Offshore Electrical Guidelines

50 Using This Manual

AbstractThis section summarizes the contents and explains the organization of the Elec-trical Manual. This manual is divided into two volumes. Volume 1 contains the engineering guidelines with accompanying appendices. Volume 2 contains specifi-cations, industry codes and standards, and engineering drawings and forms. PC disks with EG specifications are included at the end of Volume 2. Both volumes have a table of contents and a complete index to aid you in finding specific subjects.

Chevron Corporation 50-1 October 2000

50 Using This Manual Electrical Manual

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Scope and ApplicationThe Electrical Manual provides engineering guidelines and specifications pertaining to electrical engineering. These guidelines include design and calculation procedures, sample calculations, standard engineering practices, and data for designing electrical power systems, and guidance for applications of electrical components. The guidelines also contain background information and references. The model specifications include comments that explain their provisions and clarify interpretations based on Company experience.

This manual is written for entry-level engineers and nonspecialists regardless of experience. This manual should not be used as a substitute for sound engineering judgment, nor should it take precedence over the judgment of the experienced specialist in electrical engineering.

The intent of this manual is to provide practical, useful information based on Company experience and established practices. Therefore, forms are provided in the front of the manual for your convenience in suggesting changes. Your knowledge and experience are important for improving subsequent printings and keeping this manual up to date.

OrganizationThe colored tabs in the manual will help you find information quickly.

• White tabs are for table of contents, introduction, appendices, PC disks, indand general purpose topics.

• Blue tabs denote engineering guidelines.

• Gray tabs are for model specifications, industry standards, and standard drings.

• Red tab marks a place to keep documents developed at your facility.

Engineering GuidelinesThe Electrical Manual covers a range of topics relating to electrical systems andequipment: system design; system studies and protection; hazardous (classifieareas; motor control centers; switchgear, protective devices, switches, and tranformers; grounding systems; installation of electrical facilities; wire and cable anlighting; auxiliary power systems; and electrical checkout, commissioning, and maintenance. A summary of each section of the manual with pertinent specifications is given below.

Section 100, System DesignThis section contains guidelines for the design of an electrical distribution systeto be used when designing a new distribution system or making significant addtions to an existing system. The section gives an overview of the electrical desi

October 2000 50-2 Chevron Corporation

Electrical Manual 50 Using This Manual

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process, from project inception through detailed final design, including: design concepts and practices; load summary, power source, and auxiliary power systems; bus arrangement, system voltages, and one-line diagram; system studies, equipment sizing, and enclosure selection; feeder and branch circuit systems; and grounding, lighting, and system protection. Other sections of the manual are cited for details for specifying equipment. A flow chart illustrates the sequence of design activities required for designing an electrical distribution system and directs the reader to other pertinent sections of the manual.

Also included are a list of references, an appendix for sizing automatic transfer switches (Appendix A), a technical paper, “Features of a Power System Incorporating Large AC Motors/Captive Transformers” (Appendix B), Model SpecificatioELC-MS-1675, Installation of Electrical Facilities, and data sheet and data guidELC-DS-597, Instructions for 480 V Motor Control Rack Specification and Arrangement.

Section 200, System Studies and ProtectionThis section gives an introduction to electrical power system studies for the desof new systems or the modification of existing systems. These studies, which sas a framework for analyzing critical factors in power system design, include: ashort-circuit study, a motor-starting study, and a load flow analysis. Also includea brief discussion of studies for transient stability and harmonic analysis. A list oreferences is provided along with a technical paper for performing a short-circustudy (Appendix C).

Section 300, Hazardous (Classified) AreasThis section discusses the classification of locations for electrical installations. gives guidance for the selection of electrical equipment for hazardous (classifieareas. Topics discussed include: definitions of hazardous (classified) areas; maximum operating temperature and equipment enclosures; hermetically sealedevices and intrinsically safe systems; and nonincendive equipment and purgeenclosures. A list of references is included along with the engineering form ELCEF-652, Conduit Stub-up Arrangement.

Section 400, Motor Control CentersThis section provides information for selecting 600 volt, 2400 volt, and 5 kV mocontrol centers (MCCs). It discusses the relationship of motors and starters, comethods, ratings, enclosures, selection, and customizing. Also included is a dission of motor protection, overvoltages, and surge arrestors, and descriptions ofNEMA ratings.

The section refers to Company model specifications, data sheets and data guidand engineering forms that relate to motor control centers and starters. Model sfications included in this manual with data sheets and data guides are: ELC-MS3977, Medium Voltage Current-limiting Fused Motor Starters, and ELC-MS-437



Adjustable Frequency Drives. Other relevant data sheets and guides included are: ELC-DS-366, Motor Control Center Specification and Arrangement, and ELC-DS-597, Motor Control Rack Specification and Arrangement. Engineering form ELC-EF-592, Wiring Diagram for Motor and Contractor Installation, is also provided.

Section 500, SwitchgearThis section discusses switchgear assemblies and their application in an industrial facility. Specific steps in the design process are identified, including the use of stan-dard forms and major selection factors. The section also aids in selecting switch-gear for distribution and application of power up to 15 kV nominal. Also included is a glossary of terms and acronyms and a list of references. Two model specifications are included: ELC-MS-3908, Medium Voltage 5 kV and 15 kV Metal-Clad Switch-gear, and ELC-MS-3907, Low Voltage (600 V maximum) Drawout Circuit Breaker Switchgear. Data sheets and guides relating to this section are: ELC-DS-3908, Medium Voltage Switchgear, and ELC-MS-3987, Low Voltage Switchgear.

Section 600, Protective DevicesThis section addresses the two major electrical system hazards, overload and short circuit, and the risk posed by each. It discusses system protective devices, particu-larly circuit breakers and fuses, and the operation of the principal components of any protective scheme. The section also discusses indirect protective control, specif-ically relays for large motors. Circuit breakers and fuses are described with their typical numerical values. Also included are examples of relay coordination studies and time-current curves, a comparison of the advantages and disadvantages of fuses, and a list of references.

Section 700, SwitchesThis section describes and compares five types of switches used in power circuits: disconnect switches, load interrupter switches, safety switches, automatic transfer switches, and oil-fused cutouts. These switches are compared on the basis of their interrupting capabilities, and fusing is discussed for all except the disconnect switch. Model specification, data sheet, and data sheet guide for ELC-MS-3944, Load Inter-rupter Switches, are included. The standard drawing relating to this section is GF-P99972, 480 Volt Stand-by Power System One-Line Diagram.

Section 800, TransformersThis section provides technical and practical guidance for specifying distribution, power, lighting, and control transformers, including insulation for transformers, classes of self-cooled transformers, and grounding resistors and bushing current transformers. This section also lists and briefly discusses: documents containing the latest applicable standards and codes; ratings, including operating conditions; design characteristics; accessories, including liquid level gage, fluid thermometers, pres-sure vacuum gage, pressure relief diagram in cover, sampling device, pressure regu-



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lator, provisions for cooling fans, sudden pressure relays, and neutral current transformer; and quality assurance tests.

To determine transformer size, use the guidelines in Section 100. Section 600 describes transformers for relaying (current transformers and potential trans-formers), and describes transformer types and their special roles in the power system.

A transformer data sheet, ELC-DS-401, and data sheet guide are also included, along with an appendix, “Minimum Requirements for Dry-Type Transformers” (Appendix D).

Section 900, Grounding SystemsThis section contains guidelines and procedures for selecting grounding methodgeneration and distribution systems. The advantages and disadvantages of eacmethod are discussed and specific recommendations are made. Included are: dures for system, equipment, lighting, and static grounding of Company installations in the United States; descriptions of how and where to ground electrical systems and what equipment to use; methods of preventing static buildup; andto protect against the effects of lightning. This section also includes the mandatand recommended practices for grounding and the design parameters for grounsystems for onshore and offshore applications.

Two model specifications pertaining to this guideline are: ICM-MS-3651, Installtion Requirements for Digital Instruments and Process Computers, and ELC-M1675, Installation of Electrical Facilities. Standard drawings relating to this sectiare: GD-P99734, Grounding Details—Grounding Electrodes; GF-P99735, Grounding Details—Equipment Connections; and GF-J1236, Typical Ground System for Digital Instruments and Process Computers.

Section 1000, Installation of Electrical FacilitiesThis section discusses general design and installation practice for electrical facties, with reference to specification ELC-MS-1675, Installation of Electrical Facities, included in the manual. Specific guidance is given for the design and installation of conduit systems, cable tray systems, and direct burial cable. Alsoincluded is a discussion of the installation of electrical equipment: switchgear, motor control centers (MCCs), transformers, UPS systems, and UPS batteries.

Besides Model Specification ELC-MS-1675, a list of standard electrical items (Pitems) are included (ELC-MS-4377), along with seven standard drawings (see Section 1082) and engineering form ELC-EF-70, Conduit and Wire Schedule. Aprovided with this guideline are the following: “Installation Practices for Cable Raceway Systems” (Appendix E); API RP 540, Recommended Practice for Eletrical Installations in Petroleum Processing Plants; and API RP 14F, Design andInstallation of Electrical Systems for Offshore Production Platforms.



Section 1100, Wire and CableThis section gives guidance in the selection of wire and cable for power, lighting, control, instrumentation, and communication circuits. The details of the construc-tion of wire and cable are discussed, including conductors, outer jackets, armor, and shielding. Special wire and cable system designs and typical cables are addressed, including: instrument and telemetering cables; power limited tray cable; high temperature, flame retardant, and fire cable; thermocouple extension cable; computer cable; fiber optic cable; shipboard, submarine, and submersible pump cables; instrument, control, and alarm cable; and fire hazard area cable. A glossary with definitions of terms and abbreviations and acronyms is also included, along with a list of references and standards.

Four model specifications that pertain to this guideline are included in the manual: ELC-MS-2447, 5 kV and 15 kV Insulated Power Cable; ELC-MS-3551, Instrument and Control Cable Single and Multi-pair (or multi-triad) Construction; ELC-MS-3552, Twisted and Shielded Thermocouple Extension Cable Single and Multi-pair Construction; and ELC-MS-3553, 600 Volt Multi-conductor Control Cable. Industry standards contained in the manual are: API RP 14F, Design and Installa-tion of Electrical Systems for Offshore Production Platforms, and API RP 540, Electrical Installations in Petroleum Processing Plants.

Section 1200, LightingThis section gives technical and practical guidelines for the design and selection of lighting systems. It defines and describes lighting, different types of light sources, factors to consider when selecting lamps and fixtures, and the design, layout, and maintenance of lighting systems. Design considerations, including acceptable lighting levels for specific areas, economic factors, safety issues, and different methods for determining the number and layout (location) of fixtures, are also discussed. Types of light sources (lamps) discussed include: incandescent lamps, fluorescent lamps, high intensity discharge lamps, and lamp designations. The lighting calculations include discussions of the lumen maintenance factor (LMF), the watts-per-square foot method, and the iso-footcandle method, with examples of fixture layout using the iso-footcandle method.

This section also contains a glossary and list of references and the following engi-neering forms: ELC-EF-484, Lighting Schedule; ELC-EF-599, Lighting Standards, Flood Lighting Fixtures and Manufacturing Details; and ELC-EF-600, Standard Lighting Poles, Fixtures, and Receptacle Mountings.

Section 1300, Auxiliary Power SystemsThis section describes auxiliary power systems in industrial plants and provides guidelines for specifying the most commonly used equipment for auxiliary power systems. It also lists and describes various disturbances and outages in power systems, their effects, and methods for managing them. Power conditioning equip-ment discussed includes: power synthesizers, motor-generators, uninterruptible



power supply (UPS), and dual feeds. A list of references and industry standards is also included.

Two model specifications with data sheets and data sheet guides pertain to this section: ELC-MS-2643, Solid State AC Uninterruptible Power Supply; and ELC-MS-4802, DC Power Battery Storage System. Standard Drawing GF-P99972, 480 V Stand-by Power System One-Line Diagram, is also referenced.

Section 1400, Electrical Checkout, Commissioning, and MaintenanceThis section establishes requirements for the checkout and commissioning of newly installed or upgraded electrical systems. It discusses preventive maintenance of electrical systems and equipment. Inspection and testing checklists are provided. Company equipment specifications and data sheets for factory checkout and testing of most equipment are also in this section. Testing methods and topics discussed include: visual inspections, insulation testing, insulation liquid testing, protective device testing, impedance and resistance measurements, infrared inspections, trans-former fault-gas analysis, functional and operational testing, and factory testing.

Standard references are cited as well as the following specifications and engi-neering forms: ELC-MS-2469, DC High Potential Testing Medium Voltage Cable and Electrical Equipment; ELC-MS-4744, Electrical Systems Checkout and Commissioning; DRI-EG-3547, Inspection and Testing of Large Motors and Elec-trical Generators; and ELC-EF-645, High Potential Test Record Sheet.

Section 1500, Adjustable Speed DrivesThis section discusses the application of low voltage (LV) and medium voltage (MV) adjustable speed drives. It covers basic theory of drives, when to apply an adjustable speed drive and the economic benefits of drives. Also discussed are the steps involved with selecting and installing drives. Specific studies, like rotor dynamic and harmonic analysis are also briefly described. Finally, testing, commis-sioning and maintaining drives is covered.

Section 1600, Design of Electrical Systems for ESP Installations GuidelineThis section contains a guideline that is intended to provide guidance unique to the design of electrical systems for oil-field Electrical Submersible Pump (ESP) instal-lations. Downhole operating conditions are harsh and ESPs can have relatively short run lives. If application issues related to the electrical system are not sufficiently considered, they can contribute significantly to problems and unreliability of the ESP system.

Due to the large variation in downhole conditions (e.g., depth, temperature, pres-sure, fluid characteristics, liquid flow rates, and well injection fluids or gases) this guideline focuses on above ground design issues.



Specifications Drawings and Forms (Volume 2)This part of the manual contains (1) Company specifications in commented form; (2) Company standard drawings and forms that pertain to the areas discussed in the guidelines; and (3) industry standards that are pertinent to the guidelines.

Other Company ManualsThe text sometimes refers to documents in other Company manuals. These docu-ments carry the prefix of that manual. The prefixes and their referents are:

Prefix Company Manual

CIV Civil and Structural

CMP Compressor

COM Coatings

CPM Corrosion Prevention and Metallurgy

DRI Driver

ELC Electrical

EXH Heat Exchanger and Cooling Tower

FFM Fluid Flow

FPM Fire Protection Manual

HTR Fired Heater and Waste Heat Recovery

ICM Instrumentation and Control

IRM Insulation and Refractory

MAC General Machinery

NCM Noise Control

PIM Piping

PMP Pump

PPL Pipeline

PVM Pressure Vessel

TAM Tank

UTL Utilities

WEM Welding


Chevron Corporation 100-1 May 1996

100 System Design

AbstractThis section provides engineering guidelines for the design of an electrical distribu-tion system. It should be used when designing a new distribution system or making significant additions to an existing system. This section gives an overview of the electrical design process—from project inception through detailed final design. Design considerations and practices are also discussed.

An overview of major design concepts, such as system studies and grounding, is presented. Other sections in this manual that describe these concepts in more detail are referenced. Procedures for sizing equipment are included and other sections of the manual are cited for details for specifying equipment. Also included is a flow chart showing the typical sequence of design events and directing the reader to other sections of the manual.

Contents Page

110 System Design 100-3

111 Introduction

112 Design Procedure

113 Basic Design Considerations

120 Conceptual Design 100-6

121 Load Summary

122 Type of System

123 Power Source

124 Auxiliary Power Systems

125 Bus Arrangement

126 System Voltages

127 One-Line Diagram

128 Area Classification

130 Detailed Design 100-26

131 System Studies

100 System Design Electrical Manual

May 1996 100-2 Chevron Corporation

132 Equipment Sizing

133 Enclosure Selection

134 Feeder and Branch Circuit Systems

135 Grounding

136 Lighting

137 System Protection

140 References 100-60

141 Model Specifications (MS)

142 Standard Drawings

143 Data Sheets (DS), Data Guides (DG), and Engineering Forms (EF)

144 Appendices

145 Other References

Electrical Manual 100 System Design


110 System Design

111 IntroductionThis section presents recommendations for the design of an electrical system. Factors that influence design are discussed, and procedures for sizing equipment are included. Recommended design practices and alternate designs are described.

Figure 100-1 illustrates the steps involved in the system design process. It also iden-tifies other sections of this manual that contain more detail about specific subjects and guidelines for selecting equipment.

112 Design ProcedureThis section should be used with other information (e.g., the process Piping and Instrument Diagram and Plot Plan) to develop a one-line diagram and to select a distribution system. A one-line diagram (Figure 100-2) is a schematic drawing that illustrates the overall electrical system configuration and contains information on equipment sizing. It is described in more detail in Section 127. Figure 100-2 identi-fies other sections of Section 110, “System Design,” where guidelines that pertain to particular equipment can be found.

The overall system design is divided into two stages: conceptual design and detailed design. Conceptual design begins at the inception of a project and includes:

1. Gathering process and load data.

2. Choosing the most suitable system configuration and bus arrangements for the particular application.

3. Selecting a power source.

4. Determining system voltages.

Detailed design involves:

1. Developing the one-line diagram.

2. Performing system studies.

3. Sizing equipment and feeder systems.

4. Designing grounding and lighting systems.

5. Designing system protection.

113 Basic Design ConsiderationsThe following basic design considerations must be included in the design of all elec-trical systems.



Fig. 100-1 System Design Guide



Safety. Safety of life and preservation of property are the most critical factors that must be considered when designing an electrical system. Established codes and standards must be followed in the selection of material and equipment to ensure a safe system design.

Petroleum production and processing involve flammable liquids and gasses, often at elevated temperatures and pressures. Electrical systems must be designed to prevent accidental ignition of these flammable liquids and gases.

Reliability. The degree of continuity of service required is dependent on the type of process or operation of the facility. Some facilities can tolerate interruptions, while others cannot. The power source, the electrical equipment, and the protection system should provide the maximum dependability consistent with the facility requirements and justifiable costs.

Maintenance. Maintenance requirements should be considered when designing electrical systems. A well-maintained system is safer and more reliable. Systems

Fig. 100-2 General One-Line Diagram for Electrical Distribution System



should be designed to allow maintenance without major interruptions to the process. It is important to consider accessibility and availability (for inspection and repair) when selecting and locating equipment. Operating and maintenance personnel should be consulted for preferred system configurations and existing maintenance procedures. See Section 1400, for more details about maintenance.

Flexibility. Flexibility of the electrical system determines the adaptability to meet varied requirements during the life of the facility. Voltage levels, equipment ratings, space for additional equipment, and capacity for increased load should be consid-ered.

Simplicity of Operation. Operation should be as simple as possible to meet system requirements. Simplicity of operation is a necessary factor in achieving safe and reliable systems.

Voltage Regulation. Utilization voltage must be maintained within equipment toler-ance limits under all load conditions. Poor voltage regulation is detrimental to the life and operation of electric equipment.

Cost. While initial costs are important, the lifetime cost also should be considered. Safety, reliability, voltage regulation, maintenance, and potential for expansion should be considered in designing electrical systems and selecting equipment. Cost reductions achieved by using inferior apparatus should never be made at the expense of safety and performance.

120 Conceptual Design

121 Load SummaryA load summary is a detailed listing of all loads to be served by the electrical distri-bution system. It is used to determine the power requirements of a system—in order to properly size power sources, distribution equipment, and feeder systems. The load summary also aids in determining system voltages.

Load DataTo develop a load summary, data on all loads to be served and information about the facility processes should be collected first. Generally, industrial facility loads are a function of the process equipment. A list of loads must be obtained from the process and equipment designers. The list should include nameplate ratings of motors, brake-horsepower of electric motor-driven equipment, and kVA and kW ratings of all other process equipment. If available, design operating loads should be included. It is important that the system electrical designer acquire knowledge of the facility processes. This knowledge will assist in estimating loads and selecting the proper system and components.

At the initial stages of design, accurate load data may be limited. Loads must be estimated until the design is finalized. It is better to estimate loads on the “high side” to avoid undersized equipment.



Load LayoutFor large facilities, a load layout should be created using the plot plan to show major load components. If available, individual horsepower ratings should be obtained. Loads located on the plan give a geographical view of the load density, which can be used to assist in devising a logical power distribution scheme. Famil-iarity with existing facilities is also helpful.

A load center is defined as an assembly (lineup) of low-voltage (0-1000 volts) or medium voltage (1001-100,000 volts) switchgear. Load center breakers typically feed large motors, motor control centers, or other load centers.

Areas containing high load densities should be identified as possibly requiring load centers. The load layout should then be used to assist in selecting the power distri-bution scheme. Section 122 discusses selection of the various types of distribution systems.

Once the basic system has been selected, the load layout is used to assign loads to individual load centers and motor control centers (MCCs). Loads should be assigned to busses before beginning the load summary so that individual summaries can be made for each bus, making it easier to size system components.

A low voltage motor control center (MCC) is a group of motor starters and thermal magnetic circuit breakers rated up to 600 volts. Typically, 460 volt motors rated 200 hp or less are fed from MCCs and started with combination motor starters. Larger 460 volt motors commonly are started with circuit breakers if they draw too much current for combination motor starters. A combination motor starter consists of a circuit breaker, a contactor, and an overload relay. Other loads (e.g., lighting and heating) are served by thermal magnetic circuit breakers in the motor control center. See Section 400, “Motor Control Centers.”

A medium voltage MCC is a lineup of motor starters rated up to 7200 volts. Starters typically employ a current limiting fuse, a draw-out air or vacuum contactor, and ambient compensated overload relays.

Detailed Load SummaryA detailed load summary can be developed once the load data has been gathered, a load layout made, a basic distribution system chosen, and the loads assigned to indi-vidual busses. The procedures described in Sections 122 through 126 of the concep-tual design phase must be performed before starting the one-line diagram and detailed load summary. The load summary is developed for three main reasons:

1. To determine the power requirements for each load center and motor control center—permitting the designer to select distribution voltages and size distribu-tion equipment (e.g., transformers, buses, circuit breakers, starters, and feeders).

2. To determine power requirements for the entire system—permitting power sources to be sized.

3. To provide a basis for a cost estimate.



First, separate load summaries should be developed for each load center and motor control center. Next, the totals from these summaries should be combined to deter-mine power requirements for the entire system. It is best to begin summarizing at the furthermost downstream bus (often a motor control center). Summarizing in the upstream direction should continue until the source is reached. Each new summary in the upstream direction will include load data from previous downstream summa-ries for use in sizing upstream equipment.

Figure 100-3 shows an example of a one-line diagram for an electrical distribution system during the conceptual design phase. Figure 100-4 is a load summary for this system.

All significant loads in the electrical system, including planned future loads, should be listed on the summary by equipment type and number. Brake horsepower should be listed for electric motor-driven equipment. Horsepower ratings should be listed for electric motors and kVA ratings for other loads (e.g., lighting transformers, power receptacles, and heat tracing).

Fig. 100-3 One-Line Diagram for Load Summary Example



The load summary should include a calculation of connected load. Connected load is the sum of electric ratings for all equipment served by the system, including planned future loads.

Running load is the actual electrical load of the facility during operation. Running load is used to size utility service, generators, transformers, feeders, motor control centers, circuit breakers, and uninterruptible power supplies. To determine running load, individual loads must be identified as either continuous, intermittent, or spare. Running load is the sum of all continuous loads, including planned future contin-uous loads. Intermittent loads are included on a percentage basis; spare loads are not included in running load calculation.

Fig. 100-4 Load Summary for System Shown in Figure 100-3

Equip.No. Description BHP

Ratedhp

ConnectedLoad(1)

(kVA)

IntermittentLoad(kVA)

RunningLoad(kVA)

PeakLoad(kVA)

Stand-byLoad(kVA)

MCC #300

WO-1 Welding Outlet 20 20 20

HTR-1 Heater 40 40 40

LP-7 Lighting Panel 100 100 100

MP-304 Pump 43 50 50 50 50

MP-304A Pump (Spare) 43 50 50

MP-305 Pump (Future) 20 25 25 25 25

MP-305A Pump (Future Spare)

20 25 25

LP-8 Lighting panel (Stand-by)

50 50 50 50

MP-308 Firepump (Stand-by)

30 30 30 30 30

___ __ ___ ___ __

Total 390 20 295 315 80

Load Center #100

MP-101 Pump 200 200 200 200

MP-102 Compressor 250 250 250 250

MP-103 Pump 200 200 200 200

MP-104 Compressor 250 250 250 250

MCC#300 MCC #300 390 20 295 315 80

____ __ ____ ____ __

Total 1290 20 1195 1215 80

(1) For motors where power factor and efficiency are not known, assume 1 hp load requires 1kVA.



A continuous load is defined as a load that is expected to operate continuously for 3 hours or more. Intermittent loads are loads that operate continuously for periods of less than 3 hours. Spare loads are operated only when other loads are not oper-ating.

Power factor and efficiency must be known to calculate the running load. Power factor is defined as the ratio of real power (kW) to apparent power (kVA). A load with a low power factor (e.g., a motor) draws more current than a load with a higher power factor. Efficiency is defined as the ratio of output power to input power.

Initially, only estimated horsepower ratings may be available, and power factor and efficiency must be estimated. When power factor and efficiency are not known, consider 1 hp of load to require 1 kVA of power. As actual power factors and effi-ciencies become available, particularly for large motors, the load summary should be updated.

Two factors used to calculate the running load of motors for the sizing of trans-formers are demand factor and run factor. Demand factor is the ratio of actual operating load to nameplate rating. Run factor is the percentage of hours operating per day, expressed as a decimal equivalent. These factors generally are not used in the load summary. However, in cases where many large intermittent motors are connected to a bus, run factors and demand factors should be included in the running load calculations for economic reasons.

Peak load, the maximum instantaneous load drawn by a system during a stated period of time, is obtained when the facility is operating at full capacity and the maximum instantaneous intermittent load is energized. All intermittent loads on a system normally will not be energized at the same time. Therefore, to estimate peak load the process must be evaluated to determine when the maximum intermittent load will be energized. Peak load is the sum of the running load and the maximum instantaneous intermittent load.

Stand-by loads should be identified on the load summary to enable the electrical system designer to design the stand-by power system. Typically, stand-by loads include critical loads that cause damage to the process or product if power is inter-rupted, loads required for black start-up of a generator (e.g., jacket water heaters and pumps), selected plant lighting and HVAC loads, and sewage pumps.

Emergency loads deemed essential for personnel safety (e.g., building egress lighting) and UPS loads that require clean uninterrupted power (e.g., computers and certain electronic instrumentation) should also be identified on the load summary. Typically, emergency loads are powered from unit equipment separate from the stand-by system because of the more stringent requirements of emergency systems. Refer to Sections 124 and 1300 for more information on stand-by, emergency, and UPS power systems.

As the design evolves, load estimates should be updated constantly. It is important to coordinate with other design disciplines to ensure that up-to-date data are used.



122 Type of SystemOnce the load layout has been developed and areas of high load concentrations have been identified, a power distribution scheme can be selected. A system should be selected that will distribute power to the load centers by the most economical and reliable means possible that meets the particular facility requirements.

The primary distribution voltage can be distributed to the load centers economically and reliably with the following systems:

• Radial• Primary selective• Primary loop• Secondary selective

Radial SystemIn the radial system, one primary service feeder supplies power from a distribution transformer to the loads (at utilization voltage) from a load center.

This system is simple in operation, and expansion is accomplished easily. A disad-vantage of the radial system is that a loss of the source or primary feeder will shut down all loads connected to that load center. Also, loads must be shut down for system maintenance and servicing. The radial system is satisfactory only for instal-lations where the process allows sufficient down-time for adequate maintenance. Figure 100-5 is an example of a radial system.

Primary Selective SystemProtection against the loss of a primary supply can be gained through the use of a primary selective system. Each unit substation is connected to two separate primary

Fig. 100-5 Example Depicting Radial System From IEEE Standard 142, 1993, Ch. 2. Used with permission



feeders through switching equipment to provide a normal source and an alternate source. If the normal source fails, the distribution transformer is switched to the alternate source. Switching can be either manual or automatic, but there will be an interruption of power until the load is transferred to the alternate source.

If both sources can be paralleled during switching, some maintenance of the primary cables (and, in certain configurations, switching equipment) may be performed without interruption of service. Cost is higher than for a radial system because of duplication of the primary cable and switchgear. Figure 100-6 is an example of a primary selective system.

Primary Loop SystemThe primary loop system offers the same basic protection against loss of primary supply as the primary selective system. A primary cable fault can be isolated by sectionalizing—allowing restoration of service. The cost of this system may be slightly less than the primary selective system.

The disadvantage of this system is that locating a cable fault in the loop is more difficult. The method of locating a fault by sectionalizing the loop and reclosing should not be performed since it is an unsafe practice because several reclosings on the fault may be required before the fault is located. In addition, a section may be energized from two directions. For these reasons, the primary loop system is not recommended for new facilities. Figure 100-7 is an example of a primary loop system.

Fig. 100-6 Example Depicting Primary Selective System From IEEE Standard 142, 1993, Ch. 2. Used with permission



Secondary Selective SystemIf two unit substations are connected through a normally open secondary tie circuit breaker, the result is a secondary selective system. If the primary feeder or a trans-former fails, the main secondary circuit breaker on the affected transformer is opened and the tie circuit breaker closed. Operation may be manual or automatic. Maintenance of primary feeders, transformers, and main secondary circuit breakers is possible with only momentary power interruption (or no interruption if the stations can be operated in parallel during switching). Complete station mainte-nance will require a shut down. With the loss of a primary circuit or transformer, the total substation load can be supplied by one transformer. To allow for this condi-tion, one or a combination of the following features should be considered.

1. Size the transformers so that either one can carry the total load (with fans).

2. Provide forced-air cooling to the transformer(s) designated for emergency service.

3. Designate nonessential loads that can be shed during emergency periods.

4. Use the temporary overload capacity of the transformers (and accept the loss of transformer life).

A variation of the secondary selective system, a distributed secondary selective system, has two substations in different locations—connected by a tie cable with a normally open circuit breaker provided in each substation. The cost of the addi-tional tie circuit breaker and the tie cable should be compared to the cost advantage of locating the unit stations nearer the load center.

Fig. 100-7 Example Depicting Primary Loop System From IEEE Standard 142, 1993, Ch. 2. Used with permission



In locations where interruptions cannot be tolerated, a variation of the secondary selective system is to provide a normally closed tie breaker, putting the two load centers in parallel. However, this method is allowed only if the available short circuit does not exceed the ratings of the secondary buses and breakers. Figure 100-8 is an example of a secondary selective system.

123 Power SourceThe power supply usually affects system reliability more than any other compo-nent. Whether power is obtained from a utility company or is generated, it must be reliable. Electrical failures can cause costly production down-time and equipment damage, as well as increase the risk of injury to personnel. Voltage dips can also be particularly troublesome when computers or high intensity discharge (HID) lighting (e.g., mercury vapor and high pressure sodium) are in use. When considering a utility as the source of power, it is important to investigate the outage history and the quality of the power from the utility. By assigning a dollar value to lost process time due to power interruptions, the degree of reliability required can be deter-mined. If a facility elects to generate power, the quality and reliability of the gener-ated power must be considered, as well as economics.

Many economic factors must be considered when deciding whether to produce power or to buy it from a local utility. It is important to remember that many opera-tions, notably refinery operations, require dual sources of power. The utility must be able to provide service to the double-ended substations that are common in refin-eries, and at a competitive cost. The feasibility (primarily from an economic stand-point) for a facility to generate its own electricity should be evaluated. Perhaps waste gases, waste heat, or other fuels are available at the facility to operate a gener-ating unit; if not, the availability and cost of fuel should be determined. Should

Fig. 100-8 Secondary Selective System From IEEE Standard 142, 1993, Ch. 2. Used with permission



facility generation be total or partial? Should steam or hydrocarbon-fueled drivers be used? The cost of utility power varies from region to region, normally increasing with the distance transmitted. Obviously, the utility rates for power should be compared to costs of Company generation.

If an adequate, economic, and reliable utility power source is available, the cost of stepping down the voltage to the desired level must be investigated. The cost of the utility providing stepdown transformers should be compared to the cost of the Company providing them.

It is important to compare the time required to design and construct a facility gener-ating unit to the time required for a utility to install or expand a substation or trans-mission line. It takes time to complete the engineering, obtain rights-of-way, prepare environmental statements, and file permit applications; and the delivery time for large equipment can be quite long. Also to be considered are available space, requirements for protection and coordination with the utility protection system, and metering requirements.

124 Auxiliary Power SystemsAn auxiliary power system is designed to supply and distribute power to equipment when the normal electrical supply is interrupted. There are two types of auxiliary power systems: emergency and stand-by. This section describes each system, lists typical loads, and discusses criteria used in the selection and sizing of power sources. See Section 1300, “Auxiliary Power Systems,” for equipment details.

The first step in designing auxiliary power systems is to identify the loads as either emergency or stand-by since there are different requirements for each system. Emer-gency systems are intended to automatically supply illumination and power to designated systems essential for personnel safety during power interruptions. These systems often are legally required and are classed as emergency systems by authori-ties having jurisdiction. Typical emergency loads include exit signs and lights required for the safety of personnel. Other loads connected to emergency power systems are ventilation systems essential to maintain life, fire and gas detection and alarm systems, elevators, fire pumps, and industrial processes where power loss would cause safety and health hazards.

The National Electrical Code (NEC) requires that emergency power must be trans-ferred automatically to emergency loads within 10 seconds after loss of normal power. Wiring of emergency circuits must be completely independent of all other wiring. Wiring is not permitted to utilize the same raceways, cables, boxes, or cabi-nets as normal wiring. See NEC Article 700 for complete requirements.

Stand-by systems are used to provide electric power to aid in fire fighting, rescue operations, and control of health hazards. Typical loads include communication systems, ventilation and smoke removal systems, sewage disposal, certain lighting and HVAC systems, and industrial processes that, if stopped, could create hazards or hamper rescue or fire fighting operations.



Stand-by systems also provide power to critical loads that could cause damage to processes or products, serious interruption to the process, or discomfort to personnel if power were interrupted. Equipment required to minimize re-start time or to initiate black start-up are often supported by the stand-by system. See NEC Articles 701 and 702 for requirements for transfer time, type of transfer, and wiring for stand-by systems.

Auxiliary Power SourceOnce standby and emergency loads are identified, the number and type of power sources required can be determined. Emergency and stand-by loads may be fed from the same source or from separate sources. Because of requirements on wiring and transfer time for emergency loads, it is usually more economical to connect them to unit equipment and connect stand-by loads to a generator set. However, emergency and stand-by loads are sometimes connected to one source.

Four types of power sources available for emergency and stand-by systems are: engine driven generator set, storage batteries, uninterruptible power supply (UPS) systems, and unit equipment.

Engine Driven Generator Set. This power supply may be used to provide both emergency and stand-by power. Means must be provided for automatic starting of the engine and automatic transfer of loads to the auxiliary source. This is the most common power source for emergency and stand-by loads.

Storage Batteries. A storage battery supply consists of batteries and a battery-charging system.

Uninterruptible Power Supply (UPS). This power supply typically consists of a battery bank continuously charged from the supply line through a charger and an inverter that converts the DC voltage of the batteries to an AC supply. UPS is used to supply emergency and stand-by loads that require a high quality of conditioned power with no interruptions.

Unit Equipment. Individual unit equipment consists of a rechargeable battery, a battery-charging system, and a relaying device to automatically energize the equip-ment (e.g., lamps) upon failure of the normal supply. This power source is used primarily for emergency illumination.

Design Criteria

General. The following questions should be addressed when designing emergency and stand-by power systems.

1. What are the power requirements? Is high reliable and quality power (such as that serving process controls or computers) required, or would commercial quality power be acceptable?

2. What are the motor starting requirements?

3. What future loads are anticipated?



4. What are the stand-by power requirements? Is power required for only a short length of time (e.g., for an orderly shutdown), or must power be provided until commercial power is restored (e.g., to prevent hazards to equipment or personnel or financial losses)?

5. Must power be available under “no-break” conditions, or are momentary outages acceptable? If so, what frequency of occurrence is acceptable?

6. Can more than one facility be supplied from a single source?

7. Can the utility improve the reliability of its service to an acceptable level? If so, at what cost?

8. What is the utility’s outage history (number and duration of outages)? Is the quality of service improving or deteriorating? Is the utility matching load growth with new facilities, or must old facilities carry a greater burden?

9. For on-site generation, what sources of prime mover energy are available? Steam and gaseous or liquid hydrocarbon fuels are the usual choices. The economic and technical considerations involve: fuel costs and long term avail-ability; maintenance costs and personnel requirements; atmospheric and noise pollution; and potential value of waste heat. For large on-site generation facili-ties where prime mover energy is in excess of facility needs, is there a possi-bility of cogeneration with the utility?

UPS System Design. Conventional Uninterruptible Power Supply (UPS) system designs use state-of-the-art UPS technology, with 1950 technology branch circuit components. Often, the resulting system does not meet the expectations of an unin-terruptible power system. Frequently a short circuit develops on a branch circuit, causing the entire system voltage to drop, resulting in the loss of critical loads.

A UPS is not normally designed to supply the necessary short circuit current to clear a fault. To clear a fault, the UPS automatically transfers to the bypass.

Upon sensing a fault, the SCR’s in the static transfer switch begin conducting in about 1/2 cycle. For a period of 2½ to 6 cycles, the UPS inverter output and the bypass are in parallel, supplying fault current. After 6 cycles, the inverter-output circuit breaker opens and fault current is supplied by the bypass. Since most short circuits are ground faults and most UPS branch circuits are protected by circuit breakers, the short circuit condition persists for about 2 - 10 cycles. During the fault time period of between 0.03 to 0.2 seconds, all UPS branch circuits are subject to the effects of the fault, notably a low-voltage condition. If any UPS loads are sensi-tive to voltage fluctuation, e.g., solenoid valves, motor contactors, control system relays, or computers, a power interruption may occur.

Normally, fast clearing of faults has not been considered when selecting branch circuit protection and when sizing the maintenance bypass circuit, the transformer, and the branch circuits. To sustain a tolerable voltage level, the complete UPS system must be able to clear a 120-volt branch circuit fault in less than 1/2 cycle (0.008 seconds). Underwriter’s Laboratory (UL) Class CC, J, and T current-limiting fuses are the only 120-volt branch circuit protective devices that can clear a fault in 1/2 cycle and maintain system preservation. Class CC fuses are preferred because



they are in-rush tolerant. The short circuit current available however must be high enough to be in the CL range of the fuse. When sizing branch circuit protection, the smallest rated fuse should be selected. The smaller the fuse rating, the lower its current limit. For example, a 20 ampere class J fuse begins current limiting at 200 amperes, but a 10 ampere class J fuse begins current limiting at about 100 amperes. As long as the fuse is in its CL range, it will blow in less than 1/2 cycle. Otherwise, it does not afford an advantage over a circuit breaker. Class J and T fuses in ratings from 1A to 30A are available in the same fuse clip size. Class CC fuses require a different fuse clip.

When sizing the branch circuit conductor, #12 copper should be the smallest size specified. Smaller wire increases the branch circuit impedance and lowers the avail-able fault current.

120-volt circuit breakers are unable to respond as quickly and are therefore unsatis-factory for providing system voltage preservation during a fault. The best clearing time is about three cycles and system voltage can fall well below 50%.

Sizing the Auxiliary Power SourceThe National Electrical Code (NEC) requires that the power source for an emer-gency system be designed with adequate capacity and rating to carry safely the entire connected load. A stand-by system does not have this requirement. It is recommended that power sources supplying stand-by loads be sized according to peak load. Procedures for sizing power sources for emergency and stand-by systems are described below. See Section 1300, “Auxiliary Power Systems,” for equipment details.

Generator Sets. See Section 132 for information on sizing auxiliary generators.

Uninterruptible Power Supply (UPS) Sizing. The calculations to size a UPS require a complete system load analysis, including (1) connected loads (watts and power factor), (2) load demand, and (3) peak load currents.

Once the load is determined, an allowance for spare capacity of 10 to 20% is recom-mended. See Section 1300, “Auxiliary Power Systems,” for additional information.

The maximum peak inrush current is usually insignificant on large systems. On smaller systems, the equipment inrush may be very important for determining the required rating. Consultation with the UPS manufacturer is recommended. The UPS is selected to provide the needed quantity and quality of power to specific loads, for the required time period.

Battery Sizing. The size of batteries depends not only on the size and duration of each load, but on the sequence in which the loads occur. To properly size batteries and chargers, a detailed load profile should be developed. For details on sizing battery systems, refer to ANSI/IEEE Std 485, “IEEE Recommended Practice for Sizing Large Lead Storage Batteries for Generating Stations and Substations.”

Unit Equipment. Unit equipment, typically used only for emergency lighting, is selected based on the amount of illumination required. The batteries and charger are sized by the manufacturer of the equipment.



125 Bus ArrangementThe four most common types of bus arrangements are:

• Single-ended• Double-ended• Ring Bus• Breaker-and-a-half scheme

The arrangement(s) selected depends upon the needs of the particular process. A combination of bus arrangements should be used to achieve the required reliability and selectivity. In general, system costs increase with system reliability if compo-nent quality is equal.

The first step in selecting a bus arrangement is to analyze the process to determine its reliability needs and potential losses in the event of power interruption. Some processes are minimally affected by interruption; in these cases, a simple single-ended bus arrangement may be satisfactory. Other processes may sustain long-term damage by even brief interruptions. A more complex system, with an alternate power source for critical loads, may be justified in these cases.

Circuit redundancy may be required in continuous-process systems to allow equip-ment maintenance. Although the reliability of electric power distribution equipment is high, optimum reliability and safety of operations require routine maintenance. A system that cannot be maintained because of improper bus arrangements is improp-erly designed.

Single-Ended Bus ArrangementA single-ended bus arrangement, also known as a radial system, utilizes a single primary service and distribution transformer to supply all feeders. System invest-ment is the lowest of all circuit arrangements since there is no duplication of equip-ment.

Operation and expansion are simple. If quality components are used, reliability is high. However, loss of a cable, primary supply, or transformer will cut off service. Equipment must be shut down to perform routine maintenance and servicing. Where the industrial process allows enough down-time for maintenance and is minimally affected by interruptions, the simple radial system or the single-ended bus arrange-ment is recommended. Figure 100-9 shows the single-ended bus arrangement.

Double-Ended Bus ArrangementA double-ended bus arrangement, also known as a secondary selective system, utilizes two unit substations connected through a normally open secondary tie circuit breaker. This type of bus arrangement is commonly used in industrial instal-lations where high reliability is required.

If the primary feeder or a transformer fails, the circuit breaker protecting the affected transformer is opened, and the tie circuit breaker is closed. Operation may be manual or automatic. Maintenance of primary feeders, transformers, and main secondary circuit breakers is possible with only a momentary power interruption (or



no interruption if the stations can be operated in parallel with the tie breaker closed during switching). If this arrangement is ever operated with the tie breaker closed, the available short circuit current must not exceed the short circuit rating of the bus and interrupting rating of the breakers. Complete station maintenance requires shut down.

With the loss of one primary circuit or transformer, total substation load may be supplied by one transformer. To allow for this condition, one or a combination of the four features outlined in Section 122 for a secondary selective system must be implemented.

Where a process cannot be shut down for maintenance and interruption of power cannot be tolerated, a double-ended bus arrangement or secondary selective system is recommended. Each transformer should be sized to carry 75% of the total running load on both buses at its self-cooled, 55°C rating. The transformers should be dual rated with provisions for future fans. This provision ensures that when one trans-former is out of service (such as for repairs) the other transformer will be able to carry the total running load on both buses (at their 65°C rating, with forced air cooling). This design feature can be used for the main power source or for substa-tions within a facility. Figure 100-10 shows the double-ended bus arrangement.

Ring Bus ArrangementA ring bus arrangement is used primarily when two utility sources supply the facility. The ring bus arrangement offers the advantage of automatically isolating a fault and restoring service if a fault occurs in one of the sources.

Normally all breakers of a ring bus arrangement are closed (Figure 100-11). If a fault occurs in Source 1, Breakers A and D operate to isolate the fault, while Source 2 feeds the loads. A fault anywhere in the system results in two breakers operating

Fig. 100-9 Single-Ended Bus Arrangement From IEEE Standard 142, 1993, Ch. 2. Used with permission



to isolate the fault. Configuring the system with source connections and load connections diagonally opposite affords breaker-failure relaying and a continuous source of power to the load, even if a breaker fails to operate and the adjacent breaker must clear the fault. For example, if a fault develops on source 1, breakers D and C will normally clear the fault. If breaker C fails to open, breaker B clears the fault. Source 1 remains in service, providing power to one of the load transformers.

Manual isolating switches are installed on each side of the automatic device to allow maintenance to be performed safely and to allow the system to be expanded without interruption of service. This system is less expensive than the breaker-and-a-half scheme described below, but more expensive than single- and double-ended bus arrangements.

Breaker-and-a-Half SchemeA breaker-and-a-half scheme (Figure 100-12) is used extensively as an alternate scheme to the ring bus arrangement in main facility substations where more than one source of power is available. As its name implies, this arrangement requires one-and-a-half breakers for each source (three breakers for every two sources) in the scheme. Normally all the breakers are closed. This arrangement offers a high degree of security since a faulted area will in no way affect other operating sections. This design has particular advantage when more than one major circuit must share the same right-of-way where the possibility of a double circuit outage is increased.

Fig. 100-10 Double-Ended Bus Arrangement From IEEE Standard 142, 1993, Ch. 2. Used with permission

Fig. 100-11 Ring Bus Arrangement From IEEE Standard 142, 1993, Ch. 2. Used with permission



126 System VoltagesTo select distribution and utilization voltages, the following factors should be considered:

1. Specific loads served (size and voltage level).

2. Voltage level supplied by the utility or on-site generation.

3. Existing voltage levels in the facility.

4. Cost of electrical equipment and cable at different voltage levels and current ratings.

5. Losses due to higher current (at lower voltages).

6. Overall system flexibility (i.e., the capability for future expansion).

A major consideration when choosing voltage levels is the cost of equipment and cable. The advantage of a higher voltage system is that less current is required for the same power than for lower voltage systems. In some cases, equipment and cable

Fig. 100-12 Breaker-and-a-half Scheme From IEEE Standard 142, 1993, Ch. 2. Used with permission



rated at higher voltage levels may be more economical because of the reduced current rating required. A higher voltage system is also more efficient because of lower power losses.

Standard nominal system voltages for the United States are listed in Table 1 of ANSI/IEEE Standard 141. There are three system voltage classes. The low voltage class contains all nominal system voltages below 1000 volts. The medium voltage class contains nominal system voltages equal to or greater than 1000 volts, but less than 100,000 volts. The high voltage class contains nominal system voltages equal to or greater than 100,000 volts.

Distribution VoltageIn most facilities it is necessary to distribute power at a voltage higher than or equal to the utilization voltages. When choosing a distribution voltage, the first voltage level to consider should be the incoming utility (or generator) voltage. If the utility supplies a voltage in the range of 12,000 volts to 15,000 volts, it is often econom-ical to use this voltage as the primary distribution voltage for the facility because step down transformers are not required.

If the utility supply is over 15,000 volts, transformation to a lower voltage is typi-cally required. An economic study should be made to determine the primary distri-bution voltage (based on load), future expansion, and distances between load centers.

Typical primary distribution voltages are 13,800 volts, 4160 volts, and 2400 volts. Other voltages, dictated by the standard utility voltage levels in the area, may be encountered in some systems. For large plant facilities, the preferred primary distri-bution voltages are 13,800 volts and 4160 volts, but the selection depends on the total facility load and distance that the primary distribution voltage must be trans-mitted. Primary distribution voltages above 15 kV are seldom recommended in Company facilities because of significantly higher costs for equipment rated above 15 kV.

In most large facilities where facility load is less than 10,000 kVA, 4160 volts or 2400 volts is the most economical primary distribution voltage. Depending on the size of motors at the facility, a 4160 volt system may be less expensive than a 2400 volt system. The same 5 kV class of switchgear and motor controllers is used for both 2400 volt and 4160 volt systems; however, lower current-rated breakers and controllers are required for the 4160 volt system. Cable costs are also usually less on the 4160 volt systems (since smaller conductors can be used). The cost of 4160 volt motors is typically 5 to 10% more than for 2400 volt motors.

For facilities where the load is 10,000 to 20,000 kVA, an economic study (including consideration of the costs of future expansion) must be made to determine the most economical primary distribution voltage—usually between 4160 and 13,800 volts. For facilities where the load is 20,000 kVA or larger, it is most economical to use 13,800 volts for primary distribution.



Utilization VoltageSelection of utilization voltage is primarily dependent on the equipment to be served. Listed below are utilization voltages and motor voltages available, based on the size of individual motors installed at the facility (Reference: API Standard 541).

The above list demonstrates a large overlap in motor horsepowers and utilization voltages. For example, a 5000 hp motor could be added to a 13,800 volt system, a 6900 volt system, or a 4160 volt system.

The preferred utilization voltages are 480 volt, 4160 volt, and 13,800 volt. However, some existing facilities have 2400 volt systems, and some utilities provide 6900 volt service; these situations may make it more economical to choose one of these levels. The best utilization voltage depends on what voltages are available, the capacity of the bus at those voltages, and the availability and cost of installing motors at the various voltages (including the cost of the motor).

If bus capacity is available at 13,800 volts, 6900 volts, and 4160 volts, then it becomes an economic choice of which voltage level to use after considering the cost of the motor, starter, and feeder. Similarly, for motors up to 250 hp, one should consider the available system voltages and bus capacity at each voltage to select the best utilization voltage for the motor. For motors between 100 and 200 hp, typically the most cost effective utilization voltage is 480 volts. If 480 volt capacity is not available but 2400 volt or 4160 volt capacity is, the latter voltage may be more economical.

The preferred utilization voltage for small loads (such as integral horsepower motors below 100 hp) is three-phase 480 volts. Some floodlights, parking lot lights, or other outdoor lights where voltage drop is a problem, may be best served at 480 volts. Small dry-type transformers rated 480-208/120 volt or 480-240/120 volt are used to provide 208 volt three-phase, 120 volt-single phase, and 240 volt single phase for convenience outlets, lighting, and other small loads.

127 One-Line DiagramA one-line diagram is a schematic drawing that uses graphical symbols and stan-dard nomenclature to illustrate the overall configuration of an electrical system. Standard symbols are used to represent electrical equipment, and single lines are used to show the interconnection of the components. Information on size, type, and rating of the electrical equipment is also included. A complete one-line diagram, in

MotorHorsepower

(hp)

UtilizationVoltage

(V)

MotorRated

Voltage (V)

3500-25,000 13,800 13,200

1000-12,000 6900 6600

400-7000 4160 4000

250-4000 2400 2300

Up to 600 480 460



conjunction with a physical plan of the installation, should provide enough data to plan and evaluate an electrical system. See Standard Drawing GF-P99988 for infor-mation found on a typical one-line diagram and for practices used in system design. Standard form ELC-EF-541 should be used for standard electrical symbols. See: Exhibit I of API RP 14F for symbols for offshore applications. The following items should be shown on a one-line diagram:

1. Power Sources. Generators; transformers; voltages; available short-circuit current; and grounding methods of separately derived sources.

2. Metering and Relaying. Meter types, relay types, CT and PT ratios.

3. Transformers. Capacity, voltages, impedance, connection, and grounding method.

4. Buses and Bus Duct. Voltage, current rating, and short circuit bracing.

5. Medium Voltage Switchgear. Current rating and MVA rating.

6. Medium Voltage Motor Starters. Current rating.

7. Low Voltage Switchgear. Current rating, frame size, trip setting, and options (e.g., LT, ST, I.).

8. Low Voltage Motor Control Centers. Current rating, frame size, and trip setting of molded case circuit breakers, and NEMA sizes of starters.

9. Fuses. Size and type.

10. Feeders. Size, number of conductors, and conduit size.

11. Loads. Size and description.

One-line diagrams should also show known future additions; the effect of such addi-tions should be part of the original system planning. The actual drawing should be as simple as possible. Since it is a schematic diagram, it need not show geograph-ical relationship.

128 Area ClassificationLocations are classified according to the presence of flammable gases or vapors, combustible dusts, or easily ignitible fibers or flyings. Hazardous (classified) loca-tions must be identified in order to select proper electrical equipment for these areas. Restrictions are placed on the type of equipment used, and on its operation and maintenance.

See Section 300 for a detailed discussion of classified areas and selecting electrical equipment for these areas.



130 Detailed Design

131 System StudiesSeveral studies are conducted in the design phase of a project. Probably the most important of these studies is the short circuit study, which determines the maximum short circuit current that could flow at all points in the system. This infor-mation is used when specifying the current interrupting ratings and bracing for elec-trical equipment. A load flow study, a transient stability study, and a harmonic study may also be required.

