.11-3 August 2017 Reference Data Sheet 01 141

Table 1.11-1. Selected IEEE Device Numbers for Switchgear Apparatus (Continued) Device Function Definition Typical i Number Uses 41 Field circuit breaker A device that functions to apply, or to remove, — ii the field excitation of a machine. 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 1 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. 2 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 3 of the associated devices. 44 Unit sequence starting relay A device that functions to start the next available — unit in multiple-unit equipment upon the failure or 4 non-availability of the normally preceding unit. 46 Reverse-phase, or phase balance, A relay that functions when the polyphase Eaton EDR-3000/EDR-5000 feeder current relay currents are of reverse-phase sequence, or when protective relay, EMR-3000/EMR-4000/ the polyphase currents are unbalanced or contain EMR-5000 motor protective relays, 5 the negative phase-sequence components above ETR-5000 transformer protective relay, a given amount. EGR-5000 generator protective relay. 47 Phase-sequence voltage relay A relay that functions upon a predetermined Eaton EDR-5000 feeder protective 6 value of polyphase voltage in the desired phase relay, EMR-4000/EMR-5000 motor sequence. protective relays, ETR-5000 transformer protective relay, 7 EGR-5000 generator protective relay. 48 Incomplete sequence relay A relay that generally returns the equipment to the EMR-3000/EMR-4000/EMR-5000 normal, or off, position and locks it out of the motor protective relays. 8 normal starting, or operating or stopping sequence is not properly completed within a predetermined amount of time. If the device is used for alarm purposes only, it should preferably be designated 9 as 48 A (alarm). 49 Machine, or transformer, thermal relay A relay that functions when the temperature of a Eaton EMR-3000/EMR-4000/EMR-5000 machine armature, or other load carrying winding motor protective relays, ETR-4000/ 10 or element of a machine, or the temperature ETR-5000 transformer protective relay, of a power rectifier or power transformer EGR-5000 generator protective relay. (including a power rectifier transformer) exceeds (Note: When used with external RTD a predetermined value. module.) 11 50 Instantaneous overcurrent, A relay that functions instantaneously on an Used for tripping a circuit breaker 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-phase 12 of the circuit being protected. (50), phase-neutral (50N), phase-ground (50G) faults. Eaton EDR-3000/EDR-5000 protective relays, MP-3000/MP-4000/ 13 EMR-3000/EMR-4000/EMR-5000 motor protective relays, ETR-4000/ ETR-5000 transformer protective relay, EGR-5000 generator protective relay. 14 51 AC time overcurrent relay A relay with either a definite or inverse time Used for tripping a circuit breaker after characteristic that functions when the current in an a time delay during a sustained AC circuit exceeds a predetermined value. overcurrent. Used for tripping a circuit 15 breaker instantaneously during a high-level short circuit. Can trip on phase (51), neutral (51N) or ground (51G) overcurrents. Eaton EDR-3000/ 16 EDR-5000 protective relays, MP-3000/ MP-4000/EMR-3000/EMR-4000/ EMR-5000 motor protective relays, 17 ETR-4000/ETR-5000 transformer protective relay, EGR-5000 generator protective relay. 18 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 voltage interrupt this circuit under fault or emergency power circuit breakers. Eaton VCP conditions. vacuum circuit breaker, magnum DS 19 low voltage power circuit breaker 53 Exciter or DC generator relay A device that forces the DC machine field excitation — to build up during starting or that functions when 20 the machine voltage has built up to a given value. 21

CA08104001E For more information, visit: www.eaton.com/consultants 1.11-4 Power Distribution Systems Reference Data August 2017 Sheet 01 142