A load flow study determines the real and reactive power in the system under normal and special operating conditions. It is useful for determining voltage drops, transformer tap settings, and power factor.

A transient stability study is applicable only to facilities with synchronous motors and generators. It models the electrical system and examines the effects on motors and generators of system transients, such as faults, switching, and relay action. This study determines if the synchronous motors and generators will fall out of synchro-nism during transients and checks if they are capable of returning to synchronism shortly after transients dampen. It also determines if the system may become unstable, which could result in a shut down.

A harmonic study may be necessary if a facility includes power factor correction capacitors or large semiconductor power conversion equipment (such as AC and DC drives for motors and UPS systems). Facilities with this equipment may be suscep-tible to harmonics generated by the equipment. These harmonics may cause prob-lems elsewhere in the system (e.g., capacitor failure, blown fuses, malfunctioning computers, or overheated equipment). A harmonic study analyzes system harmonics and problems in the design.

A voltage drop study may be necessary if motors comprise the majority of the loads. When adding large motors to a facility, consideration must be given to the voltage drop that occurs when these motors are started, and a study must be made to ensure that the power system has sufficient capacity to start the motors. The motor-starting voltage drop on the system must be limited to avoid problems with contac-tors and relays dropping out and high intensity discharge (HID) lighting fixtures extinguishing.

It is recommended that the system be designed to limit the initial motor-starting voltage drop at the main bus to less than 15%. Voltage drop should never exceed 20%. Sometimes it is difficult to limit voltage drop to 15 to 20%, particularly when installing large motors on systems with limited short circuit capacity. Alternate methods to across-the-line starting are often required (e.g., reduced voltage starting, soft starting using solid state controllers, and wye-delta starting).

A motor-starting study typically includes voltage drop calculations, acceleration time calculations, different methods for starting motors, and voltage vs. torque rela-tionships (to determine if there is sufficient accelerating torque to start motors). Section 200, “System Studies and Protection,” discusses various system studies and



explains their use and requirements. Section 600, “Protective Devices,” explains how to conduct a relay coordination study.

132 Equipment SizingThis section provides guidelines for sizing:

• Generators• Transformers• Switchgear• Motor control centers• Switches

Once the equipment has been sized, refer to other sections of this manual for guide-lines for specifying equipment.

GeneratorsThree types of generators are discussed in this section: (1) primary power, (2) stand-by, and (3) emergency. A primary power generator supplies electrical power for normal operations. A stand-by generator supplies power to stand-by loads only. If emergency loads are connected to a generator, it is considered an emergency gener-ator and must be designed according to NEC requirements for emergency systems. See Driver Manual for guidance in determining horsepower requirements for the prime mover. Following are guidelines for sizing generators.

Step 1. Determine the generator power requirements, Pg (in kilowatts). It is recommended that Pg for primary power generators equal running load plus known future running load plus 10 to 20% spare capacity. For stand-by and emergency generators, it is recommended that Pg equal total connected load plus known future connected load plus 10 to 20% spare capacity.

Step 2. Select a standard generator rating (PG) equal to or greater than Pg. It is recommended that the generator rating be based on a NEMA Class B temperature rise. The generator should be specified with NEMA Class F (or Class H) insulation so that it will operate below its insula-tion temperature rating during normal operating conditions. This design reduces the stress on the insulation and increases generator life. The generator will also be able to operate in overload conditions for short periods of time and still remain below the allowable temper-ature ratings.

Step 3. Determine the generator voltage drop during starting of the largest motor. Usually a 15 to 20% voltage drop is acceptable if the motor is not started often. The designer should refer to the generator manufac-turer’s motor starting applications data. As a rule of thumb, if the generator rating (in kW) is at least five times the numerical value of the horsepower of the largest motor, the voltage drop will not be greater than 15% with the generator already loaded to 50 to 75%.



TransformersTransformer sizing should be based upon running loads (determined from name-plate ratings) for motors, lighting transformers, and other equipment that will be, or may be, operated under normal conditions (i.e., other than power outage). Assume 1 hp equals 1 kVA for induction motors. Spare motor drivers should not be consid-ered part of the running load for the purpose of sizing transformers, except that capacity should be provided for starting the largest spare motor with all normal motor drivers running. Motor drivers of installations having one motor-driven unit and one turbine-driven unit should be considered part of the running operating load for the purpose of sizing transformers. Transformer capacity, as used here, is the self-cooled rating without fans, at 55°C rise.

In general, power transformers (500 kVA and above) should be supplied with 55°C/65°C temperature rise ratings and provisions for future forced air cooling. A transformer dual-rated with a 55°C/65°C temperature rise is capable of supplying 112% of its 55°C kVA rating at the 65°C rise. See Section 800, “Transformers,” for a detailed explanation of transformer temperature rise and fan cooling ratings.

Single transformers with secondary ratings of 600 volts or less should be sized so that the initial running load does not exceed 80% of the self-cooled 55°C rating. Individual transformers with secondaries of less than 400 volts should not exceed a rating of 125 kVA, and transformers with secondaries between 400 and 600 volts should not exceed a rating of 750 kVA, without a detailed investigation of the effects of high short circuit currents on secondary equipment.

A single transformer at 2400 volts or more should not have an initial running load exceeding 90% of its self-cooled 55°C rating.

When sizing transformers for double-ended substations, calculate the running load on both buses; loads should be balanced between the buses. Each transformer should be sized to carry 75% of this total running load at self-cooled, 55°C rating. It is recommended that each transformer have dual ratings (55°C/65°C). Therefore, when one transformer is out of service, the remaining transformer will be able to supply 112% of its rated kVA, or 84% of the total running load, at 65°C. Sixteen percent of the load must be dropped until the other transformer is brought back into service or the transformer may be operated in an overloaded state, if ambient condi-tions allow overloading without exceeding its 65°C rise rating.

If it is not desirable to drop loads while one transformer is out of service, 55°C/65°C rated transformers with fan cooling or larger sized transformers may be used. For example, a 2500 kVA, 55/65°C, fan-cooled transformer sized to carry 75% of the total running load can actually carry 105% of the total running load with the fans on, thus giving some leeway for adding load in the future. Engineering judgment and load considerations should be used to decide if fan cooling should be provided for the transformers upon installation.

Example. Size transformers serving a double-ended substation. Total running load on both buses is 940 kVA. The minimum size transformer required is 0.75 x 940 = 705 kVA.



Consulting the table below, which lists standard transformer kVA sizes, a 750 kVA, 55°C/65°C transformer is selected. Without fan cooling, one transformer can supply 1.12 x 750 = 840 kVA of running load at its 65°C rise. Thus, 100 kVA of load will need to be dropped in order to stay within the transformer operating limits. If the transformers are equipped with fans, one transformer will be able to supply 1.29 x 750 = 968 kVA. In this case, one transformer will be able to carry the entire running load with 28 kVA to spare. As an alternate, of course, two 1000 kVA transformers without fan cooling could be selected.

Motor-starting requirements must be considered in sizing power transformers. Transformers should be sized so that the voltage drop on the secondary of the trans-former does not exceed 15 to 20% when starting the largest motor with all other loads connected to that bus operating (including both buses in a double-ended substation—but not including spare units). In general, the self-cooled kVA rating of power transformers should be at least three times the horsepower rating of the largest motor served by the transformer. See Section 200, “System Studies and Protection,” for details.

A transformer serving a single motor is called a captive transformer or unit trans-former. A captive transformer is a special application of a standard transformer, and not a uniquely designed transformer. Captive transformers are used primarily to reduce system voltage drop during motor starting. The additional impedance of the transformer in series with the motor reduces inrush current. However, the voltage drop at the terminals of the motor during starting must also be considered to ensure that there is no starting problem. Using a captive transformer may also be econom-

Standard Transformer Ratings (kVA)Single-Phase

3 75 1250 10,000

5 100 1667 12,500

10 167 2500 16,667

15 250 3333 20,000

25 333 5000 25,000

37.5 500 6667 33,333

50 833 8333

Three-Phase

15 300 3750 25,000

30 500 5000 30,000

45 750 7500 37,500

75 1000 10,000 50,000

112.5 1500 12,000 60,000

150 2000 15,000 75,000

225 2500 20,000 100,000



ical because of reduced motor cost. See Appendix B for information on the advan-tages and disadvantages of using captive transformers.

An important consideration for sizing captive transformers is the impact loading on the transformer during starting. In the motor/captive transformer combination, the transformer kVA rating closely approximates that of the motor kVA requirement. Under starting conditions, this requirement imposes a sizeable thermal and impact load on the transformer. Pulsating loads and frequent motor starting may place unusual duty on the transformer. The transformer application curve should be checked to ensure that acceptable operating limits are not exceeded. Figure B-6 of Appendix B shows a transformer application curve for pulsating or short-time loads. For applications outside of acceptable limits, a larger transformer should be speci-fied, or the manufacturer should be consulted.

If a motor is operated continuously with infrequent starting (less than once every 4 hours), the load is not considered pulsating, and the installation is considered a “usual service condition” (per ANSI/IEEE C57.12.00), then the conventional rule-of-thumb (1 horsepower = 1 kVA) can be used to size the transformer. For other applications, a larger transformer may be required. Captive transformers must be sized so the voltage at the motor terminals is sufficient to ensure adequate starting torque for the load. Consult the transformer manufacturer when sizing captive trans-formers.

Transformer Impedance. In general, transformers with manufacturer’s standard impedance are satisfactory. Higher impedance is sometimes needed to reduce the short circuit current (to match secondary equipment rating). However, voltage drops increase with higher impedance and should be checked. Conversely, lower imped-ance lowers the voltage drop, but increases the available short circuit current. Impedances higher or lower than standard values increase transformer costs. Refer to Table 72 in ANSI-IEEE Std 141 for standard impedance values of three-phase transformers.

Connection of Transformer Windings. There are four fundamental three-phase transformer connections: delta-wye, delta-delta, wye-delta, and wye-wye. The connection recommended for most applications is delta-wye (delta winding on the primary and wye winding on the secondary). The wye-connected secondary wind-ings can be used as a three-wire or four-wire system, depending on the application. It usually is used as a three-wire system with the neutral grounded; however, a fourth wire connected to the wye neutral can be used to support single-phase loads (such as lighting). Each winding connection has advantages and disadvantages that make it suitable or unsuitable for particular applications. When paralleling with an existing system, the same connection scheme must be used to provide identical phase shifting; otherwise potentially destructive circulating currents may flow.

1. Delta-Wye

Advantages

– Effective control of phase to neutral over-voltages



– Easy detection of phase-to-ground faults– Isolation of ground-fault current from the high voltage (delta) side, thus not

affecting ground relaying on the high voltage side

Disadvantages

– Possibility of large phase-to-ground fault current, leading to possible sustained arcing. (See high-resistance grounding in Section 900, “Grounding Systems,” for recommendations.)

– Interruption of critical processes due to disconnection of equipment upon detection of a ground fault. (See high-resistance grounding in Section 900, “Grounding Systems.”)

– Entire system rendered inoperable by failure of one winding

2. Delta-Delta. Not recommended for new installations, except where required to parallel with an existing system.

Advantages

– Low level of line-to-ground fault current

– Low flash hazard to personnel (from line-to-ground faults)

– Continued operation of equipment after one ground fault

– Three-phase power still available if one winding fails, although load-carrying capability must be derated

Disadvantages

– Neutral-to-ground over-voltages uncontrolled and can lead to equipment breakdown and shorter life

– Overvoltage stresses caused by unremoved faults– Possible reduced insulation life (from over-voltages)– Large circulating currents unless delta windings have identical impedance

ratings– Difficulty in locating ground faults. (There are, however, methods of

creating high resistance grounding schemes, similar to wye winding with high value neutral resistor, that allow ground faults to be found quickly without interrupting operations.)

3. Wye-Delta. Not recommended for new installations, except where required to parallel with an existing system.

Advantages

– Low levels of line-to-ground fault current– Low flash hazard to personnel (from line-to-ground faults)– Continued operation of equipment after one ground fault



Disadvantages

– Neutral-to-ground over-voltages are uncontrolled and can lead to equip-ment breakdown and shorter life

– Overvoltage stresses caused by unremoved faults– Possible reduced insulation life from overvoltages– Difficulty in locating ground faults– Entire system rendered inoperable by failure of one winding

4. Wye-Wye. Not recommended except when required by utilities.

Advantages

– Advantages on the secondary side similar to those of delta-wye connec-tion, except ground fault currents not isolated from the primary side

Disadvantages

– Voltage collapse of the neutral if a single-phase load or unbalanced load is placed on the secondary. This problem can be solved with tertiary delta-connected windings.

– Higher cost due to insulation degradation and requirement of tertiary delta windings

– Third harmonic voltages impressed upon line-to-line voltages, resulting in additional voltage stress on equipment. (Third harmonics can be signifi-cantly reduced by using three-phase core-type transformers.)

– Interference in communications circuits from third harmonic ground currents

For more information about transformer connections, consult System Grounding for Low-voltage Power Systems and Transformer Connections, both available from General Electric Company.

SwitchgearSwitchgear sizing is based on the following parameters:

• Continuous current rating of bus• Continuous current rating of breakers• Interrupting rating of breakers• Momentary current rating of breakers• Short circuit rating of bus

Continuous Current Rating of Bus. The current capacity of a bus is determined by its material (e.g., copper) and its physical size. The standard main bus ratings for medium voltage switchgear are 1200, 2000, and 3000 amperes. For low voltage switchgear, the standard bus ratings are 800, 1600, 2000, 3200 and 4000 amperes.

The continuous current rating of the main bus should be a minimum of: 1.25 times the full load current of the largest running motor, plus the full load current of



remaining running motors, plus the primary rated current of transformer loads, plus the full load current for future motor load for future space provided.

If the switchgear is served from a transformer, the main bus should be sized to carry the rated full load current of the transformer (with fans). When sizing two buses connected through a tie-breaker (i.e., a double-ended substation), each bus should be sized to carry the rated full load current of its transformer (with fans) only.

Example. Determine the main bus rating for 4160-volt switchgear with the following load summary.

Two - 1000 hp motors (running)Two - 500 hp motors (future)5000 kVA of connected transformer load

For motors, assume 1 kVA per hp and calculate the load using the method described above.

kVA = 1.25 (1000) + 1000 + 2 (500) + 5000 = 8250 kVA

= 1146 Amperes

(Eq. 100-1)

Therefore, the recommended minimum standard bus rating is 1200 amperes.

If the switchgear is fed from a 10,000 kVA dual-rated transformer, the main bus should be sized to carry the maximum full load current of the transformer with fans at 65°C rise. Full load current of the 10,000 kVA transformer with fans at 65°C is:

= 1943 Amperes(Eq. 100-2)

Since the maximum full load capability of the transformer is 1943 amperes, a 2000 ampere bus should be selected (to provide for future expansion) rather than the 1200 ampere bus indicated by the running load calculations.

Continuous Current Rating of Breakers. Conductor ampacity requirements are based on the load and can be determined by using NEC Article 220 (see Section 134 below for sizing conductors). The continuous current rating of circuit breakers is determined by the ampacity of the conductors they protect (NEC Article 240-3). Feeder breakers that serve a bus are typically rated the same as the bus.

The continuous current rating of a main circuit breaker must not exceed the ampacity of the main bus it is feeding. Typically, the two are rated the same.

I8250 kVA

4.16 kV( ) 1.732( )-------------------------------------------=

I = 10,000 kVA( ) 1.12( ) 1.25( )

4.16 kV 1.732( )-------------------------------------------------------------------



Industry standard continuous current ratings (frame sizes) for medium voltage breakers are 1200, 2000, and 3000 amperes. These breakers are tripped by protec-tive relays, set for the load being fed by the breakers. For details see Section 200, “System Studies and Protection.”

Industry standard continuous current ratings for low voltage power breakers are 800, 1600, 2000, 3000 and 4000 amperes. These breakers are available with various sizes of solid state overcurrent trip devices (i.e., current sensors and rating plugs). These trip devices are available with long time delay, short delay, instantaneous and ground fault options. Correct selection depends on the load (see Specification ELC-MS-3987 for more details). See Section 200, “System Studies and Protection,” for information on trip settings.

Interrupting Rating of Breakers. The interrupting rating of a protective device is the fault current that the device can interrupt safely. A low voltage circuit breaker operates in the first half cycle of a fault, so the interrupting rating must be greater than the short circuit current calculated at one-half cycle. A medium voltage circuit breaker begins to interrupt fault current during the third cycle. Therefore, the short circuit current must be calculated at three cycles. See Section 200, “System Studies and Protection,” for details on calculating fault currents and determining the neces-sary interrupting ratings for switchgear. Ratings for low and medium voltage circuit breakers are given in Figures 100-13 and 100-14.

Medium Voltage Breakers. The physics of arc interruption are such that oil-blast and air-magnetic circuit breakers can interrupt a higher current at a lower voltage. To take advantage of this capability, the K factor was introduced into the ANSI stan-dards for medium voltage circuit breakers. The K factor is a dimensionless number

Fig. 100-13 Maximum Short Circuit Interrupting Ratings for Low Voltage Power Circuit Breakers with Instantaneous Direct-Acting Trip Elements

Nominal Voltage(volts)

Rated MaxVoltage(volts)

Frame Size(amperes)

Maximum 3φ Symmetrical Short Circuit Interrupting Ratings

Standard Rating

(kA)High Rating

(kA)

600 635 800 22 42

600 635 1600 42 65

600 635 2000 42 65

600 635 3200 65 85

600 635 4000 85 85

480 508 800 30 42

480 508 1600 50 65

480 508 2000 50 65

480 508 3200 65 85

480 508 4000 85 85



which defines the range of voltage over which the rated short circuit current increases. Breakers using this technology have a constant MVA interrupting rating between VRated Max and VRated Max/K; and a constant current interrupting rating, equal to K times rated short circuit current, at voltages below VRated Max/K.

By applying the K factor adjustment, the symmetrical interrupting ratings of breakers can be adjusted for different operating voltages (to a limit of V/K) by the following formula:

Symmetrical current interrupting capability = rated short-circuit current × {Rated Max Voltage/Operating Voltage}.

(Eq. 100-3)

Example

Given a 4.76 kV, 2000 ampere circuit breaker with a rated short circuit of 29 kA, a maximum symmetrical interrupting capability of 36 kA, and a K factor of 1.24. Determine the adjusted interrupting rating of the circuit breaker when applied at: (A) 2.4 kV and at (B) 4.16 kV.

Solution

1. Since the operating voltage of 2.4 kV is below the V/K ratio (4.76/1.24) of 3.84 kV the circuit breaker is in its constant current interrupting capability of K times rated short circuit current. Symmetrical current interrupting capability = 1.24 x 29 kA = 35 kA.

2. The operating voltage of 4.16 kV is in the constant MVA interrupting rating of the circuit breaker; therefore, the interrupting capability is given by Equation 100-3.

Symmetrical current interrupting capability = .

(Eq. 100-4)

Fig. 100-14 Short Circuit Ratings for Medium Voltage Circuit Breakers

RatedMaximum

Voltage(kV, rms)

RatedContinuous

Current(amperes, rms)

Rated Voltage Range KFactor

Rated ShortCircuit Current

@ RatedMax Voltage

(kA, rms)

MaximumSymmetricalInterrupting Capability

(kA, rms Sym)

Close and latch Short Circuit

Current(kA, Crest)

4.76 1200, 2000 1.24 29 36 97

4.76 1200, 2000, 3000 1.19 41 49 132

15 1200, 2000 1.3 18 23 62

15 1200, 2000 1.3 28 36 97

15 1200, 2000, 3000 1.3 37 48 130

294.764.16----------× 33kA=



Figure 100-15 gives the adjusted interrupting current values and actual MVA ratings for medium voltage circuit breakers operating at the various plant voltage levels.

Circuit breakers using vacuum and SF6 puffer interrupters are essentially constant current interrupters up to a limiting maximum voltage. For this type of technology, a K factor of 1.0 is appropriate; however, to meet existing ANSI standards for metal clad switchgear, K factor ratings other than 1.0 are given. Equipment manufacturers must select vacuum and SF6 interrupters to meet the necessary interrupting current requirements at the low-end of voltage range for the voltage-class equipment. This results in vacuum and SF6 breakers of higher interrupting capability at higher applied voltages. For example, the 1000 MVA (nominal) vacuum breaker has an interrupter rating for 48 kA to allow for a low-end voltage range of 11.5 kV (V/K = 15/1.3) for 15 kV class equipment. This corresponds to an actual MVA rating of 961 at 11.5 kV. The actual MVA rating of a vacuum circuit breaker applied at 13.8 kV is 1147 MVA; however, ANSI Standards specify the capability to be rated at an inter-rupting short circuit current of:

40.2 kA or 961 MVA

Fig. 100-15 Adjusted Interrupting Current Values and Actual MVA Ratings for Medium Voltage Circuit Breakers Operating at the Various Voltage Levels

RatedMaximum

VoltagekV, rms

RatedShort Circuit

CurrentkA, rms

NominalMVA

SystemOperating

VoltagekV, rms

InterruptingCurrent @Operating

Voltage, kA

ActualMVA @

OperatingVoltage

4.76 29 250 4.76 29 239

4.16 33.2 239

2.4 36 150

4.76 41 350 4.76 41 338

4.16 46.9 338

2.4 49 204

15 18 500 15 18 468

13.8 19.6 468

12.47 21.7 468

15 28 750 15 28 727

13.8 30.4 727

12.47 33.7 727

15 37 1000 15 37 961

13.8 40.2 961

12.47 44.5 961

3715

13.8----------×



In order to apply the circuit breaker at 1147 MVA, the equipment manufacturer must test the breaker at this fault level per ANSI standards, before the circuit breaker can be nameplated with the higher interrupting rating.

Nevertheless, an additional safety margin exists when applying vacuum and SF6 circuit breakers.

Momentary Current Rating of Breakers. The momentary rating of a protective device is the maximum fault current that the device can physically withstand without failure. This commonly is referred to as the “close-and-latch” rating. This rating is determined from the one-half cycle calculation of short circuit current. Since a low voltage circuit breaker interrupts during the first half cycle, its inter-rupting rating is equal to the momentary rating. See Section 200, “System Studies and Protection,” for details about calculating fault currents and determining momen-tary ratings for switchgear.

Short Circuit Rating of Bus. The bus must have a short circuit rating (bus bracing) equal to or greater than the maximum available short circuit current both from the source and connected motors. To determine the available short circuit current at the bus see Section 200, “System Studies and Protection.”

Motor Control Centers (MCCs)Motor control centers are sized on the basis of the following parameters:

• Continuous current rating of bus• Short circuit rating of the main bus• Continuous current rating of breakers and combination starters• Interrupting rating of breakers and combination starters

Continuous Current Rating of Bus. The recommended minimum current rating of the main (horizontal) bus should be 1.25 times the full load current of the largest running motor, plus the full load current of remaining running motors, plus the primary rated current of transformer loads, plus the full load current of future motor load for future space provided, plus 10 to 20% for future load capacity. If the motor control center is fed from a transformer, the main bus should be sized to carry the rated full load current of the transformer (with fans).

Industry standard main bus ratings for 480 volt motor control centers are 600, 800, 1000, 1200, 1600, and 2000 amperes.

The method of calculating the continuous current rating of the vertical bus is exactly the same as that for calculating the current rating of the main horizontal bus, except only the loads in a specific vertical section should be used.

The industry standard for the continuous current rating of the vertical bus is 300 amperes. The manufacturer will size the vertical buses; however, particular atten-tion should be given to vertical sections where continuous current rating may exceed 300 amperes. Optional vertical bus ratings of 450 amperes and 600 amperes are available. If the load in any vertical section exceeds 300 amperes, a 450 ampere or 600 ampere bus may be specified, or the load should be rearranged in such a way



that the continuous current rating in that vertical section does not exceed 300 amperes.

If the motor control center (or panelboard) is three-phase 4-wire, the neutral bus should be rated for one-half the capacity of the main horizontal bus continuous current rating. For example, if the main bus is rated 600 amperes, the neutral bus should have a rating of 300 amperes. Most of the load on the motor control center is balanced three-phase; therefore, the unbalanced current flowing in the neutral bus is not expected to exceed half the capacity of the main horizontal bus.

Examine the single phase loads, however, to determine if the neutral capacity could be exceeded.

Example. Determine the main bus rating for a 480 volt MCC with the following running loads:

Two - 200 hp MotorsThree - 75 hp Motors40 kVA Miscellaneous Load

Assume 1 kVA per hp. The recommended minimum bus capacity (including 20% spare capacity) is:

kVA = 1.2 (1.25 × 200 + 200 + (3 × 75) + 40)= 858 kVA

I = = 1032 Amperes

(Eq. 100-5)

Therefore, a 1200 ampere rating is selected. It should be noted that the standard 1000 ampere bus would have been adequate for the present load on the motor control center; however, experience indicates that the load on the motor control center typically increases throughout design (and even after the facility is in opera-tion). It is good practice to provide 10 to 20% extra capacity on the main bus for future load growth.

Short Circuit Rating of Main Bus. The main bus must have a short circuit rating equal to or greater than the maximum available symmetrical short circuit current, both from the source and from the connected motors. To determine the short circuit current at the motor control center, see Section 200, “System Studies and Protec-tion.”

The industry standard short circuit rating for motor control center bus is 22,000 amperes. Optional short circuit bus ratings of 42,000, 65,000 and 100,000 rms symmetrical amperes are available. It is recommended that the total short circuit current of motor control centers be limited to 22,000 amperes so that standard starter units and buses can be used.

The use of current-limiting reactors in the incoming-line circuit to MCCs will allow the use of standard MCC buses and starter on systems with high short circuit avail-

858 kVA480V( ) 1.732( )

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



ability. These reactors can be sized to limit the short circuit current to the MCC to the accepted industry standard level (usually 22,000 amperes). This method of MCC protection has the advantage of being less expensive than using an MCC with a higher short circuit rating or adjusting the size of the supply transformer to limit faults. However, the disadvantage of this method is that reactors increase voltage drop.

Applications that cannot tolerate the voltage drop of a reactor can be protected by using a current-limiting fused breaker in each starter and feeder circuit. This method of protection is more expensive than adding current-limiting reactors to the incoming-line but may be less expensive than adjusting transformer sizing to limit fault current.

Continuous Current Rating of Breakers and Contactors. Conductor ampacity requirements are based on the load and are determined by using NEC Article 220. The maximum continuous current rating of circuit breakers is determined from the ampacity of the conductors they feed (NEC Article 240-3). The continuous current rating of the main breaker must not exceed the continuous current rating of the main bus.

The maximum continuous rating of low voltage molded case circuit breakers is 1200 amperes. Therefore, low voltage power circuit breakers must be used for sizes over 1200 amperes. A short delay trip feature should be included on the main breaker to allow coordination with upstream breakers. An alternative design is to omit the main breaker and provide remote trip capability to the upstream breaker. In this case, the MCC bus should have a voltmeter and an ammeter. Main circuit breakers may be deleted, however, only where permitted by NEC.

Feeder breakers in MCCs provide both overload and short circuit protection for the insulated conductors feeding the load. Feeder conductors, according to NEC, shall have an ampacity of not less than 125% of the continuous load current. After the feeder conductors are sized, the trip setting of the feeder breaker should be set to match the conductors’ ampacity. If the standard trip setting of the circuit breaker does not correspond to the ampacity of the conductors, then the next higher rating is allowed by NEC. Molded case circuit breakers can also be used for manual switching.

Combination starters are recommended to feed motors 200 hp or less. A combina-tion starter consists of a circuit breaker (usually magnetic only) or an adjustable motor circuit protector (MCP) in combination with a contactor and overload relays. NEMA sizes for combination starters are based on motor horsepower. NEMA starter sizes and maximum horsepower are listed in a table on the data sheet ELC-DS-597.

MCPs are rated corresponding to NEMA starter sizes. The continuous ratings of MCPs are also listed in the table in ELC-DS-597. The trip setting of the MCP is set at 10 to 13 times the full load current of the motor. The overload relay in each phase of the starter is selected on the basis of the full load current of the motor. For a 1.0 service factor motor, the maximum overload relay setting is 115% of full load



current; for a 1.15 service factor motor, the maximum setting is 125% of the full load current.

Interrupting Rating of Breakers and Combination Starters. Breakers and starters should have the same current interrupting rating as the short circuit rating of the main motor control center horizontal bus.

Switches

Disconnect Switches. Disconnect switches are not designed to interrupt load current. The continuous current rating of a disconnect switch must be greater than the continuous load current of the load. The short circuit momentary rating must be greater than the maximum available fault current.

Load Interrupter Switches. Load interrupter switches can interrupt load current. Their continuous current rating is sized the same as for disconnect switches. Load interrupter switches are available in 600 amperes and 1200 amperes continuous ratings and 40,000 amperes asymmetrical momentary current ratings. Voltage levels typically are 600 volts and higher.

Low Voltage Safety Switches. Low voltage safety switches are rated at 600 volts, and may be fused or unfused. Safety switches are sized the same as disconnect switches except when used to switch:

• Motor loads. The load should not exceed 80% of the current rating of the switch at its rated voltage (NEC Article 380-14).

• Resistive, inductive, or tungsten-filament lamp loads. The load should not exceed the current rating of the switch at the voltage involved (NEC Article 380-14).

Low voltage safety switches are available in various sizes—from 30 amperes to 1200 amperes, with short circuit momentary ratings of 10,000 symmetrical amperes or more. Standard short circuit ratings up to 200,000 symmetrical amperes can be obtained by combining them with current limiting fuses.

Automatic Transfer Switches. Automatic transfer switches should be sized according to procedures described in Appendix A, “Sizing of Automatic Transfer Switches” (Automatic Switch Co.).

133 Enclosure SelectionEquipment enclosures are used to isolate live parts, protect equipment from environ-mental conditions, and satisfy area classification requirements. They are provided on large groups of equipment, such as motor control centers and switchgear, as well as for individual circuit breakers, switches, and motor starters.

Enclosures are specified by NEMA type according to location (i.e., indoor or outdoor), environmental conditions (e.g., wind, rain, dust, and ice), corrosive condi-tions, and area classification.



Indoor enclosures are less expensive than outdoor enclosures. The decision to install equipment indoors or outdoors is dependent on cost, space considerations, prox-imity of the utilization equipment to the switchgear or motor control center, and the number of units to be supplied.

If outdoor enclosures are used, greater care must be taken to ensure that the equip-ment is protected from water, weathering, and corrosion. Often, outdoor enclosures are provided with space heaters to prevent moisture condensation. If possible, equipment should be installed outside of and away from hazardous (classified) loca-tions to minimize the likelihood of fire and explosion and to reduce the cost of installation.

NEMA Standards 250 and ICS 6 describe the types of electrical equipment enclo-sures and their applications. Below is a brief description of enclosure types recom-mended for typical applications:

• NEMA Type 1 enclosures are recommended for general-purpose use in unclas-sified, indoor locations where the equipment and enclosures are not exposed to unusual service conditions. The primary purpose of these enclosures is to prevent accidental contact by personnel with the enclosed energized equipment.

• NEMA Type 1A (Type 1 with neoprene gaskets) enclosures are recommended for the same basic applications as NEMA Type 1, but where some protection against dust and falling dirt and limited protection against light and indirect splashing are required. The enclosures, however, are not dust-tight or water-tight.

• NEMA Type 3R enclosures are recommended for many outdoor locations—primarily to provide a degree of protection against falling rain, sleet, and external ice formation. NEMA 3R enclosures have solid bottoms and tops.

• NEMA Type 4 enclosures are recommended for indoor or outdoor locations where protection against windblown dust and rain, splashing water, and hose-directed water is required.

• NEMA Type 4X enclosures are recommended for use in most indoor or outdoor locations where corrosion protection is required. In addition to being corrosion-resistant, this type of enclosure is watertight and dust-tight.

• NEMA Type 7 enclosures are suitable for Class I, hazardous (classified) loca-tions. NEMA Type 9 enclosures are suitable for Class II, hazardous (classi-fied) locations. Enclosed heat generating devices must not cause external surfaces to reach ignition temperatures of the surrounding atmosphere.

• If available, UL-listed NEMA Type 7 (or 9) enclosures with NEMA 4 features are recommended for outdoor classified area applications.

Walk-in and Non-walk-in Enclosures. Walk-in and non-walk-in enclosures are used to house motor control centers and switchgear in outdoor locations. In a walk-in enclosure, there is enough room inside the enclosure to work on the equipment in front of the gear. Non-walk-in enclosures do not have room in the enclosure to work. Walk-in enclosures are recommended only for onshore facilities because the



moist, salt air offshore can create potentially dangerous conditions for personnel to work inside the limited-space enclosures.

Power Houses. A power house is a complete, custom-designed electrical distribu-tion system in a prefabricated building. It may contain medium or low voltage switchgear, starters, motor control centers, relay panels and control panels. Completely wired and tested units reduce field installation time (over conventional methods). Power houses should be considered when there is significant intercon-necting wiring since all internal wiring is done in the factory. Power houses should be selected on the basis of cost, installation and check-out time, and local prefer-ence.

Another advantage of power house construction is that it may be depreciated as electrical equipment (as opposed to a building which has a longer depreciation period).

Outdoor Switchracks. When it is necessary to install local starters in the field for a small group of motors located in a certain area, switchrack mounted starters may be desirable. For use in outdoor unclassified areas, NEMA Type 4 enclosures are usually recommended (NEMA 4X in corrosive atmosphere). NEMA Type 7 enclo-sures are required in Class I locations and NEMA Type 9 in Class II locations. Switch racks may contain other equipment; for example, lighting panels, control stations, lighting transformers, and circuit breakers.

134 Feeder and Branch Circuit SystemsFeeders and branch circuits are used to distribute electrical power throughout facili-ties. A feeder is defined as all circuit conductors between the service equipment or source of the separately derived system (e.g., a transformer) and the final branch circuit overcurrent device. A branch circuit is defined as the circuit conductors between the final overcurrent device and the load. This section describes how to size conductors and raceways. Once conductors have been sized, refer to Section 1100, “Wire and Cable,” for their selection.

The routing of conduit and cable is extremely important. Space for routing feeders and branch circuits should be reserved as early as possible in the layout and design. See Section 1000, “Installation of Electrical Facilities,” and Specification ELC-MS-1675 for specific guidelines on routing and installing wire and conduits and cable systems.

ConductorsConductors must be sized to meet five different criteria:

• Current carrying capacity (ampacity)• Voltage drop• Terminations• Short circuit duty• Mechanical strength



Current Carrying Capacity. Requirements for sizing feeder and branch circuit conductors are provided by NEC. The current carrying capacity (ampacity) of a feeder conductor must be equal to or greater than 125% of the continuous load plus the noncontinuous load (NEC Article 220-10).

Branch circuit conductors must have an ampacity not less than the maximum load to be served (NEC Article 210-19 and 220-10). Branch circuit conductors supplying a single motor must have an ampacity equal to or greater than 125% of the motor full-load current rating (NEC Article 430-22). Conductors supplying two or more motors must have an ampacity equal to or greater than the sum of the full load current rating of all the motors plus 25% of the largest rated motor in the group (NEC Articles 430-24 and 430-25.)

NEC Tables 310-16 through 310-19 contain rated ampacities for conductors rated 0-2000 volts, and Tables 310-69 through 310-84 contain rated ampacities for conduc-tors over 2000 volts. The ampacity ratings of conductors are dependent on conductor material, ambient temperature, type of insulation, type of raceway, and the number of conductors in the raceway.

Copper is the preferred conductor material because of its high conductivity and resiliency. Even though aluminum conductors are light weight and inexpensive, aluminum is very ductile, which causes terminations to loosen, resulting in high resistance, heat, and fires. Copper is required by the MMS in offshore OCS areas.

The ampacity of conductors must be derated for the following conditions: high ambient temperatures; more than three conductors in a raceway; installation in underground electrical ducts; and direct burial cable. Ambient temperature derating factors for conductors rated 2000 volts or less are included in NEC ampacity Tables 310-16 through 310-19. For conductors over 2000 volts, temperature derating is determined by the following formula:

(Eq. 100-6)

where:I1 = ampacity from NEC tables at ambient, TA1

I2 = ampacity at actual ambient temperature, TA2

TC = conductor temperature from NEC tables (°C)

TA1 = ambient temperature from NEC tables (°C)

TA2 = actual ambient temperature (°C)

∆TD = dielectric loss temperature rise from IEEE S-135 (IPCEA P-46-426)

NEC Appendix B contains tables for better approximation of 0-2000 volt cable temperatures for specific installations (these ratings are also based on

I2 I1

TC TA2 ∆TD––

TC TA1 ∆TD––-------------------------------------------×=



Equation 100-6). Although the code says “these are not part of the code but included for information only,” they may and should be used for more accurate ampacity esti-mates.

When there are more than three conductors in a raceway or cable, the ampacities given in NEC tables must be derated by the derating factors following the tables. Derating factors do not apply to conductors in conduits 24 inches long or shorter.

The ampacities of cables installed in underground duct banks and of direct buried cables (as listed in NEC Tables 310-77 through 310-84 and NEC Appendix B Tables B-310-8 through B-310-10 may be required to be derated if not installed per Figure 310-1 of NEC. Computer programs for derating are available.

The type of insulation used depends on a number of factors which must be consid-ered before making a final selection. Selection depends on: voltage rating, type of voltage (i.e., AC or DC), shielding, size of load, length of circuit, type of raceway, operating conditions, and cost. These factors are all described in detail in Section 1100, “Wire and Cable,” which contains recommendations for selecting power, control, instrumentation, telemetering, and thermocouple cables.

Insulation for power cables rated above 5 kV is divided into two classifications: grounded neutral service (100% insulation level) and ungrounded neutral service (133% insulation level). Cables with 100% insulation level may be used where the system is provided with relay protection such that ground faults will be cleared as rapidly as possible (1 minute maximum). Cables with 133% insulation level are applicable to situations where the clearing time requirements of the 100% level cannot be met or where additional insulation strength is desired. Faults must be cleared on 133% insulation level cable within 1 hour. In general, 133% insulation level cable is recommended for medium voltage installations because of increased cable life and decreased likelihood of faults.

NEC Table 310-64 provides insulation thickness requirements for shielded conduc-tors rated 2001 to 35,000 volts. Shielding is recommended on conductors rated 5 kV and higher. NEC Table 310-63 provides insulation thickness requirements for non-shielded conductors rated 2001 to 8000 volts.

For cable tray installations, the cable type must be listed specifically for use in cable trays. Single conductors below 1/0 cannot be used. NEC Article 318 contains requirements for cables installed in tray.

Descriptions of operating conditions and temperature ratings for low voltage insula-tions may be found in NEC Table 310-13.

If the required conductor size is larger then 500 MCM, paralleling conductors should be considered. The rate of increase of the ampere rating per circular mil of a conductor decreases with increase of cable size because of skin effect and smaller radiating surface per circular mil. Standard size conductors used for paralleling are usually more readily available and easier to install than conductors larger than 500 MCM. Paralleling conductors allows the use of two conduits, which may be less expensive than large wire in one conduit over 4 inches. Note that the conductors should be installed so each conduit contains all three-phases (A, B, and C) to mini-



mize induction heating. NEC Article 310-4 contains requirements for paralleling conductors.

Voltage Drop. Voltage drop should be considered when sizing conductors. In most circuits, the voltage drop is not significant. However, for long runs (particularly at low voltage) and conductors feeding critical circuits, the voltage drop should be calculated to ensure satisfactory operation.

The NEC recommends (for efficiency of operation) that voltage drop should not exceed 3% on any feeder or branch circuit. It also recommends that the total voltage drop on all conductors between the service-entrance equipment and connected loads be limited to 5%. For motor circuits, not only the steady state voltage drop but also the starting voltage drop must be considered.

Because of the phaser relationships between voltage, current, resistance, and reac-tance in AC circuits, voltage drop calculations require a working knowledge of trig-onometry for making exact computations. Fortunately, most voltage drop calculations are based on assumed limiting conditions, and, therefore, approximate formulas are adequate.

For balanced three-phase AC circuits the approximate voltage drop formula is:

VD = 1.732 IL (Rcosφ + Xsinφ)(Eq. 100-7)

where:VD = voltage drop in circuit, line to line, in volts

I = current flowing in the conductor, in amperes

L = length of one conductor (i.e., distance from overcurrent device to end device), in feet

R = line resistance for one conductor, in ohms per foot

X = line reactance for one conductor, in ohms per foot

φ = angle whose cosine is the power factor of the load

For single phase AC circuits the approximate voltage drop formula is:

VD = 2IL (Rcosφ + Xsinφ)(Eq. 100-8)

where:VD = voltage drop in circuit, line to neutral, in volts



R = line resistance for one conductor, in ohms per foot



X = line reactance for one conductor, in ohms per foot

φ = angle whose cosine is the power factor of the load

In using these formulas, the line current is generally considered to be the maximum or assumed load current carrying capacity of the conductor.

The resistance R is the AC resistance of the particular conductor used and of the particular type of raceway in which it is installed. R depends on the size of the conductor, the type of conductor (copper or aluminum), the temperature of the conductor (normally 75°C for average loading and 90°C for maximum loading), and whether the conductor is installed in magnetic (steel) or nonmagnetic (aluminum or nonmetallic) raceway.

The reactance X depends on the size and material of the conductor, whether the raceway is magnetic or nonmagnetic, and on the spacing between the conductors of the circuit. The spacing is fixed for multi-conductor cable; however, it may vary with single conductor cables, so an average value is required.

Cable manufacturers’ values of R and X should be used when available. Table 9 of NEC lists AC resistance and reactance values for 600 volt conductors installed in PVC, aluminum, or steel conduit. This table also lists values of effective impedance (defined as Rcosφ + Xsinφ) calculated at 0.85 power factor.

The angle φ between the load voltage and load current is determined from the power factor of the circuit: φ = arccos (power factor).

Voltage drop tables are sufficiently accurate to determine the approximate voltage drop for most problems. A voltage drop table has been developed to easily deter-mine voltage drop for most lighting circuits. See Section 136 for details.

For single phase DC circuits the voltage drop formula is:

VD = 2ILR(Eq. 100-9)

where:VD = voltage drop, in volts



R = DC resistance of conductor, in ohms per foot

If the calculated voltage drop is excessive, a larger conductor size should be selected. If voltage drop is a problem with several loads, it might be more econom-ical to move the power center (substation) closer to the load.

Termination. Conductors should be sized to limit conductor operating tempera-tures to those designated for the termination devices involved. For UL listed devices, unless marked with higher temperature limits, the terminals of devices



rated 100A or less are typically limited to operating temperatures of 60°C. Devices rated in excess of 100A are typically limited to 75°C. In selecting circuit conduc-tors, the designer shall assure that the actual conductor temperature does not exceed the temperature rating of the terminal device. The derating required for motor circuits and continuous loads on devices such as circuit breakers, which limit the actual current allowed in circuit wiring, should be considered when determining conductor operating temperature. Other factors such as ambient temperature within enclosures and the single conductor configuration of most terminations also can be taken into account when determining the actual conductor temperatures attainable.

In metal-enclosed switchgear, power cables usually terminate on buswork, not directly on the terminals of the main switching device. This is in contrast to panel-board, switchboard and motor control center construction, where power cables may terminate on the terminals of molded-case circuit breakers or starters. The allow-able temperature rise of the connections to insulated cables and the allowable temperature of the air surrounding these cables is given in the ANSI switchgear standards, ANSI/IEEE C37.20.1 for low-voltage switchgear, and ANSI/IEEE C37.20.2 for metal-enclosed interrupter switchgear.

All three of these standards require the same temperature for these features. Para-graph 4.5.5 of each of these standards limits the temperature of the air surrounding insulated power cables to 65°C, when the switchgear assembly is equipped with devices having the maximum current rating for which the assembly is designed, is carrying rated continuous current, and is in an ambient temperature of 40°C. Table 4 of each standard limits the temperature rise of silver-or tin-surfaced connections to insulated cables to 45°C, or a total temperature of 85°C. The tests to demonstrate conformance with these limiting temperature rises require including appropriate sizes and lengths of power cables in the continuous current path.

Short Circuit Duty. Conductor size should be checked to avoid severe permanent insulation damage from short circuit currents during intervals of fault-current flow.

Selection of cable size for short circuit duty should be based on anticipated actual short circuit current (including the effect of breaker impedance, conductor imped-ance, arcing fault impedance and breaker trip time). See Section 200, “System Studies and Protection,” for information on calculating short circuit currents. Short circuit duty requires a minimum conductor size according to ICEA requirements for transient temperature limits to avoid damaging thermal and mechanical stresses. The minimum conductor sizes for various insulations are shown in Table 79 of IEEE Std 141 or in ICEA P-32-382. See Section 1100, “Wire and Cable,” for details.

Mechanical Strength. For control wiring, the minimum recommended single conductor size is 14 AWG. The minimum conductor size recommended for instru-mentation and thermocouple cables is 18 AWG for single pairs and 20 AWG for multiple pairs. The minimum recommended conductor sizes for power and lighting circuits are given below.

Voltage of Conductor(volts)

Minimum Conductor Size(AWG)

Up to 2000 12



Example Calculation for Sizing Conductors. This example illustrates how to size conductors to feed a 100 hp motor.

• Design Parameters

a. Voltage and frequency of utilization: 480 VAC, 60 Hz

b. Raceway: steel conduit, above ground

c. Conductors: three copper, 600 volt, type THW single conductors, rated 75°C

d. Circuit Length: 400 feet from overcurrent device to motor

e. Voltage drop allowed: 3% (cable drop only)

f. Ambient temperature: 35°C (105°F) maximum

g. Short circuit current available: 15,000 amperes symmetrical

h. Power factor of motor: 0.85

i. Ground: high resistance, with an alarm for manual fault clearing

• Tables Used

a. IEEE Std 141, Table 79, “Minimum Conductor Sizes for Fault Current and Clearing Times”

b. NEC Table 310-16, “Allowable Ampacities”

c. NEC Table 430-150, “Full-Load Current - Three-Phase Alternating Current Motors”

d. NEC Table 9, “AC Resistance and Reactance for 600 V Cables”

• Conductor Sizing

a. Minimum size for mechanical strength: 12 AWG (based on circuit voltage)

b. Minimum size for load current: From NEC Article 430-150, the load current for a 100 hp motor is 124 amperes. NEC Article 430-22 requires that the branch circuit conductors be sized to carry 125% of motor full load current: 1.25 x 124 amperes = 155 amperes. From NEC Table 310-16, 2/0 AWG, THW, 75°C rated conductor temperature has an ampacity of 175, and the derating factor for 35°C ambient is 0.94. Therefore, the maximum ampacity is 175 (0.94) = 164.5 amperes. Since the maximum ampacity of the conductor is greater than 155 amperes, 2/0 AWG conductors should be selected.

2001 to 5000 8

5001 to 8000 6

8001 to 15,000 2

Above 15,000 1



c. Minimum size for short circuits: 6 AWG for 15,000 amperes fault at 1/2 cycle and 2/0 AWG for 15,000 amperes fault at 10 cycle clearing time for PVC insulation. (See Table 79, IEEE Std 141.)

d. Maximum of 3% voltage drop in feeder at load current

VD = 1.732 IL (Rcosφ + Xsinφ)

I = 124 amperes

L = 400 ft

From Table 9 of NEC, the effective “Z” (defined as Rcosφ + Xsinφ) at 0.85 power factor for 2/0 AWG is 0.00011 ohms per foot.

VD = 1.732 (124) (400) (0.00011) = 9.45 volts

%VD = = 2.0%

(Eq. 100-10)

For motor starting voltage drop calculation procedures, see Section 200, “System Studies and Protection.”

Raceway SystemsFour types of raceway systems are commonly used to distribute electrical power in industrial systems.

• Conduit systems• Cable trays• Direct burial cables• Submarine cables

Conduit Systems. Underground conduit systems are used when it is necessary to provide a high degree of mechanical and fire protection and when overhead conduits would be difficult or expensive to install (e.g., when no means for adequately supporting conduit is available). It is recommended that underground conduits be enclosed in a red concrete bank for protection from damage and for ease of recognition during excavation. In an underground conduit system, schedule 40 PVC conduit, rigid galvanized steel conduit, PVC coated galvanized steel conduit, and PVC coated aluminum conduit may be used.

Aboveground conduit systems are generally used where there are overhead pipe-ways or structures to provide support for the conduits. Overhead conduits should be either schedule 40 rigid, hot dipped galvanized steel or schedule 40 copper-free aluminum conduit, as dictated by overall economics and facility site requirements.

See Section 1000, “Installation of Electrical Facilities,” for details about selecting and installing conduit systems. Figure 100-16 shows some of the advantages and disadvantages of the different conduit systems.

9.45480---------- 100×



Sizing of conduit is based on the percentage of cross-sectional area of conduit filled by the conductors or cables. Tables 1 through 8 in Chapter 9 of NEC are used to determine conduit fill and the maximum number of conductors allowed. Tables 3A, 3B, and 3C may be used to determine the number of conductors if only one type of conductor is installed in the conduit. If a combination of conductor types is needed, the percentage of fill must be calculated using Tables 4 through 8. For conductors not included in Chapter 9, such as compact or multi-conductor cables, the actual dimensions should be used.

When a conduit or nipple installed between junction boxes, cabinets, and similar enclosures does not exceed 24 inches in length, 60% of the total cross-sectional area may be filled.

In general, the minimum recommended size of conduit used in underground systems is 1 inch. For aboveground systems, the minimum recommended size is 3/4 inches for galvanized steel and 1 inch for aluminum.

Example Calculation for Sizing a Conduit

Size a conduit that contains three 4/0 AWG THWN copper wires and one 4 AWG THWN copper ground wire.

From Table 1 of NEC, 40% fill is allowed for four conductors in conduit.

From Table 5 of NEC, which lists approximate diameter and cross-sectional area of various conductors:

Total area of three 4/0 THWN wires is 3 x 0.3278 = 0.9834 in2.

Area of one 4 AWG THWN conductor is 0.0845 in2.

Total area of the conductors is 0.9834 + 0.0845 = 1.0679 in2.

From Table 4 of NEC, for more than two conductors at 40% fill, the minimum trade size of conduit allowed is 2 inches.

Conductor jamming in the conduit must be considered when sizing conduits. See Section 1000, “Installation of Electrical Facilities.”

Cable Tray Systems. A cable tray system offers low installed cost, system flexi-bility, easy accessibility for repair or addition of cables, and is space saving when compared to conduits where there are large numbers of circuits with a common routing.

Cables used in cable tray systems must be approved specifically for cable tray installations (e.g., TC Type Cables). In most process facility cable tray installations, armored cables are used instead of TC cables.

The four different types of cable trays are ladder, solid bottom, trough, and channel. The normal sizes (widths) of cable trays are 6, 12, 18, 24, 30, and 36 inches.



Ladder cable tray is used primarily with power cables and other heat-producing cable. It permits liberal air flow, but does not offer total protection against damage from external sources.

Solid bottom cable tray is not commonly used because its cost is about 30 to 50% more than the ladder type. Solid bottom cable tray affords maximum protection against damage, but, because it has a solid bottom, it provides no ventilation. Solid

Fig. 100-16 Comparison of Raceway Systems

Method of Distribution Advantages Disadvantages

Underground conduit - General

Best protection against mechan-ical and fire damage.

Not accessible for maintenance, repair, and additions.

Aboveground conduit - General

More accessible for maintenance, repair and additions.

Greater exposure to fire, explosion, corrosion, and mechanical damage.

Rigid conduit and single conductor wiring.

Most readily available materials. Electricians familiar with installa-tions. Provides high degree of mechanical protection.

Requires intermediate supports. Expensive fittings; high exposure to corrosion; structural supports always required. Labor intensive.

IMC conduit with single conductor wiring.

Not recommended for Company installations.

Not allowed by MMS in classified areas offshore.

PVC coated conduit (coated on outside only) with single conductor wiring.

Same as for rigid conduit, but more resistant to corrosion.

Same as for rigid conduit. Expen-sive.

PVC coated conduit (also coated on the inside) with single conductor wiring.

More resistant to corrosion than conduit coated just on outside.

Friction factor for pulling wire is greater than for conduit with no inside coating. Very expensive.

Rigid PVC conduit with single conductor wiring.

Highest resistance to corrosion. Very low cost.

Not approved for Class I areas. Has history of installation problems. Additional supports required.

Cable tray - General Low installed cost; easy accessi-bility for repair or addition of cable. Easy conventional installation. Additions and modifications simply made.

Greater exposure to fire, explosion, corrosion, and mechanical damage.

Galvanized steel cable tray with multi-conductor cable wiring.

Inexpensive. High maintenance cost.

Aluminum cable tray with multi-conductor cable wiring.

Light weight. Corrosion-resistant in most atmospheres.

Susceptible to corrosion in some atmospheres.

PVC coated cable tray with multi-conductor cable wiring.

More corrosion-resistant than galvanized steel.

Subject to corrosion pockets despite PVC coating. High cost. Usually available only in 12-foot lengths.

Fiberglass cable tray with multi-conductor cable wiring.

Least susceptible to corrosion. Most expensive. No ground conti-nuity. Subject to deterioration by U/V.



bottom cable tray should be used only for instrumentation, control, and communica-tion cables that do not develop heat.

Trough cable tray permits average ventilation and average protection against cable damage. It represents a compromise between the primary features of ladder and solid bottom tray.

Channel cable tray is a small tray primarily used to carry one or two cables from the main cable tray to the vicinity of cable termination. This cable tray is used when there is not space for larger tray or when large tray is uneconomical.

The sizing of cable trays depends upon the rated voltage level, type of conductors or cables, and sizes of conductors or cables in the cable trays. The complete design and sizing of a cable tray system should be in accordance with Article 318 of NEC. To determine the quantity of cables and conductors rated 2000 volts nominal or less permitted in a cable tray, refer to Articles 318-9 through 318-11. For cables and conductors rated over 2000 volts nominal refer to Articles 318-12 and 318-13.

When sizing cable trays, consideration must be given to loading and support systems. Trays are available in different strengths for minimizing sagging. For more details on cable tray installation, see Section 1000, “Installation of Electrical Facili-ties.”

Example Calculation for Sizing a Cable Tray System

Size a ladder cable tray to hold 12 1/C 250 MCM and three 1/C 1000 MCM conduc-tors. The conductors are type THWN rated 600 volts.

By the formula in NEC Table 318-10, Column 2, the area of all cables smaller than 1000 MCM should not exceed the maximum allowable fill area resulting from the computation.

Area of one 250 MCM conductor (NEC Table 5, Chapter 9) = 0.4026 in2.

Area of twelve 250 MCM conductors = 12 × 0.4026 = 4.83 in2.

Diameter of one 1000 MCM conductor (NEC Table 5, Chapter 9) = 1.317 inches

Sd = Sum of the diameter of three 1/C 1000 MCM THWN wires.

Sd = 3 × 1.317 = 3.951 inches

(1.1 × Sd) = 1.1 × 3.951 = 4.34 in2.

From Table 318-10 for 6 inch cable tray, the maximum allowable fill area is 6.5 - 4.34 = 2.16 in2. Since the area of the 250 MCM conductors (4.83 in2) is larger than 2.16 in2, a 6 inch cable tray is not large enough.

From Table 318-10 for 12 inch cable tray, the maximum allowable fill area is 13.0 - 4.34 = 8.66 in2. Since the area of the 250 MCM conductors is smaller than 8.66 in2, a cable tray 12 inches wide and 6 inches deep should be selected to conform to NEC. In addition, the cable weight should be checked to ensure that it does not exceed the manufacturer’s recommendations for maximum deflection.



See Figure 100-16 for a comparison of the advantages and disadvantages of wire and conduit systems and cable tray systems.

Direct Burial Cables. Cables may be buried directly in the ground if of a type permitted by Article 310-7 and installed in accordance with Article 300-5 of NEC. Direct burial cables are recommended only when the need for future maintenance along the cable run is not anticipated. The cables used must be suitable for direct burial and identified for such use (NEC Article 310-7). Direct burial cables rated over 2000 volts nominal must be shielded (NEC Article 310-7.) The metallic shield, sheath or armor must be grounded per NEC Article 310-7 (for personnel safety in the event of accidental dig-in). Refer to Tables 300-5 and 710-3(b) of NEC for minimum depth requirements. For direct burial cable installation details, see Section 1000, “Installation of Electrical Facilities.”

Submarine Cables. Submarine cables are used primarily to provide power to offshore platforms from shore and from one platform to other. Submarine cables are generally medium voltage to high voltage cables. For more information see “Chevron Eastern Region-ELEP, Electrical Construction Guidelines for Offshore, Marshland, and Inland Locations.”

135 GroundingGrounding is essential for personnel safety, compliance with various codes, prolonging insulation life (by limiting overvoltage), and for fast selective isolation of ground faults (thereby improving equipment protection). Various types of grounding are described below. For a detailed discussion on grounding, refer to Section 900, “Grounding Systems.”

System Grounding. System grounding involves grounding the neutral point of separately derived sources (e.g., transformers and generators). A completely ungrounded system can be hazardous to personnel and is subject to excessive over-voltage.

There are three methods of system grounding: solid, low resistance, and high resis-tance.

A solidly grounded system is connected directly to ground through an adequate ground connection where no impedance has been inserted intentionally. Solidly grounded systems are not subject to excessive over-voltages during ground fault, but values of ground fault current can be large. They are used on low voltage systems (0-1000 volts) and systems over 15 kV when immediate tripping is desired.

A low resistance grounded system is grounded through an impedance, primarily resistive, where the ground fault current is limited between 25 amperes and several hundred amperes. The system limits ground fault currents to a value that will mini-mize damage to equipment, yet allow sufficient ground current for selective relay performance. Low resistance grounded systems are not subject to excessive over-voltage due to arcing faults. They are used on 2 kV through 15 kV systems.

A high resistance grounded system is grounded through an impedance, primarily resistive, where the ground fault current is limited to less than 10 amperes. The



basic objective of the system is to prevent tripping by the first ground fault (allowing continued process operation). This system must be provided with a means for detecting and locating faults. The system is not subject to transient overvoltages due to arcing faults. This method is used on 480 volt, three-phase, three-wire systems not requiring connection of line-to-neutral loads and is rarely used on systems over 5000 volts. When used on 2400 and 4160 volt systems, the protective system may be designed to either trip or not trip on the first fault.

Equipment Grounding. Equipment grounding involves the connection to ground of all metallic non-current carrying parts in the facility (e.g., transformer enclo-sures, switchgear and motor control center cabinets, motor frames, junction boxes, cable tray, conduit, armor and shields of cable, buildings, and vessels not inherently grounded). When separate below-grade ground loops around substations, struc-tures, and buildings are used, all loops should be interconnected and tied to groups of driven ground rods. The primary objective is to protect personnel from electrical shock by limiting the potential difference between equipment and ground to a safe level—under both normal and fault conditions.

Lightning Protection Grounding. Lightning protection grounding may be required for the protection of buildings, tall structures, overhead power lines, and electrical equipment to minimize damage and personnel shock hazards in areas of frequent thunderstorm activity. These areas may require the installation of air terminals, down conductors, and ground rods for buildings and tall structures, the installation of an overhead ground wire for pole lines and substations, and the installation of surge arresters on pole lines and in substations.

Areas with frequent thunderstorm activity require more protection, possibly the addition of air terminals and surge arrestors—determined on the basis of facility experience for the particular site involved. When used, air terminal and surge arrester ground wires should be run as directly as possible to separate ground rods, with a minimum number of bends and no sharp bends. The ground rods should be interconnected and also tied into the main ground loops. Capacitors, installed along with surge arresters at the terminals of large motors, are used to protect rotating machinery insulation.

Static Electricity Grounding. Static electricity grounding concerns the grounding (bonding) of equipment and piping involving flowing combustible liquids or dust to prevent the accumulation of static charges that could spark over and cause a fire or explosion. Tank car and tank truck loading and unloading of gasoline are examples where bonding and grounding are required. Static grounds should be connected directly to the facility grounding system.

136 LightingThe scope of this section is limited to the selection of lighting voltage levels, sizing lighting transformers and panelboards, and lighting voltage drop calculations. Section 1200, “Lighting,” provides information on light sources, lighting fixture selection, lighting system design, lighting calculations, fixture layout, and emer-gency lighting requirements.



Voltage LevelThe most common voltage level for lighting fixtures is 120 volts. Incandescent lighting fixtures are available in 120, 208, and 240 volts. Fluorescent lighting fixtures are available in 120, 208, 240, and 277 volts. High intensity discharge (HID) lighting fixtures are available in 120, 208, 240, 277, and 480 volts.

Fixture supply voltages of 277 volts and less are preferred. However, it may be necessary to use 480 volts for floodlighting applications (e.g., lighting parking lots) when many large-wattage fixtures and long branch circuits are involved.

Many operating locations have standardized particular voltage levels for certain fixture types. This should be investigated before selecting a voltage level.

Lighting Transformer and Panelboard SizingA lighting transformer is used to reduce the voltage feeding a panelboard. Lighting transformers are typically rated 50 kVA and smaller and may be single phase or three-phase. However, three-phase lighting transformers and panelboards are preferred to allow better load balancing.

A panelboard is used to distribute power to individual branch circuits; each circuit must be protected by a circuit breaker. Panelboard phases must match feed phases (e.g., a three-phase four-wire panelboard must be selected for a three-phase four-wire circuit.) NEC limits the maximum size of a panelboard to 42 overcurrent devices. A two-pole breaker is considered to be two overcurrent devices, and a three-pole breaker is considered three overcurrent devices. The total continuous load on any overcurrent device is limited to 80% of its rating, unless the assembly (over-current device and enclosure) is approved for continuous duty at 100% of its rating.

In many expansion applications, sufficient spare capacity will be available on existing lighting transformers and panelboards, located in the vicinity of the new lighting system. If not, a new transformer and panelboard will be required. Stan-dard Drawing ELC-EF-484 can be used to arrange circuits, provide balanced phases, determine panelboard size, and determine transformer load and size. Future load growth should always be considered when sizing lighting transformers and panelboards. It is recommended that both be sized to carry the total continuous running load plus 25% spare capacity. A minimum 15 kVA transformer is recom-mended to reduce voltage drop and to provide high fault current levels on long branch circuits that otherwise may not have sufficient fault current to trip the breaker.

Voltage Drop CalculationsNEC recommends (for efficiency of operation) that lighting branch circuits be sized to prevent a voltage drop exceeding 3% at the furthest fixture and 5% on the feeder and the branch circuit combined.

The voltage drop for lighting circuits may be determined using the applicable formulas given in Section 134. However, for most lighting circuits, the voltage drop table shown in Figure 100-17 may be used to simplify calculations. This table is for single-phase, two-wire, AC systems with a power factor of 0.90. It was developed



for copper conductors installed in magnetic conduit. The circuit footage used in the table is the distance from the overcurrent device to the end device (i.e., conduit length). Other voltage drop tables for single-phase two-wire systems typically use the linear length of wire from the overcurrent device to the end device plus the length of return wire back to the overcurrent device. Figure 100-17 takes into account the return length. The rated operating current of each fixture (including lamp and ballast) should be used when calculating voltage drop. Figure 100-17 was developed for a conductor operating temperature of 60°C, but it may be used without significant error for conductor temperatures up to 75°C. The two examples given below demonstrate how to use the voltage drop table.

When a common neutral is used and the loads are balanced, neutral currents “cancel” because they are out of phase. In this case, the voltage drop equals one-half the voltage drop for each circuit with separate neutrals. However, the conductors should be sized for the case with full current flowing in the neutral to account for the unbalanced (worst) case when all lamps are not operating

Assumptions for using the voltage drop table for single-phase, two wire circuits:

1. The conductors are copper, installed in rigid steel conduit.

2. The circuit is single-phase two wire—ungrounded (hot) and grounded (neutral) conductors.

3. The tables have already taken into account the total circuit length in feet (i.e., the length of wire from the source to the light and back to the source), so the measured distance is just the length of the conduit.

4. Conductor temperature is 75°C or less.

Example 1. Calculate the percentage voltage drop for two 120V, 250 watt HPS floodlights installed on the same pole, 500 feet from the panel (Figure 100-18).

The rated operating current for each 250 watt HPS fixture is 2.7A (from manufac-ture’s literature).

For two 8 AWG conductors:

Ampere feet = (2.7A + 2.7A) (500ft) = 2700 A-ft

VD = 3.78V (from Figure 100-17)

%VD = = 3.2%

(Eq. 100-11)

Since the voltage drop exceeds 3%, the next larger size wire is investigated.

For two 6 AWG conductors:

Ampere feet = 2700 A-ft

VD = 2.5V (from Figure 100-17)

3.78120---------- 100×



Fig.

100

-17

Volta

ge D

rop

Tabl

e



%VD = = 2.1%

(Eq. 100-12)

Therefore, two 6 AWG conductors are acceptable for this circuit.

Example 2. Calculate the voltage available at each fixture and the percent voltage drop at the further fixture for the circuit shown in Figure 100-19. Source voltage is 120 volts, and wire size is 8 AWG.

Fig. 100-18 Voltage Drop Calculation, Example 1

Fig. 100-19 Voltage Drop Calculation, Example 2

2.5120--------- 100×



The rated operating current for each 250 watt HPS fixture is 2.7A (from manufac-turer’s literature). Total current drawn at each fixture is shown in Figure 100-19.

at V1: Ampere Feet = (5.4 + 8.1 + 5.4)(50) = 945 A-ft

at V2: Ampere Feet = 945 + (8.1 + 5.4) (50) = 1620 A-ft

at V3: Ampere Feet = 1620 + (5.4)(40) = 1836 A-ft

From Figure 100-17, using two 8 AWG wires, the voltage drop at each point is:

VD1 = 1.35 volts

VD2 = 2.27 volts

VD3 = 2.57 volts

The voltage at each fixture (V1, V2, V3) is:

V1 = VS - VD1 = 120 - 1.35 = 118.65 volts

V2 = V1 - VD2 = 120 - 2.27 = 117.73 volts

V3 = V2 - VD3 = 120 - 2.57 = 117.43 volts

The percentage voltage drop at the furthest downstream fixture is:

%VD3 = = 2.14%

(Eq. 100-13)

Therefore, 8 AWG wire is large enough for this application.

137 System ProtectionPower systems must be protected with fuses or circuit breakers against faults and current overloading. It is extremely important that the protective devices (e.g., circuit breakers, relays, and fuses) have coordinated operation to provide selective tripping; that is, the device nearest the fault (the primary protection) should trip before the devices closer to the power source (secondary protection). With proper coordination, the smallest possible portion of the electrical system is shut down when clearing a fault. Improper coordination can be very costly if an entire facility is shut down to clear a minor fault.

Coordination is a part of the system design and is determined in a relay coordina-tion study. Section 600, “Protective Devices,” describes how to select relays, current transformers and potential transformers, and how to plot relay curves on the time-current coordination sheet. It also discusses the major relays used for protection of components in an industrial electrical system.

2.57120---------- 100×



140 ReferencesThe following references are readily available. Those included with an asterisk (*) are included in this manual or are available in other manuals.

141 Model Specifications (MS)*ELC-MS-1675 Installation of Electrical Facilities

142 Standard DrawingsGF-P99968 Standard Manual Transfer Panel for Double-Ended Substations

GF-P99972 480-V Stand-by Power System, One-Line Diagram

GF-P99988 Typical One-line Diagram

143 Data Sheets (DS), Data Guides (DG), and Engineering Forms (EF)*ELC-DS-597 Data Sheet for Instructions for 480 V Motor Control Rack Spec-

ifications and Arrangement

*ELC-DG-597 Data Guide for Instructions for 480 V Motor Control Rack Specifications and Arrangement

*ELC-EF-204 Schedule of Motors and Starters

*ELC-EF-484 Lighting Schedules

*ELC-EF-541 Electrical Symbols and Index of Reference Drawings

*ELC-EF-759 Equipment Schedule and Reference Drawings

144 AppendicesAutomatic Switch Company (ASCO)

*“Sizing of Automatic Transfer Switches, Part I,” ASCO Facts Vol. 2, No. 12 (Appendix A).

*“Sizing of Automatic Transfer Switches, Part II,” ASCO Facts Vol. 2, No. 13 (Appendix A).

145 Other ReferencesAmerican Petroleum Institute (API)

*RP 14F Design and Installation of Electrical Systems for Offshore Production Platforms

*RP 540 Recommended Practice for Electrical Installations in Petroleum Processing Plants

Institute of Electrical and Electronics Engineers (IEEE)

ANSI/IEEE Std45

IEEE Recommended Practice for Electric Installations on Ship-board.

IEEE Std C57 Distribution, Power and Regulating Transformers.

ANSI/IEEE Std 141

IEEE Recommended Practice for Electric Power Distribution for Industrial Plants.



ANSI/IEEE Std 446

IEEE Recommended Practice for Emergency & Standby Power Systems for Industrial and Commercial Applications.

ANSI/IEEE Std 485

IEEE Recommended Practice for Sizing Large Lead Storage Batteries for Generating Stations and Substations.

Vol. IA-9 No. 3 “Features of a Power System Incorporating Large AC Motors/Captive Transformers,” IEEE Transactions on Industry Applications, May/June 1973.

National Fire Protection Association (NFPA)

ANSI/NFPA 70 National Electrical Code (NEC).

General Electric Company (GE)

GET-3548 System Grounding for Low-Voltage Power Systems.

GET-2H Transformer Connections, Dec. 1967.

Insulated Cable Engineers Association (ICEA)

ICEA P-32-382 Short Circuit Characteristics of Insulated Cable

National Electrical Manufacturers Association (NEMA)

NEMA 250 Enclosures for Electrical Equipment (1000 Volts Maximum)

ANSI/NEMA ICS6

Enclosures for Industrial Controls and Systems.

Other Publications

Beeman, Donald. Industrial Power Systems Handbook. New York: McGraw-Hill Book Co., Inc., 1955.


200 System Studies and Protection

AbstractThis section introduces the engineer to electrical power system studies that can aid in the design of new systems or the modification of existing systems. The studies serve as a framework for the systematic analysis of critical considerations in power system design. The studies include: a short circuit study, a motor starting study, and a load flow analysis. The discussions in this section concentrate on how and when each study may be appropriate, the quality of data required for each study, and how to use the study results. Also included is a brief discussion of studies for transient stability and harmonic analysis.

Contents Page

210 Introduction 200-3

211 System Studies Summary

220 Short-Circuit Studies 200-4

221 Scope

222 Reasons for a Short-Circuit Study

223 When to Conduct a Short-Circuit Study

224 Short-Circuit Study Methods

225 Short-Circuit Analysis: Example Using the Per-Unit Method

226 Comments on the Short-Circuit Calculation Example

227 Computer Methods for Calculating Short-Circuit Current

228 Electrical Systems Analysis Computer Programs

230 Motor-Starting Studies 200-32

231 Scope

232 Reasons for a Motor-Starting Study

233 When To Conduct a Motor-Starting Study

234 Voltage-Drop Calculations

235 Data for a Voltage-Drop Calculation

236 Voltage-Drop Calculation: Example

200 System Studies and Protection Electrical Manual


237 Correcting for Unacceptable Voltage Drop

238 Motor Acceleration Time Calculation

239 Computer Programs That Simulate Motor-Starting

240 Load-Flow Studies 200-54

241 Reasons for a Load-Flow Study

242 When To Conduct a Load-Flow Study

243 Data for a Load-Flow Study

244 Interpreting Computer Load-Flow Data

250 Transient-Stability Studies 200-55

260 Harmonic Analysis Studies 200-57




273 Data Sheets (DS), Data Guides (DG) and Engineering Forms (EF)


Electrical Manual 200 System Studies and Protection


210 IntroductionThis section explains when system studies should be conducted and how to do them. The following studies are discussed:

• Short-circuit• Motor-starting• Load-flow• Transient-stability• Harmonic analysis

Relay coordination is discussed in Section 600, “Protective Devices.”

Computers are generally used to perform the calculations in the above studies. To use computer programs properly, it is necessary to have a good understanding of the calculations involved and the expected results. Manual calculations are still used to make first-order approximations and to check computer solutions. For this reason, both manual and computer-based techniques are discussed.

211 System Studies SummaryA brief summary of each system study discussed in this section is presented below. A review of these summaries will guide the reader to information appropriate for the task.

Short-circuit studies (Section 220), sometimes called “fault” studies, are used to determine how much current will flow if there is a short circuit at any point in the system. This information is needed before specifying switchgear, motor control center starters, circuit breakers, and wire and fuses to ensure that the devices which are chosen are capable of interrupting or withstanding the available short circuit current without being damaged mechanically or electrically. The results of a short-circuit study are used to calculate the settings of protective relays within the system, and to select fuse and circuit breaker time-current characteristics.

Motor-starting studies (Section 230) are usually conducted for large motors, 500 hp or larger, and are sometimes done for smaller motors fed by weak power systems, long feeders or branch circuits. The objective of a motor-starting study is to determine if a motor will start and accelerate the driven equipment, and to deter-mine voltage dips at various points in the electrical system when the motor is started. Usually it is unacceptable to allow the voltage to drop below 80% of the nominal voltage anywhere in the system during the starting of a motor. High inten-sity discharge (HID) lighting may extinguish and some control relays may drop out if the voltage drops lower.

Load-flow studies (Section 240) utilize the same information required for short-circuit studies in addition to facts about the operational loading conditions of the system. Load-flow studies are run on a computer program that simulates the actual currents and power flows in the system. These programs produce tabulations of the magnitude and phase angle of the voltage at each bus and the real and reactive power flowing in each line. The studies also determine line losses and are useful for



selecting the tap positions on power transformers. Information from load-flow studies is used to predict voltage drops within the system and the overload status of distribution circuits. A load-flow study is a prerequisite for a transient-stability study.

Transient-stability studies (Section 250) are usually completed following short-circuit and load-flow studies. Transient stability is the ability of a power system to withstand a disturbance without a loss of synchronism in its synchronous machines. A transient-stability study simulates typical system disturbances and analyzes their effects on the rotating synchronous machines in the system.

Harmonic analysis studies (Section 260) may be needed when using large silicon controlled rectifier (SCR) drives, power conversion equipment, or power factor correction capacitors. Harmonic frequencies generated by the SCR equipment can cause problems with computer systems, blow capacitor fuses, exceed allowable harmonic levels on utility lines, cause communication circuit interference, and cause overheating of transformers and neutral conductors. A harmonic analysis may be used to evaluate these problems in advance and to design for them.

220 Short-Circuit Studies

221 ScopeA short-circuit study is a calculation of the magnitude of fault current which will flow if a short-circuit occurs in the system. If the values of prospective fault currents are known, it is possible to select circuit breakers, fuses, starters, switches, cables, motor control centers, and switchgear capable of withstanding the forces of, or interrupting the currents caused by, the fault. It also is necessary to know the poten-tial fault current values at every point in the electrical system in order to properly set protective relays for coordinated protection during a fault.

This section discusses basic methods for conducting short-circuit studies. Simple examples demonstrating the calculation techniques are presented along with a summary sheet of formulas for quick reference.

References are included for finding more information and examples of the commonly accepted methods of conducting rigorous short-circuit studies. It is not the intent of this guideline to repeat the detailed explanations given in these refer-ences, but rather to recommend that they should be consulted when performing crit-ical short-circuit studies. Also included, as Appendix C, is an article on the “MVA method,” which describes a simple method for approximate calculations and field use.

A typical computer program for a short circuit study is also discussed with the resulting output. Other programs are listed with source addresses and phone numbers.



222 Reasons for a Short-Circuit StudyIn any system subject to a fault current there is a short period of time before protec-tive devices operate when the system components are exposed to high-fault currents. A short-circuit study helps ensure that system components are appropri-ately sized to withstand the mechanical and electrical stress of the fault currents prior to clearing. A short-circuit study also provides information used to coordinate protective devices in the system.

223 When to Conduct a Short-Circuit StudyA short-circuit study should be conducted at the following times:

• Prior to ordering electrical equipment for the system. This should be followed by a complete study, including calculation of ground faults. Before finalizing the design of a new electrical system, the study should be completed according to IEEE Standard 141 (Red Book) and the appropriate ANSI standards (for applicable components). For example, there is a standard for high voltage circuit breakers, one for low voltage power circuit breakers, and another for high voltage fuses. These references are listed in the Red Book, Chapter 9.

• When adding a major electrical addition to an existing system. Examples are the addition of a cogeneration facility or a new crude unit to a refinery.

• When making electrical additions and the fault values are unknown or may have changed since the previous short-circuit study.

• Every 4 to 5 years in an existing plant. Short-circuit studies should be reviewed and updated periodically as the utility fault contributions may have changed, or system changes may have been made without consideration of the effects on fault levels. This review is of particular importance if the margin between the equipment ratings and the available fault levels is less than 10 to 20%.

• Whenever large motors or a large number of small motors are added to an elec-trical system. Additional motors could raise the fault levels significantly, and a new study should be made or the existing study should be revised.

• Whenever the electrical source to a system is modified. The fault levels could change, and a study should be made before modification.

Once a short-circuit study has been completed, it should be available for periodic update and reference. This record will make future studies easier to perform. Conducting a plant study requires a large amount of data. Future studies will reuse most of the existing data, often with only minor changes.

224 Short-Circuit Study MethodsThere are several methods of making short-circuit calculations including:

• MVA method (see Appendix C, “Short Circuit ABC: Learn It In an Hour, Use It Anywhere, Memorize No Formula”)



• Ohmic method• IEEE Per-Unit method

The MVA method is probably the easiest to use. The ohmic method is seldom used since it requires extensive calculations to reflect impedances across transformers. It is not discussed in this section. The IEEE Per-Unit method is the most commonly used.

The MVA MethodThe primary application of the MVA method is for quick calculations in the field, or for quick checks of calculations done by computer or by the per-unit method. It also is useful as a preliminary study to determine if a computer study is necessary. If there is sufficient margin between the equipment capabilities and the maximum fault current indicated by the MVA method, a computer study may not be neces-sary. Usually the results of the MVA method are fairly close to the results obtained by more rigorous methods.

The main limitation of the MVA method is that it neglects system resistance. It is necessary to include the system resistance for accurate calculations of low voltage systems and to calculate the fault duties of medium and high voltage circuit breakers by the IEEE Red Book Per-Unit method.

An article by M. Yuen explaining the MVA method is included as Appendix C. This article presents the material in an easy to understand manner, and is recommended to those unfamiliar with this method.

The IEEE Red Book (Per-Unit) MethodThe Per-Unit method as described in the IEEE Red Book (Reference 1) is the most widely accepted method for short-circuit calculations because it is accurate and versatile, and because the ratings of the equipment in the ANSI standards are based on this method. This is the method which should be used to determine the required equipment ratings on large electrical projects.

The Per-Unit method is utilized in most computer programs for the solution of short-circuit studies. The Red Book should be consulted when performing a large or critical study, as it incorporates the detailed methods currently accepted by IEEE. A description and example of the Per-Unit method is presented below.

Line-to-Neutral Model. The object of modeling is to reduce the entire system to an equivalent circuit, as shown in Figure 200-1. Ohm’s law can then be applied, and the fault current is calculated by the equation:

IFault = EL-N/Z(Eq. 200-1)

The system is modeled as a single phase line-to-neutral circuit with a single phase line-to-neutral driving voltage (EL-N). The modeled impedances are real and reac-tive circuit impedances (Zequiv.) associated with the motors, cables, transformers, generators, and utility.



The diagrams in Figures 200-2 and 200-3 demonstrate how the line-to-neutral model is derived from the three-phase representation of a system with a bolted fault. A three-phase bolted fault is a short circuit where all three phases are connected at the fault location by a zero impedance path. In Figure 200-2(b), the generator is represented by a single phase driving voltage. Its inductive reactance is represented by Xs, and its resistance is represented by Rs. The non-motor load is simply a resis-tance and reactance added to the feeder circuit resistance RL and reactance XL.

In Figure 200-2(b), the three-phase representation (Figure 200-2(a)) has been replaced by an equivalent line-to-neutral model. Most of the fault current, IF, flows through Xs and Rs to the fault and back to the neutral side of the generator. A very small amount of load current may still flow to the non-motor load. Since the voltage is almost zero with respect to neutral at the fault location, IL is usually neglected, resulting in the refined line-to-neutral model of Figure 200-2(c). The commonly seen impedance diagram, shown in Figure 200-2(d), represents the line-to-neutral model of Figure 200-2(c).

Figure 200-3(a) shows a three-phase faulted system consisting of a generator or utility and motor load. When a fault occurs, the voltage at the fault drops to almost zero, and the motor slows down. While it is slowing down, it acts as an induction generator and contributes additional fault current IM to the fault. There are now two voltage sources in the line-to-neutral model in Figure 200-3(b). Since the per-unit voltage of both sources is near unity at the instant of fault, Thevenin’s law allows them to be combined into one voltage source, as shown in Figure 200-3(c). The impedance diagram, shown in Figure 200-3(d) represents the line to neutral model of Figure 200-3(c).

Maximum Fault. In most systems, the maximum fault is a three-phase bolted fault.

Fig. 200-1 Equivalent Circuit of Fault Network



Fig. 200-2 Derivation of Line-to-Neutral Models with Non-Motor Loads for Short-Circuit Studies



Fig. 200-3 Derivation of Line-to-Neutral Models with Motor Loads for Short-Circuit Studies



Another type of fault is a line-to-line fault. This fault occurs when two of the phase conductors are connected with zero impedance. The magnitude of this fault is usually 87% of the three-phase bolted fault, so if the system is designed to with-stand a three-phase bolted fault, it will also withstand a line-to-line fault.

A third kind of fault is the ground fault. This fault is usually less than the three-phase bolted fault. It is important to note that the ground fault impedance network (known as the zero sequence network) is different from the three-phase bolted fault network. An approximation of the ground fault current is necessary for coordina-tion of ground fault relays. In some refineries and industrial plants, the ground fault current is limited to a known quantity by high or low resistance grounding, there-fore a ground fault study is usually unnecessary.

Representing Motors as an Impedance. For standard fault calculations, motors are represented by a per-unit reactance quantity, X"d, the subtransient reactance of the motor. This value can be obtained from the motor manufacturer (usually shown on the motor data sheet). The subtransient reactance may be approximated by:

(Eq. 200-2)

The subtransient reactance is given in per-unit with respect to the kVA base of the motor. Section 225 below includes an example of a short-circuit analysis using the per-unit method and also demonstrates how to convert the per-unit value to the chosen base.

Asymmetrical and Symmetrical Fault Values. Usually at the instant a system fault is initiated, the short-circuit current wave is not completely symmetrical as shown in Figure 200-4.

The first few cycles are offset from the symmetrical zero current axis by a DC component because the short-circuit impedance of the system is primarily inductive. Therefore, the current behaves in accordance with the properties of an inductor, inducing a voltage equal to:

(Eq. 200-3)

It then follows that the initial slope of the current curve must be E/L. The current cannot change instantaneously to coincide with the symmetrical steady state wave-form. The DC component of the current waveform does, however, decay over a few cycles, and the current wave changes to the symmetrical form. The time required for the DC component to decay depends on how much resistance is in the circuit. The size of the initial asymmetrical peak depends on the point on the voltage waveform



at which the short-circuit is initiated. A short-circuit initiated at a voltage zero crossing causes the maximum asymmetrical peak of current.

The asymmetry of the initial current waveform is important because the peak of the asymmetrical current can be much greater than the peak of the symmetrical current. The electrical equipment must be able to withstand the electrical and mechanical stresses associated with this increased current. Circuit breakers and fuses must have the capability to interrupt the asymmetrical current.

To account for the asymmetry of the current wave, it is standard practice to first solve for the symmetrical rms short-circuit current and then apply a multiplying factor to the result. A 1.6 multiplying factor may conservatively be applied to faults at all voltage levels. If the IEEE Red Book method is used, smaller multipliers (indi-cated in the Red Book) may be used, possibly resulting in lower calculated fault current values.

Momentary Ratings and Interrupting Ratings. The momentary rating (closing and latching rating of post-1964 circuit breakers) of medium and high voltage circuit breakers and electrical equipment is the maximum rms asymmetrical current which the equipment can withstand. It is not the value of the current which the circuit breaker interrupts.

Fig. 200-4 Asymmetrical and Symmetrical Fault Current Wave Shapes From IEEE Standard 142, 1993, Ch. 2. Used with permission.



The interrupting rating of a circuit breaker is the short-circuit current which a circuit breaker will interrupt over a range of voltages from the maximum design kV down to the minimum operating kV. It is less than or equal to the momentary rating.

Short-Circuit Impedance Networks. Different impedance diagram networks are used depending on the purpose of the short-circuit study. The three most important networks are:

• First cycle network• Interrupting case network• 30-cycle network

The difference among these networks is their representation of motor reactance.

The first cycle network is used for calculating the short-circuit current for compar-ison with the interrupting ratings of fuses (low and high voltage) and low voltage circuit breakers. These devices interrupt the short-circuit current sometime within the first cycle. Subtransient reactances are used to represent rotating machines in this network.

Most manual calculations use the first cycle network, since it is the most severe case. For additional information, see the IEEE Red Book.

The interrupting case network applies to medium and high voltage circuit breakers which interrupt the short-circuit current at the 2, 3, 5, or 8 cycle point, depending on the design of the circuit breaker. Within two to eight cycles after the initiation of the short circuit, the motor contribution has decreased. Multipliers are applied to the motor subtransient reactances to represent them as smaller contribu-tors to the fault current. Multipliers are also applied to the calculated fault duties, depending on the speed of the circuit breaker (2, 3, 5, or 8 cycle) and the proximity of the fault to generator and utility sources. As a result, the calculated rms symmet-rical short-circuit current is smaller than that of the first cycle network.

The 30-cycle network determines the short-circuit current which time delayed relays will experience after the asymmetrical component and motor contributions have died out. This network ignores the motors in the network, only considering generators and passive elements, such as transformers and cables. The calculated short-circuit current for this network is smaller than either the first cycle network or the interrupting case network.

Per-Unit Values. The per-unit (PU) system is a mathematical tool using per-unit values to simplify short-circuit calculations. A per-unit value is a ratio of a number to a base number.

(Eq. 200-4)



For example, if the base number is 225, the per-unit value of 17 is 17/225 = 0.076 per-unit on a base of 225. The per-unit value of 225 on a base of 225 is 225/225 = 1 per-unit.

Percent Values. Percent values are obtained by multiplying the per-unit value by 100.

(Eq. 200-5)

To change percent values to per-unit values, divide the percent value by 100. For example, a transformer which has an impedance of 6% has an impedance of 0.06 per-unit.

Impedance of electric equipment is usually given in percent. It is convenient to convert these figures immediately to per-unit by dividing by 100 (to avoid confu-sion).

Base Value Relations. To use the per-unit system, first select base values of voltage, current, ohms, and kVA for a given electrical system. These bases provide a reference to which resultant per-unit values can be compared.

Using the selected base values, express all parts of the electrical system in per-unit terms as follows:

(Eq. 200-6)

(Eq. 200-7)

(Eq. 200-8)

In a similar manner, the base quantities can be determined from the following basic equations:



Single-Phase System Equations

(Eq. 200-9)

(Eq. 200-10)

Note Single-phase voltages are given in line-to-neutral values.

Three-Phase System Equations

(Eq. 200-11)

(Eq. 200-12)

Note Base kVA is the three-phase kVA, and base voltage is line-to-line voltage. Base Ohms is ohms per phase.

All per-unit formulas are summarized in Figure 200-5.

Base AmpsBase kVABase kV

------------------------ Ib= =

Base OhmsBase VoltsBase Amps--------------------------- Ohmsb= =

Fig. 200-5 Per-Unit Calculation Summary Sheet for Three-Phase Systems (1 of 2)

Per-Unit Quantity =

Base kVA = Base kV × Base Amperes ×

Base Current (Amperes)

Actual QuantityBase Quantity

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

3

Base kVA 1000( )3 Base Volts( )

--------------------------------------- Base kVA3 Base kV( )

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

Base MVA 106( )3 Base Volts( )

---------------------------------------= Base MVA 1000( )3 Base kV( )

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



Selecting Base Values. At the beginning of a short-circuit study, it is necessary to select a single base kVA or MVA and base voltages for every voltage level in the system. In the example one-line diagram, Figure 200-6, the base MVA is chosen to be 100 MVA. This base MVA applies to all voltage levels in the entire system. The

Base Impedence (Ohms)

Changing Base kVA

P.U. Ohms on kVA New Base = × P.U. Ohms on kVA Old Base

Changing Base Volts

P.U. Ohms on New Base Volts = P.U. Ohms on Old Base Volts ×

Utility Impedance

1. Given Utility Short Circuit MVA: P.U. Zutil =

2. Given Utility P.U. Ohms on a Different MVA Base:

P.U. Ohms on Desired MVA Base = × P.U. Ohms on Given MVA Base

3. Given Utility Short Circuit Amperes (RMS symmetrical):

P.U. Ohms =

Transformer Impedance

P.U. Ohms =

Cable Impedance

P.U. Ohms = Actual Impedance in Ohms ×

Motors

P.U. Ohms = x"d × ; where motor kVA = F.L. Amps × Motor kV ×

Generators

P.U. Ohms = x"d ×

Note All voltages are Line-to-Line. All kVA’s are three-phase.

Fig. 200-5 Per-Unit Calculation Summary Sheet for Three-Phase Systems (2 of 2)

Base Volts3 Base Amperes( )

-----------------------------------------------= Base Volts( )2

Base kVA 1000( )---------------------------------------=

Base kV( )2 1000( )Base kVA

-------------------------------------------= Base kV( )2

Base MVA---------------------------=

kVA New BasekVA Old Base

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

Old Base Volts( )2

New Base Volts( )2----------------------------------------------

MVA BaseUtility S.C. MVA-------------------------------------

Desired MVA Basegiven MVA Base

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

Base kVA3 S.C. Amperes( ) kV Rating of System( )

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

%ZTx100

-------------- Base kVAkVA Self-Cooled( ) of Transformer--------------------------------------------------------------------------------×

Base MVA

Base kV( )2---------------------------

Base kVAMotor kVA------------------------- 3

Base kVAGenerator kVA-----------------------------------



choice is arbitrary and any value will work, although typical values are 10 MVA or 100 MVA.

The chosen base voltages are 115 kV, 13.8 kV, 4.16 kV, and 480 volts. Notice that each bus has its own base voltage, usually the nominal voltage of the system. It is important to note that the base voltages on the high and low sides of a transformer must have the same ratio as the transformer turns ratio.

Changing kVA Bases of Circuit Elements. The impedance of transformers and the reactances of motors and generators are given in percent referenced to the kVA rating or base of the device. To be used as per-unit impedances on the chosen system base, they must be converted to the new kVA base. To do this, use the following formula:

(Eq. 200-13)

Changing Voltage Bases of Circuit Elements. Sometimes a machine rated at one voltage may be used in a circuit at a different voltage. To be used as per-unit imped-ances on the chosen system base, they must be converted to the new kV base. To do this, the following formula is used:

(Eq. 200-14)

Changing Both kVA and Voltage Bases. Impedances may be changed to a new kVA base and a new kV base by combining the equations above, as follows:

(Eq. 200-15)

These equations for changes of bases are demonstrated in the example in Section 225 below. For further detailed information on the use and application of the per-unit system, see References 1, 2, and 5.

General Step-by-Step Procedure for Short-Circuit Calculations. The step-by-step procedure for short-circuit calculations is as follows:

1. Use a system one-line diagram to collect the necessary data. Include all signif-icant system components and impedances, as shown in Figure 200-6.

Identify all buses on the one-line diagram with unique numbers. It is helpful to identify all circuit components such as generators (G1, G2, G3...), transformers (T1, T2, T3...), motors (M1, M2, M3...) and cables (C1, C2, C3...).

Ohmspunew

kVAnew

kVAold--------------------- Ohmspuold

×=

Ohmspunew

kVold( )2

kVnew( )2------------------------ Ohmspuold

×=

OhmspunewOhmspuold

kVold( )2

kVnew( )2------------------------

kVAnew

kVAold---------------------××=



Fig. 200-6 Example One-Line Diagram



Figure 200-6 shows a one-line diagram with the information needed to perform a short-circuit study.

Data that needs to be gathered include the following:

– Utility short-circuit MVA (and X/R ratio if calculating per Red Book)– Cable lengths and impedances– Motor (see Figure 200-7), transformer, reactor, and generator impedances

2. Choose a base kVA or MVA, a base voltage for the system, and a base voltage for every bus throughout the system. At this point, it is useful to make a table showing base volts, amps, and ohms for each voltage level in the system. See Figure 200-8(a). The base kVA or MVA applies to all voltage levels in the system.

3. Determine the fault location for which solutions are desired. If doing a large study for a new plant, use a computer to determine the fault value of every bus in the system. A “bus” is wherever a circuit-interrupting device or switch is connected. If purchasing a new MCC, only the available fault current at that location in the system is of interest.

4. Collect and convert impedance data. In this step, the impedances of all significant circuit elements are collected and converted to per-unit impedances at the proper base voltages and system base kVA chosen in Step 2.

5. Prepare an impedance diagram. The diagram should show the per-unit impedance of every component in the system. See Figure 200-8(b).

Fig. 200-7 Typical kVA to HP Ratios and Subtransient Reactances for Motors

Induction Motor 1 HP = 1 kVA

Synchronous Motor, .8 PF 1 HP = 1 kVA

Synchronous Motor, 1.0 PF 1 HP = .8 kVA

Induction Motors

Above 1000 HP at 1800 RPM or less Xd"= .17

Above 250 HP at 3600 RPM Xd" = .17

All others, 50 HP and above Xd" = .20

Lumped motors, below 50 HP Xd" = .28

Synchronous Motors

1200 RPM and greater Xd" = .15

514 RPM through 900 RPM Xd" = .20

450 RPM and less Xd" = .28

Note All per-unit values have the kVA rating of the motor as the base kVA. These must be converted if a different kVA base is being used in the system study.



6. Combine impedances until there is a single resultant impedance between the infinite bus and the fault. See Figures 200-9 through 200-13.

7. Calculate the short-circuit current using:

(Eq. 200-16)

Then, multiply the per-unit amperes by the base current at the voltage level of the fault location to obtain the symmetrical fault current in amperes.

Iscpu

Epu

Zpu---------=



8. Apply the appropriate multiplying factors to obtain the asymmetrical or total current value of the short circuit.

Fig. 200-8 Preparing an Impedance Diagram for Short-Circuit Calculations

8(a) Determining the Base Quantities for the Impedance Diagram Example

8(b) Impedance Diagram Example Using Per-unit Impedance



225 Short-Circuit Analysis: Example Using the Per-Unit MethodThe following example presents a short-circuit calculation to determine the three-phase bolted fault current at the location in the electrical system where a new 480-volt transformer and substation are to be added. This calculation is made to deter-mine the required interrupting rating of the transformer’s secondary main breaker and the low voltage circuit breakers in the motor control center. The example also estimates the asymmetrical or total fault current for comparison with devices rated in total or asymmetrical current values. Figure 200-6 is the one-line diagram for this example.

This example illustrates the basic mechanics of the per-unit method of calculating faults. Resistances are ignored, resulting in a very conservative solution. The reac-tances associated with the motors are subtransient reactances with no multipliers, resulting in a conservative first cycle rms symmetrical fault calculation. For inter-rupting case fault calculations subtransient reactances, refer to Tables 24 and 25 of IEEE 14.

To determine the asymmetrical value of the fault current, a multiplier of 1.6 is applied to the rms symmetrical fault current, resulting in a conservative solution when the X/R ratio is not considered. The differences between the per-unit method of this example and the Red Book method are also discussed.

Step 1. Prepare a System One-Line Diagram

The example one-line diagram is shown in Figure 200-6. It contains all transformer sizes (based on self-cooled ratings) and percent impedances, all induction and synchronous motor sizes, subtransient reactances, and power factors for the synchronous motors. Also shown are the cables of significant length (to introduce additional reactance into the calculation). The maximum available fault (MVA) from the utility is given. Notice that all buses, transformers, cables, and motors are given a unique identifier (such as B1, TX1, C1 and M1).

Step 2. Choose the Base MVA and Base Voltages

100 MVA is chosen for the base. The base voltages are chosen to be consistent with the nominal voltages of the system: 115 kV, 13.8 kV, 4.16 kV, and 480 volts.

At this point, the impedance diagram is drawn (Figure 200-8(b)) showing the base volts, base amperes, and base ohms for each voltage level in the system. Notice that the 100 MVA base applies to all levels of voltage in the system. This kind of diagram is useful to change back and forth between base values in per-unit, and actual values, such as ohms and amperes. The method used to calculate the base values for the 115 kV level in the diagram is shown in Figure 200-8(a).

Step 3. Decide on the Fault Location

In this example, a new transformer, TX4, and 480-volt motor control center are to be added to an existing system. It is necessary to calculate the maximum fault at the motor control center to determine the required interrupting rating of the transformer secondary main breaker and MCC breakers, and the fault withstand capability of the



480-volt MCC bus and mechanical components. The fault location is designated F1 in Figure 200-6 and is indicated in each of the impedance diagrams that follow.

Step 4. Convert and Collect Impedance Data

The impedance data are shown on the example one-line diagram, Figure 200-6. The formulas used to convert the data are summarized in Figure 200-5. The data are converted to per-unit values of reactance on a 100 MVA base. ZTX ≈XTX indicates that resistance is not being considered. The per-unit reactance calculated is approxi-mately equal to the complex impedance in magnitude because resistance is usually small compared to the reactance in medium voltage systems. Common practice in medium voltage systems is to consider reactance only, which results in a higher calculated fault value than if both resistance and reactance are considered.

The per-unit values of all electrical components on the one-line diagram are calcu-lated by applying the formulas from the calculation summary sheet, Figure 200-5.

Utility Impedance

(Eq. 200-17)

Transformer Impedances

(Eq. 200-18)

(Eq. 200-19)

(Eq. 200-20)



Cable ImpedanceThe cable used is 500 MCM copper cable with two cables per phase in magnetic conduits. Each cable is 1500 feet long and the voltage level is 13.8 kV. To obtain the impedance, see Reference 2. Commonly, the resistances and reactances of cables are used (See Tables N1.3 and N1.7 in Reference 1). These must be converted to per-unit by dividing by base ohms. For this example, the reactance is 0.02% per 1000 feet on a 1000 kVA base. For 1500 feet of cable the impedance is:

(Eq. 200-21)

To change 0.03% to a per-unit value, divide by 100. The result is 0.0003 per-unit on a 1000 kVA base.

Next, convert the per-unit value from a 1000 kVA base to a 100 MVA base. This is calculated by using the change of base kVA formula in Figure 200-5. (Note: 1000 kVA = 1 MVA)

This is the per-unit impedance of one of the cables, but there are two per phase, so divide the value by two to obtain:

ZC1 ≈ XC1 = 0.015pu

Motor ImpedancesThe basic formula used for motor impedance is:

(Eq. 200-22)

M1 and M2 are both 3000 hp induction motors. If the actual subtransient reactance is available from the manufacturer, use that value to calculate the per-unit imped-ance. However, if it is not available the data in Figure 200-7 show that for induction motors, 1 hp = 1 kVA, and that the subtransient reactance of this size of motor is 0.17 per unit on its own kVA base.

Because this motor is 3000 hp, its own kVA base would be 3000 kVA. To convert this per-unit value to a 100 MVA base use the change of base kVA formula given in Figure 200-5:

ZMotor XMotor≈ x″dkVAb

Motor kVA----------------------------×=



(Eq. 200-23)

M3 and M4 are synchronous motors with 0.8 power factor (pf). The data in Figure 200-7 show that, for synchronous motors with 0.8 pf, 1 hp = 1 kVA, and that the typical subtransient reactance is 0.20 per unit on the motor’s kVA base. The change-of-base calculations for M3 and M4 are similar to those for M1:

(Eq. 200-24)

(Eq. 200-25)

To handle the motors on the 480-volt motor control center bus (M5, M6, M7, M8, and M9) in this example, all motors on the bus have been lumped as one large motor with a subtransient reactance of 0.25 per unit on its own kVA base. Normally, the motors would be individually represented with the reactances listed in Figure 200-7. The data in Figure 200-7 indicates that 1 hp = 1 kVA. The total hp of the lumped motors is 450 hp, so the total kVA is 450. Using the 0.25 per-unit figure on the 450 kVA base and converting it to the 100 MVA base:

(Eq. 200-26)

Step 5. Prepare the Impedance Diagram

The per-unit values calculated for the electrical components above are now shown in the impedance diagram of Figure 200-8(b). Notice that the per-unit impedances of the motors are connected between the infinite bus (so-called because it has zero impedance) and the motor supply bus. The motors are acting as induction genera-tors and contribute to the short circuit as discussed in Section 224.

Step 6. Combine Impedances in the Impedance Diagram

The next task is to simplify the impedance network until a single resultant imped-ance remains between the infinite bus and the chosen fault location. This is accom-plished by combining reactance values following the same rules as combining resistors in series and parallel.



(Eq. 200-27)

The various intermediate impedance diagrams between the initial and the final are shown in Figures 200-9 through 200-13.

Fig. 200-9 Impedance Diagram Reduction (Step 1)









Step 7. Calculate the Fault Current

Calculate the available fault current using:

(Eq. 200-28)

The final resultant per-unit impedance between the infinite bus and the fault loca-tion is the value to use for Z. In this example, it is 7.303 per unit on a 100 MVA base.

To arrive at the symmetrical per-unit fault current, solve the following equation.

(Eq. 200-29)

The 1 in the numerator is the one, per-unit, driving voltage in the line-to-neutral model. The driving voltage represents the prefault voltage. Since the prefault voltage is the base voltage at the fault location, it is 1.0 in per unit volts. To convert the 0.137 per unit amperes to actual amperes, refer to Figure 200-8(a). This table shows that the base amperes at the level of the fault location is 120,281 amperes.

To calculate the actual short-circuit current, multiply the per-unit amperes by the base amperes as follows:

SCA (rms symmetrical) = 0.137 x 120,281 = 16,478 amperes(Eq. 200-30)

This value can now be compared directly to the interrupting rating of the proposed secondary main circuit breaker of TX4. The interrupting rating of this circuit breaker and all circuit breakers in the 480-volt MCC fed by this breaker should be at least 16,478 amperes. It is common practice to specify breakers with interrupting ratings which exceed the calculated maximum fault by 15-to-20% or more, to allow for future system short-circuit growth.

Step 8. Obtain the Asymmetrical or Total Current Value of the Short-Circuit Current

When calculating the short-circuit current using a reactance network without considering resistance, it is conservative to use a multiplying factor of 1.6 applied to the rms symmetrical short-circuit current to determine the asymmetrical short-circuit current. This current is sometimes referred to as total current.

The total current may be used for comparison with electrical components which have ratings related to total rms current or asymmetrical current, such as current limiting fuse curves which show peak let-through, depending on the available asym-



metrical fault current. Although low voltage circuit breakers must withstand the asymmetrical current also, they are rated in symmetrical rms current interrupting values which have already considered the asymmetrical components up to certain limits. For a more detailed consideration of this topic see ANSI C37.13.

226 Comments on the Short-Circuit Calculation ExampleThe preceding example demonstrates a conservative, basic method for determining the short-circuit current typical of medium voltage systems when resistance is not a significant factor. In lower voltage systems with long cable runs, resistance has an increasing effect on reducing the short-circuit currents. If resistance is ignored in those situations, an overly conservative solution may be reached.

For more detailed calculations, see the IEEE Red Book for calculation methods. The Red Book uses the same basic method demonstrated here with the following refine-ments:

1. The Red Book calculates three different solutions based on three different networks, depending on how the short-circuit calculations will be applied. It has one method for high voltage circuit breakers, another for low voltage circuit breakers and fuses, and another for time-delayed relay devices.

2. The Red Book includes the resistance value of each component for the high voltage circuit breaker interrupting rating study and solves two networks to the point of fault, an X network and an R network. When the two networks are solved, an X/R ratio is established at the point of fault and used to select tabu-lated multiplying factors which are applied to E/X values to establish total rms current interrupting duties.

3. Depending on the network being calculated, the Red Book prescribes addi-tional multipliers to be applied to the subtransient reactances based on motor type.

4. The Red Book refers to the appropriate ANSI standard for the multiplier to obtain the asymmetrical, or total, rms current.

The net effect of the differences between the method employed in this example and the method of the Red Book, is that the Red Book method gives (yields) a lower calculated fault current. The ratings of circuit breakers are based on the Red Book method, which is recommended for detailed calculations.

227 Computer Methods for Calculating Short-Circuit CurrentAn example of a computer calculation of a more complex system than the example above is shown in Figure 200-14. The program employed is the GE computer program SHCKT$ used for calculating three-phase short-circuit currents.

The nodal diagram used with this program is shown in Figure 200-15. All buses are numbered, and the bus numbers appear in the input and output summaries of the computer program.