Table 1.11-1. Selected IEEE Device Numbers for Switchgear Apparatus (Continued) i Device Function Definition Typical Number Uses ii 55 Power factor relay A relay that operates when the power factor Eaton EDR-5000 feeder protective in an AC circuit rises above or below a relay and EMR-4000/EMR-5000 predetermined value. motor protective relays, ETR-5000 transformer protective relay, 1 EGR-5000 generator protective relay. 56 Field application relay A device that automatically controls the application — of the field excitation to an AC motor at some 2 predetermined point in the slip cycle. 59 Overvoltage relay A relay that functions on a given value of Used to trip a circuit breaker, overvoltage. protecting downstream equipment 3 from sustained overvoltages. Eaton EDR-5000 feeder protective relay and EMR-4000/EMR-5000 motor protective relays, ETR-5000 4 transformer protective relay, EGR-5000 generator protective relay. 60 Voltage or current balance relay A relay that operates on a given difference in — 5 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 6 or opening operation in an automatic sequence. during a brief loss of primary voltage, to prevent nuisance tripping. 63 Pressure switch A switch that operates on given values or on a Used to protect a transformer during 7 given rate of change of pressure. a rapid pressure rise during a short circuit. This device will typically act to open the protective devices above and below the transformer. Typically 8 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- 9 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. 10 65 Governor A device consisting of an assembly of fluid, — 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, 11 holding speed or load, or stopping. 66 Notching or jogging device A device that functions to allow only a specified Eaton EMR-3000/EMR-4000/EMR-5000 number of operations of a given device, or motor protective relays. 12 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 13 fractions of specified time intervals, or that is used to permit intermittent acceleration or jogging of a machine at low speeds for mechanical positioning. 14 67 AC directional overcurrent relay A relay that functions on a desired value of AC Eaton EDR-5000 feeder protective overcurrent flowing in a predetermined direction. relay, EMR-4000/EMR-5000 motor protective relays, ETR-5000 transformer protective relay, EGR-5000 generator 15 protective relay. 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. 16 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 17 being operated. 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 18 failure. An alarm contact is available as a standard option on a liquid level gauge. It is set to close before an unsafe 19 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 interrupt this circuit under fault or emergency 20 conditions. 21

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.11-5 August 2017 Reference Data Sheet 01 143

Table 1.11-1. Selected IEEE Device Numbers for Switchgear Apparatus (Continued) Device Function Definition Typical i Number Uses 73 Load-resistor contactor A device that is used to shunt or insert a step of — ii load limiting, shifting or indicating resistance in 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 1 of circuit. 74 Alarm relay A device other than an annunciator, as covered — under device number 30, which is used to operate, 2 or to operate in connection with, a visible or audible alarm. 78 Phase-angle measuring relay A device that functions at a predetermined phase EDR-5000 feeder protective relay, 3 angle between two voltages, between two currents, EMR-4000/EMR-5000 motor or between voltage and current. protective relays, ETR-5000 transformer protective relay, EGR-5000 generator protective relay. 4 (Note: For Voltage Only—78 V.) 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 5 the fault has been cleared after the power was removed from the circuit. The recloser will lock-out after a 6 predetermined amount of failed attempts to reclose. EDR-5000 feeder protective relay, ETR-5000 transformer protective relay, EGR-5000 generator 7 protective relay. 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 8 system frequency—or rate of change frequency. drifts above or below a given value. Eaton EDR-5000 feeder protective relay and EMR-4000/EMR-5000 motor protective relays, ETR-5000 9 transformer protective relay, EGR-5000 generator protective relay. 83 Automatic selective control or transfer relay A relay that operates to select automatically Used to transfer control power 10 between certain sources or conditions in sources in a double-ended equipment, or performs a transfer operation switchgear lineup. automatically. 11 85 Carrier or pilot-wire relay A device that is operated or restrained by a signal — transmitted or received via any communications media used for relaying. 12 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 abnormal conditions. a trip. Typically required to be 13 manually reset by an operator before the breaker can be reclosed. 87 Differential protective relay A protective relay that functions on a percentage or Used to protect static equipment, 14 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 15 upstream and/or downstream circuit breaker will be incorporated into the “zone of protection.” Eaton EBR-3000 bus differential relay, ETR-4000/ 16 ETR-5000 transformer protective relays, EMR-5000 motor protective relay, EGR-5000 generator protective relay. 17 90 Regulating device A device that functions to regulate a quantity or — quantities, such as voltage, current, power, speed, frequency, temperature and load, at a certain value or between certain (generally close) limits for 18 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 19 value in a given direction. 94 Tripping or trip-free relay A relay that functions to trip a circuit breaker, — contactor or equipment, or to permit immediate 20 tripping by other devices, or to prevent immediate reclosure of a circuit interrupter, in case it should open automatically even though its closing circuit 21 is maintained closed.