Fig. 200-14 G.E. Three-Phase Short-Circuit Program (1 of 2) (Courtesy of the General Electric Company)

CASE: 1-FCY Page- 1 - EPSCAC

GENERAL ELECTRIC CO. — INDUSTRIAL POWER SYSTEMSTHREE PHASE SHORT CIRCUIT PROGRAM

FIRST CYCLE CALC. FOR BREAKER DUTIES PER ANSI C37.13-198105/29/85 100 MVA BASE 60 HERTZ

10700 LINE WITH C-A TIE CLOSED- C-2 OPEN

CASE: 1-FCYNORMAL PLUS C-A CLOSED AND C-2 OPENC-1 OPEN A-1 CLOSEDINPUT DATA

BUS TO BUS R P.U. X P.U. COD

0 SWG1070 .11129 .49526 1

1 1L .66296 3.92082 0

2 2L 2.44082 10.41311 0

3 3L 2.91850 9.86118 0

4 4L 1.10471 5.86152 0

6 6L 2.03245 8.67092 0

7 7L 2.44082 10.41311 0

8 8L 5.53145 16.22288 0

8A 8AL 2.19204 9.35177 0

15A 15AL 1.59992 8.48910 0

15B 15BL 1.58087 8.38804 0

16A 16AL 1.53214 7.46832 0

20 20L .64238 3.79914 0

21 21L .47226 2.99679 0

17 17L 5.53145 16.22288 0

18 18L 1.50204 6.40807 0

10 10L 4.97831 14.60060 0

26 26L 1.50204 6.40807 0

22 22L 5.53145 16.22288 0

12 12L 5.53145 16.22288 0

9 9L 1.49907 7.30714 0

27 27L 3.54013 10.38265 0

28 28L 1.44251 7.03141 0

5 5L 1.52379 6.91756 0

13 13L 2.37090 10.11484 0

19 19L 1.46528 7.14243 0

C3 C4 .01718 .01215 0

C4 C5 .04349 .03075 0

C11 27 .90148 .17398 0



C11 19 .59196 .11424 0

SWG1070 A1 .02269 .02769 0

A1 A2 .01641 .02074 0

A2 A3 .03087 .03901 0

SWG1070 B1 .01679 .01697 0

B1 B2 .01281 .01618 0

*BUS 3 E/Ze = 9.196 KA (226/17MVA) AT’74.31DEG.,X/R= 3.56, 14.200 KV

Ze = .119557 +j .425678

1.6*ISYM = 14.71 IASYM BASED ON X/R= 10.65

CONTRIBUTIONS IN KA

BUS TO BUS MAG ANG BUS TO BUS MAG ANG

3L 3 .028 76.844 A1 3 9.168 74.303

*BUS A1 E/Ze= 8.190 KA( 201.44MVA) AT77.02DEG.,X/R= 4.34, 14.200 KV

Ze= .111536 +j .483743

CIRCUIT BREAKER TYPE 8TOT,SYM 5SYM 5TOT 3SYM

MAX DUTY LEVEL 8.19 8.19 8.19 8.19

MULT. FACTOR 1.000 1.000 1.000 1.000

CONTRIBUTIONS IN KA

BUS TO BUS MAG ANG BUS TO BUS MAG ANG

SWG1070 A1 7.649 75.721 A2 A1 .506 84.642

3 A1 .004 79.513

Fig. 200-15 Nodal Diagram for Short Circuit Study (Courtesy of the General Electric Company)

Fig. 200-14 G.E. Three-Phase Short-Circuit Program (2 of 2) (Courtesy of the General Electric Company)



The model used in the computer run of Figure 200-14 simulated faults at over 70 different locations shown in the nodal diagram. An advantage of the computer solu-tion over the manual solution is that it gives the currents in the branches feeding the fault bus, not just the total fault current. Only part of the input and output for the program is presented.

Two different cases were run for each location. The first case is the first cycle case, similar to the example presented above. First cycle (momentary), short-circuit currents are used to compare equipment mechanical strength requirements, closing and latching requirements for medium and high voltage circuit breakers, and inter-rupting duty for fuses and low voltage circuit breakers.

The second case calculated the interrupting rating requirements for medium voltage circuit breakers.

The first cycle case shows the input data, consisting of the resistance and reactance in per-unit values on a 100 MVA base for every branch between nodes.

Also shown for the first-cycle cases, are examples of the output produced by the computer. For Bus 3, the rms symmetrical fault current E/Z is 9.196 kA. The current at the faulted bus lags the infinite bus voltage by 74.31 degrees. The X/R ratio of the fault location is 3.56. The base voltage of Bus 3 is 14.2 kV. The equivalent imped-ance from the infinite bus to the fault point is 0.11957 + j0.425678 per-unit. The total asymmetrical current using the 1.6 multiplier is 14.71 kA. Using the actual X/R ratio of 3.56 to determine the asymmetrical multiplier from tables within the computer produces a total asymmetrical current of 10.65 kA by this method. This value, 10.65 kA, is considerably less than the value obtained by using 1.6 as a stan-dard multiplier (as in the example).

Following the fault current summary, the study shows fault current contributions from other buses.

Also calculated is the interrupting case. Next to Bus A1, E/Ze (the symmetrical fault current) is 8.190 kA. The same information discussed in the first cycle case is also provided. Following that are the fault levels to be compared to medium and high voltage circuit breakers with 8, 5, or 3 cycle interrupting times, depending on whether or not they are rated in total current or symmetrical current. The multiplier is determined by internal tables and relates to the X/R ratio. The multiplier times the symmetrical fault current gives the maximum duty level.

228 Electrical Systems Analysis Computer ProgramsThe following programs have been used successfully by the Company and are recommended for analysis of electrical systems.

1. Electrical Transient Analyzer Program (ETAP) is the most usuable set of PC-based programs to analyze electrical systems. ETAP is available from:

Operation Technology, Inc.17870 Skypark Circle, Suite 102



Irvine, CA 92714(714) 476-8814

This set of programs includes loadflow, short circuit, motor starting, simple dynamic stability, cable ampacity derating, and cable pulling programs. The cost of this set of programs is approximately $7,500.

2. The General Electric computer program SHCKT$ used in the short-circuit example presented above is available on disk from:

General Electric CompanyIndustrial Power Systems Engineering1 River Road, Building 6, Third FloorSchenectady, NY 12345(518) 385-4500

This program, available on a timeshare basis, also contains a motor-starting program, a load-flow program, and a data-reduction program (in addition to the short-circuit program).

3. Another IBM PC-based program is the ESAPP Program available from:Electrical Systems Analysis, Inc.16545 S. Archer DriveOregon City, OR 97045(503) 655-3615

The ESAPP program performs short-circuit analysis. The output has current values in phase and symmetrical component format.

4. Westinghouse has a group of programs known as Westcat. They are available on a time share basis from:

Westinghouse Electric CorporationAdvanced Systems Technology777 Penn Center BoulevardPittsburgh, Pennsylvania 15235(412) 824-9100

The Westcat program can perform short-circuit analysis, load-flow, dynamic stability, and impedance calculations. Westinghouse also has harmonic-analysis, data-reduction, and device-analysis programs.

230 Motor-Starting Studies

231 ScopeA complete motor-starting study consists of two parts: a voltage-drop calculation and an acceleration-time calculation.



232 Reasons for a Motor-Starting StudyMotor-starting studies should be done in preliminary form as early as possible in a project. If the calculations are completed before the motor is specified, the torque vs. speed and starting current limitations on the motor can be calculated. Early studies make use of typical torque vs. speed characteristics and starting current values of motors similar to the one to be purchased. When the bids are received, enough information should be available to determine if the motor will meet the system requirements.

233 When To Conduct a Motor-Starting StudyA motor-starting study is not always necessary. If a 30-hp motor-driven centrifugal pump is being added to a motor control center that already supplies a 50-hp motor and centrifugal pump which starts and runs without problems, it is safe to assume that a 30-hp motor will start more easily than the 50-hp motor and that a study is not necessary.

Several reasons for conducting a motor-starting study are:

• Transformer kVA is less than three times the motor kVA

• Cable between transformer and motor reduces available short-circuit kVA at the motor to less than eight times motor- starting kVA

• Ratio of bus short-circuit kVA to motor-starting kVA is 8 or less

• Load has high inertia

• Utility restricts utility-line voltage drop

These are general guidelines only. Special conditions, such as starting a motor under load where high starting torque is needed would require a motor-starting study even if none of the above criteria were met.

If, for example, a 200-hp motor that will drive a reciprocating pump or a compressor is being added, and it is powered from a 500 kVA transformer with a 6% transformer impedance and long cables between the motor control center and the motor, it will be necessary to conduct a motor-starting voltage drop study (and possibly an accelerating time study). The reason that a study is required is that the transformer kVA is not much larger than the motor kVA, so there may be excessive voltage drop through the transformer, causing low voltage at the motor terminals. Another reason for conducting a motor-starting study is that a reciprocating compressor or pump has a higher breakaway torque (the amount of torque required to initially move the crank shaft) than for a centrifugal pump. Motor-starting torque is proportional to the square of the voltage. If the voltage dips to 80% of normal, the motor will deliver only 64% of its normal starting torque, which may not be enough to drive the pump. The long cable length feeding the motor further decreases the voltage at the motor terminals.

If the system has 500 hp or larger medium voltage motors, a motor-starting calcula-tion is almost always recommended.



234 Voltage-Drop CalculationsWhen a motor is first started, it performs in a similar manner to a transformer with its secondary shorted and draws line current four to six times its normal full load current. As this current flows to the motor terminals from the power source through power lines, transformers, and other impedances in the system, various voltage drops occur. When all these voltage drops are accounted for, the voltage at the motor terminals can be significantly less than 100% of the bus voltage feeding the motor.

This voltage reduction during motor starting occurs to some extent at every point in the electrical system. If the voltage drop is too large at any of these points, it can cause problems throughout the system. Lights may flicker, dim, or even extinguish momentarily during motor starting. Many utilities limit the size and current inrush of motors to prevent voltage drops of more than 5% at the utility. Some utilities require less than a 2% drop on their lines.

If the voltage drop exceeds 15 to 20%, control relays may drop out causing shut-downs or erratic operation of systems and computers. In some instances, the voltage drop during starting maybe so severe that the motor will not start at all. It will just hum, drawing locked rotor current at the reduced voltage until its breaker or starter trips on overload.

The largest voltage drop occurs at the motor terminals, and should be designed to be less than 15%. In extreme cases where weak power systems are involved, 20% or more may be allowable.

235 Data for a Voltage-Drop CalculationThe following data are needed to perform a complete motor voltage-drop calcula-tion.

1. Motor nameplate information

a. Voltage

b. Full-load current

c. Horsepower

d. rpm at full load

e. Locked-rotor current or locked-rotor kVA

2. Starting power factor (or an approximation)

3. System impedance data (including the utility)

4. Running load on system at time of starting (and approximate power factor if more accuracy is desired).



236 Voltage-Drop Calculation: Example

Circuit Model. The motor-starting voltage-drop calculation normally utilizes the per-unit method, as does the short-circuit study. For more information on the per-unit method, see Section 220, “Short-Circuit Studies,” and References 2 and 5.

For a motor-starting voltage-drop study, it is necessary to use the minimum avail-able short-circuit MVA available from the utility, as this will produce the most severe voltage drop calculation (the conservative case).

The location of the motor impedance in the line-to-neutral circuit model for the motor-starting study is different from the location of the motor impedance in the model for the short-circuit calculation. Figure 200-16 presents an example of a one-line diagram for a sample voltage-drop calculation. Figure 200-17 shows the line-to-neutral model used for a short-circuit calculation at point A. In the short-circuit case, the motor is a current source that contributes to the fault and is modeled as an impedance in parallel with the series combination of the utility and the transformer impedances.

In the motor-starting example, shown in Figure 200-18, the motor is not a source of current as in the short-circuit example, so its impedance is in series with the utility, transformer, and cable impedances. As shown in Figure 200-18, the voltage drop at the utility can be calculated directly by voltage division as a ratio of the utility impedance to the total impedance in the circuit. Similarly, the terminal voltage at the motor can be calculated as a ratio of the motor-starting impedance to the total impedance of the circuit. Use the per-unit system to calculate the voltage drop.

How to Represent the Starting Motor as an Impedance. To model the starting motor as an impedance, find the starting kVA of the motor. Smaller motors will have a locked-rotor code on their nameplate as (described in NEC 430-7). This code gives the locked-rotor kVA per horsepower range. Multiply the horsepower by the locked-rotor code value to obtain the locked-rotor (starting) kVA. Use the maximum kVA per horsepower in the range for the particular locked-rotor code, to be conser-vative. To change the locked-rotor kVA to MVA, divide by 1000.

Suppliers of larger motors will give the maximum locked-rotor current, ILR, at the rated motor voltage. To calculate the locked-rotor MVA in this case, use the following formula:

(Eq. 200-31)

It is important to use the motor nameplate voltage for Vmotor. For example, the nameplate voltage of the motor in Figure 200-16 is 2.3 kV, although the bus voltage is 2.4 kV.



Fig. 200-16 Example of a One-Line Diagram for Motor Starting



Fig. 200-17 Short Circuit Model for Fault Current at Point A

Fig. 200-18 Circuit Model for Motor Starting Voltage Drop at Point A



Once the locked-rotor kVA is calculated, it must be changed to a per-unit imped-ance value at the same base voltage as that of the system impedance diagram. This is calculated by the following formula:

(Eq. 200-32)

This equation calculates the impedance (Z) of the motor. For approximate calcula-tions in medium voltage systems, impedance can be considered to be all reactance (X), ignoring resistance, as shown in the example in Figure 200-19. In this case the impedance is assumed equal to the reactance.

Example of Motor-Starting Voltage-Drop Calculation Using the Per-Unit MethodCalculate the utility voltage drop during starting and the terminal voltage of the motor as shown in Figure 200-16, using the per-unit method described in Section 220. Approximate motor-starting studies can be done using the MVA method. Although this method is simpler, it is not as versatile. The MVA method is described in Appendix C.

After assembling the required data and one-line diagram, complete the following tasks:

1. Make an impedance diagram.

2. Calculate component impedances on a common MVA base.

3. Choose the base voltage of the system.

4. Calculate voltage drop.

For the example, the following steps were completed in accordance:

1. An impedance diagram was drawn (Figure 200-19).

2. Impedances were calculated on a 100 MVA base.

3. 13.8 kV and 2.4 kV were chosen as base voltages.

4. The voltage drop was calculated as 73% full voltage at the motor terminals upon starting.

In this example, system resistance was ignored since it is a medium voltage system and the reactive component of impedance has the largest effect. Cable impedance is also ignored in this example; however, it should be included in low voltage motor-starting cases and medium voltage cases with long cable runs. The calculation summary in Section 220 (Figure 200-5) shows how to derive the cable impedance (which could be included in the motor-starting impedance diagram).



Fig. 200-19 Motor Starting Voltage Drop Impedance Diagram



In this example, the voltage at the instant the motor starts is 73% of the 2.4 kV bus voltage. This is equal to 76% of the motor nameplate voltage (2.3 kV). A 76% starting voltage (24% voltage drop) is a very marginal voltage for starting the motor and is the value used to adjust the motor torque vs. the speed curve. It may be allow-able if further investigation shows there is enough torque to start the load, and if it will not cause control problems at the motor bus (or elsewhere in the system); for example, causing the relays to dropout. The torque vs. voltage relationship is discussed below in Section 238.

The voltage drop on the 13.8 kV utility bus was found to be 1.5%. This means that if the utility voltage at the time the motor was started was 13.8 kV, the voltage would drop to 13.6 kV as the motor accelerated. When the motor reaches rated speed, the current drops to the normal loaded value, and the voltage drops throughout the system return to normal.

Effect of Running LoadThe running load at the time of starting a motor can make the voltage drop more severe because the voltage may be initially something less than 1 per unit. For example, if there were a large running load on the 2.4 kV bus in Figure 200-16, the voltage prior to starting the 1500 hp motor would be something less than 2.4 kV (due to the running load voltage drop).

An approximate means of accounting for the voltage drop due to running load is to model the running loads as a lumped impedance on the bus. For example, if there is a 500 hp combined load already running on the 2.4 kV bus (Figure 200-16), this could be modeled as 500 kVA. This 500 kVA can be represented conservatively by an impedance using the following formula:

(Eq. 200-33)

The impedance representing the running load is located in the impedance diagram as shown in Figure 200-20.

The effect of running load can sometimes make the voltage drops throughout the electrical system, and at the motor terminals, a few percentage points higher than if it were not considered. For this reason if the initial calculation without considering running load indicates a marginal voltage drop, then the effect of running load should be calculated. Computer programs that calculate motor-starting voltages can easily calculate the actual effects of running load.

Including Resistance in the Motor-Starting Circuit ModelThe resistive component of impedance becomes important in low voltage motor-starting calculations where a significant portion of the voltage drop is due to resis-tance. In medium voltage motor-starting calculations, knowing the effect of resis-



tance produces a slightly more accurate solution; however, this makes manual calculations more time consuming, particularly if running load is also considered as a complex impedance. If high accuracy is required because the predicted voltage drop by manual calculation is marginally acceptable, use a computer program such as the one described in Section 239.

A further refinement of the motor-starting impedance diagram includes the resistive component of the utility, transformer, cable, running load, and starting motor imped-ances.

• Utility

Including the resistance of the utility in the impedance diagram is illustrated in Figure 200-21. The utility is resolved into a complex per-unit impedance, R +

Fig. 200-20 Running Load Impedance



jX. It is necessary, however, to know the short-circuit MVA and the X/R ratio of the utility source.

• Transformer

Transformer impedance can be resolved into R and X components by using typical X/R ratios for transformers from the IEEE Red Book if the impedance and kVA of the transformer are known. These data may also be obtained from transformer test data.

• Motor Impedance

The motor impedance (from Equation 200-2) may be resolved into R and X components if the starting power factor is known. On large motors, the manu-facturer can provide the starting power factor. If it is not available, it can be assumed that starting power factor is 0.2, a reasonable approximation.

If the 1500 hp motor depicted in Figure 200-16 (with an impedance of 12.462 per-unit ohms) has a starting power factor of 0.2, then its impedance can be resolved into R and X components as shown in Figure 200-21.

237 Correcting for Unacceptable Voltage DropIf the starting voltage drop calculation predicts that a motor will produce too large a voltage drop for the system, several options for correcting the problem are available.

1. Specify a motor with a smaller starting current to limit the voltage drop. See Section 200 of the Driver Manual for further discussion.

2. Use a reduced voltage starter to start the motor. Reducing the voltage at the time of starting will reduce the motor-starting current and associated utility or plant voltage drop. However, it will also reduce the available starting torque by the square of the ratio of the reduced voltage to the motor voltage. This method can be used only when there is net accelerating torque to sacrifice, which should be verified before specifying reduced voltage starting. See Section 440, “Starting Methods for Motors,” for specific methods of reduced voltage starting.

3. Find a power supply source with a larger available short-circuit MVA to start the motor. Such a power source has less impedance and will allow larger starting currents to flow without as great a voltage drop on the utility.

4. Consider feeding the motor from a larger transformer. This alternative will cause the voltage drop across the transformer to be smaller, allowing a larger starting voltage at the motor.

5. Install a capacitor bank connected to the motor-starting bus during motor starting to cancel out the reactive current drawn by the motor during starting. This arrangement will reduce the starting current and the associated voltage drop. References 5 and 7 give examples of this application.



Fig. 200-21 Resistance in the Motor Starting Model



6. Use an adjustable speed drive unit as a soft-starter for the motor. The use of a drive on a motor can almost eliminate the starting inrush current; however, this is a very expensive alternative if the adjustable speed feature is not needed.

238 Motor Acceleration Time CalculationThe following information is necessary to make a time calculation for net starting torque and acceleration. Most of this information is available from the manufacturer.

• WK2 (moment of inertia) of the motor rotor

• WK2 of the driven equipment, referenced to the same rpm as the motor rotor

• Torque vs. speed curve of the motor for 100% of motor nameplate voltage, and another curve for the percent of rated motor terminal voltage predicted in the starting voltage drop calculation

• Torque vs. speed curve of the driven equipment (may use assumed curves for noncritical installations)

• Instantaneous voltage drop at the motor terminals from the motor-starting voltage-drop study

• Speed of the motor at full load, and speed of the driven equipment if it is gearbox-connected to the motor

• Current vs. speed curve for the motor at full voltage

• Power factor vs. speed curve for the motor

Basic Mechanical RelationshipsThe acceleration time of a motor is governed by the torque developed by the motor, by the counter-torque developed by the driven equipment, by the moment of inertia (WK2) of the motor and driven equipment, and by the operating speed.

Torque, horsepower, and speed (rpm) are related by the following formula:

(Eq. 200-34)

where:Torque = tangential effort in ft-lb

hp = horsepower developed

rpm = revolutions per minute

The full load torque of the 1500 hp, 1780 rpm motor depicted in Figure 200-16 is:



(Eq. 200-35)

The term “full load torque” is defined as the torque associated with the horsepower rating of the motor at operating speed.

The acceleration time of the motor and driven load are governed by the following relationship:

(Eq. 200-36)

where:t = Time, in seconds

WK2 = Total moment of inertia of motor and driven equipment, in lb-ft2

rpm Change = Increment of speed change, in rpm.

T = Net accelerating torque, in ft-lb

To use this equation to predict the acceleration time, a torque vs. speed curve for the motor and the driven load is needed (usually available from the manufacturer).

Torque vs. Speed Curve of Motor and Driven LoadFigure 200-22 is an example of a combination torque vs. speed curve for a 3500 hp, 1800 rpm induction motor and the pump it drives. This information was supplied by the motor vendor, who obtained the torque vs. speed data for the pump from the pump manufacturer.

As indicated on the motor torque vs. speed curve in Figure 200-22, the motor produces 84% of its full-load torque on starting (Point A). This value is known as starting torque or locked-rotor torque. As the motor accelerates the load, the motor torque at first slowly increases, then rapidly increases until it peaks at 95% speed. Motor torque then drops rapidly until the operating speed is reached (in this case 1780 rpm). The motor rated speed of 1800 rpm is not reached, even at no load condition, because motor torque is not developed at synchronous speed. At 1800 rpm, there is no relative motion between the induction motor rotor and the rotating magnetic field to induce rotor current which is required to produce torque.

Discharge Valve on Centrifugal Pump. For centrifugal pump, speed-torque curves, be aware of the difference between the curves with the discharge valve open and those with the valve closed. When the discharge valve is closed, less torque is required at a given rpm. Check the position of the discharge valve, open or closed, when the pump is to be started and use the appropriate curve. To be safe, use the worst case scenario. Figure 200-23 shows the difference between the two cases.



Motor Operating Speed. The speed at which the system will operate is determined by the intersection of the motor torque vs. speed curve with the load torque vs. speed curve. In Figure 200-22, the intersection is at point “C,” 1780 rpm.

Net Accelerating Torque. If a motor is to accelerate to operating speed, the torque supplied by the motor must exceed the torque required by the load at every speed except at the operating point (where they are equal). The margin by which the motor torque exceeds the load torque (at any speed from standstill to the operating point) is known as net accelerating torque. The net accelerating torque at 50% of synchro-nous speed (as shown in Figure 200-22) is about 70% of motor full-load torque (0.70 x 10323 ft-lbs = 7226 ft-lbs). The bold arrow shows where the measurement is

Fig. 200-22 Induction Motor Starting Characteristics (Calculated) at 100% Line Voltage



taken at 50% speed. The net accelerating torque on starting is 84% - 14% = 70%. At other points on the curve, the net accelerating torque changes with speed can be determined.

Effect of Reduced Voltage. The net accelerating torque changes drastically with the terminal voltage of the motor since the motor torque is proportional to the square of the motor terminal voltage. If the voltage drops to 85% of rated voltage when the motor starts, the torque available on starting will be only (0.85)2 or 72% of the starting torque at full voltage.

Figure 200-22 is the speed torque curve for a 3500 hp motor at 100% of rated voltage during starting. Figure 200-24 presents the same information except at 85% of rated motor voltage during starting. By comparing motor torques at similar speeds for the two curves, it can be seen that if the voltage drops to 85% during starting, the motor torque for all speeds is shifted down to 72%. If only the curve at 100% of rated motor voltage is available and an adjusted curve based on the motor-

Fig. 200-23 Compared Effects of Open and Closed Pump Discharge Torque



starting voltage drop is required, the square relationship between terminal voltage and torque can be used as a good approximation to shift the motor torque curve.

Current vs. Speed Curve for a Starting MotorFigure 200-24 demonstrates that the starting current of the motor decreases slowly until about 85% speed is reached, then it decreases rapidly. As the starting current decreases while the motor is turning, the voltage drop becomes less severe; there-fore, there is higher motor terminal voltage as speed increases. This increase in voltage causes the motor torque to be higher than if the same reduced voltage encountered at initial starting is maintained until the motor reaches operating speed. For this reason, it is conservative to shift the 100% motor torque vs. speed curve by

Fig. 200-24 Induction Motor Starting Characteristics (Calculated) at 85% Line Voltage



the square of the voltage, as described above, at all speeds. In reality, the same voltage drop will not be present at all speeds.

Power Factor vs. Speed Curve for a Starting MotorFigure 200-22 also shows the power factor vs. speed curve for a starting motor. Notice that the first value for the curve is about 0.21 and the slope does not rise appreciably until the motor attains about 80% of speed. The slope of the curve then increases rapidly with speed and reaches a final value of about 0.92 at running speed. The fact that motors start with a low power factor contributes to large starting currents. One way to reduce these large starting currents is to add correction capaci-tors that switch into the circuit during motor starting. This arrangement improves the starting power factor of motors and results in greatly decreased starting currents. Once the motor reaches operating speed, the capacitors usually can be switched out of the circuit since most motors have reasonable power factors at running speed.

Example of a Motor Acceleration Time CalculationFor this example, the motor shown in Figure 200-16 will be used. This motor has a full load torque of 4424 ft-lbs at 100% terminal voltage of 2300 volts.

Steps to calculate total acceleration time are:

1. Calculate WK2 (moment of inertia) of motor, gearbox, and pump.

2. Verify that there is a net positive accelerating torque at all times (from the motor and pump torque vs. speed curves).

3. Divide the motor and pump torque vs. speed curves into an equal number of increments.

4. Calculate the time for the motor to accelerate through each increment.

5. Add the acceleration times calculated for each interval. The sum is the total time to accelerate the motor and load to full speed.

Step 1.

To calculate the acceleration time, first calculate the combined WK2 of the motor, the gearbox, and the pump. From the information in Figure 200-16, the motor rotor has a WK2 of 1900 lb-ft2 at 1780 rpm. The gear box has a WK2 of 300 lb-ft2 at 1780 rpm, and the pump rotor has a WK2 of 10 lb-ft2 at 7000 rpm. Notice that the pump WK2 is not at the same rpm as the rotor and gear box. The pump WK2 must be referred to the motor rated speed by multiplying it by the ratio of the squares of the two speeds. Then all values for moment of inertia (WK2) are added to obtain the total moment of inertia, shown below:



(Eq. 200-37)

The value to use for WK2 in the accelerating time equation is 2355 lb-ft2.

Step 2.

Because the voltage drop calculation predicts a drop in motor terminal voltage to 76% of the rated 2300 volts, use the motor torque vs. speed curve for 76% voltage. Seventy-six percent is a rather severe voltage drop, and it is necessary to look closely at the torque vs. speed curve of the motor and the load to determine if there is net accelerating torque at all points. These curves must be obtained from the manufacturer of the motor.

Step 3.

The motor and pump torque vs. speed curves are shown in Figure 200-25. The curve has been divided into 10 equal increments (each 10% of rated speed), and the per-unit net accelerating torque has been measured and drawn at the center of each of these sections. The curve can be divided into smaller increments for greater accu-racy.

Figure 200-25 shows that the minimum net accelerating torque in any speed interval is 0.22 per-unit or 22% of motor full load torque. Therefore, there is sufficient net accelerating torque, even though only 76% voltage (24% drop) is expected on starting. Ten percent is a good guideline for the minimum acceptable net acceler-ating torque at all points from startup to operating speed.

Step 4.

Using the accelerating time equation, calculate the time required to accelerate through each 10% increment of total speed (178 rpm), based on the midpoint net acceleration torque shown in each interval.

(Eq. 200-38)

For example, in the first interval, the net percent accelerating torque is 0.28 per-unit. The full load motor torque is 4424 ft-lb, so the net accelerating torque is:



T = Tpu x T total

T = 0.28 x 4424

T = 1,238.72 ft-lb

WK2 is 2355 lb-ft2 and the speed change is 10% of 1,780, or 178 rpm. Thus, the accelerating time for the first interval is:

(Eq. 200-39)

Acceleration times for all the intervals are listed in Figure 200-26.

The value in each row of the time column (Figure 200-26) is the time for the motor to accelerate through the speed interval. The sum of these is 11 seconds, the total time to accelerate to 1780 rpm.

Fig. 200-25 Speed vs. Torque for the Example Motor and Load Acceleration Calculations



This accelerating time information may now be used to plot the motor-starting current vs. time curve on the motor time overcurrent relay protection sheet.

The only question remaining is: Will the motor exceed its thermal protection limits in the 11 seconds required to reach operating speed? This question can be answered by plotting the motor acceleration time vs. current curve on the same time current coordination sheet as the motor thermal limit curve.

Correcting for Unacceptable Acceleration TimeIf the acceleration time study indicates that it will take too long to accelerate the motor, consider the following options:

1. Use a larger size motor if additional voltage drop during starting is available.

2. Specify a motor with a higher torque characteristic. This will increase the net accelerating torque, but does so at the expense of motor efficiency. Motor manufacturers can vary the torque vs. speed characteristics of motors by changing the design of the rotor bars.

3. If starting the motor loaded is the problem, install an interlock or stipulate an operational requirement so that the motor can only be started if the driven equipment is unloaded.

239 Computer Programs That Simulate Motor-StartingSeveral computer programs can simplify calculating motor-starting voltage drop and acceleration time. One of these is the General Electric timeshare program, MOTST$.

Fig. 200-26 1500 HP Motor Accelerating Time Calculation

Speed Interval P.U. Net Acc. Torque Net Acc. Torque Time

0 - 10% 0.28 1238.72 1.10

10 - 20% 0.32 1415.68 0.96

20 - 30% 0.34 1504.16 0.90

30 - 40% 0.30 1327.20 1.03

40 - 50% 0.30 1327.20 1.03

50 - 60% 0.25 1106.00 1.23

60 - 70% 0.24 1061.76 1.28

70 - 80% 0.22 973.28 1.40

80 - 90% 0.22 973.28 1.40

90 - 100% 0.38 1681.12 0.81

Total Acceleration Time 11.14



The information required for the GE program is similar to that used in the manual calculation previously discussed; however, this program also includes running load, impact load, and tapped transformers. It allows the user to change cases very easily. The program can model the running load as constant impedance, constant kVA, or constant current, to more accurately model the behavior of the on-line loads as voltage changes during the starting of the motor.

The computer program input requires WK2 values, motor and load torque vs. speed curve points, power factor vs. speed curve points, current vs. speed curve points, and impedance diagram information. The output is shown in Figure 200-27.

Fig. 200-27 G.E. Motor Starting Program (Courtesy of the General Electric Company)GENERAL ELECTRIC MOTOR STARTING PROGRAM

LINE IMPEDANCES ON 10 MVA BASE

ABC STEEL

SCHDY, NY

START 8000 HP MOTOR

CASE 1A - 04/02/80

BUS BUS R X TAP P.U. INITIAL VOLTAGE

SOURCE 0.003 0.0197 1.002

1 2 0.005 0.022 1

2 3 0.0053 0.332 1

LOAD CONSTANT MVA CONSTANT I CONSTANT Z

BUS MW MVAR MW MVAR MW MVAR

1 .00 .00 .00 .00 .00 .00

2 5.52 3.42 .00 .00 .00 .00

STARTING MOTOR DATA SYN. START

HP KVA M-KVOLT BUS KVOLT WK-2 RPM CAP(KVA)

8000.0 7796.3 6.60 6.90 526000.0 360 .0

% SPEED %FL AMPS %PWR FACTOR %MOT TRQ %LD TRQ

0 395 13.3 59 10

2 390 13.3 58 0.1

10 385 15 56 0.2

TIME VOLTAGE SOURCE MOTOR

(SEC) BUS1 BUS2 BUS3 MW MVAR VOLTS %M-TRQ %LD-TRQ %AMPS %SPEED

0.0- 1.002 .992 .000 5.55 3.52 .000 .00 .00 .0 .00

0.0+ .972 .929 .442 6.70 17.88 .462 12.61 10.00 180.3 .00

1.42 .972 .929 .442 6.70 17.88 .462 12.39 .10 180.3 2.00

APPROX. FINAL MOTOR SPEED IS 99.8 % IN 52.23 SEC



240 Load-Flow Studies

241 Reasons for a Load-Flow StudyA load-flow study models an electrical power system for normal, abnormal, or special case operating configurations. It determines the magnitude and phase angle of the voltage at each bus, and the real and reactive power flowing in each line.

The study examines the effects of changing lineups, adding motors, taking trans-formers out of service, changing taps on transformers, adding capacitor banks or synchronous condensers, adding new transmission lines, adding or shifting genera-tion, or making other changes in the system. It illustrates the effects on the overall system of any of these changes prior to actually implementing the change. The study consists of the examination of a series of load-flow solutions for different cases.

242 When To Conduct a Load-Flow StudyA load-flow study is necessary when:

• Significantly changing the plant configuration or simulating a proposed plant design

• Predicting plant power factor and the effect of adding capacitors

• Adding cogeneration or large motors

243 Data for a Load-Flow StudyThe data needed to perform a load-flow study are the same as that required for the short-circuit study, but with a few additions.

The system is presented in one-line form similar to that shown for the short-circuit study (Section 220). The following information is required:

1. Base voltages of all buses.

2. Initial per-unit voltage at buses.

3. Total watts and vars of all loads.

4. Resistances and reactances of all lines connecting buses.

5. Buses designated as: swing bus; a regulated bus (where voltage magnitude is held constant by generation of reactive power); or a bus with fixed real and reactive power.

6. Transformer tap settings.

7. Vars produced by capacitors.



244 Interpreting Computer Load-Flow DataFigure 200-28 is an example of a computer printout for a load-flow study for the one-line diagram shown in Figure 200-29.

When the program is run, the computer derives a solution by several iterations of calculations that converge towards a solution. When the specified degree of accu-racy is reached, the solution is output.

In the printout in Figure 200-28, the real and reactive power are generated by Bus 1, the swing bus. P is the real power in MW, and Q is the reactive power in Mvar. The current I flowing from Bus 1 is given in per-unit amperes. The swing bus phase angle is zero since it is the reference bus, and the voltage is 1.0 per-unit volts.

Computer data also include the power flow (in real and reactive power), and the current flowing from each bus to adjacent buses. The current flowing in each line is compared to the ampacities of the lines to make sure there is no overloading. It can be seen that further from the swing bus, the voltage drop becomes greater. At Bus 10, the bus voltage is 0.974 per unit, about a 3% drop during normal running load operation. The voltage at Bus 10 lags the voltage at the swing bus by 1.394 degrees.

The power factor of the plant can be calculated from the real and reactive power flowing from the swing bus and by constructing the power triangle. The power factor is 0.89, which may have some effect on the utility billing.

For more detail about load-flow studies, see the IEEE Brown Book (IEEE Std. 399).

250 Transient-Stability StudiesComputerized transient-stability studies provide a fast, simple, and inexpensive way to simulate transient performance of an electrical system.

Stability applies only to electrical systems with two or more synchronous machines tied together electrically (e.g., a large synchronous motor powered by a large AC generator). Another example would be several generation units and several large hydrogen compressors driven by synchronous motors.

Stability exists if all of the AC synchronous motors and generators are in synchro-nism, that is, they are in step with each other. A system which is stable under normal

Fig. 200-28 Example of a Computer Load-Flow Study

P-MW Q-MVAR I-P.U. V-P.U. ANGLE-DEG

* Bus 1 * (Swing) 1.000 .000

To Bus 2 2.1540 1.0939 .0242

Generate 2.1540 1.0939 .0242

* Bus 10 *

Const Load .3500 .2500 .0044 .974 -1.394

To Bus 4 -.3499 -.2500 .0044



steady-state operating conditions may not be stable when it undergoes a transient, such as a switching operation, a separation from the utility, a fault, or a relay action. If the system has transient stability, the machines may oscillate with respect to each other momentarily, but will regain synchronism within a very short period of time.

If the system is unstable, a transient may cause a permanent loss of synchronism among the machines. This asynchronous operation can cause high transient mechan-ical torques and currents with associated mechanical and thermal damage. Most synchronous machines are equipped with pullout protection that shuts down the machines when they pull out of step. Frequent outages are another problem related to instability. Distance relays may interpret the large surges in real and reactive power flow as fault currents and also cause system shutdown related to instability.

A transient-stability study is a good way to simulate the response of the power system to predictable transients, such as loss of generators, faults, or utility outages. The study should be made when large synchronous machines are added to a power system. Transient-stability studies should be included in the design phase of cogen-eration projects.

Fig. 200-29 One-Line Diagram for the Example Computer Load-Flow Study



A transient-stability study is a very complex study that includes a significant amount of data in addition to that required for the short-circuit study, relay study, and the load-flow study. It includes system data (as used in the short-circuit study), rotating machine data (such as moments of inertia of the rotors of the electrical and driven mechanical machines), load data (as used in the load-flow study), and distur-bance data.

The output of the computer programs can include the following information:

• Rotor angles, torques, and speeds of synchronous machines• Real and reactive power flow throughout the system• Voltage and phase angles at all buses• System frequency• Torques and slips of induction machines

System stability is determined by examining the swing curves produced by the computer programs. Swing curves are plots of the rotor angles of synchronous machines vs. time. These plots make it easy to determine if the swing curves come back into step after the initial disturbance, or if they diverge, indicating instability for the particular transient under consideration.

A transient-stability study has such a degree of complexity that it is best assigned to someone that specializes in such studies. The Westinghouse Westcat program is a commonly used transient-stability computer program available on timeshare. PC-based programs are also available.

260 Harmonic Analysis StudiesHarmonic analyses evaluate the potential effects of harmonics (usually produced by solid state power conversion equipment) on electrical systems. The study is usually done with a computer and allows solutions to problems to be simulated and tested before they are physically installed.

Harmonic voltage and currents are produced primarily by solid state power conver-sion equipment using rectifiers and thyristors. Examples of equipment producing harmonic voltages and currents include the following:

• UPS systems• DC drives• AC drives• Computer power supplies• Rectifiers

The larger the equipment, the larger the magnitude of the harmonics generated.

Harmonics are voltages or currents with a frequency which is some multiple of the fundamental frequency (60 Hz). Fourier analysis shows that any periodic waveform can be represented as the sum of an infinite series of sine and cosine waveforms harmonically related.



A pure 60 Hz sine wave has no harmonics, only a fundamental component at 60 Hz—the wave itself. Solid state power conversion equipment, such as rectifiers and motor drives, chop the AC current waveform by allowing current to flow during only part of the cycle. The commutation of SCRs causes notching and distortion of the input voltage waveform. As a result, the sine wave becomes distorted. The peri-odic distorted wave contains harmonics, since it no longer is a pure sine wave. The dominant harmonics are typically the fifth (300 Hz), seventh (420 Hz), and elev-enth (660 Hz).

These harmonics can cause problems in the plant electrical system. Some examples of problems that can occur are: excessive capacitor fuse operation (due to reso-nance at harmonic frequencies), communication interference (due to mutual coupling at harmonic frequencies), computer problems, and excessive heating of equipment.

A harmonic analysis of the electrical system should be considered in the following situations:

1. When applying large capacitor banks for power factor correction.

2. When installing solid-state AC-to-DC power conversion equipment.

3. When there is a history of harmonic-related problems (such as blowing fuses in capacitor banks).

4. In the design stage of an installation using large solid-state power conversion equipment with capacitor banks.

5. When installing large, solid-state power conversion equipment at a plant where the utility has restrictive requirements on harmonics put into the utility line.

A harmonic analysis program examines the effects of the particular harmonic frequencies that are expected to be produced by the solid state conversion equip-ment and checks to see if they will coincide with any resonance points in the power system. It is similar to a load-flow study except the harmonic analysis considers bus voltages and power flows at many frequencies other than 60 Hz. The input data for computer programs are similar to the load-flow data with additional requirements for data on the semiconductor convertors and capacitor and reactor installations in the system. Harmonic analyses are best done by a specialist.

270 ReferencesThe following references are readily available. Those marked with an asterisk (*) are included in this manual or are available in other manuals.

271 Model Specifications (MS)There are no specifications related to this guideline.



272 Standard DrawingsThere are no standard drawings related to this engineering guideline.

273 Data Sheets (DS), Data Guides (DG) and Engineering Forms (EF)There are no engineering forms related to this engineering guideline.

274 Other References1. ANSI/IEEE Standard 141 IEEE Recommended Practice for Electric Power

Distribution for Industrial Plants.

2. Beeman, Donald, Industrial Power Systems Handbook (McGraw-Hill, 1955).

3. *Yuen, Moon H., Short Circuit ABC — “Learn It in an Hour, Use It Anywhere, Memorize No Formula.” Paper No. PCI-73-7, presented at the 1973 IEEE PCIC Conference. (See also Paper No. PCI-82-1, presented at the 1982 IEEE PCIC Conference, for a paper which describes using this method with a hand-held calculator.) Included as Appendix C.

4. Oscarson, G.L., EM Synchronizer - The ABC of Synchronous Motors (Electric Machinery Mfg. Co., 1954).

5. Stevenson, Jr., W.D., Elements of Power System Analysis (McGraw-Hill, Fourth Edition, 1982).

6. Thode, H.W. and B. Brozek, High Inertia Load — Induction Motor Design Considerations (Paper No. PCI-81-5, presented at the 1981 IEEE PCIC Confer-ence).

7. Nichols, W., R. Bried, R.D. Valentine, and J.E. Harder, Advances in Capacitor Starting (Paper No. PCI-81-31, presented at the 1981 IEEE PCIC Conference).

8. Lewis, H.W. and F.A. Woodbury, Large Motors on Limited Capacity Transmis-sion Lines (Paper No. PCI-77-41, presented at the 1977 IEEE PCIC Confer-ence).

9. Nailen, R.L., Large Motor Starting Problems in the Petroleum Industry (Paper No. PCI-68-43, presented at the 1968 IEEE PCIC Conference).

10. St. Pierre, C.R., and Mirabile, J.S., G.E. Timeshare Computer Manual for LFLOWS, (General Electric Company Industrial Power Systems Engineering Operation, 1983).

11. ANSI/IEEE Standard 399, IEEE Recommended Practice for Power System Analysis.

12. ANSI/IEEE Standard 242, IEEE Recommended Practice for Protection and Coordination of Industrial and Commercial Power Systems.


300 Hazardous (Classified) Areas

AbstractThis section discusses the classification of locations for electrical installations. It provides guidance in the selection of electrical equipment for hazardous (classified) locations. Section 1500 of the Fire Protection Manual provides additional informa-tion.

Area classification should be effected in conformance with these guidelines as they are applicable. Foreign projects should conform to applicable foreign codes and standards as conditions dictate.

Contents Page


320 Classification of Locations for Electrical Installations 300-3

330 Types of Equipment for Class I Hazardous (Classified) Locations 300-6

331 Maximum Operating Temperatures

332 Equipment Enclosures

333 Hermetically Sealed Devices

334 Intrinsically Safe Systems

335 Nonincendive Equipment

336 Purged Enclosures

340 Electrical Equipment Requirements and Recommendations for Class I Hazardous (Classified) Locations 300-10

350 Types of Equipment for Class II Hazardous (Classified) Locations 300-16

351 Maximum Operating Temperatures

352 Equipment Enclosures

353 Hermetically Sealed Devices

354 Intrinsically Safe Systems

355 Nonincendive Equipment

356 Pressurized Enclosures

300 Hazardous (Classified) Areas Electrical Manual


360 Electrical Equipment Requirements and Recommendations for Class II Hazardous (Classified) Locations 300-18

370 Area Classification Based on the IEC “Zone” System for Flammable Gases or Vapors 300-23






Electrical Manual 300 Hazardous (Classified) Areas


310 IntroductionThis section provides guidelines for classifying domestic locations for electrical installations. It also discusses the necessary requirements and provides recommen-dations for electrical equipment installed in these areas. Reference Section 1500 of the Fire Protection Manual for additional information.

Location classification is based on the properties of flammable vapors, liquids, gases, combustible dusts or easily ignitable fibers which may be present and the likelihood that a flammable or combustible concentration will be present. It is necessary to identify hazardous (classified) locations in order to select the proper electrical equipment for these areas. Restrictions are placed on the types of equip-ment used and their operation and maintenance.

Proper equipment must be chosen to ensure safety. Equipment suitable for use in hazardous locations is designed either to prevent accidental ignition of ignitable substances or to prevent damage if there is ignition by confining explosions to elec-trical enclosures and conduits.

Switches, circuit breakers, fuses, motor starters, single phase and DC motors, push-button stations, plugs, and receptacles can produce arcs or sparks capable of igni-tion in normal operation. Other devices, such as lighting fixtures, can produce enough heat to ignite flammable mixtures or combustible dusts. A loose lamp can combine arcing with heat. Many parts of an electrical system, such as wiring (partic-ularly splices in the wiring), transformers, solenoids, and other low-temperature devices without make-or-break contacts can become ignition sources through insula-tion failure.

A flowchart directing the designer to specific NFPA, API, and ISA documents containing procedures for determining area classification and selecting electrical equipment is provided in Figure 300-1. Necessary procedures and requirements are included in the referenced documents.

An alternative system of classifying areas, referred to as the International Electro-technical Commission (IEC) “Zone” system, has been introduced in the 1996 NEC (NFPA 70) as Article 505 and is described in Section 370 of this manual.

320 Classification of Locations for Electrical InstallationsIn order to properly select and install electrical equipment in a location which contains, or may contain, flammable gases or vapors, combustible dust, or easily ignitable fibers or flyings, the location must first be “classified.” The classification process is three-fold:

1. Designate the type (Class) of hazard which may be present—gas, dust, or fiber.

2. Designate the specific “Group” of the hazardous substance.

3. Determine the probability that the hazardous substance will be present (Divi-sion).



Designating the type of hazard is the first and easiest of the steps. The area is called Class I if the hazardous material is flammable gas or vapor. It is called a Class II area if the hazardous material is combustible dust, and it is designated Class III if easily ignitable fibers or flyings may be present. Examples of Class I locations are oil refineries and natural gas compressor stations. Grain elevators, portions of some chemical and oil shale plants, and coal mines are examples of Class II locations. Cotton gins and textile mills are examples of Class III locations.

Designating the “Group” of a specific material is easily accomplished by refer-encing either the National Electrical Code or the National Fire Protection Associa-

Fig. 300-1 Area Classification Flowchart for Hazardous (Classified) Locations

GENERAL REQUIREMENTS AND DEFINITIONS OF TERMSNFPA 70 (NEC) Article 500 or 505

API RP 14F

API RP 500

ISA S12.1

Fire Protection Manual

STEP 1Determining Class, Group and Properties of

Flammable Vapors, Liquids, Gases and Combustible DustsNFPA 497M

NFPA 30

NFPA 325M

NFPA 321

UL 58, 58A, AND 58B


STEP 2Determining Division and Extent of Classified Area


API RP 500 (Petroleum Facilities)

NFPA 497A (Chemical Plants)

NFPA 70, Article 514 and NFPA 30A (Gasoline Dispensing Stations)

NFPA 70, Article 515 (Bulk Storage Plants)

STEP 3Selecting and Installing Equipment

NFPA 70 Articles 500 and 501 (All Class/Division Installations) and 505

API RP 14F (Producing and Drilling Installations Offshore)

API RP 540 (Refineries)

NFPA 496 (Purging Methods)

ANSI/UL 913 (Intrinsically Safe Systems)

ISA RP 12.6 (Intrinsically Safe Systems, Installation)Note This flowchart is intended to direct the reader to appropriate standards and publications containing guidelines and procedures for

determining area classification and requirements for selecting electrical equipment.



tion’s documents numbered 325M and 497M. Most hydrocarbons are included in Group D. Hydrogen is in Group B, and hydrogen sulfide is in Group C. Acetylene is the only gas in Group A. Combustible dusts are included in Groups E, F, and G according to their electrical properties. Group E includes metal dusts; Group F is comprised primarily of carbon dusts; and Group G primarily of plastic and agricul-tural dusts. There are no groups for Class III materials.

Determining the probability that the hazardous substance will be present is the most difficult of the three steps in classifying an area. Class I and II areas are referred to as Division 1 areas when hazardous material is anticipated during normal opera-tions on a continuous or intermittent basis. Areas are referred to as Division 2 when hazardous material is anticipated only during abnormal operations. Additionally, in Classes I and II, areas are considered Division 1 if a process failure is likely to cause both combustible levels of hazardous material and an electrical fault in a mode which could result in an electrical arc. Class II areas are also considered Divi-sion 1 if the hazardous dust involved is metallic or is a Group E or F dust with a resistivity less than 105 ohm-centimeters. Class III areas are specified Division 1 if easily ignitable materials are handled, manufactured or used, and Division 2 if they are stored or handled in a non-manufacturing environment.

To promote uniformity in area classification within Chevron, refer to the Fire Protection Manual, Section 1500. To promote uniformity within the industry in area classification for oil and gas facilities, the American Petroleum Institute (API) has developed Recommended Practice 500 for refining facilities, producing and drilling facilities, and pipeline facilities. In a similar manner, NFPA 70, Article 514, provides specific guidance for the classification of gasoline dispensing and service stations. While some individual judgment is required, most people following these guidelines would arrive at very similar area classification drawings—that is, draw-ings showing Division 1, Division 2, and unclassified area boundaries within a specific facility.

Typical areas at oil and gas facilities are classified Class I (due to gas or vapor, as opposed to dust or fibers), Group D (because most hydrocarbons are included in Group D), and either Division 1 (for areas of high probability of exposure to flam-mable concentrations of gas), Division 2 (for areas of lower probability), or unclas-sified (for areas of extremely low probability).

Area classification drawings should include information about the gas or vapor involved, to help facilitate the selection of the electrical equipment for installation in the hazardous location. The following information should be included on the drawing:

• specific type of hazardous vapor or gas• auto ignition temperature (AIT) of the gas or vapor (per NFPA 497M)• gas or vapor’s (temperature) Identification Numbers per (NEC Table 500-3(d))• any other information that affects equipment selection

Once area classification drawings have been prepared, the National Electrical Code (and API RP 14F for offshore drilling and producing facilities) provides very explicit rules for the specific types of electrical equipment which are permitted in



the various classified areas, and the methods by which the equipment must be installed. Therefore, with proper area classification drawings, safe electrical installa-tions can be made in areas which may be exposed to flammable concentrations of gases and vapors, combustible dust, or easily ignitable fibers or flyings.

This section is intended to give inexperienced personnel a basic understanding of area classification. Consultation with project engineers, process engineers, and safety engineers may be needed to establish area classifications. If one is classi-fying an area for the actual design and installation of electrical equipment, the National Electrical Code and other applicable documents should be consulted for additional details.

Each individual area (whether room, building, process plant area, indoors, or outdoors) of the facility must be considered separately in determining the area clas-sification. By applying this process, the area classification drawing is created.

Sections 330 and 340 of this guideline cover Class I locations. Sections 350 and 360 cover Class II locations. Section 370 covers the IEC Zone classification system. Class III will not be discussed because there are no known Company Class III locations.

330 Types of Equipment for Class I Hazardous (Classified) LocationsElectrical equipment installed in hazardous (classified) locations must be suitable for the area classification — Class, Division, and Group. This section defines the various types of electrical equipment suitable for use in Class I hazardous (classi-fied) locations. It is very important to have a clear understanding of the reasons behind the classification of areas and of the different installation methods employed to ensure cost effective installations that do not compromise safety.

Electrical installations in hazardous locations are more costly and require special and additional precautions during maintenance operations. When practical, major electrical equipment should be installed either outside hazardous (classified) loca-tions or in less hazardous locations (i.e., Division 2 versus Division 1). In some applications, it may be more practical or economical to utilize purging and pressur-ization techniques.

331 Maximum Operating TemperaturesThe NEC requires that the exposed surfaces of all approved equipment used in hazardous locations operate below the ignition temperature of the specific flam-mable gas or vapor which may be present.

Heat producing equipment must be marked to show the class, group, and operating temperature or temperature range, referenced to a 40°C (104°F) ambient. The temperature range, if provided, is indicated by identification numbers in accordance with NEC Table 500-3(d). This temperature identification number is often referred to as the T-rating. Unless equipment is T-rated, its maximum temperature must not exceed 80% of the ignition temperature of the gas or vapor involved (expressed in degrees Centigrade). Equipment identified with a T-rating (by a nationally recog-



nized testing laboratory) can be applied up to the auto ignition temperature (AIT) of the gas or vapor involved equal to the T-rating.

Identifying only the group to which the flammable substance belongs is not suffi-cient to establish maximum surface operating temperatures of equipment. Since there is no consistent relationship between the ignition temperature and the other explosive properties of a substance, equipment selection must be based on Class and Group as well as on operating temperature. See NEC Article 500-3 and NFPA 497M for additional information.

332 Equipment EnclosuresExplosionproof enclosures are capable of withstanding an internal explosion and preventing its propagation to the external atmosphere. Explosionproof enclosures suitable for use in Class I (Division 1 and 2) locations are designated NEMA (National Electrical Manufactures Association) Type 7.

Explosionproof enclosures breathe when the ambient temperature changes and, therefore, may accumulate both moisture, and hazardous gases within. If an internal explosion occurs, the enclosure must withstand a very rapid buildup of pressure which is relieved by the escape of the expanding gases. These gases must be cooled before they reach the surrounding atmosphere. Three methods are widely used to achieve this cooling:

• Ungasketed, precision ground flanges or joints machined to specific widths and narrow tolerances

• Threaded joints in which at least five full threads are engaged

• Precision serrated joints (commonly found in explosionproof unions)

Adequate strength is a requirement for this type of enclosure. In most designs for Class I, Divisions 1 and 2, a safety factor of 4 is used (i.e., the enclosure must with-stand a hydrostatic test four times the maximum pressure normally produced by an explosion within the enclosure).

In addition, the surface temperature of the enclosure must not be higher than 80% of the ignition temperature (expressed in degrees C) of the gas or vapor involved, unless the equipment has been T-rated by a recognized testing laboratory.

NEMA Type 8 enclosures are also suitable for Class I locations. These enclosures are arranged so that all arcing contacts on connections are immersed in oil. Arcing is confined under the oil so that it will not ignite an explosive mixture of the speci-fied gases in internal spaces above the oil or in the atmosphere surrounding the enclosure. Since they prevent (versus contain) explosions, NEMA Type 8 enclo-sures are not “explosionproof.” The surface temperature of these enclosures must not be higher than 80% of the ignition temperature (in degrees C) of the gas or vapor involved, unless T-rated by a nationally recognized testing laboratory (NRTL).

In order to comply with NEC Article 500-3(b), even if NEMA designations are used, explosionproof enclosures containing equipment and built as a complete



assembly (e.g., motor starters) must be labeled with the appropriate Class and Group designations and either the operating temperature or the temperature range. Particular attention must be paid to the Group(s) listed.

For a complete description of NEMA enclosures and their requirements, refer to NEMA Standards Publication 250. Refer also to API RP 14F and API RP 540 for guidelines on the application of enclosures in offshore and refinery locations, respectively.

333 Hermetically Sealed DevicesHermetically sealed devices are designed to prevent flammable gases from coming in contact with sources of ignition, such as arcing contacts or high-temperature components. These devices are suitable for use in Division 2 and unclassified areas. The materials used to accomplish hermetic sealing must be resistant to mechanical abuse and durable enough to withstand normal aging, exposure to chemicals and hydrocarbons, and the effects of severe weather. The bond between the different materials employed must be permanent, mechanically strong, and capable of with-standing the surrounding environment. Hermetically sealed enclosures must be sealed through glass-to-metal or metal-to-metal fusion at all joints and terminals. Enclosures whose seals are formed by O-rings, epoxy, molded elastomer, or sili-cone compounds are not necessarily considered hermetically sealed; nor is the potting of components necessarily considered hermetic sealing.

In Division 2 applications, significant savings can be realized by using hermetically sealed devices since non-explosionproof enclosures are then allowed. The use of hermetically sealed devices also enables the designer to use NEMA 4X and other enclosures which provide better environmental protection for the enclosed equip-ment (as well as the inherent environmental protection for the hermetically sealed contacts.) This feature is particularly desirable in corrosive atmospheres or outdoor installations.

334 Intrinsically Safe SystemsIntrinsically safe systems are incapable of releasing sufficient electrical or thermal energy under normal or abnormal equipment operating conditions to cause ignition of a specific ignitable atmospheric mixture in its most easily ignitable concentra-tion. Abnormal equipment conditions include accidental damage to or failure of any part of the equipment, wiring, insulation, or other components, and exposure to overvoltage. Normal conditions include periods of adjustment and maintenance. The most common applications are in instrumentation and communication systems.

Intrinsically safe systems are suitable for use in any hazardous (classified) location for which they are approved. Article 504 of the NEC governs the requirements for the installation of intrinsically safe systems. NEC Articles 500 through 517 do not require intrinsically safe systems. However, such systems may require that specific equipment items, such as controllers, be located in an unclassified area. Where equipment has been rated intrinsically safe by a recognized testing laboratory, it may be employed with various end devices to form an intrinsically safe system. No



end device is of itself intrinsically safe, but is intrinsically safe only when employed in a properly designed intrinsically safe system. Proper design of an intrinsically safe system requires adherence to strict rules, detailed mathematical analysis, and in most cases, laboratory testing. Standards UL 913 and ISA RP 12.6, and NEC Article 504 should be followed closely when designing and installing intrinsically safe systems. See Section 1400, of the Instrumentation and Control Manual.

The two most important advantages of intrinsically safe equipment are:

1. Safety. Intrinsically safe equipment does not require explosionproof enclo-sures. Thus, missing bolts and covers, enclosures open during maintenance and testing operations, and corroded conduit systems will not impair the safety of the systems. The low voltages and currents involved may reduce the hazard of electrical shock.

2. Economy and Convenience. Wiring for intrinsically safe systems need only meet the requirements of Article 504 of NEC. Thus, expensive, bulky, explo-sion-proof enclosures are not required. Intrinsically safe apparatus and wiring may be installed using any of the wiring methods suitable for unclassified loca-tions. Maintenance and calibration operations can be performed in classified areas without de-energizing the equipment or shutting down process equipment.

Two disadvantages of intrinsically safe systems are:

1. High Contact Resistance. Low power signals are more easily affected by high contact resistance. This disadvantage can be minimized by using hermetically sealed contacts or devices with wiping contacts.

2. Circuit Separation. Wiring for intrinsically safe systems must be installed separately from higher power circuits. This could increase the installed system cost, depending on the wiring methods used.

Intrinsically safe equipment must always be maintained as an intrinsically safe system, with maintenance personnel specifically trained with that proper mainte-nance in view.

335 Nonincendive EquipmentNonincendive equipment is not capable of igniting a flammable mixture under normal circumstances, but ignition is not necessarily prevented under abnormal circumstances. Such equipment is suitable for use only in Division 2 and unclassi-fied locations. Nonincendive equipment is similar in design to other equipment suit-able for Division 2 locations. However, in nonincendive equipment, sliding or make-and-break contacts need not be explosionproof, oil immersed, or hermetically sealed.

Portions of a nonincendive system may operate at energy levels potentially capable of causing ignition. Therefore, wiring methods must conform to area classification requirements. Nonincendive equipment normally is limited to instrumentation and communication systems. When employing nonincendive systems, extreme care should be exercised.



336 Purged EnclosuresPurging (frequently referred to as pressurizing) is a method of installing electrical equipment in a Class I area without using explosionproof enclosures. NFPA 496 provides information for the design of purged enclosures and purging methods to reduce the classification of the area within an enclosure:

• From Division 1 to unclassified (Type X purging)• From Division 1 to Division 2 (Type Y purging)• From Division 2 to unclassified (Type Z purging)

NFPA 496 discusses the different requirements for the purging of small enclosures, power equipment enclosures, and large volume enclosures (such as control rooms). On an offshore platform, the use of humid salt air for purging will cause corrosion damage to equipment; thus, use of inert gas or dehydrated clean air must be consid-ered. Any source of air for purging must be from an unclassified location.

340 Electrical Equipment Requirements and Recommendations for Class I Hazardous (Classified) Locations

This section discusses the requirements for electrical equipment located in Class I areas and provides recommendations for various applications. Generally, environ-mental and corrosive considerations are outside the scope of this section.

NEC Article 501 provides requirements for wiring and equipment in Class I loca-tions. API RP 14F provides requirements and recommendations for wiring and equipment located on fixed offshore production platforms.

Manufacturers’ literature, such as Crouse Hinds Company “Code Digest” and Appleton Electric Company “Code Review” also provide excellent descriptions of Class I requirements and photographs of typical installations.

The word “approved” as used in this section is defined as “acceptable to the authority having jurisdiction.” Most authorities will require equipment to be tested and approved by a nationally recognized testing laboratory (NRTL), not just built to appropriate standards.

TransformersIn Division 1 areas, transformers containing flammable liquids must be installed in vaults. If they do not contain flammable liquids, they must either be installed in vaults or be approved for Division 1 locations.

In Division 2 locations, dry-type transformers are normally more economical for 600 volts or less and for 150 kVA or smaller sizes. (Totally enclosed, non-ventilated transformers are recommended for harsh outside environments.) Liquid-filled trans-formers usually require external metering and protective devices which must be suit-able for the area. Also, liquid-filled units may require costly curbing and drains in environmentally sensitive areas.



See NEC Article 501-2 for Class I locations. Refer to NEC Article 450 for addi-tional transformer requirements, particularly concerning vaults.

Arcing and High Temperature DevicesSwitches, motor starters, single phase and DC motors, relays, fuses, and circuit breakers are typical arcing devices. High temperature devices are devices that can operate at a temperature exceeding 80% of the ignition temperature (expressed in degrees C) of the specific gas or vapor involved. Space heaters, grounding resistors, and lamps should be considered high temperature devices unless they are T-rated by an NRTL.

In Class I, Division 1 areas, arcing and high temperature devices must be installed in enclosures which are either approved explosionproof or purged in accordance with NFPA 496.

In Class I, Division 2 areas, arcing contacts must be installed in explosionproof enclosures, immersed in oil, hermetically sealed, or be nonincendive. High tempera-ture devices in Class I, Division 2 locations must be installed in explosionproof enclosures.

Fuses in Class I, Division 1 locations must be installed in explosionproof enclo-sures. In Class I, Division 2 locations, certain types of fuses can be installed in general purpose enclosures:

• silver-sand, nonindicating current limiting fuses

• hermetically sealed fuses

• fuses used for overcurrent protection (not switching) of circuits or feeders supplying fixed lamps

All other fuses installed in Class I, Division 2 locations must be installed in explo-sionproof enclosures.

Hermetically sealed reed switches, suitable for Division 2 locations, are commonly available for level switches and other sensing devices. Typically they are single-pole, single-throw, and are limited to 100 VA. Also, hermetically sealed mercury switches are suitable for Division 2 locations and can be obtained as single-pole, double-throw. Solid state switches, without contacts, are suitable for general purpose enclosures for Division 2 locations, if the surface temperature of the mecha-nism does not exceed 80% of the AIT (in °C) of the gas or vapor involved.

Pressure switches in Division 1 and 2 areas should be of two barrier construction or must be installed with a special type of sealing fittings (not yet commercially avail-able) that satisfy the requirements of NEC Article 501-5(f)(3) when sensing ignit-able fluids.

Utility switches, for example, light switches and start-stop stations, are limited to a maximum of 480 volts. Factory-sealed units are suitable for Division 1 and Divi-sion 2 areas without external sealing fittings. However, in offshore areas where certain cables are allowed in Division 1 areas, they must be sealed where cable (other than type MI) is used.



Frequently, it is desirable (for environmental protection) to install hermetically sealed control stations (e.g., hand-off-automatic, and start-stop devices) in NEMA 4X or 3R enclosures. These installations are suitable for Division 2 areas.

Refer to NEC Article 501-3 and API 14F (for offshore platforms) for additional details.

Wiring MethodsThe following wiring methods are allowed in Class I, Division 1 locations:

1. Threaded rigid metal conduit

2. Intermediate metal conduit

3. Type MI (mineral-insulated metal-sheath) cable

4. Explosionproof flexible connections

5. Rigid nonmetallic conduit, installed below grade, and encased in concrete per the requirements of Article 501-4(a), Exception No. 1, of the 1996 NEC

6. Type MC cable, listed for use in Class I, Division 1 locations with a gas/vapor-tight continuously corrugated aluminum sheath, an overall jacket of suitable polymeric, separate grounding conductors, and other provisions of Article 501-4(a), Exception No. 2, of the 1996 NEC

IMC and Type MI cable are not recommended for offshore installations. See API RP 14F, Section 4.4 for additional application guidelines.

In Class I, Division 2 locations, the NEC allows all of the wiring methods for Divi-sion 1 locations, except rigid nonmetallic conduit. Additional wiring methods allowed in Division 2 locations include the following:

1. Enclosed gasketed busways

2. Enclosed gasketed wireways

3. Type PLTC (power-limited tray cable) cable in accordance with NEC Article 725

4. Type MC, MI, TC, and other specific cables, with approved fittings

5. Type ITC (instrumentation tray cable) cable in accordance with NEC Article 727

Flexible cord rated for extra hard service with an equipment grounding conductor, flexible metal and liquid tight conduit (with an external or internal bonding jumper) and certain armored cables are also allowed in Division 2 areas for special applica-tions requiring flexibility. Lengths should be kept as short as possible and cannot exceed 6 feet unless an approved internal bonding system is provided. See NEC Articles 501-16(b), 250-91(b) and 250-79(c) and (f) for additional requirements relative to flexible connections.



Type TC (Tray Cable) and Type MC (Metal Clad) cables are suitable for use in Class I, Division 2 locations. The extruded polymeric cable jacket (PVC, CPE, CSPE, etc.) is considered to be a gas/vapor tight continuous sheath, and the cable is permitted to pass from a Division 2 location to an unclassified location without a seal. The NEC does qualify this “no seal requirement” at the Division 2 and unclas-sified boundary by stating that the sheath must be unbroken. Cables installed in trays per the cable manufacturer’s recommendation should not suffer jacket damage due to installation. If the jacket is damaged or if an in-line splice is made in a Class I, Division 2 location, the splice should be made with a heat shrink tubing to main-tain the integrity of the unbroken sheath.

NEC Article 501-5 contains the requirements for sealing cables and conduits in Division 1 and 2 areas. See API 14F Section 4.8(a) for a description of the purposes for sealing. For sealing requirements on offshore installations see API 14F Section 4.8(b).

It is recommended that underground conduits, in soil that may be hydrocarbon laden, be sealed where they enter and/or exit the ground.

All threaded connections (including enclosures and conduits) should be lubricated with an electrically conductive and antiseize compound which will survive in the environment and is approved for flame path use.

Motors and GeneratorsThe proper selection of motors and generators is imperative to ensure safety and minimize initial and subsequent maintenance costs. Motors and generators should be selected to provide optimum protection from the environment and satisfy the area classification.

Four types of rotating electric machinery are suitable for Class I, Division 1 areas: (1) explosionproof approved for Class I, Division 1, (2) totally enclosed, supplied with positive-pressure ventilation, (3) totally enclosed, inert gas filled, and (4) liquid submerged. Auxiliary equipment, such as space heaters, must also be approved for the location in which it is installed. Refer to NEC Article 501-8 for complete requirements on motors, generators, and other rotating electric machinery used in Class I locations.

If installation in Division 1 locations is unavoidable, explosionproof machines approved for Class I, Division 1 are preferred. For large motors and generators, it may be more economical to select totally enclosed units supplied with positive pres-sure ventilation as described in NEC Article 501-8(a).

In Division 2 areas, non-explosionproof motors and generators having no arcing or high temperature devices are permitted. This generally applies to three-phase induc-tion motors and brushless generators. Some enclosures typically specified are: open drip proof (ODP), weather protected I (WPI) and II (WPII), totally enclosed fan cooled (TEFC), totally enclosed pipe ventilated (TEPV), and totally enclosed water/air cooled (TEWAC).

In Division 2 areas, motors, generators, and other rotating electrical machinery that employs sliding contacts, switching devices or resistance devices, must be approved



for Class I, Division 1 locations, unless those devices are enclosed in Class I enclo-sures. These devices may be installed in machines with enclosures of TEPV design with the source of air and vent in nonhazardous locations.The exposed surface temperature of motors, generators, other rotating equipment, space heaters and similar ancillary devices must not exceed 80% of the ignition temperature (in degrees C) of the gas or vapor involved when operated at rated voltage. Maximum surface temperature shall be permanently marked on a visible nameplate mounted on the motor. Because all equipment must meet the area classification requirements (Class, Division, and Group), selection of a specific type of motor or generator is dependent on economical, environmental, and corrosion considerations. For motor auxiliary, arcing or high temperature devices, it may be more economical to use purged enclosures for these devices in accordance with NFPA 496. Motor surge arresters of the gapless non-arcing types such as sealed type, metal oxide varistor (MOV) and surge capacitors may be installed in general purpose enclosures for these devices in Division 2 locations. Surge arresters of types other than described above shall be installed in enclosures approved for Class 1, Division 1 locations, as described in NEC Article 501-17. See the Driver Manual for additional information on motors and generators.

Lighting FixturesIn Division 1 areas, lighting fixtures must be explosionproof and marked to indicate the maximum wattage of allowed lamps. They must be protected against physical damage by suitable guard or by location. Pendant fixtures must be suspended by conduit stems and provided with set screws or other effective means to prevent loos-ening. Stems over 12 inches in length must be laterally braced within 12 inches of the fixture.

In Division 2 areas, portable lamps must be explosionproof. Other fixtures must be either explosionproof or labeled as suitable for Division 2 and for the particular Group involved. They must be protected from physical damage by a suitable guard or by location. The requirements above for Division 1 fixtures concerning stems also apply.

Remote mounted ballasts may be mounted at a lower level, facilitating maintenance and extending ballast life if the ballasts would otherwise be mounted in a high temperature area.

Section 1230 of this manual contains a detailed procedure for choosing suitable lighting fixtures. Refer to NEC Article 501-9 for further details on Class I locations.

Receptacles and Attachment PlugsReceptacles and attachment plugs must be approved for Class I locations. This equipment must provide for connection of a flexible cord, grounding conductor.

Ignition SystemsLow tension (voltage) systems must be utilized on all offshore locations and at onshore locations classified Class I, Division 1 or 2. Stationary internal combustion engines with breaker point distributor-type ignition systems should not be used in hazardous (classified) locations unless they are modified in accordance with the



section on internal combustion engines in the Fire Protection Manual. Solid-state ignition systems should be provided as original equipment and as replacements when economically justified. This modification does not eliminate internal combus-tion engines as a possible ignition source but substantially reduces the possibility of an ignition occurring.

In Class I locations, protective boots or covers should be provided for all high voltage (tension) connections. “Standard equipment” high voltage (tension) wiring should be replaced with high temperature silicon rubber ignition wire to reduce arcing to ground through insulation leaks which are common in lower quality wire. Resistance wire with a carbon impregnated linen core should not be used; the conductor is easily broken by bending the wire, making it susceptible to arcing. The use of shielded ignition wire is allowed but not required.

All ignition systems must be designed and maintained to minimize a release of energy sufficient to cause ignition of an external combustible mixture or substance. All wiring should be kept as short as possible, clean, and clear of hot or rubbing objects.

Communication EquipmentStationary radio equipment must not be located or used in any Class I area unless it has a label stating that it is suitable for the area (typically, utilizing intrinsically safe circuits). Many portable hand-held radios used throughout the Company are listed (usually by Factory Mutual) as intrinsically safe or nonincendive. If there are any questions concerning a particular model, consult the Telecommunications Division of Chevron Information Technology Company.

Telephone equipment (including outside ringers) installed in Class I areas must be explosionproof or otherwise suitable for the area.

FlashlightsOrdinary commercial two- and three-cell flashlights present a minimal risk of igniting natural gas and most petroleum vapors. However, under “ideal” conditions, even these ordinary flashlights can ignite flammable gases and vapors. (See UL783, “Electrical Flashlights and Lanterns for Hazardous Locations, Class I, Groups C and D,” for additional information.) Therefore, it is recommended that all flash-lights be approved by a recognized testing laboratory as suitable for Class I, Group D hazardous (classified) locations when they are to be used either (1) on an offshore producing or drilling facility or (2) in Class I hazardous (classified) areas (Division 1 or Division 2) at other facilities. All locations should be reviewed for Class I areas which are other than Group D (e.g., Group B for hydrogen), and if such areas exist, the flashlights used should be suitable for the appropriate classifi-cation (group).

CamerasMost modern cameras (still, video, and movie) utilize batteries for light sensors and may utilize batteries for artificial illumination (flash or continuous) and automatic film advance. Unless cameras have been properly evaluated, it must be assumed that they are a source of ignition (particularly those with flashes or motor drives).



Cameras should not be utilized in hazardous (classified) areas unless it has been verified that either (1) the camera is not capable of ignition or (2) that the area is (and remains) gas/vapor free. The former method generally requires testing by a recognized testing laboratory; the latter method generally requires the utilization of a portable combustible gas detector by a qualified operator. As a practical proce-dure, cameras without either a flash (strobe or flash bulb) or a motor drive may be utilized in open, well ventilated areas which are at least 10 feet from oil and gas processing equipment gas-operated pumps, and similar devices. These may be used after ascertaining from the person-in-charge that no unusual operations (such as venting) are in progress or anticipated. Cameras must not be used in enclosed areas such as buildings which contain producing or drilling equipment, or flammable chemical or gas handling equipment, without first taking the precautions outlined above.

Miscellaneous EquipmentAir conditioning units used in unclassified areas often have equipment exposed to external Class I, Division 2 areas. In such installations, all openings between the internal and external environments must be sealed. Specifically, vents should be sealed closed and sealant should be placed around the perimeter of the wall penetra-tion.

Storage batteries should not be installed in Class I, Division 1 areas. Storage batteries in Class I, Division 2 areas must have explosionproof or hermetically sealed disconnect switches that allow removal of the electrical load before removing battery leads or performing maintenance on battery-powered equipment.

350 Types of Equipment for Class II Hazardous (Classified) LocationsElectrical equipment installed in hazardous (classified) locations must be suitable for the area classification (Class, Division, and Group). This section defines the various types of electrical equipment suitable for use in Class II hazardous (classi-fied) locations. Refer to Section 330 for additional comments.

351 Maximum Operating TemperaturesRefer to Section 331 for a general discussion of maximum operating temperatures. Class I and Class II areas are covered by the same basic maximum temperature requirements. Class II temperature limits are given in NEC Article 500-3(f).

352 Equipment Enclosures“Dust-ignitionproof” enclosures are capable of excluding ignitible quantities of dusts or amounts that might affect performance or rating. When installed and protected in accordance with the NEC they will not permit arcs, sparks or heat within the enclosure to cause ignition of a specified dust on or in the vicinity of the enclosure. Dust-ignitionproof enclosures suitable for use in Class II (Division 1 and 2) locations are designated NEMA (National Manufacturers Association) Type 9.



Explosionproof enclosures are not required and are not acceptable for Class II areas unless they are additionally approved for such areas.

Dust tight enclosures are made with gaskets or other means to exclude dust. They have no openings or knockouts. Conduit entries into dust tight enclosures must be through tapped threads with a minimum of three threads engaged or by a gasketed, bonded conduit hub. The door or cover must be dust tight — obtained with either a securely fastened gasket or closeness of fit of the mating flanges. The door or cover must be captive to the enclosure. Threaded-hub fittings must be dust tight through welding or gasketing. Dust tight enclosures are suitable for Class II, Division 2 loca-tions. They cannot be used in Class II, Division 1 locations. NEMA 3, 3S, 4, 4X, 6, 6P, 12, 12P, and 13 enclosures can be made dust tight.

The surface temperature of the enclosure must not be higher than 80% of the igni-tion temperature (in degrees C) of the dust involved, unless the equipment has been T-rated by a nationally recognized testing laboratory (NRTL).

In order to comply with NEC Article 500-3(b), even if NEMA designations are used, dust-ignitionproof and dust tight enclosures containing equipment and built as a complete assembly (e.g., motor starters) must be labeled with the appropriate Class and Group designations and either the operating temperature or the tempera-ture range. Particular attention must be paid to the Groups(s) listed.

For a complete description of NEMA enclosures and their requirements, refer to NEMA Standards Publication 250.

353 Hermetically Sealed DevicesHermetically sealed devices are designed to prevent combustible dusts from coming in contact with sources of ignition, such as arcing contacts or high-temperature components. These devices are suitable for use in Division 1, Division 2 and unclas-sified areas if they do not exceed 80% of the ignition temperature of the specific dust and they do not exceed the temperatures given in NEC table 500-3(f). The materials used to accomplish hermetic sealing must be resistant to mechanical abuse and durable enough to withstand normal aging, exposure to chemicals and dusts, and the effects of severe weather.

In Class II applications, significant savings can be realized by using hermetically sealed devices since non-dust-ignitionproof enclosures are then allowed. The use of hermetically sealed devices also enables the designer to use NEMA 4X and other enclosures which provide better environmental protection for the enclosed equip-ment (as well as the inherent environmental protection for the hermetically sealed contacts). This feature is particularly desirable in corrosive atmospheres or outdoor installations.

354 Intrinsically Safe SystemsIntrinsically safe systems are described in Section 334. They are suitable for use in any hazardous (classified) location for which they are approved.



355 Nonincendive EquipmentNonincendive equipment is not capable of igniting a specific explosible mixture of dust or an accumulation of combustible dust that will propagate or cause a fire under normal circumstances, but ignition is not necessarily prevented under abnormal circumstances. Such equipment is suitable for use only in Division 2 and unclassified locations. Nonincendive equipment is similar in design to other equip-ment suitable for Division 2 locations. However, in nonincendive equipment, sliding or make-and-break contacts need not be dust-ignitionproof, dust tight, or hermetically sealed.

Portions of a nonincendive system may operate at energy levels potentially capable of causing ignition. Therefore, wiring methods must conform to area classification requirements. Nonincendive equipment normally is limited to instrumentation and communication systems. When employing nonincendive systems, extreme care should be exercised.

356 Pressurized EnclosuresPressurizing is a method of installing electrical equipment in a Class II area without using dust-ignitionproof or dust tight enclosures. NFPA 496 provides information for the design of pressurized enclosures and pressurizing methods to reduce the classification of the area within an enclosure to unclassified.

NFPA 496 discusses the different requirements for the pressurizing of small enclo-sures, power equipment enclosures, and large volume enclosures (such as control rooms). Any source of air for pressurizing must be from an unclassified location.

360 Electrical Equipment Requirements and Recommendations for Class II Hazardous (Classified) Locations

This section discusses the requirements for electrical equipment located in Class II areas and provides recommendations for various applications. Generally, environ-mental and corrosive considerations are outside the scope of this section.

NEC Article 502 provides requirements for wiring and equipment in Class II loca-tions.

The word “approved” as used in this section is defined as “acceptable to the authority having jurisdiction.” Most authorities will require equipment to be tested and approved by a nationally recognized testing laboratory (NRTL), not just built to appropriate standards.

TransformersIn Division 1 areas, transformers containing flammable liquids must be installed in vaults. If they do not contain flammable liquids, they must either be installed in vaults or be approved as a complete assembly for Class II locations. No transformer shall be installed in a location where metal dust may be present.



In Division 2 locations, dry type transformers shall be installed in a vault or have their windings and terminal connections totally enclosed and not operate over 600 volts. Transformers containing flammable liquids must be installed in vaults. Trans-formers containing askarel and rated above 25 kVA shall be provided with pressure-relief vents, be able to absorb gasses generated by arcing, and have an air space not less than 6 inches between the case and combustible material. Also, liquid-filled units may require costly curbing and drains in environmentally sensitive areas.

See NEC Article 502-2 for Class II locations. Refer to NEC Article 450 for addi-tional transformer requirements, particularly concerning vaults.

Arcing and High Temperature DevicesSwitches, motor starters, single phase and DC motors, relays, fuses, and circuit breakers are typical arcing devices. High temperature devices are devices that can operate at a temperature exceeding 80% of the ignition temperature (expressed in degrees C) of the specific dust involved. Space heaters, grounding resistors, and lamps should be considered high temperature devices unless they are T-rated by an NRTL.

In Class II, Division 1 areas where metal dusts may be present, arcing and high temperature devices must be installed in enclosures specifically approved for Class II, Division locations.

In Class II, Division 1 areas, arcing and high temperature devices must be installed in enclosures which are either approved dust-ignitionproof and approved for Class II locations as a complete assembly or pressurized in accordance with NFPA 496.

In Class II, Division 2 areas, arcing contacts must be installed in dust tight or dust-ignitionproof enclosures. High temperature devices in Division 2 locations must be installed in dust-ignitionproof enclosures.

Fuses in Class II, Division 1 areas must be installed in dust-ignitionproof enclo-sures and approved as a complete assembly for Class II locations. In Class II, Divi-sion 2 locations, they must be installed in dust tight or dust-ignitionproof enclosures.

Frequently, it is desirable (for environmental protection) to install hermetically sealed control stations (e.g., hand-off-automatic and start-stop devices) in NEMA 4X or 3R enclosures. These installations are suitable for Division 2 areas if the control station does not exceed 80% of the ignition temperature (in degrees C) of the dust involved.

Refer to NEC Article 502-6 for additional details.

Wiring MethodsThe following wiring methods are allowed in Class II, Division 1 locations:

1. Threaded rigid metal conduit

2. Intermediate metal conduit

3. Type MI (mineral-insulated metal-sheath) cable



4. Dust tight flexible connections

5. Type MC cable, listed for use in Division 1 locations, with a gas/vapor-tight continuously corrugated aluminum sheath, an overall jacket of suitable poly-meric, separate grounding conductors, and other provisions of Article 502-4(a), Exception No. 1, of the 1996 NEC

In Division 2 areas, the NEC allows the Division 1 wiring methods, plus the following:

1. Dust tight wireways

2. Type PLTC (power-limited tray cable) cable in accordance with NEC Article 725

3. Type MC and TC cable, with approved fittings

4. Type ITC (instrumentation tray cable) cable in accordance with NEC Article 727

Flexible cord rated for extra-hard service with an equipment grounding conductor and liquid-tight flexible metal and non-metal conduit (with an external or internal bonding jumper) are also allowed in Class II areas for special applications requiring flexibility. Lengths should be kept as short as possible and cannot exceed 6 feet unless an approved internal bonding system is provided. See NEC Articles 502-16(b), 250-91(b) and 250-79(c) and (f) for additional requirements relative to flex-ible connections.

NEC Article 502-5 contains the requirements for sealing cables and conduits in Division 1 and 2 locations. Seal fittings shall not be required to be explosionproof, and electrical sealing putty is an acceptable method of sealing.

All threaded connections (including enclosures and conduits) should be lubricated with an electrically conductive and enthuses compound which will survive in the environment.

Motors and GeneratorsThe proper selection of motors and generators is imperative to ensure safety and minimize initial and subsequent maintenance costs. Motors and generators should be selected to provide optimum protection from the environment and satisfy the area classification.

Two types of rotating electric machinery are suitable for Class II, Division 1 areas: (1) dust-ignitionproof approved for Class II, Division 1, and (2) totally enclosed, pipe ventilated. Auxiliary equipment, such as space heaters, must also be approved for the location in which it is installed. Refer to NEC Article 502-8 for complete requirements on motors, generators, and other rotating electric machinery used in Class II locations.

If installation in Division 1 locations is unavoidable, dust-ignitionproof machines approved for Class II, Division 1 are preferred. For large motors and generators, it



may be more economical to select totally enclosed pipe ventilated units as described in NEC Article 502-8(a).

In Division 2 areas, motors and generators shall be totally enclosed fan cooled (TEFC), totally enclosed pipe ventilated (TEPV), totally enclosed non-ventilated (TENV), or dust-ignitionproof.

If totally enclosed pipe ventilated units are installed in Class II locations, the venti-lating piping must comply with NEC Article 502-9.

Lighting FixturesIn Division 1 areas, lighting fixtures must be dust-ignitionproof and marked to indi-cate the maximum wattage of allowed lamps. In areas where metal dusts may be present, lighting fixtures must be approved for the specific location. They must be protected against physical damage by a suitable guard or by location. Pendant fixtures must be suspended by conduit stems or chains with approved fittings and provided with set screws or other effective means to prevent loosening. Rigid stems over 12 inches in length must be laterally braced within 12 inches of the fixture.

In Division 2 areas, portable lamps must be dust-ignitionproof. Other fixtures must be either dust-ignitionproof or labeled as suitable for Division 2 and for the partic-ular Group involved. They must be protected from physical damage by a suitable guard or by location. The requirements above for Division 1 fixtures concerning stems also apply.

Remote mounted ballasts may be mounted at a lower level, facilitating maintenance and extending ballast life if the ballasts would otherwise be mounted in a high temperature area.

Section 1230 of this manual contains a detailed procedure for choosing suitable lighting fixtures. Refer to NEC Article 502-11 for further details on lighting fixtures in Class II locations.

Receptacles and Attachment PlugsReceptacles and attachment plugs must be approved for Class II locations. This equipment must provide for connection of a flexible cord, grounding conductor.

Ignition SystemsStationary internal combustion engines with breaker point distributor-type ignition systems should not be used in hazardous (classified) locations unless they are modi-fied in accordance with the section on internal combustion engines in the Fire Protection Manual. Solid-state ignition systems should be provided as original equipment and as replacements when economically justified. This modification does not eliminate internal combustion engines as a possible ignition source, but substantially reduces the possibility of an ignition occurring.

In Class II locations, protective boots or covers should be provided for all high voltage (tension) connections. “Standard equipment” high voltage (tension) wiring should be replaced with high temperature silicon rubber ignition wire to reduce arcing to ground through insulation leaks which are common in lower quality wire.



Resistance wire with a carbon impregnated linen core should not be used; the conductor is easily broken by bending the wire, making it susceptible to arcing. The use of shielded ignition wire is allowed but not required.

All ignition systems must be designed and maintained to minimize a release of energy sufficient to cause ignition of an external combustible mixture or substance. All wiring should be kept as short as possible, clean, and clear of hot or rubbing objects.

Communication EquipmentStationary radio equipment must not be located or used in any Class II area unless it has a label stating that it is suitable for the area (typically, utilizing intrinsically safe circuits). Many portable hand-held radios used throughout the Company are listed (usually by Factory Mutual) as intrinsically safe or nonincendive. If there are any questions concerning a particular model, consult the Telecommunications Divi-sion of Chevron Information Technology Company.

Telephone equipment (including outside ringers) installed in Class II areas must be dust-ignitionproof or otherwise suitable for the area.

CamerasMost modern cameras (still, video, and movie) utilize batteries for light sensors and may utilize batteries for artificial illumination (flash or continuous) and automatic film advance. Unless cameras have been properly evaluated, it must be assumed that they are a source of ignition (particularly those with flashes or motor drives). Cameras should not be utilized in hazardous (classified) areas unless it has been verified that either (1) the camera is not capable of ignition or (2) that the area does not have a substantial amount of airborne dust. The former method generally requires testing by a recognized testing laboratory; the latter method generally requires visible inspection by a qualified operator. As a practical procedure, cameras without either a flash (strobe or flash bulb) or a motor drive may be utilized in open, well ventilated areas which are at least 10 feet from dust processing equipment. These may be used after ascertaining from the person-in-charge that no unusual operations are in progress or anticipated. Cameras must not be used in enclosed areas such as buildings which contain dust handling equipment, without first taking the precautions outlined above.

Miscellaneous EquipmentAir conditioning units used in unclassified areas often have equipment exposed to external Class II, Division 2 areas. In such installations, all openings between the internal and external environments must be sealed. Specifically, vents should be sealed closed and sealant should be placed around the perimeter of the wall penetra-tion.

Storage batteries should not be installed in Class II locations unless provided with suitable enclosures.



370 Area Classification Based on the IEC “Zone” System for Flam-mable Gases or Vapors

Article 505 of the 1996 NEC has introduced the International Electrotechnical Commission (IEC) classification system in the United States. This system has been applied outside of the US for decades. It is not a replacement for the “Division” classification system, but may be used as an alternative under the supervision of a qualified Registered Professional Engineer.

The practical application of the Zone system cannot be used until Nationally Recog-nized Testing Laboratories (NRTL) have standards to approve equipment for use in Zone 0, 1 and 2 locations. These standards are currently under development by a number of ISA committees. Also, the American Petroleum Industry (API) is in the process of developing a recommended practice, similar to RP500, for the Zone clas-sification system.

Figure 300-2 describes the Zone classification system.

Zones 0 and 1 combined, are approximately equivalent to Division 1. Zone 2 is approximately equivalent to Division 2. Equipment listed for Division 1 locations can be installed in Zone 1 locations and equipment listed for Division 2 in Zone 2 locations, but not vice versa. That is, Zone 1 listed equipment cannot be installed in Division 1 locations (which also includes Zone 0); nor can Zone 2 listed equipment be installed in Division 2 locations unless the equipment is NRTL-listed for the specific application.

Figure 300-3 gives a cross reference between the NEC and IEC area classification systems. An IEC concept not yet available for application with an NEC equivalent is the IEC “increased safety” (EX “e”) category. Equipment such as lighting, motors, and electrical heat tracing utilizing the EX “e” protection technique can be applied in Zone 1 locations and will offer a significant cost advantage over explo-sionproof apparatus, after suitable NRTL test standards are complete. Increased safety equipment essentially limits surface temperatures and provides protection against sparking within apparatus, and requires specifically approved and secure terminations.

Generally, the NEC permits all wiring methods allowed in Division 1 to be used in Zone 1 locations, and permits all wiring methods allowed in Division 2 to be used in Zone 2 locations. Only intrinsically safe systems are allowed in a Zone 0 loca-tions. Full applicability of the Zone system awaits the publication of suitable test standards, but these test standards should be fully available by the time that the 1999 NEC is issued.




381 Model Specifications (MS)There are no model specifications in this guideline.

Fig. 300-2 Zone Classification System

Zone Description

Class I, Zone 0 A location:

1. in which ignitible concentrations of flammable gases or vapors are present continu-ously; or

2. in which ignitible concentrations of flammable gases or vapors are present for long periods of time.

Class I, Zone 1 A location:

1. in which ignitible concentrations of flammable gases or vapors are likely to exis-tunder normal operating conditions; or

2. in which ignitible concentrations of flammable gases or vapors may exist frequently because of repair or maintenance operations or because of leakage; or

3. equipment is operated or processes are carried on, of such a nature that equipment breakdown or faulty operations could result in the release of ignitible concentra-tions of flammable gases or vapors and also cause simultaneous failure of electrical equipment in a mode to cause the electrical equipment to become a source of igni-tion; or

4. that is adjacent to a Class I, Zone 0 location from which ignitible concentrations of vapors could be communicated, unless communication is prevented by adequate positive-pressure ventilation from a source of clean air and effective safeguards against ventilation failure are provided.

Class I, Zone 2 A location in which:

1. ignitible concentrations of flammable gases or vapors are not likely to occur in normal operation and if they do occur will exist only for a short period; or

2. in which volatile flammable liquids, flammable gases, or flammable vapors are handled, processed, or used, but in which the liquids, gases, or vapors normally are confined within closed containers or closed systems from which they can escape only as a result of accidental rupture or breakdown of the containers or system, or as the result of the abnormal operation of the equipment with which the liquids or gases are handled, processed, or used; or

3. in which ignitible concentrations of flammable gases or vapors normally are prevented by positive mechanical ventilation, but which may become hazardous as the result of failure or abnormal operation of the ventilation equipment; or

4. that is adjacent to a Class I, Zone 1 location, from which ignitible concentrations of flammable gases or vapors could be communicated, unless communication is prevented by adequate positive-pressure ventilation from a source of clean air, and effective safeguards against ventilation failure are provided.





384 Other ReferencesVarious organizations have developed numerous codes, guides and standards that are widely accepted by industry and governmental bodies. Codes, guides and stan-dards useful in classification of locations for electrical installations and selecting equipment for these locations are listed below as references only. These are not

Fig. 300-3 Cross Reference Between NEC and IEC for Classified Locations of Gases and Vapors

Classification Topic NEC IEC

Locations Class IGroup AGroup BGroup CGroup D

Group II≈ IIC≈ IIB plus Hydrogen≈ IIB≈ IIA

Divisions (Zones) Division 1Division 2

Zone 0 & Zone 1Zone 2

Type of Protection Intrinsically Safe Division 1 andDivision 2

ExplosionproofNEMA Type 7Division 1,2

PurgedDivision 1, 2

Hermetically sealed Division 2Nonincendive Division 2

Intrinsically SafeEx Type ia, Zone 0, 1, 2Ex Type ib, Zone 2

FlameproofEx Type dZone 1,2

PressurizationEx Type p, Zone 1,2

Ex Type h, Zone 1

Ex Type n, Zone 2

Identification Number (NEC) T1 450°CT2 300°CT3 200°C T4 135°CT5 100°CT6 85°C

T1 450°CT2 300°CT3 200°C T4 135°CT5 100°CT6 85°C

GF-P99987 Typical Area Classification for Selection of Electrical Equip-ment—Process Plant, Tank Field and T.T.L.R.

ELC-EF-652 Conduit Stub-up Arrangement



considered to be a part of this guideline except as they are specifically referenced within the text.

American Petroleum Institute (API)RP 2G Recommended Practice for Production Facilities on Offshore Structures

RP 14C Recommended Practice for Analysis, Design, Installation, and Testing of Basic Surface Safety Systems for Offshore Production Platforms

*RP 14F Design and Installation of Electrical Systems for Offshore Production Platforms

*RP 500 Recommended Practice for Classification of Locations for Electrical Installations at Petroleum Facilities

RP 540 Recommended Practice for Electrical Installations in Petroleum Processing Plants

International StandardsThe International Electrotechnical Commission (IEC) Publication 79-7 and Complete Series

The European Committee for Electrotechnical Standardization (CENELEC) Publi-cation CEN 110.83

National Fire Protection Association (NFPA)*ANSI/NFPA 30 Flammable and Combustible Liquids Code

ANSI/NFPA 30A Automotive and Marine Service Station Code

ANSI/NFPA 58 Standard for the Storage and Handling of Liquified Petroleum Gases

ANSI/NFPA 69 Explosion Prevention Systems

ANSI/NFPA 70 National Electrical Code

ANSI/NFPA 321 Basic Classification of Flammable and Combustible Liquids

ANSI/NFPA 325M Fire Hazard Properties of Flammable Liquids, Gases & Vola-tile Solids

ANSI/NFPA 491M Hazardous Chemical Reactions

*ANSI/NFPA 496 Standard for Purged and Pressurized Enclosures for Electrical Equipment

*ANSI/NFPA 497A Classification of Class I Hazardous (Classified) Locations for Electrical Installations in Chemical Process Areas

*ANSI/NFPA 497M Manual for Classification of Gases, Vapors, and Dusts for Electrical Equipment in Hazardous (Classified) Locations

NFPA Fire Protection Handbook



NFPA Electrical Installations in Hazardous Locations, Peter J. Schram and Mark W. Easley

Underwriters’ Laboratories, Inc. (UL)UL 58 Bulletin of Research No. 58, An Investigation of Fifteen Flammable Gases or Vapors With Respect to Explosionproof Electrical Equipment

UL 58A Bulletin of Research No. 58A, An Investigation of Additional Flammable Gases or Vapors With Respect to Explosionproof Electrical Equipment

UL 58B Bulletin of Research No. 58B, An Investigation of Additional Flammable Gases or Vapors with Respect to Explosionproof Electrical Equipment

ANSI/UL 595 Marine-type Electric Lighting Fixtures

ANSI/UL 674 Electric Motors and Generators for Use in Hazardous Locations, Class I, Groups C and D, Class II, Groups E, F and G

ANSI/UL 698 Industrial Control Equipment for Use in Hazardous (Classified) Locations

ANSI/UL 844 Electrical Lighting Fixtures for Use in Hazardous (Classified) Loca-tions

ANSI/UL 913 Intrinsically Safe Apparatus and Associated Apparatus for Use in Class I, II, and III, Division 1, Hazardous Locations

UL 1604 Electrical Equipment for Use in Hazardous Locations, Classes I and II, Division 2, and Class III, Divisions 1 and 2

Factory Mutual Research Corporation (FM)Approval Standard Class No. 3611 Electrical Equipment for Use in Class I, Divi-sion 2, Class II, Division 2, and Class III, Divisions 1 and 2 Hazardous Locations

Handbook of Industrial Loss Prevention

Institute of Electrical and Electronics Engineers (IEEE)ANSI/IEEE 45 IEEE Recommended Practice for Electric Installations on Ship-board

ANSI/IEEE 303 IEEE Recommended Practice for Auxiliary Devices for Motors in Class I, Groups A, B, C and D, Division 2 Locations

National Electrical Manufacturers Association (NEMA)NEMA 250 Enclosures for Electrical Equipment (1000 volts maximum)

Instrument Society of America (ISA)ISA RP 12.1 Electrical Instruments in Hazardous Atmospheres

ANSI/ISA RP 12.6 Installation of Intrinsically Safe Systems for Class I Hazardous (Classified) Locations



ISA S 12.10 Area Classification in Hazardous (Classified) Dust Locations

ISA S 12.12 Electrical Equipment for Use in Class I, Division 2 Hazardous (Classi-fied) Locations

ISA S 12.13, Part I, Performance Requirements, Combustible Gas Detectors

ANSI/ISA RP 12.13, Part II, Installation, Operation, and Maintenance of Combus-tible Gas Detection Instruments

Chevron Corporation Practices and StandardsChevron U.S.A. Inc., Eastern Region—Exploration, Land & Production, Electrical Construction Guidelines for Offshore, Marshland, & Inland Locations


Government Codes, Rules, and RegulationsCode of Federal Regulations, Title 29, Labor, Chapter XVII, OSHA, Part 1910, OSHA Standard Subpart H, Hazardous Materials, Paragraph 1910.106

Code of Federal Regulations, Title 29, Labor, Chapter XVII, OSHA, Part 1910, OSHA Standards, Subpart S, Electrical

Code of Federal Regulation, Title 30, Part 250, Oil and Gas and Sulphur Operations in the Outer Continental Shelf (Minerals Management Service)

Code of Federation Regulations, Title 46, Shipping, Chapter I, Coast Guard, Depart-ment of Transportation, Subchapter J, Subpart 111.105 Hazardous Locations

United States Department of Interior, Bureau of Mines, Flammable Characteristics of Combustible Gases and Vapors, Bulletin 627

American Bureau of Shipping, Rules for Building and Classing Mobile Offshore Drilling Units

Miscellaneous ReferencesAppleton NEC Code Review (Appleton Electric Company)

Code Digest (Crouse Hinds Company)


400 Motor Control Centers

AbstractThis section assists the engineer with selecting 600 volt, 2400 volt, and 5 kV motor control centers (MCCs). It also discusses the relationship of motors and starters, control methods, ratings, enclosures, selection and customizing.

Contents Page


411 Motor Starters—Basics

412 Motor Control Centers—An Overview

420 Motor Starters (Controllers) 400-4

421 Combination Starter (Low Voltage)

422 Manual Starter

423 Motor Starter (Medium Voltage)

424 Adjustable Speed Controllers

430 Control Circuit 400-6

431 Contactors

432 Control Wiring Methods

433 Control Power Sources

440 Starting Methods for Motors 400-10

441 Full-Voltage Starting

442 Reduced-Voltage Starting

443 Reduced-Inrush Starting

444 Adjustable Speed Drives

445 Capacitor Starting

450 Motor Protection 400-15

451 Low Voltage Motor Protection

452 Medium Voltage Motor Protection

400 Motor Control Centers Electrical Manual


453 Overvoltages

454 Surge Arrestors

460 NEMA Ratings 400-18

461 Starter Ratings

462 Low Voltage MCC NEMA Classes and Types

463 Bus Bracing

464 Medium Voltage MCC

470 Enclosure Types 400-20

480 Selecting Equipment Types and Characteristics 400-21

481 Design Specifics

482 Checklist






Electrical Manual 400 Motor Control Centers


410 IntroductionThis section is a guide for the selection of motor control centers (MCCs). Common types of controllers are discussed.

411 Motor Starters—BasicsA motor starter (controller) normally contains the following equipment:

• A means of disconnecting the controller from the power supply and protecting against short-circuit damage (either circuit breakers, switches, fuses or a combi-nation of these)

• A means of connecting the power supply to the motor (a contactor)

• A means of protecting the wiring system and motor from overload or abnormal conditions (overloads)

412 Motor Control Centers—An OverviewA motor control center (MCC) groups multiple motor controllers into one enclosure and combines motor control equipment with electrical power feeders. The control equipment includes starters, contactors, circuit breakers, fuses, switches, relays, metering and auxiliary devices. See Figures 400-1 and 400-2.

Low voltage MCCs are available for systems up to 600 volts and are primarily used to control 460-volt motors. Medium voltage MCCs are available for systems up to 7200 volts. Two types of medium voltage MCCs are available. One type is rated for 4800 volts and is used to control 2300-volt and 4000-volt motors. The other type is rated for 7200 volts; however, it is more common to use electrically operated circuit breakers to control motors above 4800 volts. Electrically operated circuit breakers may also be used to control 460-volt motors 200 hp and larger. See Section 500, “Switchgear,” for information about switchgear used as motor starters.

To specify motor controllers, the following Company documents are available:

• Data Sheet ELC-DS-366 and Data Sheet Guide for 480-volt MCCs

• Explosionproof 480-volt motor control (switch) racks, Data Sheet ELC-DS-597 and Data Sheet Guide

• MCCs for 2300 volt and 4000 volt motors: use Specification ELC-MS-3977, Data Sheet ELC-DS-3977 and Data Sheet Guide

• Adjustable frequency drives: use Specification ELC-MS-4371, Data Sheet ELC-DS-4371 and Data Sheet Guide



420 Motor Starters (Controllers)A motor starter (controller) is an electric device that provides the basic functions of starting and stopping a motor. It can be used for speed reduction, braking, reversing, speed variation, and protection. Four types of motor starters are discussed below.

421 Combination Starter (Low Voltage)Combination starters are the most common starters used in low voltage MCCs. A combination starter combines a contactor, short circuit protection, and a disconnect in one enclosure. It has several advantages over separately mounted starters and disconnects. It requires less space, less time to install and connect, and provides greater safety through mechanical interlocks.

The standard low voltage combination motor starter includes the following devices:

Fig. 400-1 Low Voltage Motor Control Center Three Vertical Sections



• Magnetic-only circuit breaker (“Motor Circuit Protector”) having only an instantaneous (no-delay) characteristic

• Contactor (an electrically operated relay)

• Overload relay (see Section 600)

• Control-power transformer which supplies control power for starter control circuit (usually 120-volt AC)

422 Manual StarterManual starters normally are not used, but can be used with motors up to approxi-mately 10 hp; however, they are most commonly used with fractional-horsepower equipment. A manual starter has a contact mechanism (hand operated) and overload protection. Basically, it is an on-off switch with an inherent (direct-acting) overload-protection device. It is applied directly across full-line voltage. Standard manual starters cannot provide under-voltage protection. That is, if power fails the contacts

Fig. 400-2 Medium Voltage Motor Control Center



remain closed; when power returns, the motor will immediately restart. This can be an advantage when the equipment is required to restart after power outage. For some applications, automatic restarting can be hazardous to personnel and/or to equipment.

423 Motor Starter (Medium Voltage)Medium voltage motor starters employ (a) a no-load break switch and current limiting fuses instead of a circuit breaker for isolation and short circuit protection; (b) a stationary or draw-out type air or vacuum contactor; and (c) overload devices. Motor protection is discussed in Section 452.

Medium voltage starters are available in one, two, or three-high enclosures (see Figure 400-2). Stacking two-high is recommended to provide lower cost MCCs while maintaining ease of maintenance. Stacking three-high is not recommended because it makes maintenance difficult.

424 Adjustable Speed ControllersAdjustable frequency drives are used to provide speed control for AC motors and may be used for soft starts to minimize voltage drop. In adjustable speed control-lers, solid state components produce a variable frequency AC output to provide speed variations. This method of control is used with equipment which has large turndowns between startup and final operating conditions, with solids handling systems, or with fluid flow control applications. These applications should be referred to an experienced electrical engineer or to the Materials and Equipment Engineering Unit of CRTC for assistance. Specification ELC-MS-4371 and Data Sheet ELC-DS-4371 can be used to specify these controllers. Section 1500 of the Electrical Manual provides guidelines for applying adjustable speed drives.

Adjustable speed can also be provided by varying the voltage to DC motors. DC motors with adjustable speed controllers are used for high starting torque applica-tions. No Specification or Data Sheets are provided. This application should also be referred to an experienced electrical engineer or the Materials and Equipment Engi-neering Unit of CRTC for assistance.

430 Control Circuit

431 ContactorsThe magnetic contactor is the primary device in all motor starters. It is the compo-nent in a controller that actually closes and opens the circuit between the energy source and the motor. A contactor combined with a thermal overload unit is called a magnetic starter.

The contactor is controlled by a relatively small flow of current through the coil of an electromagnet. Electrical power contacts large enough to handle motor current are mounted on the armature. When proper voltage is applied to the coil, the power



contacts close. The contacts, wired in series with the power circuit, provide power to the motor. When voltage is removed from the coil, the power contacts open.