CA08104001E For more information, visit: www.eaton.com/consultants 1.11-6 Power Distribution Systems Reference Data August 2017 Sheet 01 144

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

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.11-7 August 2017 Reference Data Sheet 01 145

Enclosures i The following are reproduced from NEMA 250. Table 1.11-2. Comparison of Specific Applications of Enclosures for Indoor Nonhazardous Locations ii Provides a Degree of Protection Against the Enclosure Type Following Environmental Conditions 1 1 2 1 44X566P1212K13

Incidental contact with the enclosed equipment ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ 1 Falling dirt ■ ■ ■ ■ ■ ■ ■ ■ ■ ■ Falling liquids and light splashing ■ ■ ■ ■ ■ ■ ■ ■ ■ Circulating dust, lint, fibers and flyings 2 ■ ■ ■ ■ ■ ■ ■ 2 Settling airborne dust, lint, fibers and flyings 2 ■ ■ ■ ■ ■ ■ ■ ■ Hosedown and splashing water ■ ■ ■ ■ Oil and coolant seepage ■■■ Oil or coolant spraying and splashing ■ 3 Corrosive agents ■■ Occasional temporary submersion ■■ Occasional prolonged submersion ■ 4 1 These enclosures may be ventilated. 2 These fibers and flying are nonhazardous materials and are not considered the Class III type ignitable fibers or combustible flyings. For Class III type ignitable fibers or combustible flyings, 5 see the National Electrical Code, Article 500. Table 1.11-3. Comparison of Specific Applications of Enclosures for Outdoor Nonhazardous Locations 6 Provides a Degree of Protection Against the Enclosure Type Following Environmental Conditions 3 33R 3S 4 4X 6 6P 7 Incidental contact with the enclosed equipment ■ ■ ■ ■ ■ ■ ■ Rain, snow and sleet 4 ■ ■ ■ ■ ■ ■ ■ Sleet 5 ■ Windblown dust ■■■■ ■ ■ 8 Hosedown ■ ■ ■ ■ Corrosive agents ■ ■ Occasional temporary submersion ■■ 9 Occasional prolonged submersion ■ 3 These enclosures may be ventilated. 4 External operating mechanisms are not required to be operable when the enclosure is ice covered. 10 5 External operating mechanisms are operable when the enclosure is ice covered. Table 1.11-4. Comparison of Specific Applications of Enclosures for Indoor Hazardous Locations 11 Provides a Degree of Protection Against Class Enclosure Types Enclosure Type Atmospheres Typically Containing 7 and 8, Class I Groups 6 9, Class II Groups 6 (For Complete Listing, See NFPA 497M) ABCDEFG10 12 Acetylene I ■ Hydrogen, manufactured gas I ■ diethyl ether, ethylene, cyclopropane I ■ 13 Gasoline, hexane, butane, naphtha, propane, acetone, toluene, isoprene I ■ Metal dust II ■ 14 Carbon black, coal dust, coke dust II ■ Flour, starch, grain dust II ■ Fibers, flyings 7 III ■ Methane with or without coal dust MSHA ■ 15 6 For Class III type ignitable fibers or combustible flyings, see the National Electrical Code, Article 500. 7 Due to the characteristics of the gas, vapor or dust, a product suitable for one class or group may not be suitable for another class or group unless so marked on the product. 16 Note: If the installation is outdoors and/or additional protection is required by Ta b l e s 1. 11- 2 and 1.11-3, a combination-type enclosure is required. 17

CA08104001E For more information, visit: www.eaton.com/consultants 1.11-8 Power Distribution Systems Reference Data August 2017 Sheet 01 146

Table 1.11-5. 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)

IP NEMA Enclosure Type IP ii First 12 33R3S 44X 5 6 6P 12 1312K Second Character Character IP0– IP–0 1 IP1– IP–1 IP2– IP–2 IP3– IP–3 2 IP4– IP–4 IP5– IP–5 IP6– IP–6 IP–7 3 IP–8 ABABABABABABABABABABABABAB A = A shaded block in the “A” column indicates that the NEMA Enclosure Type exceeds the requirements for the respective IEC 60529 4 IP First Character Designation. The IP First Character Designation is the protection against access to hazardous parts and solid foreign objects. B = A shaded block in the “B” column indicates that the NEMA Enclosure Type exceeds the requirements for the respective IEC 60529 5 IP Second Character Designation. The IP Second Character Designation is the protection against the ingress of water. EXAMPLE OF TABLE USE 6 An IEC IP45 Enclosure Rating is specified. What NEMA Type Enclosures meet and exceed the IP45 rating? Referencing the first character, 4, in the IP rating and the row designated “IP4–” in the leftmost column in the 7 table; the blocks in Column “A” for NEMA Types 3, 3S, 4, 4X, 5, 6, 6P, 12, 12K and 13 are shaded. These NEMA ratings meet and exceed the IEC protection requirements against access to hazardous parts and solid foreign objects. Referencing the second character, 5, in the IP rating and the row designated “IP–5” in the rightmost 8 column in the table; the blocks in Column “B” for NEMA Types 3, 3S, 4, 4X, 6 and 6P are shaded. These NEMA ratings meet and exceed the IEC requirements for protection against the ingress of water. The absence of shading in Column “B” beneath the “NEMA Enclosure Type 5” indicates that Type 5 does not meet the IP45 protection 9 requirements against the ingress of water. Likewise, the absence of shading in Column “B” for NEMA Type 12, 12K and 13 enclosures indicates that these enclosures do not meet the IP45 requirements for protection against the ingressof water. Only Types 3, 3S, 4, 4X, 6 and 6P have both Column “A” in the “IP4–” row and Column “B” 10 in the “IP–5” row shaded and could be used in an IP45 application. The NEMA Enclosure Type 3 not only meets the IP45 Enclosure Rating, but also exceeds the IEC requirements 11 because the NEMA Type requires an outdoor corrosion test; a gasket aging test; a dust test; an external icing test; and no water penetration in the rain test. Slight differences exist between the IEC and NEMA test methods, but the IEC rating permits the penetration of water if “it does not deposit on insulation parts, or reach live parts.” 12 The IEC rating does not require a corrosion test; gasket aging test; dust test or external icing test. Because the NEMA ratings include additional test requirements, this table cannot be used to select IP Designations for NEMA rated enclosure specifications. 13 IEC 60529 specifies that an enclosure shall only be designated with a stated degree of protection indicated by the first characteristic numeral if it also complies with all lower degrees of protection. Furthermore, IEC 60529 14 states that an enclosure shall only be designated with a degreeof protection indicated by the second characteristic numeral if it also complies with all lower degrees of protection up to and including the secondcharacteristic numeral 6. An enclosure designated with a second characteristic numeral 7 or 8 only is considered unsuitable 15 for exposure to water jets (designated by second characteristic numeral 5 or 6) and need not comply with requirements for numeral 5 or 6 unless it is dual coded. Because the IEC protection requirements become more stringent with increasing IP character value up through 6, once a NEMA Type rating meets the requirements for 16 an IP designation up through 6, it will also meet the requirements for all lower IP designations. This is apparent from the shaded areas shown in the table. 17

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.11-9 August 2017 Reference Data Sheet 01 147

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 1.11-6. 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 1.11-10. 17

CA08104001E For more information, visit: www.eaton.com/consultants 1.11-10 Power Distribution Systems Reference Data August 2017 Sheet 01 148

Table 1.11-7. 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 1.11-8. 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 1.11-9. 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 1.11-11 August 2017 Reference Data Sheet 01 149

Current Carrying Capacities of Copper and Aluminum and Copper-Clad Aluminum Conductors From National Electrical Code (NEC), 2014 Edition (NFPA 70-2014) i Table 1.11-10. 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 Ta b l e 1. 11- 10 , see NEC Article 310 in its entirety.