A contactor must be capable of closing on, and carrying high inrush currents without undergoing undue degradation from either the currents or the applied voltage. NEMA standards establish maximum operating conditions of six-times full load motor current (FLA) for AC motors, four times for DC motor reduced voltage starters, and 10 times for DC across-the-line full voltage starters.

NEMA standard ICS 2 lists eleven sizes (00, 0, and 1 through 9) of low voltage (600 volt maximum) contactors for use in across-the-line full voltage controllers (see Figure 400-3). These NEMA sizes correspond to motor horsepower. The Company does not recommend using sizes smaller than NEMA size 1. A size 1 will control small motors for a small increase in equipment cost and reduce the amount of spare parts required. Contactors larger than NEMA size 5 are not recommended. Instead vacuum contactors or air breakers should be used.

Auxiliary ContactsStarters usually come equipped with auxiliary contacts which are available normally open or normally closed and mechanically interlocked with the main power contacts of the starter. Auxiliary “a” contacts close when the power contacts close; “b” contacts open when the power contacts close.

These auxiliary contacts are used for control, display, alarms, and interlocking purposes. They should be specified when the starter is ordered.

Fig. 400-3 NEMA ICS Standard Continuous Ratings for Low Voltage Starters NEMA. Used with permission.

3-PHASE HORSEPOWER AT VOLTAGE LISTED BELOW

Size of Controller

Continuous- current Rating, A 110 Volts 208/230 Volts 460/575 Volts

Service-limit Current Rating, A

00 9 0.75 1.5 2 11

0 18 2 3 5 21

1 27 3 7.5 10 32

2 45 - 15 25 52

3 90 - 30 50 104

4 135 - 50 100 156

5 270 - 100 200 311

6 540 - 200 400 621

7 810 - 300 600 932

8 1,215 - 450 900 1,400

9 2,250 - 800 1,600 2,590



Thermal OverloadThe portion of the wiring that includes the coil of the starter (or contactor) and over-load contacts, is called the control circuit. It opens when excessive (overload) current is sensed by the thermal units in the power circuit. Operation of the thermal units causes the overload contacts in the control circuit to open, removing voltage from the coil. This in turn causes the power contacts to open, interrupting current to the motor.

Control Circuit DevicesControl-circuit devices (e.g., pushbuttons, level switches, limit switches, relay contacts, and PLC contacts) can be wired into the control circuit.

432 Control Wiring MethodsSeveral control methods are shown on Engineering Form ELC-EF-592. The basic methods of motor control are discussed below.

Three-Wire Control (Start-Stop Station)“Start-Stop” pushbutton stations require the use of three wires between the control station and the starter. The “Start” button is connected parallel with the seal-in contact. In the event of a power failure, the starter will drop out and remain de-ener-gized until the “Start” button is depressed. See Figure 400-4.

Two-Wire ControlTwo-wire control is generally used for pilot devices such as thermostats, pressure switches, level switches or selector switches. As the term implies, these devices require the use of two wires between the control unit and the starter. The device is connected in series with the contactor coil of the starter. This arrangement is gener-ally referred to as “maintained contact” (i.e., the equipment will restart following a power outage.)

Fig. 400-4 Three-Wire Control With Control-Power Transformer (CPT) (From Switchgear and Control Handbook by R. Smeaton, 1987. Used by permission from McGraw Hill, Inc.)



The opening or closing of two wire pilot devices directly de-energizes or energizes the starter. Run-Off-Auto or Hand-Off-Auto switches are modified versions of the two-wire control.

Two-wire control is not recommended for applications where automatic restarting (after a power outage) of equipment can be hazardous to personnel and/or detri-mental to equipment. Examples of applications where automatic restart could be considered undesirable are drill presses and conveyors. This type of control is used for critical pumps, refrigeration compressors or cooling fans, which can be safely restarted to maintain system integrity.

433 Control Power Sources

Control-Power Transformer (CPT)Integral CPTs (CPT in each starter enclosure) are frequently used to provide low voltage control power where the system voltage is higher than the desired control circuit voltage (usually 120 volts). This method is most commonly used because it eliminates foreign voltage at the motor or motor starter when the starter breaker is opened for maintenance. Also, only the affected motor shuts down when there is a CPT failure since each motor has its own CPT. The disadvantage of this method is that space heaters powered from the CPT will not be energized when the starter breaker is opened. The CPT should be fused to protect the control circuit and the starter against damage from short circuits in the control devices. See Figure 400-4.

Common ControlWhen the control and power circuits are powered from a single common source, it is called common control. The control voltage is the same as the power voltage. This method may be used up to 480 volts, but it is not recommended above 120 volts. See Figure 400-5.

Fig. 400-5 Common Control (Not Recommended) (From Switchgear and Control Handbook by R. Smeaton, 1987. Used by permission from McGraw Hill, Inc.)



Separate ControlA method of avoiding high voltages in the control circuit is to power the control circuit from a remote low voltage source. This method, though less expensive than the integral control power transformer scheme, is not recommended for safety reasons. The source of power usually is not disconnected when the starter breaker is opened unless a circuit breaker auxiliary contact (normally open) is used. See Figure 400-6.

440 Starting Methods for MotorsA comparison of starting currents and torques produced by various types of reduced voltage starters is shown in Figures 400-7 and 400-8.

441 Full-Voltage StartingMost AC motors are started by connecting them directly across the supply lines. This is referred to as “full voltage” or “across the line starting.” However, both a power system capable of supplying full voltage and inrush current as well as a starter capable of carrying the inrush current are required to prevent unacceptable voltage dips in the system.

442 Reduced-Voltage StartingOccasionally, the size or characteristics of a motor or the power system are such that the initial inrush of starting current from full across-the-line voltage is so large that it would cause an unacceptable voltage drop in the supply voltage. This can affect other equipment supplied by the same utilization system. See Section 200, “System Studies and Protection,” for a discussion of voltage drop during motor starting and how it affects motor torque.

Reduced voltage starting or “soft-starting” is used to start motors without causing unacceptable voltage drop. See Figures 400-7 and 400-8 for the effect on motor torque. In a closed-circuit transition, power to the motor is not interrupted during the starting sequence. In an open-circuit transition, it is. Closed-circuit transition mini-

Fig. 400-6 Separate Control (From Switchgear and Control Handbook by R. Smeaton, 1987. Used by permission from McGraw Hill, Inc.)

Electrical Manual

400 Motor Control Centers

Chevron Corporation400-11

May 1996

Fig. 400-7 Types of Motor Starting (Courtesy Electric Machinery, Synchronizer)

Starting Characteristics In Percent Of Rated Starting Values

MotorTerminalVoltage

Motor Current

Line Current Torque

TorquePer kVA

1 FULL VOLTAGE STARTING

Full voltage starting gives the highest starting torque effi-ciency - that is, the highest torque per starting kVA. Full voltage starting should always be used unless (1) power system disturbance makes reduced current inrush necessary, (2) torque increments are required in starting.

100 100 100 100 100

2 PART-WINDING STARTING

Reduced inrush, closed transition starting by connecting the sectionalized, parallel stator windings to the line in two or more steps. This type of starting requires no auxil-iary current reducing device and uses simple switching. If the motor can be designed for part-winding starting, resultant starting torque and reduced inrush possibilities may meet the requirement of the load and system at least possible expense.

100 70 HIGH SPEED 70

50(1) 72

100 50(1) LOW SPEED 55

50 90

3 REACTOR OR RESISTOR STARTING

Reduced inrush, closed transition, starting by inserting impedance (reactor) or resistance (resistors) in the circuit during motor starting. Torque per kVA is lower than with auto-transformer starting. For increment starting, more than two resistance steps may be used.

80 80 80 64 80

65 65 65 42 65

50 50 50 25 50

4 AUTO-TRANS-FORMER STARTING (Closed transition)

Reduced inrush by using an auto-transformer to reduce voltage to the motor. Addition of switches in the auto-transformer interconnection provides closed transition in transfer to full voltage. Ratio of starting torque to starting kVA is highest with this type of starting.

80 80 64 64 100

65 65 42 42 100

50 50 25 25 100

5 WYE-DELTA STARTING (Closed transition)

Reduced inrush by switching the windings on a motor designed for wye-delta connection. Provides closed tran-sition by use of a small resistor inserted during transfer. When wye connected, winding voltage is 58% rated.

100 33 33 33 100

(1) These values are for 2-step part-winding starting and are approximate. Actual values will vary with the motor design and application.



Fig. 400-8 Starting Methods (1 of 2) (Courtesy Electric Machinery, Synchronizer)



Fig. 400-8 Starting Methods (2 of 2) (Courtesy Electric Machinery, Synchronizer)



mizes inrush voltage disturbances and is recommended for all applications of reduced-voltage starting.

Methods of Reduced-Voltage Starting

Auto-TransformerThe auto-transformer starter is usually provided with two or more taps. Motor current is reduced in direct proportion to the voltage applied at the motor terminals. The line current is reduced in proportion to the square of the motor-terminal voltage because of the auto-transformer action. Thus a high value of torque is produced per unit of starting current.

With an auto-transformer, adjustments of torque and inrush current can easily be made in the field by selecting a different voltage tap (e.g., 50%, 65%, or 80%).

Auto-transformer starters are the most widely used reduced-voltage starters because of their high efficiency and flexibility. All power taken from the line, except trans-former losses, is transmitted to the motor. A disadvantage is that they are generally the most expensive reduced-voltage starting method.

Primary ResistorThe primary resistor method of reduced-voltage motor starting provides series resis-tors in each phase of the motor primary circuit. Resistance value is reduced in one or more steps until full voltage is applied to the terminals. Inrush current is limited by the resistors. Starting torque is a function of the square of the applied voltage; therefore, if the initial voltage is reduced to 50%, the starting torque of the motor will be 25% of its full-voltage starting torque. A compromise must be made between the required starting torque and the inrush current.

Primary ReactorThe primary reactor method of reduced-voltage motor starting is similar to resistor starting, but separate reactors are necessary for each step since a portion of a reactor cannot be short-circuited as with a resistor. Starting characteristics can be adjusted by tap selection.

443 Reduced-Inrush StartingThere are two principal methods of minimizing the initial inrush of starting current to a motor without reducing voltage. These methods require special motor configu-rations as well as special starters.

• Part-Winding

The part-winding method is attractive due to its simplicity, and it is generally the least expensive of the techniques for reducing starting currents. It uses only part of the motor winding on starting, and therefore is not suitable for motors which drive equipment demanding high torques during acceleration.

• Wye-Delta



In general, wye-delta starters cost less than auto-transformers or primary-resistor starters. However, they are more expensive for some ratings. Starting torque is only one-third of that at rated voltage. The delta wound motor is started with the wind-ings connected in a wye and then switched to run with the windings connected in a delta.

444 Adjustable Speed DrivesAdjustable frequency drives produce a soft start, as well as speed control by starting the motor at low speed and increasing until full running speed is reached. These solid state motor controllers increase voltage to induction motors during starting, thereby reducing inrush currents and also torques. They typically control the volts/hertz ratio. As the motor speed (frequency) increases, the voltage level is increased.

445 Capacitor StartingMotor starting shunt capacitors are switched on with the motor. They provide reac-tive (magnetizing) current to the motor during starting, thereby reducing the voltage drop on the power system. The capacitor is switched off when the motor is up to speed.

450 Motor ProtectionSee Section 600, “Protective Devices” for more details of motor protection.

451 Low Voltage Motor Protection

Disconnect RatingThe minimum required rating of the breaker or fused disconnect is determined by the MCC short-circuit rating. The short-circuit rating can usually be found on the one-line diagram or in the system study. The following methods and devices for motor protection are recommended.

Short Circuit ProtectionShort circuit protection and a means to disconnect the motor from its source are provided by a circuit breaker or a fused disconnect switch.

Molded-Case Circuit BreakersMolded-case circuit breakers with thermal magnetic trip elements, used for motor starters for many years, are gradually being replaced by motor circuit protectors (see below).



Motor Circuit ProtectorsMotor Circuit Protectors (MCPs) are magnetic trip-only circuit breakers available in size graduations that match starter and motor sizes. They provide protection against fault currents and feature an adjustment for setting the minimum trip value. This feature allows for faster tripping and offers better protection than molded-case circuit breakers.

A current-limiting attachment (attached to the load side of the MCP) can be used to provide an interrupting rating up to 100,000 amperes. The current-limiter is coordi-nated with the MCP so that short circuits will be cleared by the MCP. Only high fault currents will cause the current limiter to function.

Fused Disconnect SwitchA fused disconnect switch provides short circuit protection and a means of discon-nect. It is used as an inexpensive method for providing short circuit protection, but has the disadvantage of not being resettable (damaged fuses must be replaced).

Overload ProtectionMotor overload protection is provided by thermal overloads which interrupt the control circuit and cause the contactor to open. See Figure 400-4.

452 Medium Voltage Motor ProtectionTwo methods are used to control medium voltage motors: current-limiting starters and switchgear-type circuit breakers. Although current-limiting fuses provide short circuit protection for current-limiting starters, relays or other protection devices listed below should also be used in both methods. Solid state relay devices for medium voltage motors are available and may be used instead of the individual devices listed below.

The type of service and whether or not the motor is spared should be considered when evaluating relay application. The extent of motor protection should be consis-tent with the protection philosophy of the driven equipment.

Winding RTDs should be installed in critical motors and motors subject to “threat-ening” situations, such as blocked filters on WPII motors and water shutoff on TEWAC motors. Bearing RTDs should be applied to critical motors consistent with the driven equipment protection.

Under 500 HP (suggested breakpoint):

Thermal Overloads Ambient Compensated, Bimetallic

Instantaneous Ground Fault Relays (50G). These should be used only on low resistance grounded systems, provided fault current is less than contactor inter-rupting capacity.

Relays Recommended for 500 HP and Above (suggested breakpoint):

Thermal Overload Relay, Replica Type (49)



Time Overcurrent (Locked Rotor) (51)

Phase-Balance and Single-Phase (46)

Lockout, with external reset (86)

Instantaneous Ground Fault Relays (50G). These should only be used on low resistance grounded systems provided fault current is less than contactor inter-rupting capacity.

Bearing RTD relay (38)

Winding RTD relay (49)

Additional Relays Recommended for 1500 HP and Above (suggested break-point):

Differential Current Relay (87)

Additional Relays Recommended for Synchronous Motors:

Incomplete Sequence (48)

Power Factor (55) for Pullout Protection

453 OvervoltagesFor a detailed discussion of overvoltages, see Chapter 4 of IEEE Standard 141 (Red Book.)

A number of disturbances can occur in the distribution system supplying power to an MCC and its motors. These include the following:

• Lightning strikes and operation of lightning arresters• Forced-current zero interruptions (such as operation of a current-limiting fuse)• Operation of circuit breakers and reclosers• Fault conditions• Accidental contact with higher voltage systems

Motors are vulnerable to high rate-of-rise surge voltages. In general, the highest stress is across the first few turns of the winding since the voltage of the surge is attenuated as it progresses through the winding.

A portion of the surge is reflected along the incoming conductor back toward the source, and the rest is passed through to the motor winding. This effect is most severe when the motor surge impedance is much larger than that of the incoming conductor. This refracted voltage can approach twice the incoming voltage level (already very high in the surge) for motors with high surge impedance.

For surge protection, surge capacitors (connected from each phase to ground at the incoming motor cable terminals) are recommended. Leads to the motor should be kept as short as possible.



Surge capacitors of the proper value will reduce the rate of rise of an incoming wave to a tolerable value. Recommended values are as follows:

• 1.0 microfarad for low voltage motors (600 volts and below)• 0.5 microfarad for 2.3-6.9 kV motors• 0.25 microfarad for motors above 6.9 kV

Surge capacitors generally are not used on motors of 460 volts and below, unless they are supplied by uninsulated overhead lines.

454 Surge ArrestorsMachines connected to circuits which are exposed to lightning require surge arres-tors to limit the peak of the voltage surge. Station arrestors designed for rotating machines are available in ratings of 3 to 27 kV. Until recently, surge arrestors were constructed with nonlinear resistors made of bonded silicon carbide. However, a new type of arrestor has become the industry standard: the metal-oxide surge arrestor (MOSA). The MOSA draws only a few milliamperes of line current at normal system voltage. During a surge, only the current necessary to limit the over-voltage is conducted. Therefore, there is positive clearing after the surge has passed.

Specifics regarding performance of MOSAs are given in Table 19 of IEEE 141 (Red Book).

460 NEMA Ratings

461 Starter RatingsFigure 400-3 lists NEMA ICS standard continuous ratings for low voltage starters and can be used for preliminary size selection of a motor starter. It provides typical full-load current based on horsepower, speed, and voltage. Final selection of a motor starter should be based on specific motor data. These data are available from the nameplate of the motor or from certified drawings provided by the manufacturer.

462 Low Voltage MCC NEMA Classes and TypesThere are two MCC NEMA classes: Class I and Class II. These classes pertain to factory-provided interwiring or interlocking and define where field terminations are made on the MCC. Class II, Type B is recommended for most applications. Details on NEMA classes are presented below.

NEMA Classes

Class I: Class I MCCs consist of a mechanical grouping of combination motor starters, feeders, and/or other units, arranged in an assembly with only power connections furnished. They do not include interwiring or interlocking between units and remotely mounted devices. Nor do they include control-system engi-neering. Diagrams of only the individual units are supplied. Class I is generally



specified for independently operated motors requiring no interlocking or other inter-connection between units.

Class II: Class II MCCs consist of a grouping of combination motor controllers, feeders, and/or other units designed to form a complete control system and are recommended for most applications. They include the necessary electrical inter-locking and interwiring between units and interlocking provisions for remotely mounted devices, in addition to the power connections. The MCC manufacturer should provide a suitable diagram showing all controls associated with the MCC.

Class II is generally specified when a group of motors requires sequencing, inter-locking, or interconnecting.

NEMA Types

Type A: Applicable to Class I only, field terminations are made directly to the unit components. No terminal blocks are supplied on the units for load or control connections.

Type B: Applicable to both Class I and II, unit-mounted control terminal blocks are supplied. Unit load terminal blocks are provided for size 3 and smaller starters. Load terminals are not supplied for feeder units. Type B is recommended for most applications.

Type C: Applicable to both Class I and II, Type C MCCs are similar to Type B MCCs with the addition of the master-section terminal boards. Wiring between combination controllers, or control assemblies, and the master terminal boards is provided.

463 Bus BracingBuses must be braced to withstand the maximum of short-circuit currents available. NEMA standards for bracing are based on ratings of 10 kA, 14 kA, 30 kA, and 42 kA rms symmetrical. Buses rated 65 kA and 100 kA symmetrical are also available. The bracing of the horizontal and vertical buses of the MCC should be coordinated with the rating of the incoming line and the type of short-circuit protection employed in the MCC.

464 Medium Voltage MCCMedium voltage starters are labeled NEMA Class EI if the contacts are used for interrupting short circuit current, and are labeled NEMA Class EII if fuses are used for interrupting short circuit currents. The size of the contactor has a NEMA desig-nation of H2, H3, H4, or H5, corresponding to specific continuous current ratings and interrupting ratings. For more detail refer to NEMA Publication No. ICS 2. The most commonly used contactors are H3 (rated for 400 A continuous) and H5 (rated for 700 A continuous). Refer to the NEMA ICS 2 or manufacturer’s data for specific motor sizes and voltage ratings.



470 Enclosure TypesNEMA Standards 250-295 and ICS 6-1983 describe enclosures according to their environmental capabilities. The recommended enclosure for outdoor use is Type 3R, but, Type 4X and Type 7 are used for certain applications. For most indoor applica-tions, Type 1A (with neoprene gasketing) is recommended.

• Type 1 (General Purpose)– Type 1A (Type 1 with neoprene gasket)

Type 1A enclosures are for general-purpose use indoors where they are not exposed to unusual service conditions. Their primary purpose is to prevent accidental contact with the enclosed equipment by personnel. They provide some protection against dust and falling dirt, but are not dust-tight. They also offer limited protection against light splashing and indirect splashing.

• Types 3 and 3R (Outdoor)

Types 3 and 3R enclosures provide a degree of protection against windblown (for Type 3) and falling (for Type 3R) dust, rain, and sleet, as well as against external ice formation.

– Type 3S (Outdoor)Type 3S enclosures provide the protection of Type 3 and 3R enclosures, plus opera-tion of external mechanisms when ice laden.

• Type 4 and 4X (Indoor and Outdoor)

Type 4 and 4X enclosures provide protection against dripping or splashing water and are dust-tight. NEMA Type 4 enclosures can be used either in indoor or outdoor locations. NEMA Type 4X enclosures are corrosion resistant.

• Type 7 and 9

If it is necessary to locate motor starters in classified areas, refer to Section 300, “Hazardous (Classified) Areas.” In such instances, starters housed in explosion-proof enclosures suitable for the specific area must be used (Type 7 for Class I and Type 9 for Class II). If weather protection is needed in a classified area, a NEMA 7 or 9 UL listed enclosure with NEMA 4 features should be specified.

Explosionproof equipment is listed by the Class and Group appropriate for the loca-tion in which the ignitable material may be present. See Section 300, “Hazardous (Classified) Areas.”

ELC-DS-597, Motor Control Rack Specification and Arrangement, is useful for specifying explosionproof starters.

The two types of explosionproof enclosures are screwed-cover and ground joint bolted-cover. See Section 300, “Hazardous (Classified) Areas,” for more informa-tion.



480 Selecting Equipment Types and Characteristics

481 Design SpecificsThe designer should first develop an MCC one-line diagram using standard symbols and presentation according to Section 100, “System Design.” The one-line diagram should include the following data:

• Motor horsepower

• Starter type

• Starter size

• Circuit-breaker type, frame and trip rating, or fused-switch rating and fuse size

• Voltage, number of phases, number of wires, frequency, bus continuous-current rating, and short-circuit current rating

MCC LayoutThe equipment arrangement for an MCC layout is often left for the vendor, but the designer should do the following:

1. Specify the location and size of the incoming line compartment.

2. Specify the wireway location after determining whether most circuits enter or leave via the top or bottom.

3. Specify whether available space requires front-only or back-to-back arrange-ment.

4. Locate units in specific vertical sections.

5. Locate units controlling similar or associated process functions adjacent to one another if possible.

6. Specify that larger units be installed at the bottom of vertical sections (for ease of handling).

482 ChecklistThe following checklist should be reviewed before completing the MCC design and issuing the one-line diagram.

• Is each load supplied by the correct voltage? 460-volt motors will be supplied at 480 volts, and 4000-volt motors will be supplied at 4160 volts.

• Is the bus continuous rating adequate? Does it allow for anticipated future growth?

• Is the short-circuit rating adequate? Does it take into account the effects of motor contributions?



• Can each motor be started, stopped, and otherwise controlled as required? (If a reactor has been used to limit short-circuit currents, motor starting calculations will have to be reviewed.)

• Is each starter sized adequately for continuous operation?

• Is each motor properly protected?

• Have sufficient future spaces and spares been provided?

• Is adequate space provided for control wiring?

• Is top or bottom entry specified for power and control cables?

• Is the enclosure proper for the environmental conditions, such as ambient temperature range, relative humidity, elevation above sea level, indoor or outdoor location, corrosive substances, and area classification

• Have the control devices, relays and control power transformers been specified according to the control diagrams?

490 ReferencesThe following references are readily available. Those with an asterisk (*) are included in this manual or are available in other manuals.


492 Standard DrawingsThis guideline has no Standard Drawings.


* ELC-MS-3977 Medium Voltage Current-limiting Fused Motor Starters

* ELC-MS-4371 Adjustable Frequency Drives

ELC-MS-5008 Medium Voltage Adjustable Speed Drives

* ELC-DS-366 Motor Control Center Specification and Arrangement

* ELC-DG-366 Data Sheet Guide for Motor Control Center Specification and Arrangement

* ELC-DS-597 Motor Control Rack Specification and Arrangement

* ELC-DG-597 Data Sheet Guide for Motor Control Rack

* ELC-DS-3977 Medium Voltage Current-limiting Fused Motor Starters Data Sheet



494 Other ReferencesANSI/IEEE Standard 141, IEEE Recommended Practice for Electric Power Distri-bution for Industrial Plants.

ANSI/IEEE Standard 242, IEEE Recommended Practice for Protection and Coordi-nation of Industrial and Commercial Power Systems.

ANSI/IEEE Standard 100, IEEE Standard Dictionary of Electrical and Electronics Terms.

ANSI/IEEE C37.2, Electrical Power System Device Function Numbers.

ANSI/NEMA ICS2, Part 2-322, Standards for Industrial Control Devices, Control-lers and Assemblies.

ANSI/NEMA ICS2, Part 2-324, AC General-Purpose Medium-Voltage Contactors and Class E Controllers, 50 Hz and 60 Hz.

NEMA Standard 250, Enclosures for Electrical Equipment (1000 Volts Maximum).

ANSI/NEMA ICS6, Enclosures for Industrial Controls and Systems.

API RP 14F, Design and Installation of Electrical Systems for Offshore Production Platforms.

ANSI/NFPA, National Electrical Code 70.

ANSI/UL 347, High Voltage Industrial Control Equipment.

Applied Protective Relaying, Westinghouse Electric Corporation, Relay-Instrument Division.

* ELC-DG-3977 Data Sheet Guide for Medium Voltage Current Limiting Fused Motor Starter Data Sheets

* ELC-DS-4371 Adjustable Frequency Drive Data Sheet

* ELC-DG-4371 Data Sheet Guide for Adjustable Frequency Drive Data Sheet

* ELC-EF-592 Wiring Diagram for Motor and Contactor Installation


500 Switchgear

AbstractThis section discusses switchgear assemblies and their application in an industrial facility. Specific steps in the design process are identified, including the use of stan-dard forms and major selection factors. This section also aids in selecting switch-gear for distribution and application of power up to 15 kV nominal. Circuit breakers, fuses, and relays are discussed in Section 600, “Protective Devices.”

Contents Page


511 Scope

512 Switchgear—An Overview

520 Application Procedure 500-4

521 General Considerations

522 Indoor vs. Outdoor

523 Ratings

524 Control Power

525 Accessory Equipment and Space Heaters

526 Type of Assembly

527 Materials

530 Application Steps 500-9

531 Incoming and Outgoing Cables

540 Labels, Markings and Listings 500-10

550 Materials to be Supplied 500-11

560 Glossary of Terms 500-11

561 Acronyms




500 Switchgear Electrical Manual




Electrical Manual 500 Switchgear


510 Introduction

511 ScopeThis section of the Electrical Manual presents an overview of switchgear assem-blies. When used in conjunction with the documents listed below, this section will assist in the selection, specification, and ordering of switchgear.

Specifications

Data SheetsELC-DS-3908 and ELC-DS-3987

Data Sheet GuidesELC-DG-3908 and ELC-DG-3987

512 Switchgear—An Overview“Switchgear” (or “metal-clad switchgear”) is a general term used in connection with power transmission or distribution circuits, and includes a variety of switching and interrupting devices. Switchgear may be used either alone or in combination with control, instrumentation, metering, protective and regulating equipment.

Switchgear assemblies consist of one or more pieces of equipment in addition to main bus conductors, interconnecting wiring, accessories, supporting structures, and enclosures. In actual usage, the word “switchgear” applies to both the items of which a switchgear assembly consists and the assembly itself. The primary switching components are generally circuit breakers, which are the principal devices used in opening and closing (“switching”) power circuits. A comprehensive description and discussion of circuit breakers can be found in Section 600, “Protec-tive Devices.”

Switchgear is used throughout the electric power system of an industrial facility for incoming line service, and for distributing power to load centers, motors, trans-formers, motor control centers, panelboards, and other secondary distribution equip-ment.

Major switchgear assemblies for Company facilities are generally located indoors. Outdoor switchgear assemblies can be either walk-in (with an enclosed mainte-nance aisle) or non-walk-in (aisle-less).

The switchgear described in this section are the heavy-duty, industrial-type with withdrawable power circuit breakers. Lighter duty “molded-case” or “insulated-case” circuit breakers are not included, and are typically not recommended for industrial applications.

ELC-MS-3908 Medium Voltage Metal-Clad Switchgear

ELC-MS-3987 Low Voltage Draw-out Circuit Breaker Switchgear



520 Application Procedure

521 General ConsiderationsBy using an Application Table such as Figure 500-1, the applications or design engineer can select switchgear of adequate rating for the operating requirements. For example, if 500 MVA Class switchgear is selected (Figure 500-1) for an appli-cation at 13.8 kV, its three phase and line-to-line fault rating would be:

(Eq. 500-1)

19.6 kiloamperes is its current interrupting rating at a time of 5 cycles (0.083 sec) after a fault occurs. The circuit breaker and switchgear assembly rating for “momen-tary,” 1/2 cycle (0.0083 second), current is given in the last column of Figure 500-1, or 37 kiloamperes asymmetrical.

Tables are also available for selection of current potential and control-power trans-formers. Ancillary equipment such as space heaters are also included.

After determining the functional needs as well as physical layout and environ-mental conditions, the applications or design engineer then selects the most appro-priate standardized switchgear cubicle layouts. Technical application is not the only criterion. Cost must be considered as well as the need for compatibility between existing and new components and equipment.

522 Indoor vs. OutdoorIndoor locations are preferred for easier maintenance and protection from weather related problems. Plant layout logistics should be considered to optimize feeder and bus duct lengths. For some plant layouts it may be necessary to use an outdoor enclosed switchgear assembly. In outdoor applications, factors such as sun, wind, moisture, area classification, and local ambient temperatures should be considered in determining the suitability and capacity of the switchgear. Outdoor enclosures should be specified to have front aisles (as a minimum) for ease of maintenance and protection from weather.

Light-colored nonmetallic paints will minimize the effect of solar energy loading and avoid derating the equipment in outdoor locations. Recommended paint is ANSI 70 light gray enamel or lacquer. ANSI/IEEE C37.24-197 is the primary refer-ence for solar loading in switchgear.

Where considerable interwiring is necessary, “power houses” are often used. (See Figure 500-2.) These are prefabricated units containing switchgear, and/or MCCs, lighting transformers, and other panels. The manufacturer provides the units either completely assembled or in modules; both are ready for external connections.

EKV--------- rated short circuit current( )

15.013.8---------- 18( )=

19.8 kiloamperes symmetrical=



Fig. 500-1 Typical Application Table for Circuit Breakers (Courtesy of Cutler-Hammer)



Fig. 500-2 Power House



523 RatingsSwitchgear has two current ratings; short-circuit and continuous. The short-circuit current ratings depend on whether the switchgear is low voltage (600 volts or less) or medium voltage (greater than 600 volts).

Since low voltage switchgear circuit breakers operate to interrupt a circuit very quickly, usually during the first cycle (0.016 second), the circuit breakers and switchgear assemblies have interrupting ratings and mechanical bus-bracing ratings that correspond with the one-cycle short-circuit current.

In contrast, medium voltage switchgear circuit breakers are larger and take longer to interrupt a circuit, usually in the order of 3 to 5 cycles (0.05 to 0.08 seconds). Medium voltage switchgear has a short-circuit rating called its interrupting rating. This is the magnitude of current existing three to five cycles (0.05-0.08 seconds) after the interaction of a fault and is the magnitude of current which the circuit breaker contacts must successfully interrupt. The short-circuit current contributions from motors decay during this interval. Subsequently, the circuit breaker will not be subject to full short-circuit contributions from the motor and/or generator. Medium voltage circuit breakers and switchgear assemblies have a “close-and-latch” or “momentary” rating corresponding to the highest current the equipment will experi-ence during the first cycle (0.016 second) of a short circuit. This is the mechanical withstand rating of the switchgear assembly.

The continuous current rating of switchgear assemblies and circuit breakers corre-sponds to the highest current which can be carried without exceeding temperatures that can be harmful to insulating materials and/or equipment.

There are voltage ratings and other current ratings associated with switchgear assemblies and current breakers. These are described in ANSI C37.06 for low voltage current breakers, ANSI C37.16 for medium and high voltage current breakers, and ANSI C37.20.1, C37.20.2, and C37.20.3 for switchgear assemblies.

524 Control PowerSuccessful operation of switchgear is dependent on a reliable source of control power. The two primary uses of control power in switchgear are to provide tripping power and closing power. Because an essential function of switchgear is to provide instantaneous and unfailing protection in emergencies, the source of control power to trip the breaker must always be available. The requirements for power to close are less rigid. We use electrically-operated (a solenoid is used to operate the spring-operated mechanism) breakers below 600 volts for the main and tie circuit breakers for a switchgear line up and for all circuit breakers feeding low voltage motors. Commonly, medium voltage circuit breakers are electrically operated for both closing and tripping.

Batteries (DC) can be a source of both tripping power and closing power. (However, to optimize battery capacity, an AC source for closing power is recom-mended.) Battery ampere-hour and inrush requirements have been reduced by the use of stored-energy spring-mechanism closing of power circuit breakers through



34.5 kV. AC general distribution systems cannot be relied upon for tripping power, because outages are possible. Outages could potentially occur during those times when the switchgear is required to perform its protective functions.

The importance of periodic maintenance and testing of the tripping power source cannot be overemphasized. The most elaborate protective relaying system is useless if tripping power is not available to open the circuit breaker when required. Alarming for abnormal operating conditions of the tripping source is recommended.

Some major questions to ask when choosing control power are:

• Is adequate maintenance for a battery system available?

• Is suitable housing for a battery system available?

• Is the control power the same as that for existing equipment? Will it allow new and existing equipment to be interchanged?

The following are three practical sources of tripping power:

• Direct current from a storage battery

• Direct current from a charged capacitor

• Alternating current from the secondaries of potential transformers in the protected power circuit. (This application is not recommended.)

DC tripping power is recommended. Furthermore, it is recommended that the trip-ping power be obtained by rectifying the output from a control-power transformer, to charge a set of batteries, which provide the primary source of tripping power.

525 Accessory Equipment and Space HeatersAccessory equipment such as instrument transformers, voltmeters, ammeters, watt-hour meters can be located in almost any compartment of metal-clad or metal-enclosed switchgear.

Space heaters are supplied as a standard feature in outdoor metal-enclosed switch-gear to eliminate condensation on surfaces and insulation. They are also recom-mended on indoor switchgear to keep the temperature above the dew point inside the enclosure during shutdown conditions. Space heaters should be placed in each breaker or auxiliary compartment as well as in each cable area.

Space heaters can be manually or thermostatically controlled. If the heater is manu-ally operated, a switch must be provided to turn off the heater when work is being performed inside the cubicle. If the space heater is thermostatically controlled, a bypass switch is required for manual operation and an operating temperature must also be specified. In most installations, particularly where the ambient temperature becomes warm in the summer, it is better to have thermostatically controlled space heaters. If the climate is always humid or damp, the space heaters should be on all of the time (manual operation). An ammeter should be installed in each main heater circuit so the operator can determine if the space heaters are operating properly.



To help ensure longevity, space heaters should be sized for low surface tempera-tures. This can be accomplished by either specifying a low-watt density heater, or sizing the heater to operate at half normal voltage. For heaters operating at half voltage, those rated at four-times the watts actually required in the compartment must be installed.

526 Type of AssemblyLow voltage, metal-enclosed switchgear is available for applications at 600 volts and below. Metal-clad switchgear is available for voltages from 2.4 kV through 15 kV. In both instances, assembly elements are completely enclosed by sheet metal, affording optimum structural integrity and considerable personnel protection.

Most bus arrangements, (e.g., as radial, double, circuit breaker and a half, main, transfer, sectionalized, synchronizing, and ring) are available to achieve the desired system reliability and flexibility. Selections should be based on total electrical system requirements, initial cost, installation cost, and required operating proce-dures.

527 MaterialsIn the manufacturing of certain parts for switchgear assemblies, several different materials and finishes can be used. Recommendations are as follows.

• All buses should be copper.

• Bus bars for 5 kV bus systems should be insulated with thermoplastic sleevings and held in place by high-strength molded polyester glass insulators.

• 15 kV bus insulation should be high-alumina (high strength) porcelain.

• Bolted bus connections (plated connections are recommended) should be of silver or tin plate.

• Exposed handles, screws, and hinges should be of corrosion-resistant material.

530 Application StepsEngineering the system according to Section 100, “System Design,” and Section 200, “System Studies and Protection” of this manual results in a one-line diagram that provides the following:

• Equipment to be served from the switchgear• Maximum load each piece of equipment represents• Initial system capacity and provisions for future load growth• Maximum short circuit rating of switchgear

This information provides the basis from which to select sizes, styles, ratings, and special features of switchgear devices to distribute power to points of application. In the process it is necessary to:



• Determine the configuration of the circuit breakers and switchgear

• Determine the ratings of the power switching apparatus

• Select the main bus rating

• Select the current transformer ratios and locations

• Select the potential transformer ratios, connections (wye or open-delta), and locations

• Select metering, relaying, and control power transformer ratings

• Select closing and tripping voltage and power

• Consider special requirements

The appropriate Data Sheets, ELC-DS-3908 and ELC-DS-3987 should be completed using their respective Data Sheet Guides, ELC-DG-3908 and ELC-DG-3987. The standard specifications in this section should be used to specify switch-gear.

531 Incoming and Outgoing CablesAll cables, (incoming and outgoing) usually enter/exit at the bottom of switchgear. All outdoor switchgear should have cables entering from the bottom because it is easier to provide support at the bottom than at the top and it reduces water entry from condensation and rain. However, specific design considerations may make it advantageous to enter from the top. Special terminations are used for shielded conductors and sufficient space must be provided to make these terminations (stress cores).

540 Labels, Markings and ListingsLocal inspectors rely heavily on labels, markings, and listings to identify equipment that complies with applicable standards. The most common label is from Under-writers’ Laboratories, Inc. (UL). However, Factory Mutual (FM) and Canadian Standards Association (CSA) are usually accepted to most as inspection organiza-tions.

Equipment recognized by UL carries either a UL mark or is listed in a UL publica-tion as a recognized component. Switchgear and certain items of control apparatus should have an attached label indicating UL recognition.

Items of control apparatus are manufactured to specific standards but may not be listed, marked, or labeled because the manufacturers have chosen not to spend the time and money required to obtain UL approval of these items. These items should not be used unless approval is obtained from the local electrical inspector. Manufac-turers who design and build to UL and NEMA standards are usually willing to certify compliance with their interpretation of these standards if such certification will assist in obtaining local approval. In general, it is easy to obtain a UL label for switchgear rated at or below 600 volts. Medium voltage switchgear, however, is an



engineered item with very few standard configurations and is difficult to have UL-labeled unless done by a third-party examination service.

550 Materials to be SuppliedSpecification ELC-EG-3908 requires all engineering data for equipment, as speci-fied and ordered, to be supplied by the manufacturer. Among the items to be supplied are the following:

• Specific (not typical) structural drawings (elevation drawings)

• One-line and three-line diagrams

• Elementary (schematic) diagrams

• Detailed connection (wiring) diagrams

• Material lists that includes the quantity, rating, type, and manufacturer’s catalog number of all equipment in each unit

• Catalog data for relays, switches, circuit breakers

• Relay and power-fuse time-current curves and application information

• Complete spare parts lists.

• Lists of priced spare parts that the manufacturer recommends be available for startup and the first year’s operation.

560 Glossary of TermsMetal-Clad Switchgear: Metal-enclosed switchgear that has specific features enumerated in Section 9.3.4 of ANSI/IEEE Standard 141.

Metal-Enclosed Bus: An assembly of rigid electrical buses with associated connec-tions, joints, and insulating supports, all housed within a grounded metal enclosure.

Metal-Enclosed Switchgear Assembly: Switchgear enclosed on the top and all sides by sheet metal on a supporting structure. Ventilating openings and inspection windows may be present. Access to the inside is provided by doors or removable panels.

Open Switchgear Assembly: An assembly that does not have an enclosure as part of its supporting structure.

Power Switchgear Assembly: One or more of the devices mentioned in the defini-tion of switchgear, including conductors, interconnections, accessories, supporting structures, and any enclosures.

Switchgear: Switching and interrupting devices alone or in combination with asso-ciated control, metering, protective, and regulating equipment.



561 Acronyms

570 ReferencesThe following references are readily available. The ones which are marked with an asterisk (*) are included in this manual or are available in other manuals.


572 Standard DrawingsThere are no standard drawings in this guideline.


574 Other ReferencesANSI/IEEE Standard 141, IEEE Recommended Practice for Electric Power Distri-bution for Industrial Plants.

ANSI/IEEE Standard 100, IEEE Standard Dictionary of Electrical and Electronics Terms.

ANSI/IEEE C37.20.1, Metal-Enclosed Low-Voltage Power Circuit Breakers.

ANSI/IEEE C37.20.2, Metal-Clad and Station-Type Cubicle Switchgear (Above 1000 V).

ANSI/IEEE C37.20.3, Metal-Enclosed Interrupter Switchgear (Above 1000 V).

CSA Canadian Standards Association

NEMA National Electrical Manufacturers Association

NFPA National Fire Protection Association

UL Underwriters’ Laboratories, Inc.

* ELC-MS-3908 Medium Voltage 5 kV and 15 kV Metal-clad Switchgear.

* ELC-MS-3987 Low Voltage (600 V maximum) Drawout Circuit Breaker Switchgear

* ELC-DS-3908 Medium Voltage Switchgear Data Sheet

* ELC-DG-3908 Data Sheet Guide for Medium Voltage Switchgear Data Sheet

* ELC-DS-3987 Low Voltage Switchgear Data Sheet

* ELC-DG-3987 Data Sheet Guide for Low Voltage Switchgear Data Sheet



ANSI/IEEE C37.23, Metal-Enclosed Bus and Guide for Calculating Losses in Isolated Phase Bus.

ANSI/IEEE C37.24, Guide for Evaluating the Effect of Solar Radiation on Outdoor Metal-Clad Switchgear.

Beeman, Industrial Power Systems Handbook. NY: McGraw-Hill, 1955.

Fink and Carroll, Standard Handbook for Electrical Engineers. NY: McGraw-Hill, 1968.

Chevron Corporation 600-1 November 1991

600 Protective Devices

AbstractThis section addresses the two major electrical system hazards, overload and short circuit, and the risk posed by each. It discusses system protective devices (most importantly circuit breakers and fuses) and the operation of the principal compo-nents of any protective scheme. The section also discusses indirect protective control, specifically relays for large motors. Circuit breakers and fuses are described with typical numerical values.

Contents Page


611 Protective Devices—An Overview

612 Characteristics of Protective Devices

620 Circuit Breakers 600-5

621 Power Circuit Breaker

622 Molded-Case Circuit Breakers

623 Current Limiting Circuit Breakers

630 Relays and Protective Device Coordination 600-8

631 Zones of Protection

632 Instrument Transformers

633 Basic Considerations for Overcurrent Relaying and Coordination

634 Ground Fault Relaying and Coordination

635 Other Common Types of Relay Protection

636 Electrical Component Protection and NEC Requirements

640 Fuses 600-57

641 Advantages and Disadvantages of Fuses

642 Design Features

643 Time-Current Curves

644 Miscellaneous Considerations

600 Protective Devices Electrical Manual

November 1991 600-2 Chevron Corporation

645 Current-Limiting Fuses






Electrical Manual 600 Protective Devices


610 IntroductionThis section gives an overview of the devices and methods for protecting electrical systems and electrical system components. Three types of protective devices are discussed: circuit breakers, fuses, and relays. Each has its relative merits and weak-nesses for system protection. Circuit breakers and fuses physically perform the circuit interruption. Relays sense the electrical parameters and control the circuit breakers and contactors. Basic guidance on using and setting relays is given, as well as a discussion of current and potential transformers.

611 Protective Devices—An OverviewTwo problems can disrupt an electrical system: overloads and short circuits. Protecting the components of an electrical system when either of these problems occurs is the function of protective devices. It is important to coordinate protective devices so that only the device immediately upstream to faulted equipment operates and the remainder of the system continues to supply power to the other loads. Protective devices must be applied only within their ratings.

OverloadsHeat caused by overloads damages components of electrical systems. Protective devices designed to prevent overloads are therefore primarily heat sensitive; that is, they monitor current and time which translates into heat.

Short CircuitsShort circuits, also called faults, are defined as abnormal connections or arcs between two points of different potential. These abnormal connections can be caused by insulation failure, accidental short circuiting caused by misplacement of tools and wiring, or mechanical failure. Protective devices designed to protect against short circuit damage are primarily current sensitive.

Three basic types of faults occur in electrical systems: bolted faults, arcing faults, and high impedance faults.

Bolted Fault. This fault is so named because it is as solid as if an electrical conductor had been bolted to the points of short circuit. It causes power sources to deliver their maximum short circuit capacity. Fortunately, these faults are extremely rare.

Arcing Fault. Arcing, the most common type of fault, is caused by a variety of events, such as insulation failure or careless placement of wire or tools. The wire or tool melts, and a line-to-ground or line-to-line arcing fault remains. An arcing fault can be extremely destructive if not quickly extinguished by a protective device.

High Impedance Fault. This type of fault occurs when a high impedance current path exists between phases or between phase and ground. One example is a leakage current through failing insulation between phase windings in a motor. High imped-ance faults are characterized by low fault current magnitudes, which make their detection by protective devices difficult.



612 Characteristics of Protective DevicesCircuit protective devices consist of two components:

• Detecting (sensing) devices which monitor the desired circuit parameters

• Protecting (interrupting) devices which receive the signal from detecting devices and isolate the circuit.

In circuits above 1000 volts, the detecting devices commonly used are relays, and the protective devices are power circuit breakers. In circuits of lower voltage, both functions can be combined in one device, such as a thermal-magnetic molded-case circuit breaker or an air circuit breaker.

Fuses provide both sensing and interrupting functions.

Common Characteristics of Protective DevicesProtective devices have several common characteristics:

• They all have an inverse time-current characteristic; that is, the higher the current, the faster the device acts to interrupt it. The speed of this operating response is limited by the mechanical and arc-quenching capacity of the device.

• They all have a minimum value of current necessary for operation called the “pickup” current. The accuracy (or repeatability) of operation varies among devices. In order of decreasing accuracy, these are as follows:

1. Solid-state trip units.

2. Electromechanical relays.

3. Fuses.

4. Magnetic direct-acting trip devices.

If maintained in accordance with manufacturers’ specifications, protective devices will perform in the same manner in repeated operations, including fuses, if they are replaced with exactly the same parts.

No protective device is perfect. None operates in zero time or prevents unwanted current from flowing. Even a fast-acting fuse takes a finite time to heat up to its melting point, melt, and separate enough to cause current flow to cease. This process takes at least a quarter cycle (4 milliseconds for 60 Hz current).

Protective devices must be capable of successfully interrupting the maximum fault current that flows. Where an improperly applied circuit breaker is subjected to higher than rated fault currents, the fault current could weld together the contacts of the breaker and continue to flow until the breaker explodes.

Breakers and controlling relays should be adjusted to ensure their fastest possible operation to clear a fault or other abnormal condition without nuisance interrup-tions for minor transients. “Instantaneous tipping of breakers,” usually occurs within one cycle (16.7 milliseconds for 60 Hz current).



Through-Fault Withstand CapacityAll protective devices require a finite time to clear a fault. During this time, all system components in series, from the source(s) to the fault point, are subjected to the fault current and its effects of heat and mechanical stress. The components must be able, therefore, to withstand the thermal and mechanical effects until the fault is cleared.

In a fault condition a protective device may never open because the faulted circuit may be removed from the system by another protective device. Before the second device opens, full fault current flows through the first one. Therefore, it is important to know whether the first device can withstand full fault current momentarily and function satisfactorily afterwards.

620 Circuit BreakersWhen properly applied within its rating, a circuit breaker is a device designed to open a circuit automatically on a predetermined overcurrent without damage to itself. The two types of circuit breakers are: power circuit breakers, for medium and low voltage applications, and molded-case circuit breakers, for low voltage applica-tions. See Figure 600-1.

Fig. 600-1 Typical Low Voltage Air Circuit Breaker with Magnetic Air Chutes; Breaker Shown in the Open Position



621 Power Circuit BreakerMedium voltage (601 volts to 15 kV) power circuit breakers are rugged devices built on several standard sizes of metal frames. Air interrupter types are the most common.

The vacuum circuit breaker is another type of power circuit breaker. Its contacts are enclosed in a vacuum container which allows rapid arc extinguishment and short contact travel. Together, they make possible fast interruption and very short clearing time—generally in one cycle or less after the contacts part. A drawback of the vacuum breaker is the fragile nature of the vacuum container, which must be protected from rough treatment. See Figure 600-2.

Low voltage (600 volts and below) power circuit breakers are open construction assemblies on several standard sizes of metal frames. See Figure 600-1. Parts are designed for easy access for maintenance, repair, and replacement. These breakers are intended for service in switchgear compartments or other enclosures of dead-front construction.

Tripping units are field adjustable and are usually interchangeable within the frame sizes. Air circuit breakers are the most common type of low voltage power breakers. Because of their larger size, longer contact travel, and other characteris-tics, they are slower acting than molded-case circuit breakers.

622 Molded-Case Circuit BreakersA molded-case circuit breaker is a low voltage (600 volts and below) switching device and an automatic protective device assembled in an integral housing of insu-lating material. In general, these breakers are capable of clearing a fault more rapidly than power circuit breakers, but more slowly than fuses.

Fig. 600-2 Details of 15 kV Horizontal-drawout Vacuum Circuit Breaker (Courtesy of ABB)



These breakers generally are not designed to be maintained in the field like low voltage power circuit breakers. Many are sealed to prevent tampering — precluding inspection of the contacts. Moreover, replacement parts generally are not available since manufacturers recommend total replacement if a defect appears or the unit begins to overheat. Molded-case breakers, particularly the larger sizes, are not suit-able for repetitive fault clearing (more than 1000 to 5000 operations).

The two modes of operation for molded-case breakers are: magnetic (only) trip and thermal-magnetic trip.

Magnetic (only) trip breakers have trip units sensitive to the magnetic field caused by the current. A pickup setting is adjustable to select the magnitude of fault current that will trip the breaker. Only fault currents are interrupted by this type of breaker; therefore, another protective device is needed to protect equipment against heating caused by overload current. These molded-case circuit breakers, called motor circuit protectors (MCPs), can only be used in combination motor starters.

Thermal-magnetic breakers have two major components. One is a thermal-trip unit. If an overload persists long enough to raise the temperature of a heat sensitive element to a predetermined temperature, the breaker opens. The other component is the magnetic pickup described above.

623 Current Limiting Circuit BreakersCurrent limiting (CL) circuit breakers (UL 489) provide high interrupting capabili-ties. They also limit let-through energy (I2t) and current to a value less than the I2t of a half-cycle wave of the available symmetrical prospective current.

The frame size of a family of circuit breakers determines the breakers current limita-tion. For example, a 100-ampere frame CL circuit breaker will have one current-limiting characteristic for all ratings (20, 30, 40, 70, 100) in that frame.

CL circuit breakers do not provide the same current limitation as similarly sized and rated CL fuses. For example, the instantaneous peak let-through current of 100-ampere, 600 V circuit breaker is 25,000 amperes. A 100 ampere, 600 V CL fuse will limit the peak let-through to 10,000 amperes.

CL circuit breakers are not available in the single-pole 120-V branch-type (e.g. Westinghouse Quicklag or GE Q-Line). If current-limiting characteristics (lower-peak short-circuit levels and fast-acting operation, less than 1/2 cycle) are desired for branch circuits, CL fuses are the only available protective device. Branch circuits supplying critical loads fed from an uninterruptible power supply (UPS) system are protected best by CL fuses. (See Section 124, UPS System Design)

If very high levels of fault current are available on feeders, a cost-effective approach is to apply series-connected molded-case circuit breakers, i.e., two molded-case CB electrically in series sharing fault-interrupting duties. Series-connected CB must meet the appropriate sections of UL-489 to be listed with Underwriters Laboratory for series connection.



630 Relays and Protective Device CoordinationThis section provides essential information for selecting the appropriate protective devices during design stages of a project (prior to purchasing the equipment). The method for setting these devices so they will operate together in a safe and effective manner is explained, and the different types of relays and their uses are presented. Instrument and potential transformers are also discussed, and the basic tools and mechanics for completing a coordination study using time current curves on log-log paper are presented.

Relays are precise, versatile, and dependable for protecting electric circuits and devices. However, they are sensing devices only and must be used in conjunction with a contactor or circuit breaker to actually protect a circuit. See Figure 600-3. A variety of relays is available to protect against electrical abnormalities.

A preliminary relay coordination study should be done early in the design stage to ensure that the proper type and range of relays are specified and that they can be coordinated to achieve selective tripping. The actual settings are determined later in the design phase after the short circuit calculations have been made.

This information is then applied to protection schemes for individual components, such as buses, feeders, transformers, and motors. Section 635 below gives a descrip-tion by number of standard electrical power system devices.