Table 1.11-11. Correction Factors From NFPA 70-2014 (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

CA08104001E For more information, visit: www.eaton.com/consultants 1.11-12 Power Distribution Systems Reference Data August 2017 Sheet 01 150

Ampacities for Conductors (B) Tables. Ampacities for conductors (3) Adjustment Factors. i rated 0–2000 V shall be as specified Rated 0–2000 V (Excerpted in the Allowable Ampacity (a) More Than Three Current- from NFPA 70-2014, 310.15) Table 310.15(B)(16) through Carrying Conductors in a Raceway ii Table 310.15(B)(19), and or Cable. Where the number of Note: Fine Print Note (FPN) was changed Ampacity Table 310.15(B)(20) and current-carrying conductors in a to Informational Note in the 2011 NEC. Table 310.15(B)(21) as modified raceway or cable exceeds three, or 1 by 310.15(B)(1) through (B)(7). where single conductors or multi- (A) General. conductor cables are installed (1) Tables or Engineering Supervision. Note: Table 310.15(B)(16) through without maintaining spacing for 2 Ampacities for conductors shall Table 310.15(B)(19) are application tables a continuous length longer than be permitted to be determined by for use in determining conductor sizes 24.00-inch (600 mm) and are not on loads calculated in accordance with installed in raceways, the allowable tables as provided in 310.15(B) or Article 220. Allowable ampacities result 3 under engineering supervision, from consideration of one or more of ampacity of each conductor shall be as provided in 310.15(C). the following: reduced as shown in Table 310.15(B)(3)(a). Each current-carry- Note: Informational Note No. 1: Ampacities 4 (1) Temperature compatibility with ing conductor of a paralleled set of provided by this section do not take voltage conductors shall be counted as a drop into consideration. See 210.19(A), connected equipment, especially Informational Note No. 4, for branch circuits the connection points. current-carrying conductor. 5 and 215.2(A), Informational No. 2, for feeders. (2) Coordination with circuit and Note: Informational Note No. 1: See Annex Note: Informational Note No. 2: For the system overcurrent protection. B, Table B.310.15(B)(2)(11), for adjustment allowable ampacities of Type MTW wire, factors for more than three current-carrying 6 see Table 13.5.1 in NFPA 79-2007, Electrical (3) Compliance with the requirements conductors in a raceway or cable with Standard for Industrial Machinery. of product listings or certifications. load diversity. See 110.3(B). 7 (2) Selection of Ampacity. Where Note: Informational Note No. 2: See 366.23(A) more than one ampacity applies (4) Preservation of the safety benefits for adjustment factors for conductors in for a given circuit length, the of established industry practices sheet metal auxiliary gutters and 376.22(B) lowest value shall be used. and standardized procedures. for adjustment factors for conductors in 8 metal wireways. Exception: Where two different (1) General. For explanation of type let- ampacities apply to adjacent (1) Where conductors are installed in 9 portions of a circuit, the higher ters used in tables and for recognized sizes of conductors for cable trays, the provisions of ampacity shall be permitted to 392.80 shall apply. be used beyond the point of the various conductor insulations, 10 transition, a distance equal to see Table 310.104(A) and Table (2) Adjustment factors shall not apply 10 ft (3.0 m) or 10 percent of the 310.104(B). For installation to conductors in raceways having circuit length figured at the higher requirements, see 310.1 through a length not exceeding 24.00-inch 11 ampacity, whichever is less. 310.15(A)(3) and the various (600 mm). articles of this Code. For flexible Note: See 110.14(C) for conductor cords, see Table 400.4, Table (3) Adjustment factors shall not apply 12 temperature limitations due to 400.5(A)(1) and Table 400.5(A)(2). to underground conductors enter- termination provisions. ing or leaving an outdoor trench if those conductors have physical 13 protection in the form of rigid metal conduit, intermediate metal conduit, rigid polyvinyl chloride 14 conduit (PVC), or reinforced thermosetting resin conduit (RTRC) having a length not exceeding 15 10 ft (3.05 m), and if the number of conductors does not exceed four. 16