631 Zones of ProtectionWhen designing relay protection for industrial plants, the usual procedure is to divide the one-line diagram into zones to be protected. Figure 600-4 shows a typical one-line diagram divided into several zones. Each zone contains a compo-nent to be protected—such as a bus, a feeder, an incoming line, a transformer, or a motor. Each zone is protected by a primary protection scheme and a backup protec-tion scheme which will function only if the primary protection fails.

Each zone is protected by circuit breakers or fuses which will open if there is a fault within the zone. If these primary circuit breakers fail to operate, then the backup circuit breakers will operate—isolating the fault. For example, in Figure 600-4, if there is a fault on Bus A in Zone 2, the protective relays will cause breakers 2, 3, and 4 to trip (as necessary) to clear the fault. If, for example, breaker 2 fails to trip, then breaker 1 (the backup protection) will trip and clear the fault.

The zones may be protected by various types of relays, such as differential relaying, pilot wire relaying, phase overcurrent relaying, and ground overcurrent relaying. It is common practice to have the zones overlap, as shown in Zones 1 and 2. This is done by locating the current transformers (CTs) so that the fault in the overlapping area is sensed by the relays of both zones.



632 Instrument Transformers

Current TransformersCurrent transformers (CTs) are used in protective relay circuits to detect currents in the protected circuits, and transform them to proportional currents of smaller magni-tudes which can be sensed directly by relays. Current transformers also isolate the relay from the primary circuit voltage.

The four main types of CTs are:

• Wound• Bar• Window• Bushing

Three types of current transformers are illustrated in Figure 600-5. The particular type is normally selected by the manufacturer of the electrical gear with which it is associated.

CT OperationIn electrical drawings, CTs are represented by the symbol shown in Figure 600-6. A primary current, IP, flows through the CT primary. In most cases, this primary current is the one flowing in the circuit to be protected. The cable or bus carrying this current usually passes through the center of a window-type CT and does not

Fig. 600-3 One-line Diagram of Current-limiting Fuse and Motor Controller with a Thermal Device. (From Standard Handbook for Elec-trical Engineers, by D. Fink & W. Beatty, 12ed/ 1987. Used by Permission from McGraw Hill, Inc.)

Fig. 600-4 Diagram Depicting Zones of Protection. (Reprinted with permission from IEEE Std. 141-1986, 1986 IEEE. All rights reserved.)



contact the wiring of the CT itself. See Figure 600-7 which provides a pictorial representation of the schematic of Figure 600-6.

Ground fault protection often uses window-type (zero sequence) current trans-formers enclosing all the conductors of a three-phase circuit and the neutral. Figure 600-8 shows the symbol for three conductors passing through a window-type CT. This configuration is used in ground fault protection schemes. Figure 600-9 illustrates this scheme.

CT SymbologyThe two small squares in Figure 600-6 are the standard polarity symbols for current transformers. The convention is as follows: instantaneous current entering the square in the primary (represented by IP) results in an instantaneous current out of the square in the secondary (represented by IS). These squares or polarity symbols

Fig. 600-5 Current Transformers



are marked in a similar manner on the actual current transformer. The polarities are very important when several current transformers are connected together in a protec-tion scheme such as differential relaying. If the polarities are not correct, the protec-tion system will not function properly.

Fig. 600-6 Standard CT Symbology Fig. 600-7 Current Transformer Ratio

Fig. 600-8 Standard Zero Sequence CT Symbology Fig. 600-9 Core Balance Ground Fault Scheme with Zero Sequence CT



CT RatiosCTs transform higher currents to lower currents in accordance with their CT ratio. In Figure 600-6, the ratio is 1200:5. By U.S. industry standards, the CT rated secondary current normally is 5 amperes. CTs are available in standard ratios as shown below:

Standard Ratios for Current Transformers

Current transformers are also available with taps to allow multiple ratios on one CT.

A CT ratio must be selected so that at maximum continuous current in the primary circuit, the secondary current will be less than or equal to 5 amperes. For example, a 1200 ampere-feeder breaker might be supplied with a CT having a 1200:5 ratio. If the feeder breaker supplies loads well under 1200 amperes, a smaller ratio might be chosen. When selecting a CT ratio, it is recommended that the maximum antici-pated ampere loading not be greater than two-thirds of the CT primary current rating.

CTs have ratings other than the CT ratio that must also be considered for proper selection. Usually, the switchgear manufacturer chooses the proper ratings appro-priate for the equipment after the desired ratio is specified. Some of the other ratings associated with CTs are: voltage, insulation class, frequency, basic impulse insulation level (BIL), accuracy class, and mechanical and thermal capability. These ratings and the verifying tests are discussed in detail in ANSI C37.13.

CT SaturationThus far, only ideal current transformers have been discussed. In actuality, a current transformer is a nonlinear device, subject to saturation of the magnetic core. During faults, the CT may saturate. At saturation, the currents in the primary and secondary are no longer related by the CT ratio and large errors are introduced.

The relay burden is the electrical impedance of the relay. The value should be given in the relay literature. When the burden of the relay is too high for the CT, it causes the CT to saturate during fault conditions—producing errors in relay operation. For a more in-depth explanation of the use of the excitation curve, burdens, and equiva-

10:5 600:5

15:5 800:5

25:5 1200:5

40:5 1500:5

50:5 2000:5

75:5 3000:5

100:5 4000:5

200:5 5000:5

300:5 6000:5

400:5 12000:5



lent circuit, see Applied Protective Relaying, edited by J. L. Blackburn (Westing-house Electric Corporation, Coral Springs, Florida, 1982). Different accuracy classes of CTs are required for different applications. Accuracy classes are discussed in the IEEE Buff Book and ANSI C57.13.

Safety PrecautionsFor safety reasons, CTs should never be left open circuited. High voltages can be induced in the secondary; this can cause overheating of the CTs or possibly become a personnel hazard. For this reason, many CTs are fitted with shorting bars or shorting contacts, and CT circuits normally are not fused. CTs should be left shorted until the final connection of the relay is made into the CT circuit. The shorting bars must be removed in the field, or the relays will not work.

Potential TransformersPotential transformers (PTs), sometimes called voltage transformers, are used to convert the high voltages of primary circuits to proportionally lower voltages suit-able as relay and metering input voltages. PTs also provide isolation between the primary and secondary circuits.

PT RatingsIn general, the secondary voltage of potential transformers in the U.S. is 120 volts. Most primary voltages are available (e.g., 13.8 kV, 4.16 kV, and 480 volts). Poten-tial transformers are connected in an open delta configuration as shown in Figure 600-10 or in a wye-wye configuration. The convention is as follows: the instantaneous voltage polarity on the H1 terminal is the same as the instantaneous voltage polarity on the X1 terminal. The polarity symbols H1, H2, X1, and X2 are marked on the transformer.

Fig. 600-10 Open Delta PT Connection



Like current transformers, potential transformers have several ratings associated with them. These ratings include: insulation class, basic impulse level, ratio, primary and secondary voltage, frequency, usage, thermal loading, and accuracy. These ratings are described in detail in ANSI C57.13.

Accuracy classes range from 0.3 to 1.2 percent. Potential transformers also have maximum thermal burdens expressed in volt-amperes. If these burdens are exceeded, the lives of the transformers will be reduced.

Unlike current transformers, potential transformers should have their primaries fused to protect the power system from faults in the potential transformer windings. Sometimes they are provided with secondary fuses to protect them against short circuits on their secondaries. Potential transformers are similar to power trans-formers in most respects and can be open-circuited without high voltage being induced in their secondaries.

633 Basic Considerations for Overcurrent Relaying and CoordinationThe most common type of relaying is overcurrent relaying, which is used for both phase fault protection and ground fault protection.

Overcurrent Relay TypesThere are two types of overcurrent relaying: instantaneous overcurrent relaying and time overcurrent relaying. Both are usually combined into one relay as shown in Figure 600-11. When the two functions are combined, the relay is designated as a 50/51 device. The 50 is the instantaneous overcurrent relay and the 51 is the time overcurrent relay. Overcurrent relays incorporate targets that indicate when they are tripped. The targets must be reset manually.

Fig. 600-11 Construction of a Typical Induction Disk Overcurrent Relay (Courtesy of the General Electric Company)



Instantaneous relays, of the hinged armature-type (solenoid-type), trip the associ-ated circuit breaker immediately when the current reaches a preset value. It usually takes the relay 0.5 to 2 cycles to operate plus circuit breaker operating time.

Current transformers are normally used to match overcurrent relays to the current levels of the electrical system. The time overcurrent operating coil operates in series with the instantaneous overcurrent unit operating coil, if both are used, and each is set to cover its own portion of the tripping range.

Residually Connected RelaysThe typical method of connecting overcurrent relays into a circuit with the current transformers is shown in Figure 600-12. The relay in the single return leg is known as a residually connected, or 51N, overcurrent relay. The current sensed is the ground fault current if one of the primary phases goes to ground. When there are no faults in the system, the relay normally does not sense current. It is set to pick up at a lower current than the other three overcurrent relays.

Zero-sequence ConnectionAnother method of using overcurrent relays to protect against ground faults is to use a window (zero-sequence) CT as shown in Figure 600-9. This method uses a standard overcurrent relay with a low tap current range. The three phase conductors and the current carrying neutral, if there is one, are passed through the window of the CT. The CT detects any ground fault current which occurs if one of the phases shorts to ground. When shielded cable is used, the shield wiring must not go through the CT in one direction only. The shield wiring must return through the CT (to ground) to prevent cancelling out ground fault currents. See Figure 600-9 for one type of installation method.

Fig. 600-12 Typical Connection of Overcurrent Relays and CTs



Basic Relay OperationThe basic operating unit of an overcurrent relay consists of a magnetic core oper-ating coil, an induction disk, a damping magnet, and a set of contacts. All of these combine to produce a time versus current operating characteristic. Figure 600-11 shows an induction disk relay.

Time overcurrent relays trip after a time delay when the current magnitude is within their preset tripping range. The delay time varies depending on the magnitude of the current. Time overcurrent relays have an inverse time characteristic (i.e., the larger the current, the shorter the time it takes to trip). Overcurrent relays can be obtained with different time versus current characteristics: inverse, very inverse, extremely inverse, long time inverse, medium time inverse, and short time inverse. The differences in these characteristics are shown in Figure 600-13.

The characteristics chosen depend on the piece of equipment being protected and the devices being coordinated. It is much easier to coordinate relays in series if they have the same type of characteristic curve shape. The curves will not be prone to cross each other. For example, the extremely inverse characteristic usually is chosen to coordinate with fuses because it is closer in shape to the fuse characteristic. The very inverse characteristic is usually chosen as a starting point for overcurrent protection.

Overcurrent Relay Pickup, Taps, and Time Dials

Taps. Time-overcurrent relays have two adjustments: taps and a time dial as shown in Figure 600-11. Taps are used to determine the level of current at which the relay

Fig. 600-13 Time Characteristics Available for Overcurrent Relays



will begin to actuate. The pickup current is the minimum current which will start the induction disk moving (and ultimately close its contacts). For example, if the 2.5 amperes tap on an overcurrent relay is selected, 2.5 amperes is the current which will start to move the induction disk towards contact closure. If the relay is connected to a 300:5 current transformer, then it will take 150 amperes in the primary of the CT to produce 2.5 amperes in the secondary, which is what is sent to the relay coil. The taps are adjustable in steps over a fixed range of current values (e.g., 0.5 to 2 amperes, 1.5 to 6 amperes, or 4 to 16 amperes). Taps are changed by inserting a special screw in the appropriate hole in the face of the relay corre-sponding to the desired relay pickup current. To determine the actual current in the primary which will cause the relay to pick up, multiply the tap times the CT ratio:

Pickup Current = Tap Value × CT Ratio

For the example above, pickup current equals 150 amperes, which equals 2.5 times 300 divided by 5.

Time Dial. The time required for a relay to operate at any particular current value is determined by the time dial setting. The time dial setting determines the distance the induction disk must turn to close the relay contacts. The larger the time dial setting, the longer it takes the relay to trip for any given current. Time dial settings usually have an adjustable range from 0.5 to 10. The tripping range is any current larger than the pickup current. The time required for an overcurrent relay to operate can be determined from its time-current characteristic curve.

Time-current CurvesThe time-current characteristic curve for a typical time-overcurrent relay is shown in Figure 600-14. Notice that both vertical and horizontal scales are logarithmic. The vertical axis indicates the time to trip (in seconds). The horizontal axis is the current axis. Current is expressed in multiples of relay pickup current. If the pickup current is 150 amperes as calculated in the previous example, this would be repre-sented as 1 on the horizontal axis; 10 would represent 1500 amperes. The relay curves do not extend all the way to the pickup current because, theoretically, it takes an infinite amount of time to trip at the pickup current. The time to trip can be determined from the time-current curve. For example, at 1500 amperes, 10 times the pickup current, it will take this particular relay 0.3 seconds to trip if the time dial is set to 1, and 1.5 seconds to trip if the time dial setting is 6.

By varying the settings of the taps and time dials of an overcurrent relay, the charac-teristic curve can be moved vertically and horizontally on a time-current relay coor-dination curve, as illustrated in Figure 600-15.

• Curve A has a time-dial setting of 0.5• Curve B has the same tap setting as Curve A, but a time dial setting of 10• Curve C has the same time-dial setting as Curve A, but a different tap setting• Curve D has different tap and time-dial settings than Curve A

Notice that the x-axis is expressed in amperes in Figure 600-15, not in multiples of pickup current. Current scaling on the x-axis is more convenient because it is not necessary to refer elsewhere for the pickup current.



Fig. 600-14 Typical Time Current Characteristic Curve



The inset diagram in the lower right half of Figure 600-14 is the characteristic of the instantaneous unit. It also has a setting which is separate from the overcurrent unit tap setting. Usually the instantaneous relay adjustment is made by a screw which can be turned to move a plug in or out of the coil to vary the instantaneous pickup. Typically, instantaneous pickup ranges are adjustable between 40 to 160 amperes, 20 to 80 amperes, 10 to 40 amperes, 4 to 16 amperes, or 2 to 8 amperes. The instantaneous setting is calculated in the same way as the overcurrent setting. The tap setting multiplied by the CT ratio yields the primary pickup current. For example, if the instantaneous relay adjustment is set at 100 amperes and the CT ratio is 300:5, then the relay will trip at 100 x 300/5 = 6000 amperes. This value neglects effects due to CT saturation. Time dials do not affect the setting of the instantaneous unit. There is no intentional time delay in an instantaneous unit; it trips very quickly (within approximately 8 milliseconds) upon reaching the pickup current.

Once the settings of the taps and time dials are made, relays should be checked (using special testing equipment) in the field to ensure that they are working and properly calibrated.

Information Needed to Perform an Overcurrent Relay Coordination StudyAn overcurrent relay coordination study is a time-versus-current study of all devices in series, from the utility source to the utilization device. An overcurrent relay coordination study plots the time-current characteristics of relays and other protective devices (such as fuses and circuit breakers with direct acting solid state trip units) on the same log-log graph of time-versus-current to ensure that they coor-dinate. Coordination means that the relay or device nearest the fault has sufficient

Fig. 600-15 Diagram Showing How Time vs. Current Characteristic Curve of a Relay can be Shifted by Varying the Tap and Time Dial Settings



time to act in order to clear the fault before the devices closer to the source, which also see the fault current, have time to initiate a trip. With proper coordination, the overcurrent device nearest the fault will clear the fault, shutting down the smallest possible part of the total system. This is known as selective tripping. With proper coordination, unnecessary shutdowns are eliminated. In large electrical systems, eliminating a single unnecessary shutdown can more than pay for the time required to complete a relay study. The actual settings of the protective devices are deter-mined in the course of the coordination study.

The following information is needed to perform a coordination study.

1. A system one-line diagram (and a meter and relaying drawing if separate from the one-line diagram).

2. Values of short circuit current through the devices considered in the study.

3. Values of three phase bolted fault current and ground fault current.

4. Values of load currents.

5. The manufacturer and model of all relays in the system to be studied, their tap ranges, the ratio of the CTs to which they are connected, the factory relay curves, and instruction manuals for all relays.

6. Existing settings of all relays in the system to be studied.

7. Manufacturer model and fuse size of all fuses in the system and their time-current curves for melting and clearing.

8. For large motors and generators, the current withstand limit curves. These curves may include the time-versus-current withstand limit curves for the machines during running overloads or stalled conditions.

9. For cables in the system, the short circuit withstand curve (the insulation damage curve)—based on the particular type of insulation and the current ampacity.

10. For transformers in the system, the transformer short time capability curve, the full load current, and inrush current. The short time capability curve is avail-able from ANSI C57.109 or the IEEE Buff Book.

11. For motors, the starting current, the full load current, and the acceleration time.

12. For molded-case circuit breakers, the manufacturer, model, trip setting, and time-current curves.

13. For solid state trip units, the manufacturer’s curves and instructions on how to set the long time, short time, delay bands, and instantaneous settings.



When to Conduct a Coordination StudyConditions requiring a coordination study are as follows:

1. When the available short circuit current from the source is increased.

2. When significant new loads are added to an existing system or when existing equipment is replaced with equipment of a different rating.

3. When a fault in a minor part of an electrical system causes a major shutdown due to tripping of main breakers upstream (rather than selectively tripping local breakers).

4. Following a major electrical plant modification.

5. During the design phase of a new facility.

The Time-Current Coordination CurveAfter the information listed above is gathered, it must be transferred to the Time-Current Coordination Sheet. This is done on log-log transparent paper (e.g., K&E type 42-5258.)

First the voltage and current level for the horizontal scale must be selected. Usually, it is best to select the lowest voltage level of the relays being studied. It is common to show relays at two or three voltage levels on the same sheet, all referenced to the common voltage level on the coordination curve. All curves must be shown with equivalent current at one chosen voltage level. For example, there may be relays on the primary and secondary side of a three-phase transformer, with 13.8 kV on the primary and 4.16 kV on the secondary. A secondary current of 100 amperes will cause a primary current to flow.

(Eq. 600-1)

On the time-current curve the 13.8 kV primary voltage can be shown as either 100 amperes at the 4.16 kV secondary voltage level or 30.1 amperes at 13.8 kV. A voltage level within the system must be chosen and all currents referenced to that voltage level. See Figure 600-16.

The x-axis is expressed in amperes of current at the reference voltage. See (1) in Figure 600-17. Often the current axis at the bottom of the curve is scaled. If so, the title should indicate the scaling factor (e.g., “Current in Amperes x 1000,” if the scaling factor is 1000.)

1004.1613.8----------× 30.1 A=



Fig. 600-16 Case 1 Relay Coordination Example (Courtesy of the General Electric Company)



Fig. 600-17 Case 2 Relay Coordination Example (Courtesy of the General Electric Company)



Other information displayed on the time current curve is as follows:

1. Maximum fault current level the protective devices can be subjected to. The characteristic curves of protective devices are normally not drawn beyond the maximum fault current level. See (2) in Figure 600-17.

2. The time-current characteristics of all relays, fuses and molded-case circuit breakers relating to the system being coordinated. Their CT ratios, tap, time dial, and instantaneous setting values. See (3) in Figure 600-17.

3. The one-line diagram of the system to be coordinated. See (4) in Figure 600-17.

4. Any thermal damage or withstand limit curves for cables, motors, transformers or generators. See (5) in Figure 600-17.

5. Cable ampacities, transformer full load amperes, generator and motor full load amperes. See (6) in Figure 600-17.

6. Transformer inrush points.

7. Motor acceleration time-current curves. See (7) in Figure 600-17.

Fault Levels and the Coordination CurveBoth symmetrical and asymmetrical currents are of interest in relay applications since different relays respond to different fault currents. To determine which relay will operate at a given point in time, the value of fault current to which each relay responds must be known.

Fuses, direct acting trip units associated with low voltage circuit breakers, and instantaneous relays respond to asymmetrical short circuit current. The value of this current can be approximated by multiplying the calculated symmetrical first cycle short circuit current by 1.6, although this multiple varies with the impedance-to-resistance ratio (X/R). For an explanation of first cycle short circuit current, see Section 220, of this manual.

Induction disk overcurrent relays respond to the symmetrical fault current a few cycles later, after it is reduced in magnitude. This current value is approximated by the interrupting current calculated in the short circuit study at 3 to 5 cycles.

Coordination Time IntervalsRelay curves are extended only to the value of the maximum fault current that affects them. At the fault current value, the vertical time separation between curves of relays in series (which see the same current), determines if selective coordination exists. If the curves have too little vertical separation at the fault current level, the relay that will operate first cannot be predicted, and selective tripping cannot be guaranteed.

Figure 600-18 shows the suggested minimum values of time intervals between over-current protective devices in series, to insure coordination. If the relays characteris-tics are of the same general shape, and if these intervals are applied at the maximum fault level, the relays will also coordinate at lower values of current.



Fig. 600-18 Time Margins for Use with Induction Disc Overcurrent Relays (1 of 2) (From Procedure for an Overcur-rent Protective Device, January, 1979. Courtesy of Square D. Company)



Fig. 600-18 Time Margins for Use with Induction Disc Overcurrent Relays (2 of 2) (From Procedure for an Overcur-rent Protective Device, January, 1979. Courtesy of Square D. Company)



In addition to the information in Figure 600-18, induction disk relay-to-relay coordi-nation time intervals can be reduced from 0.38 seconds to 0.25 seconds at the maximum fault level if the relays are set and calibrated at specific critical operating points in the field. It is recommended that this be done before startup. In some of the examples, 0.25 second intervals are used, based on field calibration being performed. If the relays are not calibrated in the field, 0.38 seconds must be used.

When coordinating molded-case circuit breakers with other molded-case circuit breakers or solid-state-direct-acting relays on low voltage circuit breakers with other solid-state-direct-acting relays, the coordination criterion is that there be no overlap. No space is required between the boundaries of the time bands of the two devices; however, they cannot overlap.

Example Showing How to Interpret Relay Coordination CurvesFigure 600-16 and Figure 600-17 provide two examples of typical information shown on time coordination curves including transformers, cables, and motors, and show how to interpret them. These examples are not exhaustive, but serve to make some important points. For more information on protective relaying see the refer-ence section (Section 650).

Case 1—Transformer Protection (Figure 600-16)Figure 600-16 shows the overcurrent relaying of a 5000 kVA delta-delta trans-former with a 13.8 kV primary and a 4.16 kV secondary.

One-line Diagram The one-line diagram of the system being studied is shown to the side of the relay curves. It shows all of the relays whose curves are on the coordination drawing and all CT ratios. All voltage levels are also shown on the one-line diagram, as well as the transformer kVA, impedance, and winding type. The size of the cable is also shown.

Graph ScalesThe current scale is identified as currents at 13.8 kV. Any currents on the 4.16 kV side of the transformer must be multiplied by the factor 4.16/13.8 before they can be displayed on the curve.

Fault Current ValuesThe fault currents at the locations of interest in the one-line diagram are shown at the top of the figure; sometimes they are marked at the bottom for convenience. The fault current values should always be shown on a time overcurrent curve since the coordination time interval requirements must be met at this value of maximum fault current. The relay curves are not extended any further than the maximum fault current to which they can be exposed since the current will never exceed this value. The transformer full load current (209 amperes) is marked at the top of the figure. The requirement of Article 450-3 of NEC is that the primary breaker not be set at a value higher than 600% of rated current. This is the “6 X Trans FL” point at the top



of the diagram, and limits the maximum allowable pickup setting of the primary 50/51 relay.

Cable ProtectionThe cable also must be protected in accordance with requirements of NEC. For low voltage cables, the relay must protect the cable according to its ampacity; for cables at voltages greater than 600 volts, the breaker must be set to trip below six times the ampacity of the cable (NEC Article 240-100). The transformer and cable overload protection are the lower constraints on the relay protection.

The cable heating limit (CHL) curve is in the lower right area of the time current coordination curve. This curve shows how long the cable can withstand short circuit currents of different magnitudes without exceeding the temperature which would cause damage to the insulation. Cables have different CHL curves, depending on the type of insulation and the wire size. These curves are available from sources listed in the references of Section 200, “System Studies and Protection” (see also the Buff Book). An example of a CHL curve is shown in Figure 600-19.

Transformer ProtectionThe ANSI transformer short-time-loading-limit curve is plotted on the time-current sheet. This curve is found in ANSI C57.109-1985 and also in the Buff Book. Curves can be applied directly at the values shown in the ANSI curve for trans-formers with delta-delta or wye-wye windings. For delta-wye transformers, the short-time-loading-limit curve current values must be reduced to 58% of the values shown. This reduction provides protection for a secondary side single phase to neutral fault and would result in shifting the short-time-loading-limit curve to the left.

The transformer inrush point must also be indicated on the coordination drawing. This point is usually shown at 12 times the transformer full load current at 0.1 seconds for primary substation and pad type units, and at eight times full load current at 0.1 second for load center type units.

Relay SettingsFigure 600-16 shows that there is a time overcurrent relay and an instantaneous relay associated with the primary circuit breaker. The time overcurrent is set with a tap setting of 10 amperes and a time dial setting of 3. The primary pickup current for this relay is the CT ratio multiplied by the tap setting (300/5 x 10 = 600 amperes). Transformer full load current is 209 amperes. The 600 amperes pickup is less than six times the transformer full load current (1254), the maximum allowed by NEC, Table 450-3.

Note that the transformer primary overcurrent relay curve is below and to the left (Figure 600-16) of the transformer short-time-loading curve at the three-phase short circuit (interrupting rating) current value on the secondary side of the transformer. Therefore, the primary overcurrent relay will provide short-circuit protection for secondary short-circuit currents.



Fig. 600-19 Typical Insulated Cable Short Circuit Heating Limits (Time-Current Curves). (Courtesy of General Electric Company)



Transformer Primary-side ProtectionAs added protection, an instantaneous relay was used on the primary. It is set just above the asymmetrical value of the first cycle short circuit current (1.6 x IFCY). This is the current impressed on the primary side if there is a fault on the secondary side of the transformer; therefore, a secondary fault will not trip the primary instan-taneous relay. This feature ensures selectivity with the secondary overcurrent relay, which should trip first on a secondary fault. The primary side instantaneous relay is set below the asymmetrical value of the first cycle current for a short circuit on the primary side of the transformer so the instantaneous relay will trip for a primary side fault, but not for a secondary side fault. The instantaneous relay is set below the cable heating limit curve, but above the transformer inrush point (called magne-tizing current and labelled MAG).

Transformer Secondary-side ProtectionThe secondary time overcurrent device, labelled 51 in Figure 600-16, has a pickup below six times the cable ampacity needed to comply with NEC requirements, but above the full load current of the transformer. It also must have a pickup below three times the full load current of the transformer as required by NEC Article 450-3.

The secondary 51 device curve is below and to the left of the transformer short-time-loading curve at the maximum three phase secondary fault through breaker B1, so the transformer is protected against faults. It is also 0.25 seconds below the primary overcurrent relay curve to provide coordination at the maximum secondary fault, IINT. Only a 0.25 second coordination interval is required if the relays are field calibrated. If the relays are not field calibrated, 0.38 to 0.40 seconds are required.

Case 2— Motor Protection (Figure 600-17)Figure 600-17 demonstrates relay coordination for a 3000 hp motor, protected by a circuit breaker with an overcurrent relay and an instantaneous relay. The one-line diagram is in the upper right corner of the coordination drawing, showing the CT ratio (200/5), the cable size, and the relay device numbers.

The cable short circuit heating limit curve is plotted for the 1/0 feeder conductors. The cable ampacity, 195 amperes, is plotted at the top of the figure. The asymmet-rical fault current at the motor, from the short circuit study, is indicated at the top right of the figure since the instantaneous device responds to this current. The instantaneous device is set below the maximum asymmetrical fault current so that it will respond to the fault current.

Motor Acceleration CurveThe motor accelerating current curve, consisting of three parts, is also plotted. When induction motors are first started, they have a magnetic inrush, similar to that of a transformer (which lasts less than 0.1 seconds)—this is the motor starting amperes (MSA). The value of this starting current is approximately 1.6 times the locked rotor amps, usually less than 10 times the full load amps of the motor. The



instantaneous device is set approximately 10% above this value to ensure it will not trip when the motor starts, yet will still trip for fault currents above this value.

The second part of the motor accelerating curve is the locked rotor amperes (LRA)—640 amperes in this case. This value is usually in the range of four to six times the full load current of the motor. The value can be obtained from the manu-facturer or, for low voltage motors, can be calculated from the locked rotor code, which gives the starting kVA per horsepower. When the motor reaches operating speed, after about 5 seconds, the current levels off to approximately the full load amps of the motor—110 amperes in this case. The actual acceleration time can be estimated or calculated as demonstrated in Section 400, where motor starting is discussed.

The acceleration time-current curve serves as a lower restraint for the 51 relay time-current curve. If the relay curve intersects the motor acceleration time-current curve, the motor will be shut down before it reaches operating speed.

Motor Thermal Limit CurveNext, the motor thermal limit curve is drawn on the time current sheet. For large motors this curve is obtained from the manufacturer. Sometimes the thermal limits are given in terms of maximum stall times from a hot or cold starting condition. Both conditions are illustrated in Figure 600-17. The curve for the motor overload protection, supplied by the 51 device in this case, passes below and to the left of the motor thermal limit curve. The tap setting of the 51 relay is set at 4, establishing a pickup current of 200/5 x 4 = 160 amperes. The time dial is set at 2; therefore, the relay provides the required protection for the motor and the feeder. Typical pickup current settings for a 51 device used for stall protection of a motor is 150% to 250% of the motor full load amps. Since the cable ampacity is 200 amperes, the cable is adequately protected against overloading. NEC requires that the cable be protected within six times its ampacity.

Setting the RelayThe motor full load amps is 110 amperes, so the pickup setting allows the motor to run. The curve of the 51 relay lies between the motor acceleration curve and the motor thermal limit curve, allowing the motor to start and run, but protecting it against locked rotor conditions. The instantaneous setting at 110% of the motor starting amps, which exceeds the motor starting amps, provides an extra degree of protection against faults and also gives additional cable fault protection.

634 Ground Fault Relaying and CoordinationAnother form of overcurrent relaying is ground fault relaying. The majority of all electrical faults involve ground faults. Arcing ground faults can be extremely destructive in electrical systems since they can be of such low current values that standard phase overcurrent devices may not detect them. If these faults are not cleared, the arcing may continue until a fire or serious damage results. This circum-stance is particularly applicable to low voltage systems, but it is important to consider ground fault relaying in electrical systems at all voltage levels.



Typical ground fault protection schemes are not sensitive to load currents; there-fore, the ground fault relay pickups can be set much lower than the phase overcur-rent relays protecting the same feeder or electrical device. Typical pickup settings for ground fault relaying range from 10% to 100% of the phase overcurrent relay settings, usually closer to the lower end of the range for modern sensitive ground fault relays.

Ground fault relays usually do not require as severe coordination time restraints as phase overcurrent relays. Ground faults are not seen by the relays on both sides of delta-wye and wye-delta transformers. They are seen only on the faulted side, so the relays on both sides of the transformer do not have to be time delayed to allow mutual coordination.

Types of Ground Fault Protection1. Residually Connected Ground Fault Relaying (Device 51N)

A residually connected ground fault relaying scheme is shown in Figure 600-12. This scheme normally is used on medium voltage systems. Usually the currents in phases A, B, and C vectorially add to zero—resulting in little or no current through the ground residual relay. However, if one of the phases becomes grounded, the flow of the external ground fault current causes an unbalance in the CT currents, and a current proportional to the ground fault current flows through the residual relay—causing it to trip the circuit breaker. Since the residual relay does not actuate for normal load currents, it can be set to pick up at much lower currents than the phase overcurrent relays fed by the same set of CTs. It should be set low enough to provide sensitive ground fault tripping, but high enough to eliminate spurious tripping and allow coordination with any other downstream ground fault relaying which sees the same fault.

The residual scheme is not as sensitive as the core balance or zero sequence (window CT) scheme, and is not often used on low voltage systems. It is used widely on medium voltage systems since ground fault currents usually are higher.

2. Core Balance Ground Fault Relaying (Device 50/51G)

Figure 600-9 shows a typical core balance or zero sequence current trans-former ground fault relay scheme. This method is very sensitive and is widely used on low voltage systems.

During balanced normal load current flow, the magnetic fields of the three phases passing through the window CT vectorially add to zero, producing no secondary current in the CT. Like the residually connected ground fault scheme, the core balance method is insensitive to normal load currents. However, if one of the conductors becomes grounded, a large external current flows outside the window CT, resulting in a flux unbalance within the window CT. This produces a secondary current of sufficient magnitude to trip the ground fault relay.

The core balance ground fault relaying device can be used with shielded or non-shielded cables. If it is used with shielded cables, it is important to route



the shield drain wires back through the window CT as shown in Figure 600-9. This arrangement prevents magnetic flux due to ground fault currents (which return through the shield) from cancelling and therefore remaining undetected.

Another problem related to shield wires where multiple grounds are used is caused by currents that circulate through the shields due to different ground potentials. These circulating currents can cause sensitive core balance relays to trip. There are two ways to solve this problem: (1) the ground loop can be elim-inated or (2) the relay can be adjusted to be less sensitive so that it will not trip as a result of the circulating currents.

3. Ground Return

Figure 600-20 shows a medium voltage delta-wye transformer with a low resis-tance grounded wye secondary. The CT in the neutral ground resistor circuit path sees only ground fault currents which return to the transformer neutral from a fault on one of the phases. As in the other schemes, this CT would not see load current; therefore, it could be set with a much lower pickup.

Figure 600-21 shows a similar arrangement commonly used in high resistance grounded 480 volt systems. Instead of a CT, a meter relay monitors the voltage across the grounding resistor. Under normal conditions, there is little or no voltage across the resistor. However, if one of the phases goes to ground, there will be a ground return current through the resistor. This current will produce a voltage approaching line-to-neutral. The meter relay will detect this voltage and alarm.

Fig. 600-20 Ground Return Relay for a Low Resistance Grounding Scheme on a Transformer

Fig. 600-21 Meter Relay Used for High Resistance Grounding Scheme on a Transformer



4. Solid State Direct-Acting Ground Fault Relaying in Low Voltage Circuit Breakers

Low voltage circuit breakers are available with solid state trip units which have a ground fault protection feature (as well as the standard long time, short time, and instantaneous functions). A typical time-current curve for such a device is shown in Figure 600-22. The pickup levels which can be chosen are much lower than the phase overcurrent long time pickup selections, as can be seen from the available settings for the ground fault function. These solid state devices also have an adjustable ground fault delay band (time delay) to allow coordination with other ground fault devices.

Selection of Settings for Ground Fault RelayingFor best protection against ground faults, ground fault relaying should be applied from source to load. The pickup current for the series ground fault relays can all be set at approximately the same current level (between 10% and 100% of the phase overcurrent pickup level). It is recommended that the pickup level be set as low as possible without causing spurious shutdowns due to inrush currents.

The time delays for coordination between series ground fault devices which sense the same faults follow the same rules as the overcurrent device coordination inter-vals. The ground fault relays which protect load devices (such as motors) can also be obtained with an instantaneous setting.

Ground Fault Relaying ExampleFigure 600-23 shows a typical ground fault protection scheme for a transformer, a feeder, and motor branch circuits. The ground fault relays protecting the motor branch circuits are 50GS instantaneous ground fault relays set to trip well below the full load current of the motors. The ground fault relays protecting the transformer and feeder, 51G1 and 51G2, are both fed by the same CT and are coordinated so they provide two levels of ground fault protection above the 50GS protecting the motors. They are both set with the same tap setting (to pick up at about 20 amperes), but the time dials are set differently to provide coordination; 51G1 is set 0.25 seconds above the instantaneous motor ground fault relay to provide coordina-tion. Note that these relays must be field calibrated to use the 0.25 second interval rather than the standard 0.38 second interval. Two relays are used to provide backup protection. The 51G1 relay trips the secondary breaker. If this fails, then the 51G2 relay trips A7, the transformer primary breaker. The settings on both relays are well below the expected load currents of the transformer and motors.



Fig. 600-22 Typical Time-Current Characteristics of Low-Voltage Breakers (From Procedure for an Overcurrent Protective Device, by Curd & Curtis, January, 1979. Courtesy of Square D. Company)



Fig. 600-23 Example of Ground Fault Relay Coordination (Courtesy of the General Electric Company)



635 Other Common Types of Relay Protection

Thermal Overload ProtectionThermal overload relays are used for motor thermal overload protection.

1. Bimetallic

Two metals with different coefficients of expansion are bonded together, usually in the form of a strip—occasionally a disc. One end is fixed; the other can move freely. A resistive heater element in series with the motor current is wound around the strip.

If the strip is heated sufficiently, it moves over a certain distance and opens, by snap action, a normally closed contact in the coil circuit of the starter for the motor. When the coil circuit is opened, the main contacts of the starter open, and the motor is de-energized. Heaters are chosen from manufacturer’s tables, based on the normal load current of the motor.

2. Melting-alloy

This type of thermal overload protection employs a metal alloy that is called eutectic; it melts at an extremely low temperature for metals. This temperature is between 80°C and 150°C (176°F to 272°F). Since this same alloy is used for specialty soldering, this type of overload relay is sometimes called a solder-pot relay.

During normal operations a small ratchet is kept under torsional force by a spring. However, the ratchet is kept from turning by the solidified eutectic metal. A heating element melts the eutectic metal if the overload persists long enough.

When the metal alloy melts, the ratchet turns on its shaft because of the spring. A lever opens a normally closed relay contact, which in turn opens a normally closed contact in the coil circuit of the motor. This removes power from the motor. The relay can be reset.

3. Ambient-compensated

If a motor and its starter are exposed to different ambient temperatures, it may be necessary to use an ambient-compensated thermal relay to achieve proper overload protection. The most common situation is that in which the ambient of the starter is controlled, but that of the motor is not.

Only bimetallic relays are available with ambient-compensated features.

4. Current-actuated Overload Relay (Device 49)

A current actuated overload relay is sensitive to sustained stator currents in excess of the motor’s continuous rating, to the high inrush currents that flow during the starting period, and to overcurrents resulting from unbalanced voltage conditions. It will also respond to heat resulting from jogging or frequent starting.



The relay may or may not be ambient-compensated. Ambient compensation is used to offset the differences in temperature between the motor ambient and the interior of the controller enclosure. The relay is mounted in the controller. This relay is recommended for all motors above 600-volts.

5. Temperature-actuated Overload Relay (Device 49T)

A temperature-actuated overload relay detects and responds to actual heating in the motor by means of resistance temperature detectors (RTDs) embedded in the motor windings. The RTDs may have a 10 ohm value, but 120 ohms are recommended as 120 ohm RTDs are more accurate. The value to be used should be established and included in the motor specifications.

A temperture-actuated overload relay is sensitive to motor heating due to continuous overloads, frequent starting, jogging, unbalanced voltage condi-tions, loss or restriction of ventilation, high atmospheric temperatures, and other abnormal conditions. It is recommended for motors rated 1500 hp and larger.

6. Combination Thermal Overload Relay (Device 49/49T)

A combination thermal overload relay is a solid state relay. It uses an RTD input to sense motor temperature, provide continuous overload protection, and a current-actuated input that is responsive to the rate of temperature rise of the rotor during the starting period. This relay combines the best features of the current-actuated and temperature-actuated overload relays described above (4 and 5) to provide good overall protection in a single device.

Complete motor information (such as full-load current, locked-rotor current, rotor/stator thermal time limit, motor-winding temperature rise, RTD ohms, and CT ratio) must be furnished for proper selection and calibration of the relay. A combination thermal overload relay may be used in lieu of either a current-actuated or a temperature-actuated overload relay, or both.

Fault Protection1. Instantaneous Overcurrent Relay (Device 50)

An instantaneous overcurrent relay is an instantaneous current-sensing unit capable of being adjusted over a wide range of current settings. It should be set to operate at currents above the locked-rotor inrush (including its DC offset)—typically 10 times the motor full-load current.

The 50 relay can be integrally mounted in the same case as the current-actuated thermal relay (49) or timed-overcurrent-relay (51), or provided in a separate case. When a fused magnetic-contactor starter is used, this relay is not required since the fuse will provide short-circuit protection. An instantaneous overcur-rent relay is recommended for all motors above 600 volts.

2. Differential Relay (Device 87)

A differential relay provides sensitive high-speed protection against internal motor faults. It is recommended for motors rated 1500 hp and larger. It is also



recommended for critical motors. The decision to use differential protection is normally based on a comparison between the cost to provide the protection and the cost to repair or replace a motor. Downtime costs are also a factor to be considered. Two basic schemes are used to provide this protection for large motors: conventional and self-balancing.

a. Conventional scheme. The conventional scheme utilizes a total of six current transformers and three differential relays. One set of current trans-formers is located in the motor controller, and the other set is located in the motor terminal box (on the neutral side of the motor winding). This scheme provides protection against phase-to-phase internal winding faults, faults in the primary cable, and ground faults. The relay typically used is either a standard-speed, fixed-percentage, induction-disk relay or a high-speed variable-percentage relay. The latter costs slightly more. (See Figure 600-24a.)

b. Self-balancing differential scheme. This scheme consists of three differ-ential relays energized from three flux-balance current transformers mounted at the motor terminals. Small-ratio current transformers (e.g., 50:5) are recommended to obtain higher sensitivity to lower primary currents.

Because of faster operation, better sensitivity, and lower cost, the self-balancing scheme is usually preferred over the conventional scheme. However, the stiffness of the feeder cables required by large motors may limit its application because of the difficulty of routing the supply and return wires through the junction box. (See Figure 600-24b.)

Fig. 600-24 Differential Schemes

(a) Conventional Differential Protection Scheme, OnePhase Shown

(b) Self-Balancing Differential Scheme



Undervoltage or Loss of Voltage Protection1. Undervoltage Relay (Device 27)

An undervoltage relay should be provided on each bus supplying motors controlled by switchgear or latched contactors. The function of the under-voltage relay is to trip the buses on complete loss of voltage or sustained volt-ages below tolerable operating limits. This relay will prohibit instant restart of motors upon return of voltage and also limit overheating of the stator windings because of sustained undervoltage. Undervoltage relay protection is not required for low voltage motor starters (less than 60 volts) since the contactor opens on low voltage. However, undervoltage relays may be used to open the contactor if low voltage is of short duration.

The undervoltage relay has an inverse time characteristic with adjustable oper-ating settings for both time and voltage. A single relay sensing phase-to-phase voltage is adequate, since voltage variations normally affect all phases. The undervoltage relaying scheme is designed to trip each motor controller (through an auxiliary relay) rather than trip the incoming line breaker. Undervoltage relays are recommended for all medium voltage motors (600 volts and above). For most installations, it is recommended that this device be combined with current balance (46) and phase sequence voltage (47) relays.

Current and Voltage Unbalance Protection1. Current-Balance Relay (Device 46)

In a fused motor starter, an open fuse will allow the motor to operate single-phased. The resulting unbalanced currents in each of the unopened phases will produce serious heating in the motor. A current-balance relay on each motor feeder will properly sense this unbalanced condition and trip the motor. This relay is a three-phase device that will operate when there is a fixed percentage of unbalance between any two phases. Device 46 is recommended for 1500 hp and larger motors.

Standard current-operated overload relays (even one per phase) cannot be depended upon for reliable protection against unbalanced conditions. The rate of heating in the rotor due to negative-sequence currents is considerably higher than that for positive-sequence currents. The current in the two unopened phases has a large component of negative-sequence currents, approximately equal to the positive-sequence currents. These currents can cause rotor damage before the overload relay operates. Although the overload may eventually initiate tripping, the motor can be substantially damaged before it can be removed from the bus.

2. Voltage Balance Relay (Device 60)

This device detects unbalanced voltages and provides a trip signal which can be used for protection of motors against single phasing.

Another use of this relay is to monitor fuses of potential transformers and other relays connected to the potential transformers, thus preventing unnecessary trip-



ping in the event of a blown fuse. Alarms to indicate blown fuses can also be provided.

3. Blown-Fuse Trip

The blown fuse trip is not recommended for motors greater than 1500 hp; it is not reliable. The lower cost of the blown-fuse trip device is its only advantage over the current-balance relay. The blown-fuse trip consists of a trip bar that will trip and close a switch contact in the event of a blown fuse, thus sending a signal to the contactor to open the other two phases. This feature can be purchased as an option on medium voltage fused starters.

Phase Sequence Protection1. Phase Sequence Voltage Relay (Device 47)

A phase sequence relay is used to detect a reversed phase rotation. The relay can protect against starting a motor with a reverse-phase sequence. A reverse-phase sequence causes a motor to run in the opposite direction, which can cause equipment damage. A phase sequence voltage relay may be used on a bus to protect a group of motors.

Special Protection Schemes1. Incomplete Starting Sequence (Device 48)

This scheme provides additional protection to the motor and its associated starting equipment in the case of failure to complete the predetermined starting sequence. It is used in reduced-inrush starting schemes, wound-rotor motor starting schemes, and unloaded-start synchronous motor starting schemes. A time delay relay is used to sense a failure of equipment to reach normal running conditions within a specified starting time. An auxiliary contact on the motor starter is used to engage the timer. The timer is preset to have a slightly longer time interval than is required for normal starting. The tripping contact of the timer is blocked by an auxiliary contact that operates last to complete the starting sequence. This scheme is recommended for medium voltage (2300 volts to 13.2 kV) synchronous motors.

2. Repetitive-Start Protection

All large motors have a limitation on the number of starts allowed within a given time period (e.g., three per hour). A time-delay relay may be used to block successive restarts until a preset time interval has elapsed. This protec-tion will ensure that the maximum allowable number of starts in a given period is not exceeded.

3. Directional Overcurrent Relay (Device 67)

This relay is similar to a standard overcurrent relay (Device 51) except that it provides sensitive tripping for fault currents in one direction and ignores load and fault currents in the other direction. A typical use of this relay is on incoming power from a source. In this case, the relay would only detect power flowing from the plant to the source, a situation which would occur for a fault



located near the source. It would not detect load current flowing to the load; therefore, it could be set lower than a normal bi-directional overcurrent relay.

4. Lockout Relay (Device 86)

A lockout relay sends a signal to trip the breaker it is associated with. This relay is used in conjunction with other protective relays in switchgear and motor control centers. It has no protective features and serves as a contact multiplier or allows the use of higher currents through its contacts than the relay contacts can withstand.

In a typical application, relay contacts are wired to the trip circuit of a lockout relay. When the relay contacts close, the lockout relay trips, thus tripping the circuit breaker or starter. The lockout relay must be manually reset before the circuit breaker or starter can be reclosed. The lockout relay is often connected so that it can be tripped by multiple relays.

5. Directional Power Relay (Device 32)

This device is sensitive to power flow in one direction and ignores power flow in the other. A typical application is used for utility lines serving a plant which also has local generating capability. If it is needed only to import power from the utility, the directional power relay can be set to alarm or trip on power flow from the plant generators to the utility.

Another use of the directional power relay is as an anti-motoring device for generators. It should be set to detect power entering the generator terminals from other parallel generators, indicating a paralleling problem or a loss of the prime mover.

6. Fault Pressure Relay (Device 63)

This device is mounted directly on a transformer and has a pressure tap to the inside of the transformer tank. If there is an internal fault in the transformer, it will produce gases which will increase the internal pressure. The fault pressure relay will detect the sudden increase in internal pressure and close a set of contacts. These contacts are usually wired to send a trip signal to the trans-former’s primary circuit breaker.

7. Overvoltage Relay (Device 59)

This relay is adjustable to trip on increasing voltage at a specified value. It is used for protection of sensitive components against sustained overvoltage.

Another common use of this relay is in ground fault protection circuits, such as those utilizing a high resistance grounding resistor. This relay would be used to monitor the voltage across the ground resistor and to close a set of alarm contacts if the voltage reaches a specified value.

8. Loss of Excitation Relay (Device 40)

This relay is used to protect against loss of field for both synchronous motors and synchronous generators. In the simpler cases for small motors, it monitors



field current and provides a trip signal on loss of this current. On larger motors and generators, it monitors the relative angle between voltage and current. It also provides a trip signal when the angle indicates a loss of field.

9. Synchronizing Relays (Device 25)

Synchronizing relays are used to control breaker closure when connecting two power sources which must be synchronized. A typical application of this type of relay would be to supervise or initiate the breaker closure of generators connected to the same bus.

A synchronizing relay monitors the difference between the terminal voltage, frequency, and phase angle of the oncoming generator and the bus to which it is to be connected. When these differences are within the specified range, the relay supplies a contact closure which serves as a permissive for manual breaker closure, or initiates the breaker closure automatically, thus connecting the generator to the bus.

10. Distance Relay (Device 21)

Distance relays are fault detection devices that are mainly used on transmission lines. They provide a trip signal if the fault is within a specified distance from the relay location.

The distance relay monitors the phase relationship between the current and voltage on the transmission line. From this relationship, the distance to the fault can be determined. If the fault is within the specified distance zone of the relay, a trip signal is initiated. This distance is altered by adjusting the values allowed for R and X for which the relay will trip.

636 Electrical Component Protection and NEC Requirements

Bus ProtectionSince switchgear buses are vital parts of the electrical system, they need protection that will rapidly clear ground faults or phase faults on the bus. On low voltage buses this function usually is handled by the multi-function solid-state direct-acting trips on the incoming and outgoing circuits. These units can provide both overcur-rent protection and ground fault protection.

On medium voltage buses, differential protection is often used to provide instanta-neous bus fault protection (see Differential Relay, Device 87). This protection offers an advantage since the differential relays do not have to be time delayed to coordinate with overcurrent relaying at different voltage levels in the electrical system. The principle behind differential relaying is that the sum of the currents entering the bus must equal the sum of the currents leaving the bus. If a fault occurs on the bus, this upsets the balance and all the breakers on the bus are immediately tripped to clear the fault. This scheme works well with sectionalized buses connected by tie breakers. Both sections of the bus can be protected by individual bus differential relays, so a fault on one side of the bus will isolate only that side, allowing continuity of load on the other side. Bus differential relays are not sensi-



tive to faults outside the bus zone. Figure 600-25 shows a typical bus differential scheme.

Buses protected by bus differential schemes have backup protection provided by overcurrent relays on the incoming line to the bus.

Feeder ProtectionThe most commonly applied protection of feeders is time overcurrent relaying. Other less common schemes are pilot wire differential relaying and directional over-current relaying.

1. Low Voltage Feeders

In general, low voltage feeder conductors are required to be protected against overcurrent according to their ampacities per NEC Article 240-3 and the tables of Article 310. Low voltage feeders are usually protected by fuses or circuit breakers which give this protection. Additionally, separate ground fault protec-tion may be provided.

It is important to note that an instantaneous trip feature should not be provided on feeders which supply motor control centers with molded case circuit breakers. The instantaneous overcurrent trip on the feeder breaker will not coor-dinate with the molded-case circuit breakers in the MCC and may result in an outage of the entire MCC when there is a fault on a motor or other device. A suitable short-time delay trip feature should be used instead of an instanta-neous trip feature on the feeder to an MCC.

Fig. 600-25 Typical Bus Differential Relay Scheme



2. Medium Voltage Feeders

NEC Article 240-100 requires that feeders above 600 volts be protected against short circuit by a fuse set at a maximum of three times the ampacity of the feeder, or by a circuit breaker set at a maximum of six times the ampacity of the feeder.

3. Typical Overcurrent Schemes

Figure 600-26 shows a typical overcurrent scheme suitable for low voltage feeders. The instantaneous Device 50 should not be used if there are down-stream devices requiring coordination at the same voltage level. Also shown on this figure is a ground fault relay 50/51 GS. A residually connected 50/51N relay is often used in lieu of the 50/51 GS.

In addition to overcurrent protection, the short circuit heating limit of the cable must be considered for protecting feeders. If the feeder is protected by a time delay relay, it will allow the short circuit current to persist for a short time. This time period must be compared to the short circuit heating limit curve for the cable. Figure 600-19 (located at the end of this section) shows typical short circuit heating limit curves. The curves depend on the wire size and the insula-tion of the cable. When plotted on the same time-current coordination curve, the overcurrent relay curve should lie below and to the left of the short circuit heating limit curve.

A directional overcurrent scheme is applied when it is desirable to have relays detect overcurrent conditions in one direction only. This situation might occur on an incoming line where current only should be flowing to the plant. A reverse in current direction would indicate a fault or abnormal condition.

Fig. 600-26 Typical Feeder Protection Scheme



4. Pilot Wire Relays

Pilot wire relays use a form of differential relaying that provides high speed fault protection for feeders. The system compares line currents at both ends of the line and trips if there is a significant difference. The pilot wire scheme requires additional small conductors to be installed the length of the line and special circuitry to make it unnecessary to route the actual CT current from one end of the line to the other. The advantages of pilot wire relaying are high speed and sensitivity, which minimize the possibility of feeder damage due to overheating during a fault.

Transformer ProtectionTransformers should be protected against internal faults, external faults, and over-load conditions. Transformers connected to overhead lines should also be protected by surge arresters to prevent insulation failure due to lightning overvoltage impulses. For more information, see Section 800, “Transformers.”