For more information, visit: www.eaton.com/consultants CA08104001E Power Distribution Systems 1.11-13 August 2017 Reference Data Sheet 01 151

(4) Adjustment factors shall not Where conductors or cables are (5) Neutral Conductor. apply to Type AC cable or to installed in circular raceways exposed i Type MC cable under the following to direct sunlight on or above rooftops, (a) A neutral conductor that carries conditions: the adjustments shown in Ta b l e 1. 11- 1 2 only the unbalanced current from shall be added to the outdoor other conductors of the same ii a. The cables do not have an overall temperature to determine the circuit shall not be required to outer jacket. applicable ambient temperature be counted when applying the provisions of 310.15(B)(3)(a). b. Each cable has not more than three for application of the correction 1 current-carrying conductors. factors in Table 310.15(B)(2)(a) or (b) In a three-wire circuit consisting Table 310.15(B)(2)(b). of two phase conductors and the c. The conductors are 12 AWG copper. 2 Note: Informational Note: One source for neutral conductor of a four-wire, d. Not more than 20 current-carrying the average ambient temperatures in various three-phase, wye-connected conductors are installed without locations is the ASHRAE Handbook system, a common conductor 3 maintaining spacing, are stacked, —Fundamentals. carries approximately the same or are supported on”bridle rings.” current as the line-to-neutral load Table 1.11-12. NEC (2014) Table 310.15(B)(3)(c) currents of the other conductors (5) An adjustment factor of 60 percent Ambient Temperature Adjustment for Circular and shall be counted when applying 4 shall be applied to Type AC cable or Raceways or Cables Exposed to Sunlight On the provisions of 310.15(B)(3)(a). Type MC cable under the following or Above Rooftops (c) On a four-wire, three-phase wye 5 conditions: Distance Above Roof to Temperature Bottom of Conduit Adder ºF (ºC) circuit where the major portion of a. The cables do not have an overall the load consists of nonlinear loads, outer jacket. 0–0.51-inch (0–13.0 mm) 60 (33) harmonic currents are present in 6 Above 0.51-inch (13.0 mm)– 40 (22) the neutral conductor; the neutral b. The number of current carrying 3.54-inch (90.0 mm) conductor shall therefore be con- conductors exceeds 20. Above 3.54-inch (90.0 mm)– 30 (17) sidered a current-carrying conductor. 7 c. The cables are stacked or bundled 11.81-inch (300.0 mm) (6) Grounding or Bonding Conductor. longer that 24.00-inch (600 mm) Above 12.00-inch (300.0 mm)– 25 (14) A grounding or bonding conductor without spacing being maintained. 36.00-inch (900.0 mm) 8 shall not be counted when applying (b) More Than One Conduit, Tube, (4) Bare or Covered Conductors. the provisions of 310.15(B)(3)(a). or Raceway. Spacing between Where bare or covered conductors 9 conduits, tubing, or raceways are installed with insulated shall be maintained. conductors, the temperature rating of the bare or covered 10 (c) Circular Raceways Exposed to conductor shall be equal to the Sunlight on Rooftops. lowest temperature rating of the insulated conductors for the 11 purpose of determining ampacity. 12

CA08104001E For more information, visit: www.eaton.com/consultants 1.11-14 Power Distribution Systems Reference Data August 2017 Sheet 01 152

Table 1.11-13. 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 1.11-14. 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 lb 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 lb 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

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