NEC Article 450-3 prescribes the required minimum overcurrent protection require-ments for transformers both above and below 600 volts.

Short Time Withstand CapabilityTransformers must also be protected according to their short time withstand capa-bility. These withstand curves are found in the IEEE Red Book, Buff Book, and in ANSI C57.109. When applying the transformer short time withstand curves for the purpose of relay coordination, the effect of external secondary faults on delta-delta and delta-wye transformers must be considered. Phase-to-neutral and phase-to-phase faults on the secondary side of a delta-wye transformer will not have the same per-unit current value on the primary side. This difference is due to the delta-wye connection, and may prevent the primary relay from responding quickly enough to prevent transformer damage. As a result, for delta-wye transformers, the ANSI short time withstand curve must be shifted to the left on the time-current curve by 58% so that the primary protective device will provide protection against a secondary line-to-neutral fault in accordance with the short time withstand rating, as illustrated in Figure 600-27.

Transformer InrushWhen protecting a transformer with overcurrent protection devices, it is necessary that their settings be high enough to allow the transformer inrush current that occurs on energizing the transformer. This inrush current is usually considered to be eight to 12 times the transformer full load current for 0.1 second duration. This point is usually shown on the time-current coordination curve. The inrush point should fall below and to the left of the curve of the transformer primary protective device. See Figure 600-16 for an example showing transformer magnetic inrush on a time-current coordination curve.

Primary/Secondary DevicesIf a transformer is protected by both primary and secondary overcurrent protective devices, it is desirable that they coordinate, particularly if the primary device is a



Fig. 600-27 Effect of External Secondary Faults on Transformer Protection and Coordination Requirements (From Procedure for an Overcurrent Protective Device, by Curd & Curtis, January 1979. Courtesy of Square D. Company.)



fuse. If a fault occurs on a bus fed by the secondary of a transformer, it is preferable for the secondary breaker to trip rather than for the primary fuse to blow. If the fuses blow, replacements may not be available and more work is required to replace fuses on the high voltage side of the transformer than to reset the secondary breaker.

An instantaneous overcurrent relay may be used in combination with a time over-current relay on the transformer primary protection and still provide coordination with the transformer secondary overcurrent device, if the primary instantaneous relay is set above the maximum secondary asymmetrical fault value but below the primary maximum asymmetrical fault value. This is demonstrated in the Case 1 example of relay coordination illustrated in Figure 600-16.

Internal FaultsThere are several means of protecting against internal transformer faults. A fault pressure relay (Device 63), mounted on the transformer, detects a sudden pressure increase inside the transformer due to an internal fault and trips the primary circuit breaker. Device 63 is usually specified on large oil-filled transformers (1000 kVA). Upstream primary overcurrent and ground fault protective relays will also provide a degree of protection against internal transformer faults, but may be too slow for some low-level internal faults.

One of the best methods of protecting large transformers against internal faults is to use transformer differential relaying (Device 87T). This system includes the trans-former and a surrounding zone which may also include some of the transformer feeder cable. The transformer differential relaying compares the primary trans-former current with the equivalent secondary current. To accomplish this, the CTs on the primary and secondary of the transformer have different ratios to match the transformer turns ratio. If there is an internal fault, it is quickly detected and cleared. The relay action is instantaneous, thereby minimizing damage to the trans-former and reducing costly repairs. It does not have to be coordinated with other relays. Depending on the extent of the zone covered by the differential relaying, it may provide some degree of external fault protection.

When using transformer differential relaying on transformers of 2 MVA or larger at 15 kV and above, differential relays with a harmonic restraint feature should be used to prevent the transformer from tripping on energizing because of the harmonics of the inrush current.

Overload ProtectionTransformer overload protection is usually provided by an overcurrent device in the secondary main breaker or by a secondary fuse of the transformer. On large trans-formers, an embedded winding thermocouple or oil temperature thermometer (Device 49) can be used to alarm or shut down when insulation temperature limits are exceeded.

ExamplesFigure 600-28 shows the typical protection for a small transformer. Figure 600-29 shows typical protection for a transformer with medium voltage windings. Figure 600-30 is a coordination curve showing the primary and secondary protec-



tion of a transformer. Notice that the primary overcurrent relay curve lies below and to the left of the transformer short time withstand curve and coordinates with the secondary main breaker. Notice too that the transformer inrush point is plotted and lies below and to the left of the primary overcurrent relay.

Since the transformer is a delta-wye, the short time withstand curve has been shifted to the left to 58% of its unshifted value to protect against line-to-neutral faults. Unshifted curves can be obtained from the IEEE Red Book. Since a secondary line-to-line fault of 0.86 per unit results in a primary current of 1.0 per unit, a 16% current margin has been left between primary and secondary relay curves (to insure selectivity).

The instantaneous function of the primary relay has been set above the maximum asymmetrical secondary fault current to allow selectivity with the secondary breaker for secondary faults. The instantaneous relay will respond only to faults on the primary. It is set high enough not to respond to secondary faults. The pickups of the two relays are set to meet the requirements of NEC Article 450-3.

Motor ProtectionNEC Article 430 provides extensive, detailed information about the requirements for motor protection and installation.

In general, motors should be protected against the following hazards:

1. Electrical

– Faults in windings and associated circuits

Fig. 600-28 Recommended Minimum Protection for Transformers 2500 kVA and Below, Medium and Low-Voltage Windings

Fig. 600-29 Recommended Minimum Protection for Transformers 750 kVA and Above, Medium-Voltage Windings



– Excessive overloads– Reduction or loss of supply voltage– Phase reversal– Phase current unbalance– Loss of phase– Loss of excitation or synchronism for synchronous motors– Excessive ambient temperatures– High cyclic duty operation– Lightning and voltage surges

2. Mechanical

– Bearing and lubrication failures– Loss of ventilation– Excessive vibration

It is not always possible, or even desirable, to provide protection against each of these hazards (especially for small motors where the cost of protection may approach the replacement cost of the motor). The cost of motor protection must be weighed against the probability of a failure occurring, the cost of motor repair or replacement, and the cost of motor downtime.

Most three phase motors less than 250 hp which are fed by low voltage (less than 600 volts) are protected by thermal overload relays included in the combination

Fig. 600-30 Example of Transformer Protection Coordination Curve



starter. These relays have heaters in series with the motor conductors. Their sizing is based on the full load current of the motor. When the temperature of the heaters rises due to excessive motor current, this causes a bimetallic switch in the overload relay to change state, tripping the motor. Sometimes melting-alloy overload relays are used instead of the bimetallic type (see Section 635 above).

NEC Article 430-32 requires that the overload relays be set to trip at, or less than, the following multiples of full load current.

Ambient-compensated overload relays can be provided in motor starters to avoid deviations in the trip setting when the motors and starters are not at the same ambient temperatures.

Starter manufacturers have standard tables to help select appropriate overload heaters and circuit breakers or motor circuit protectors supplied with the starters. A motor circuit protector is a circuit breaker with an adjustable instantaneous magnetic trip. See ELC-DS-597, Motor Control Center Specification Data Sheet, for the sizes of motor circuit protectors or manufacturers’ literature. The motor circuit protector provides fault protection for the motor (less than 250 hp)

1. Solid State Multi-function Relay

Large motors and motors at voltages exceeding 600 volts require more exten-sive protection. Figure 600-31 is a guideline for desirable protection functions for motors based on size and voltage. Many of these functions may be combined in solid-state multi-function relays which are specifically applicable to motor protection. These relays are extremely versatile and may have 15 or more functions to protect the motor. These multi-function relays are available for use for motors in conjunction with fused medium voltage starters. Above 1500 hp it is recommended that discrete relays be used for each function (instead of a single multi-function relay). If one of the discrete relays fails, other discrete relays provide backup protection. With discrete relays, all protec-tion is not lost, as might be the case with a multi-function relay failure. Motor starters for motors above 1500 hp usually use circuit breakers rather than fuses.

2. Vibration Instrumentation

On motors of 1000 hp and larger, vibration instrumentation is normally required. The instrumentation (consisting of either bearing-housing mounted velocity probes, accelerometers, or non-contacting shaft vibration probes) monitors motor vibration and provides a signal to shut down the motor if the vibration exceeds specified limits. These devices are recommended since they indicate impending mechanical problems and help to prevent major damage to motors by detecting problems that can be corrected in the early stages.

Motor Category Maximum TripCurrent

Motors with Service Factor 1.15 125%

Motors with temperature rise 40°C 125%

All other motors 115%



Fig. 600-31 Application Table for Motor Protective Devices (Used with permission from “Plant Engineering Maga-zine”, 3-7-74.)



Figures 600-32 through 600-35 show typical relaying schemes for protecting motors of different sizes and voltages. These figures include recommendations for specific considerations for motor protection.

Fig. 600-32 Recommended Minimum Protection for Induction Motors below 1500 hp

Fig. 600-33 Recommended Minimum Protection for Induction Motors 1500 hp and Above



Fig. 600-34 Recommended Minimum Protection for Brushless Synchronous Motors, Medium-Voltage, below 1500 hp

Fig. 600-35 Recommended Minimum Protection for Brushless Synchronous Motors 1500 hp and Above



The following sections briefly discuss some of the protective devices and schemes for motors.

Thermal Protection. Thermal protection (Device 49) is one of the most important protective functions for a motor. The temperature of the insulation of a motor deter-mines the life of the motor; this device warns of high temperature. In small motors, the thermal overload relay provides this function. In larger motors, resistance temperature detectors (RTDs) embedded in the stator windings provide a more direct indication of insulation temperature. In many cases, on large motors, the RTDs are backed up by a special time overcurrent relay which is set so that its char-acteristic is below and to the left of the motor thermal limit curve supplied by the manufacturer. See Figure 600-17 for an example.

Locked Rotor Protection. Closely related to thermal protection, locked rotor protection is often provided by the same relays as overload protection. When a motor starts, it draws locked rotor current. This current significantly increases the temperature of the motor winding. As the motor accelerates, the current deceases to normal. If the motor binds mechanically and does not accelerate, it will continue to draw locked rotor current with a high probability of sustaining damage unless it is tripped off the line. Overload relays provide locked rotor protection on small motors. On larger motors, manufacturers specify a maximum time which the motor can withstand locked rotor current or provide a thermal limit curve with the same information in graphic form. Special time overcurrent relays provide locked rotor protection for large motors. The characteristic curves for these relays lie below and to the left of the thermal limit curve, yet allow the motor time to accelerate and run without being tripped off the line.

Fault Protection. On small low voltage motors (less than 250 hp) fault protection (Device 50/51) is usually provided by motor circuit protectors or fuses. Ground fault protection (Device 50G or 50GS) is usually provided by the circuit breaker for solidly grounded systems or by the ground detection system for high resistance grounded systems. On larger motors (up to about 1500 hp) fault protection may be provided by fused medium voltage starters. These fused starters usually have CTs connected to a ground sensor circuit which trips the starter on a ground fault. The fuses provide the phase fault protection. It is important to specify the anti-single phasing feature on fused starters to prevent continued operation on single phase power (when one of the three fuses blows). On larger motors, the fault protection (Device 50/51) is usually provided by individual phase overcurrent relays and instantaneous overcurrent relays which control circuit breakers. Normally it is recommended that a 50G ground sensor relay be provided on large motors for ground fault protection, only on low resistance grounded systems.

Loss of Field Protection. Synchronous motors and generators require loss of field protection, but induction motors do not. A synchronous motor starts as an induction motor using an auxiliary squirrel cage known as the Amortisseur winding. When the motor is up to speed, the rotor field is energized and the rotor is pulled into synchronism. The Amortisseur winding is no longer used once the motor reaches synchronous speed. If the field is lost while under load, the motor slows down and again tries to run on the Amortisseur winding. The Amortisseur winding will be damaged, unless tripped off the line by a protective device, since the Amortisseur



winding is not built for continuous full load operation. This condition usually is detected by a power factor relay (Device 55). When running normally, the synchro-nous motor has a high power factor (usually 0.8 leading to 1.0). On loss of field, the power factor drops, sometimes as low as 0.5 to 0.6 lagging. The power factor relay detects this drop and trips the motor. The relay is usually blocked during motor acceleration and enabled after the motor has reached synchronous speed. The power factor relay also serves to detect if the motor slips out of synchronism due to system transients and will trip it off the line should the problem persist. Another method of detecting loss of field is to monitor field current and trip on loss of field current. The power factor relay is the preferred method.

Undervoltage Protection. Undervoltage can cause high currents to flow in motors. The undervoltage relay (Device 27) serves to disconnect the motor from the power source on low voltage or loss of voltage. It sends a trip signal to the circuit breaker. Motors served by magnetic starters normally will drop off the line on loss of voltage.

Overvoltage Protection. Switching surges and lightning can cause voltage surges which may endanger motor insulation. Surge arrestors should be used on motors subject to the effects of lightning on overhead lines or switching surges.

Incomplete Sequence Protection. Motors with reduced voltage starting and synchronous motors have multi-step starting sequences which should be completed within a certain amount of time. If the motor does not accelerate to speed and the starter does not complete its sequence within the normal amount of time, the incom-plete sequence relay (Device 48) shuts the motor down.

Motor Differential Protection. This protection is very rapid and is effective at detecting internal faults and ground faults. Like the other forms of differential protection, this relay (Device 87) compares the current entering each winding of the motor with the current leaving the other end of the winding. If they are different, it trips the motor off the line.

Current Balance Protection. Device 46 compares the three phase currents and trips the motor off the line if the difference reaches a specified setpoint. Unbalanced currents in motors can cause severe overheating for small amounts of voltage unbal-ance. This relay also detects loss of phase voltage (due to a blown fuse or an opened winding).

Figure 600-17 depicts a typical time overcurrent curve showing motor fault protec-tion and overload protection.

Generator Protection. Generator protection is beyond the scope of this discussion. See ANSI/IEEE 242 and “Applied Protective Relaying” for more information on generator protection.



640 FusesThere are two major types of fuses: current-limiting and noncurrent-limiting. The IEEE Buff Book is a good source of information. Some fuses respond to fault currents more rapidly than the fastest-acting circuit breakers. Good design practice sometimes dictates a mix of circuit breakers and fuses.

641 Advantages and Disadvantages of FusesThe advantages and disadvantages of fuses over circuit breakers are discussed below.

Advantages• Fuses are mechanically simple, with no moving parts. Thus, they are mainte-

nance-free and do not require periodic checking.

• Fuses generally require less space than circuit breakers.

• Initially fuses are less expensive.

• Fuses combine sensing and interrupting elements in one unit.

• Current-limiting fuses can act quickly enough to limit let-through short-circuit energy and thereby prevent or limit damage to protected equipment and lines.

• A blown fuse provides more incentive for an electrician to correct the cause of a failure than does a tripped circuit breaker. (The tendency with a breaker is simply to reclose it in the hope that the problem has “gone away.”)

Disadvantages• Fuses are single-phase devices. A single one may blow, removing power in an

unbalanced manner. Unless special provisions have been made, a three-phase motor could run single-phased long enough to overheat and be damaged.

• Fuses must be replaced after they have blown.

• Replacing fuses is more hazardous to personnel than resetting a circuit breaker.

• Stocks of replacement fuses must be maintained.

• A fuse might carry several times its rated amperage for an extended period but never blow because the low-level fault eventually is corrected by some other device.

• Blown fuses generally must be replaced by an electrician. This problem is avoided with circuit breakers.



642 Design FeaturesLow voltage (600 volt) fuses are designated by classes: G, H, J, K, L, and others. For each classification, UL standards specify the following design features and defi-nitions.

Current rating. The value of current that can flow through the fuse indefinitely.

Voltage rating. The voltage at which the fuse is intended to be used; i.e., the desig-nated voltage of a circuit in which the fuse can be used safely.

Frequency rating. The designated frequency of the operating voltage of a circuit in which the fuse can be used.

Interrupting rating. The maximum value of current that the fuse is capable of safely interrupting.

Maximum peak let-through current. The instantaneous peak value of current through the fuse during the time that it is opening a circuit.

Maximum clearing thermal energy. The amount of thermal energy developed throughout the entire short-circuit path during the total clearing time, comprised of melting and arcing times, and forming the clearing characteristic of the fuse.

643 Time-Current CurvesManufacturers produce time-current curves (TCCs) for fuses. These are curves with time plotted on the y-axis and current on the x-axis. There are two curves for each fuse—one for minimum melting time and one for total clearing time. The area between the curves is usually cross-hatched, giving the appearance of a band. TCCs are required to coordinate circuit protective devices. See Figure 600-36.

644 Miscellaneous ConsiderationsWhen fuses are used in equipment at elevations above 3000 feet, both their contin-uous-current ratings and their interrupting ratings must be reduced by a correction factor obtainable from Table 1 in ANSI/IEEE C37.40. This correction is necessary because the dielectric strength of air decreases with increases in elevation.

Another consideration when coordinating fuses is that the minimum-melting curves are determined by the manufacturer under the conditions of no initial load current. Manufacturers provide curves necessary to modify the TCCs to account for thermal preloading and high ambient locations of fuses.



645 Current-Limiting FusesCurrent-limiting (CL) fuses, by definition, open and clear (total clearing) the flow of short-circuit current (SCC) in less than 1/2 cycle (0.008 seconds) if the SCC is in the CL range of the fuse. The interrupted current is considerably less than that which would flow if the fuse were replaced by a non-CL device. See Figure 600-37.

One minor drawback to using current-limiting fuses is that the current is interrupted so rapidly that a voltage surge (considerably larger than the system voltage) may be generated. The engineer designing a system must ensure that the basic impulse insu-lation level (BIL), or impulse withstand rating, of all circuit elements is high enough to withstand this arc-voltage surge (which might be twice the system voltage).

The most common type of current-limiting fuse is the silver/sand fuse, which has a silver element in a sand medium (see Figure 600-38). The silver element is current-responsive. The sand cools and absorbs the vaporized silver when the fuse blows.

Heat produced by long-duration overloads damages fuses which are not self-protecting. Heat anneals or otherwise affects the metal element that is the heart of the fuse and can derange its characteristics of operation and renders the fuse erratic

Fig. 600-36 Typical Current-Limiting Fuse Characteristics, Two Different Types Shown (From Standard Handbook for Electrical Engineers, by D. Fink & W. Beatty, 12 ed/1987. Used by Permission of McGraw Hill, Inc.)



and unreliable as a system protective device. A self-protecting fuse is not damaged by moderate overloading. It is prudent however to replace all three fuses in a three-phase system if one fuse blows.

Some manufacturers use patented techniques to manufacture fuses that they claim to be “fatigue-proof” (i.e., self-protective). The silver elements are bent or spiralled to enable them to absorb the contractions and expansions created by the alternate heating and cooling associated with severe duty cycling.

It is important to understand that references made to the interrupting rating of a current-limiting fuse refer to the full available fault current that could flow, and not to the first portion of current that actually does flow (let through by the fuse). More-

Fig. 600-37 The Current Limiting Action of Current-limiting Fuses (From Standard Handbook for Electrical Engineers, by D. Fink & W. Beatty, 12 ed/1987. Used by permission of McGraw Hill, Inc.)

Fig. 600-38 Typical Current-limiting (Silver-Sand) Fuse (Copyright by, and reprinted with permission of A. B. Chance Company) (Courtesy of A. B. Chance Co.)



over, current-limiting fuses are not capable of protecting against low levels of fault current. Interrupting extremely high levels of fault current is the real forte of CL fuses.

No device approaches a CL fuse’s capacity to extinguish very high fault currents in less than 1/2 cycle of the fault’s initiation.

Medium Voltage CL FusesBecause of the highly specialized action of CL fuse’s, two variations of the “pure” CL fuse has been developed for medium voltage circuits. The first type is the orig-inal “pure” fuse, now called an R-rated fuse (ANSI C37.46), or a “backup” fuse because it offers backup protection against large faults. Less important faults are handled by other protective devices in series with the backup fuse.

ANSI R-rated CL fuses are excellent for motor service since they are able to carry high starting currents during prolonged acceleration without blowing or deterio-rating. Normally they are not assigned actual current ratings, but information is provided about typical melting time, total arc clearing time, and CL characteristics. Generally, the R rating multiplied by 100 approximates the ampere level that will cause the fuse to melt in about 20 seconds. The minimum fault current these fuses can respond to is the continuous current rating. Lesser currents must be interrupted by some other overload protection device.

A second type, developed to handle low-level and high-level fault currents, is the general-purpose E-rated CL fuse. This fuse is designed to interrupt faults reliably at 200% to 264% of the fuse’s continuous current rating.

Low Voltage CL Fuses - 600 V and LessUnderwriters Laboratory (UL) recognizes and permits the labeling of only class G, J, L, R, CC, and T fuses as current limiting. A particular UL classification does not indicate unique performance or time-current characteristic; however, dimensional characteristics are unique for a particular class of fuse. By the nature of their fast action, CL fuses are capable of not only limiting the damage normally resulting from a short circuit but also maintaining system voltage to voltage-sensitive equip-ment. Normally, when a fault persists for 2-4 cycles, the system voltage collapses. This fast clearing of faulted branch circuits is especially important for critical loads served by Uninterruptible Power Supply (UPS) systems. Systems designed properly with sufficient fault duty to operate the CL fuse in its current-limiting range, can ride through a shorted branch circuit without jeopardizing the entire system. (See Section 124 System Design).

For UPS-fed 120-V branch circuits, UL Class T (300 V and 600 V) and Class J (600 V) fuses are recommended. Transformers and branch-circuit wire size and circuit lengths must be selected carefully to ensure that a minimum of 200 amperes of fault duty is available at the load (end device). At 200 amperes, a 20-ampere Class J or T CL fuse is at the low end of its current-limit range and clears a fault completely in less than 1/2 cycle.



Smaller rated fuses become current limiting at progressively lower fault levels. For example a 10 ampere Class J or T CL fuse is current limiting at about 100 amperes compared to 200 amperes for a 200 ampere Class J or T fuse.


651 Model Specifications (MS)There are no specifications related to this guideline.

652 Standard DrawingsThere are no standard drawings related to this engineering guideline.

653 Data Sheets (DS), Data Guides (DG) and Engineering Forms (EF)There are no engineering forms related to this engineering guideline.

654 Other ReferencesANSI/IEEE C37.40, Service Conditions and Definitions for High Voltage Fuses, Distribution Enclosed Single-Pole Air Switches, Fuse Disconnecting Switches, and Accessories

ANSI/IEEE C37.2, Electrical Power System Device Function Numbers

ANSI/IEEE Standard 141, IEEE Recommended Practice for Electric Power Distri-bution for Industrial Plants

ANSI/IEEE Standard 242, IEEE Recommended Practice for Protection and Coordi-nation of Industrial Power Systems

*API RP 14F, Design and Installation of Electrical Systems for Offshore Produc-tion Platforms

ANSI/IEEE Standard 100, IEEE Standard Dictionary of Electrical and Electronics Terms

Beeman, Donald, ed., Industrial Power Systems Handbook (McGraw-Hill: NY, 1977).

Fink, Donald G., and Wayne Beaty, eds., Standard Handbook for Electrical Engi-neers (McGraw-Hill: NY, 1987).

Blackburn, J.L., ed., Applied Protective Relaying, Westinghouse Electric Corpora-tion (Coral Springs, Fla., 1982).



Smeaton, Robert W., ed., Switchgear and Control Handbook (McGraw-Hill: NY, 1977).

Chevron Corporation 700-1 September 1990

700 Switches

AbstractThis section describes and compares five types of switches used in power circuits: disconnect switches, load interrupter switches, safety switches, automatic transfer switches, and oil fused cutouts. The switches are compared on the basis of their interrupting capabilities. Fusing is discussed for all of the above except for the disconnect switch.

Contents Page


711 Scope

712 Switches—An Overview

720 Disconnect Switch 700-4

730 Load Interrupter Switch 700-4

731 Air Load Interrupter Switches

732 Metal-Enclosed Load Interrupter Switches

733 Oil Interrupter Switch

734 Air Interrupter Switch vs. Oil Interrupter Switch

735 Interrupting Power to Transformers

736 Fused Load Interrupter Switch

740 Low Voltage Safety Switches 700-9

750 Automatic Transfer Switches 700-11

760 Oil Fused Cutouts 700-13


771 Model Specification (MS)




700 Switches Electrical Manual

September 1990 700-2 Chevron Corporation

710 Introduction

711 ScopeThis section provides an overview of the five basic types of switches used in power circuits:

• Disconnect switch• Load interrupter switch• Safety switch• Automatic transfer switch• Fused oil cutout

712 Switches—An OverviewA switch is a device which opens and closes a circuit. When a switch is closed, it will conduct electricity and when it is opened, it will not conduct electricity. Switches are often referred to as single-pole or multi-pole devices. “Multi-pole” usually means two or three poles. A pole is that portion of a switch associated with a separate conducting path. In a multi-pole device, the poles are coupled in such a manner that they mechanically operate together. A multi-pole device is often referred to as a gang or group-operated device. Switches are often referred to as “single throw” or “double throw” devices. These are qualifying terms indicating the number of open and closed positions of a switching device. A single throw device has one open and one closed position only. A double throw device can change the circuit connections by utilizing either one of its two closed positions.

The switches discussed below are used primarily on distribution feeder circuits. A disconnect switch (see Figure 700-1) is often used to isolate a circuit or equipment from a source of power. Disconnect switches usually are operated when circuits are de-energized or when the interrupted currents are low.

Load interrupter switches (see Figure 700-2) are three-pole devices associated with unit substations supplied from the primary distribution feeder. The most common function of load interrupter switches is to provide isolation of the unit substation from its incoming feeder.

A quick-make, quick-break switch is one in which the operating speed of the switch mechanism is independent of the speed of the handle movement. The switch has springs that cause the contacts to move very quickly once operation of the switch is initiated. Not all switches discussed in this section are quick-make, quick-break.

Electrical Manual 700 Switches


Fig. 700-1 Disconnect Switches (Courtesy of S & C Electric Company)

Fig. 700-2 Load Interrupter Switch (Courtesy of S & C Electric Company)



720 Disconnect SwitchDisconnect switches are used to isolate equipment or a section of line from a feeder, a feeder from a substation, or a substation from a transmission line. This electrical isolation makes the area safe for repairs, tests, inspections or modification after the circuit has been grounded. This switch is sometimes designed to interrupt the small capacitive charging current of cables or transmission lines and the magne-tizing current of transformers. It is not designed to interrupt load current. Inter-locking is generally provided to prevent operation when the switch is carrying load current. A disconnect switch is designed to carry normal load current continuously and abnormal or short circuit current for a specified short interval. A disconnect switch must not be opened under load; the load must be disconnected by some other means such as a circuit breaker. If a disconnect switch is opened under load, an arc could be drawn between the blade and the stationary contact, or even between the blade and other conductors or ground. The hot arc produced could damage the switch and injure personnel.

A number of disconnect switch types are available. Each is designed to perform its circuit isolation function in a specific fashion. Generally, when reference is made to a disconnect switch, a no-load disconnect switch is implied. A no-load disconnect switch is an air-break, hand-operated switch. It is not designed to interrupt current. Its function is simply to disconnect equipment after all loads have been discon-nected by other means. One type of disconnect switch is shown in Figure 700-1.

Disconnect switches typically are not quick-make, quick-break.

To purchase disconnect switches, it is recommended that manufacturers’ standards be utilized.

730 Load Interrupter SwitchThe load interrupter switch (see Figures 700-2 and 700-3) is a switch (fused and unfused) which combines the operations of interrupting the load current and discon-necting the circuit. Load interrupter switches can be air or oil-immersed and are usually manually operated. These switches have blades and stationary contacts. Air interrupter switches are equipped with arcing horns (pieces of material in which the arc forms when a circuit carrying current is opened). Air load interrupter switches have primary (blade) and arcing (secondary) contacts. The main blade opens first, disconnecting the circuit. The secondary contact of the interrupter switch then lengthens and cools the arc until it extinguishes. In other load interrupter switches, there are only main blades and arc chutes. In oil-immersed load interrupter switches, the oil cools and extinguishes the elongated arc.

Load interrupter switches are most often used for services above 600 volts and are usually associated with substations supplied from the primary distribution system. They are available in ratings up to 4000 amperes interrupting capacity at 600 volts and 1200 amperes at 5 kV and 15 kV. Load interrupter switches are quick-make, quick-break. They have close and latch current ratings which specify the maximum fault current into which they can close. The close and latch current is the current



flowing when a switch successfully latches. These switches also have short-time current ratings for both momentary (one cycle) and 3-second conditions.

731 Air Load Interrupter SwitchesAn air load interrupter switch is designed to open and close one or more poles with contacts that separate in air. There are three basic types of air interrupter switches: the single air interrupter switch, the duplex selector switch, and the selector switch.

The single air interrupter switch has open and closed positions and is usually three-phase. The interrupter has a stored-energy (spring) device and can be equipped to operate manually or electrically. A stored-energy-operated device uses springs to open or close the switch, making the speed of opening and closing inde-pendent of the speed of the operating handle. A switch with a stored-energy mecha-nism must be properly adjusted so that when the switch is closed it will have complete contact. With a stored-energy device, the spring is charged as the handle is moved to the open position. This assures a delay after the switch is closed and prevents the switch from being opened before a protective device has operated. Operating mechanisms have indicating targets to show the position of the switch blades and to show the condition of the charging springs (charged or discharged). There is also a window on the front panel for visual inspection of the switch blades.

A duplex selector switch consists of two three-pole, single-throw, air interrupter switches. The two switches may permit four different positions (line 1, line 2, lines 1 and 2, or open). See Figure 700-4.

The two switches can be key-interlocked to prevent being closed at the same time. Both switches can be designed for manual or electrical operation and are stored-

Fig. 700-3 Fused Load Interrupter Switch (Courtesy of S & C Electric Company)



energy-open and stored-energy-closed. Indicating targets show whether the switch blades are open or closed. A window permits inspection of the switch blades. The duplex selector switch is frequently used when two separate power sources feed one load.

A selector switch consists of one three-pole, single-throw, two-position (open and closed) air interrupter switch and one three-pole (line 1, open, line 2) disconnect switch, both of which are mounted in a single enclosure. See Figure 700-5. The interrupter switch is stored-energy open and stored-energy closed and can be electri-cally or manually operated. The disconnecting switch handle has indicating targets (line 1, line 2 and open) to show the position of the switch blades. The interrupter switch is connected in series with the disconnecting switch. The handle of the disconnecting switch usually is interlocked with the interrupter switch to prevent operation of the disconnect switch when the interrupter switch is closed.

Fig. 700-4 Typical One-Line of a Three-Pole Duplex Selector Switch

Fig. 700-5 Typical One-Line of a Three-Pole Selector Switch



732 Metal-Enclosed Load Interrupter SwitchesIf metal-enclosed load interrupter switches are being considered, contact an elec-trical engineer who is familiar with their application (i.e., The Electrical Group in Engineering Technology Department) for a list of suitable manufacturers. The selec-tion requires critical review to ensure that a reliable design is being purchased. To purchase 5 kV and 15 kV switches, it is recommended that Data Sheet Guide ELC-DG-3944, Data Sheet ELC-DS-3944, and Model Specification ELC-MS-3944 be used.

Metal-enclosed load interrupter switches are available with interrupting ratings of 600 or 1200 amperes for system voltage ratings of 2.4 through 34.5 kV. This switch is completely enclosed with sheet metal except for ventilating openings and inspec-tion windows. Metal-enclosed load interrupter switches typically are installed ahead of a transformer as a primary disconnect means. See Figure 700-6.

To ensure proper performance, metal-enclosed interrupter switches should provide the following features:

• Minimal periodic maintenance requirements

• Adequate interrupting capability for load currents, transformer magnetizing currents, and line and cable charging currents

• Interruption of currents without external arc or flame

• Visible isolating air gap after interruption

• Capability, where required, of manually or automatically closing on faults up to the interrupting rating of the associated fuses

Fig. 700-6 Metal-enclosed Load Interrupter Switch



• Controlled sequence, so that interrupting unit contacts do not open except within the arc extinguishing chamber of the interrupting unit

• Full load interrupting rating equal to continuous current rating of the device

• Doors of the enclosure interlocked to prevent accidental opening while the interrupter switch is energized. This also prevents energizing while the door is opened (unless there is a protective barrier). Any barrier must also be inter-locked to prevent opening if the load interrupter switch is closed or closing

Metal-enclosed interrupter switches are provided with a handle used to charge the quick-make, quick-break mechanism. Most handles are provided with holes for padlocking in either the open or closed position. The switch should have an indi-cating device to show the position (open or closed).

733 Oil Interrupter SwitchOil interrupter switch specifications are not provided in this manual. Oil interrupter switches have contacts which open and close under oil. The switch contacts are immersed in oil and the entire apparatus is enclosed in a steel container. The oil insulates the poles and helps extinguish the arc formed when the switch contacts are opened. After several hundred operations, the oil should be replaced or filtered to remove carbon products formed by arcing.

734 Air Interrupter Switch vs. Oil Interrupter SwitchThe advantages of the air interrupter switch over the oil interrupter switch are as follows:

• The air interrupter switch has a visible air break so there is no question that the circuit is disconnected

• Air, the insulating medium, does not require maintenance; oil could leak out of the enclosure of an oil interrupter switch

• Air switch contacts are easily accessible for testing (e.g., phasing)

• The air interrupter switch does not use oil which can carbonize and allow some current to flow when the switch is open

The disadvantages of the air interrupter switch compared to the oil interrupter switch are as follows:

• Air switches are not as resistant to corrosive environments as oil switches. This is particularly important for off-shore platforms

• Air switches are larger than oil switches. This factor can be a problem when floor space is at a minimum

• Air switches cannot be used in Class I, Division 1 or 2 hazardous (classified) areas unless enclosed in NEMA 7 enclosures



735 Interrupting Power to TransformersIn many cases the primary switching devices on transformers are air- or oil-filled load interrupter switches. These interrupter switches must not carry full-load currents more than the continuous rating of the switch. Short term currents in excess of the continuous current rating of the switch may be caused by events, such as temporary or prolonged overload, motor-starting, or faults in the system, that can subject the switch to currents in excess of its interrupting rating. It is recommended that all loads be removed before primary load interrupter switches are opened. Key-interlocking prevents operation of the switch unless the transformer secondary breaker is opened. This requires the operator to lock the transformer secondary breaker open before the switch can be operated.

736 Fused Load Interrupter SwitchLoad interrupter switches are often fused and are referred to as “fused load inter-rupter switches” or “fused load-break switches.” These switches are used to both disconnect and protect circuits. Fused load interrupter switches consist of an inter-rupter switch and fuses mounted on a common base, usually in a metal enclosure. Although generally less expensive than circuit breakers, they have protection and system application limitations. Circuit breakers are usually recommended. The configuration shown in Figure 700-7 shows a typical fused load interrupter switch.

740 Low Voltage Safety SwitchesSafety switches (see Figure 700-8) are used for voltages up to 600 volts and are always enclosed. These switches have quick-make, quick-break features, and can be fused or unfused. The safety switch is operated with an outside handle. The handle

Fig. 700-7 Typical Fused Load Interrupter Switch (Courtesy of S & C Electric Company)



is interlocked so that the enclosure cannot be opened unless the switch is in the open position (or the defeater is operated.)

If a motor is protected with a safety switch, the safety switch should be capable of interrupting the maximum starting current of the motor (the locked rotor current). The continuous current rating of the safety switch must be at least 115% of the full-load current rating of the motor. Some safety switches use current-limiting fuses. Switches are labeled to indicate the proper switch and fuse combination that meet the specified current rating. Safety switches should be tested per UL 98 “Enclosed Switches.”

Bolted-pressure safety switches have a toggle mechanism for applying bolted pres-sure to both the hinge and the jaw contacts. Two different types of bolted-pressure

Fig. 700-8 Typical Safety Switch



switches are available, the manually operated bolted pressure switch and the elec-tric-trip bolted pressure switch. Both types of bolted pressure switches consist of movable blades and stationary contacts. The stationary contacts have “arcing contacts” which cause the arc to be extinguished rapidly. The operating mechanism (that part of the mechanism that actuates all the main-circuit contacts of the switching device) consists of a spring that is compressed by the operating handle and released at the end of the operating stroke to provide quick-make and quick-break operations. The bolted-pressure switch can be applied to 100% of its rating.

The electrical-trip bolted pressure switch uses a stored-energy latch mechanism and a solenoid trip release to provide automatic electrical opening for low voltage main and feeder circuits rated at 600 amperes and above. These switches can be used with ground fault protection equipment and have contact interrupting ratings of 12 times the continuous current rating. When used with current-limiting fuses, this switch can be used on some circuits with available symmetrical fault currents of 200,000 amperes. These switches are most commonly used in commercial buildings.

750 Automatic Transfer SwitchesAutomatic transfer switches are typically used to connect an alternate power source or standby power generation system to the distribution system. When the power fails, the transfer mechanism automatically transfers the load to the alternate source or system. See Figure 700-9 for a typical sequence.

Fig. 700-9 Typical Sequence for Automatic Switching on a Two Feeder System



The automatic transfer switch can be programmed to automatically reconnect the load to the preferred feeder when it has been restored. This switch is furnished with relays, controls, and critical operating components, such as timers, test switches, and indicating lights. Automatic transfer switches usually are double-throw without overcurrent protection. These switches are available in ratings of 30 to 4000 amperes. Switches rated over 100 amperes are mechanically held and are electri-cally operated from the power source to which the load is to be transferred. Auto-matic transfer switches must satisfy the following requirements:

• Close against inrush currents without contact welding

• Carry full rated current continuously without overheating

• Withstand available short-circuit currents without contact separation for at least 0.2 seconds

• Properly interrupt circuits without flashover between the two power sources

Some automatic transfer switches include in-phase monitors for transfer between sources. If the sources are in phase, there will be no flashover. It is important to coordinate the automatic transfer switch and the overcurrent protection. When high fault currents occur, electromagnetic forces are created in the contacts of circuit breakers. These electromagnetic forces help circuit breakers to open quickly and minimize clearing time of faults. Automatic transfer switches, designed to with-stand high fault currents, utilize the electromagnetic forces in the reverse manner—keeping the transfer switch contacts closed until the fault has been cleared. If the contacts of the automatic transfer switch should open during a fault, the high fault current could cause arcing and welding of the contacts. For more information on specifying an automatic transfer switch with proper ratings, accessories and features, see Section 4.3 of the IEEE Orange Book (IEEE Standard 446).

The three types of automatic transfer switches are non-preferential, fixed-preferen-tial, and selective-preferential. The non-preferential type automatically re-transfers the load to the original source only when the alternate source, to which it has been connected, fails. The fixed-preferential type is a device in which the original source always serves as the preferred source and the other source serves as the emergency source. This switch will re-transfer the load to the preferred source when it is re-energized after a loss of voltage. The selective-preferential type is a device in which either source may be designated as the preferred or emergency source and can be pre-selected. The switch will re-transfer the load to the preferred source upon re-energization.

For both the fixed-preferential and the selective-preferential type, the re-transfer of the load to the preferred source from the emergency source upon re-energization may be of the make-before-break type or the break-before-make type. These two switches differ in that the make-before-break transfer switch transfers from one circuit to another without interrupting the current, while the break-before-make transfer switch interrupts the current flow before transferring to the other source.

Many automatic transfer schemes can be used. To accommodate the variety of transfer control schemes required, a number of manufacturers provide standard



automatic control devices for integration with metal-enclosed load interrupter switches. Automatic transfer switches can be purchased to provide the following:

• Either source preferred• Manual or automatic transfer• Make-before-break or break-before-make transfer• Time delay on transfer• Manual or automatic re-transfer• Lockout on bus faults

To develop specifications for automatic transfer switches for emergency power systems, refer to Standard Drawing GF-P99972. For applications, consult manufac-turer directly.

760 Oil Fused CutoutsOil fused cutouts can be used to disconnect and protect circuits. Oil fused cutouts must not be used to energize circuits because they are not rated to close into a fault. Instead, an upstream circuit breaker must be used to energize the circuit. A fused oil cutout switch is a combination of a load interrupter switch and fuses. The fuse in the fused oil cutout usually is of the non-current-limiting type. The switch is used for circuits rated up to 15 kV. The interrupter (which is the “cutout”) and the fuses are immersed in oil. They have low short circuit ratings and no “close-and-latch” rating.

Oil-fused cutouts may be used to energize circuits if (a) they have a fault closing rating and (b) they fully comply with NEC 710-21(d).

Oil-fused cutouts differ from the other switches discussed in this section; when manually operated the speed of the switch is dependent on the speed with which the operator moves the handle. When an overcurrent occurs, the excessive current melts the fuse, creating an arc below the oil level.

See: Eastern Region Exploration, Land and Production, Electrical Construction Guidelines for Offshore, Marshland and Inland Locations for an example of special packaging for 5 kV oil-fused cutouts suitable for corrosive environments.


771 Model Specification (MS)

*ELC-MS-3944 Load Interrupter Switches





774 Other ReferencesANSI/IEEE, Standard 446 - IEEE Recommended Practice for Emergency and Standby Power System for Industrial and Commercial Applications

ANSI/IEEE, Standard 141 - IEEE Recommended Practice for Electric Power Distribution for Industrial Plants

ANSI/IEEE C37.30 - Definitions and Requirements for High-Voltage Air Switches, Insulators, and Bus Supports

IEEE C37.32 - Schedules of Preferred Ratings, Manufacturing Specifications, and Application Guide for High-Voltage Air Switches, Bus Supports, and Switch Acces-sories

ANSI, C37.33 - Rated Control Voltages and Their Ranges for High-Voltage Air Switches

ANSI/IEEE, C37.34 - Test Code for High-Voltage Air Switches

IEEE, C37.35 - Guide for the Application, Installation, Operation and Maintenance of High-Voltage Air Disconnecting and Load Interrupter Switches

ANSI/IEEE, C37.37 - Loading Guide for AC High-Voltage Air Switches (In Excess of 1000 Volts)

ANSI/IEEE, C37.48 - Guide for Application, Operation, and Maintenance of Distri-bution Cutouts and Fuse Links, Secondary Fuses, Distribution Enclosed Single-Pole Air Switches, Power Fuses, Fuse Disconnecting Switches, and Accessories

ANSI/IEEE, C37.71 - Standard for Three-Phase, Manually Operated Subsurface Load Interrupting Switches for Alternating Current Systems

ANSI/IEEE, 100 - IEEE Standard Dictionary of Electrical and Electronic Terms

Beeman, Donald. Industrial Power System Handbook (McGraw-Hill, 1955).

Smeaton, R. W. Switchgear and Control (McGraw-Hill, 1987).

Kurtz and Shoemaker. The Lineman’s and Cableman’s Handbook (McGraw-Hill, 1986).

*GF-P99972 480 Volt Stand-by Power System One-Line Diagram

*ELC-DS-3944 Load Interrupter Switch Data Sheet

*ELC-DG-3944 Data Sheet Guide for Load Interrupter Switch Data Sheet


800 Transformers

AbstractThis section provides technical and practical guidance for specifying distribution, power, lighting, and control transformers. The transformer size must first be deter-mined using the guidelines in Section 100, “System Design.” Transformers for relaying (current transformers, potential transformers) are covered in Section 600, “Protective Devices,” which also describes the various transformer types and their specific roles in the power system. This section also lists and briefly discusses the documents containing the latest applicable standards and code requirements. It also describes rating considerations (including operating conditions), design characteris-tics for specific job applications, accessories needed for safe operation, and quality assurance tests.

Contents Page


811 Scope

812 Overview

813 Standards and Codes

814 Transformer Types

820 Insulation for Transformers 800-6

821 Liquid Insulation

822 Dry Insulation

830 Classes of Self-Cooled Transformers 800-8

831 Auxiliary Cooling

832 Typical Cooling Ratings

840 Ratings 800-9

841 kVA Ratings

842 Primary and Secondary Voltage Ratings

843 Temperature Rise

844 Altitude

800 Transformers Electrical Manual


845 Basic Impulse Level (BIL)

846 Impedance

847 Secondary Circuit Voltage

850 Winding Connections 800-13

851 Angular Displacement (Nominal) between Voltages of Windings for Three-Phase Transformers

852 Series Multiple Windings

860 Design Characteristics and Their Application (Construction) 800-14

861 Voltage Taps

862 Paralleling Transformers

863 Location

864 Painting

865 Termination

866 Tertiary Windings

870 Accessories 800-15

871 Liquid Level Gage

872 Fluid Thermometer, Dial Type

873 Pressure Vacuum Gage

874 Pressure Relief Diaphragm in Cover

875 Sampling Device

876 Pressure Regulator

877 Provisions for Future Cooling Fans

878 Sudden Pressure Relays

879 Neutral Current Transformer

880 Grounding Resistors and Bushing Current Transformers 800-21

881 Grounding Resistors

882 Bushing Current Transformers

883 Surge Capacitors/Lightning Arrestors

884 Shop Testing

885 Economics—Evaluation Factor




Electrical Manual 800 Transformers



894 Appendices




810 Introduction

811 ScopeThis section focuses on the basic information required for selecting, specifying, and ordering transformers. It should be used along with the Data Sheet Guide when completing the Transformer Data Sheet, ELC-DS-401.

812 OverviewTransformers are primarily used to reduce (or increase) voltage to a level where it can be used to power equipment. Transformers are also used to isolate loads from power sources and to accomplish a variety of special functions. These functions include phase shifting, regulating, and networking.

Transformers obey the following relationship: the ratio of the primary voltage to the secondary voltage equals the ratio of the number of primary turns to the number of secondary turns. This ratio also equals the ratio of secondary current to primary current.

813 Standards and CodesTransformers are designed, fabricated, and tested in accordance with ANSI, NEMA, and IEEE standards.

Dry-type distribution transformers through 1000 kVA three-phase, and through 167 kVA single-phase, 600 volts and below, are designed in accordance with Under-writers’ Laboratories, Inc. (reference documents UL-506, 891, and 1561.)

NFPA-70 (National Electrical Code), API RP 14F, and applicable governmental regulations should be reviewed prior to selecting transformers. Transformers should be labeled by a recognized testing laboratory (usually Underwriters’ Laboratories, Inc.) in the United States. Foreign-made transformers are built to specific national or IEC standards.

814 Transformer TypesSix types of transformers are described below: distribution, power, control power, buck-and-boost, auto-transformer, and constant voltage.

Instrument transformers are discussed in Section 600, “Protective Devices.” Captive transformers, power transformers that supply power to a single motor load, are discussed fully in Section 100, “System Design.” Grounding transformers are discussed in Section 900, “Grounding Systems.”

DistributionDistribution transformers cover power ranges of 3 to 500 kVA. They are either liquid-immersed or dry. They can be mounted on a pole, pad, wall, or floor. They



can be installed aboveground or underground (in a transformer vault) and can be installed indoors or outdoors.

PowerPower transformers cover power ranges above 500 kVA. They can be dry-type but more often are liquid-immersed (oil-filled). Oil-filled transformers are recom-mended for most outdoor installations.

Control PowerControl power transformers generally supply power to instruments, relays, and startup and shutdown circuits, however, they are sometimes used for cubicle and motor space heating and for substation lighting. They usually are rated up to 15 kVA and are of encapsulated core and cell construction—providing a totally enclosed, non-ventilated system.

Buck-and-Boost TransformerBuck-and-boost transformers are power transformers that can decrease or increase the voltage level. They are designed for small voltage increments and only for low voltage systems (600 volts and below). For example, voltage at motor terminals can be corrected by using a buck-and-boost transformer instead of resizing the line. Some electrical equipment requires that line voltage be at or near its nameplate rating for efficient operation. Buck-and-boost transformers provide a convenient and cost-effective way to match the line voltage to the equipment nameplate rating.

Buck-and-boost transformers are not suitable for solving a fluctuating voltage problem. They are only suitable for compensating for high or low voltage when the available line voltage is constant.

Buck-and-boost transformers are connected as auto-transformers and can be used for single and three-phase circuits. They can be installed indoors or outdoors.

Auto-TransformerAuto-transformers can be either distribution or power transformers. They typically are used to step voltage up or down slightly (±5%). For example, they can be used to reduce a 13.8 kV bus to a 12.47 kV bus. The auto-transformer’s primary and secondary circuits share a single coil (two coils connected in series). Because the primary and secondary circuits share part of a coil, the transformer does not provide electrical isolation between the load circuits and the primary circuits. However, the auto-transformer does have certain advantages over a two-winding transformer: lower cost, greater efficiency, better regulation, smaller physical size and weight, and a smaller exciting current.

These advantages are the result of the following: unlike a normal transformer where all the power must flow across the electrical isolation from the primary to the secondary by means of a magnetic field, an auto-transformer requires only a frac-tion of the power to flow across the electrical isolation by means of an electric field. The remainder flows directly from the primary to the secondary by means of the shared coil with no electrical isolation.



See Figure 800-1 for a better understanding of the principle and function of auto-transformers.

Constant Voltage TransformerSensitive electronic equipment may be subjected to line transients, surges, spikes, and sustained low voltage. These voltage variations can have damaging effects on sensitive equipment over the long term due to stresses on the power supply compo-nents.

A constant voltage transformer can be used to minimize these voltage fluctuations. The transformer operates in its saturation region so that a small voltage fluctuation on the primary side will not be transferred to the secondary side. This transformer is frequently called a voltage regulator.

820 Insulation for TransformersTransformers are insulated by either a liquid or a dry media.

821 Liquid InsulationLiquid-immersed transformers include 1) oil insulated, 2) non-flammable liquid insulated (Inerteen or PCB laden Askarel), and 3) low-flammable liquid insulated.

Oil InsulatedThe oil-insulated unit is the least expensive of liquid-insulated transformers and is suitable for mounting outdoors or, when enclosed in a vault, indoors. Mineral oil is recommended for most oil-insulated transformers because of its high dielectric strength, durability and high flash point.

Fig. 800-1 Auto-Transformer Connection



Non-Flammable Liquid InsulatedThe manufacture of non-flammable (PCB) liquid-insulated transformers in the United States ceased in 1977 as a result of laws and regulations concerning the envi-ronmental and health effects of PCBs. When replacing or repairing existing trans-formers, be aware that PCB-filled transformers are still in use at many Company facilities. The law does not allow the repair (removal of the core) of a transformer with greater than 500 PPM concentration of PCB. For this reason, and to lower PCB exposure, it is recommended that Company facilities replace or detoxify PCB-contaminated transformers.

Processes are available to chemically treat a transformer in order to reduce the level of PCBs. The benefit is that repair to the core of the transformer can be performed if necessary without further inspection for PCB purposes. Detoxification allows treat-ment of the unit as a non-PCB transformer.

All PCB transformers must be labeled, inspected, handled and disposed of in accor-dance with strict safety and environmental regulations.

See ANSI/IEEE C57.102 for further information on handling PCBs. Also see EPA regulation TSCA, “Electric Rule” of 1982 and “Fires Rule” of 1985.

Low-Flammable Liquid InsulatedFor indoor installations, the discontinued use of askarel-filled transformers has promoted the use of less flammable liquid-insulated transformers (formerly referred to as high fire point liquids). These include silicones, polyalphaolefins, and high molecular weight hydrocarbons that have a flash point of at least 300°C. In general, these less flammable insulation materials are more expensive than mineral oil.

Two agencies, Factory Mutual Research Corp. and Underwriters’ Laboratories Inc., list less flammable liquids for transformers.

822 Dry InsulationDry-insulated transformers do not employ a liquid as a cooling or insulating medium. The dry-type transformer is designed to have the core and coils surrounded by an atmosphere (which may be air), that is free to circulate from the outside to the inside of the transformer enclosure. An alternative to circulating outside air freely through the dry-type transformer is to provide a sealed enclosure in which an insu-lating gas or vapor is contained. In either case, the surrounding medium acts both as a heat transfer medium and as a medium suitable for either indoor or outdoor instal-lation, as specified.

The primary disadvantage of the dry-type transformer is that the basic insulation level (BIL) is lower than for liquid-immersed transformers. This disadvantage may be compensated for, if necessary, by installing surge capacitors and lightning arres-tors. Most 30 kVA and larger dry-type distribution transformers manufactured today are designed with a NEMA Class 220°C insulation system.

For many offshore applications, non-ventilated dry-type transformers are specified. The shell is constructed of a 10-gage, type 316 stainless steel enclosure rated



NEMA 4X. The insulation system is a vacuum impregnated, Class H rated silicone varnish. The temperature rise of the completed transformer is specified not to exceed 80°C, in accordance with NEMA and ANSI test standards (See Appendix D, “Minimum Requirements for Dry-Type Transformers”).

830 Classes of Self-Cooled TransformersANSI standard C57.12 lists two classes of self-cooled transformers:

• Liquid-immersed, self-cooled: Class OA. A liquid-type transformer in which the insulating oil circulates by natural convection within a tank having smooth sides, corrugated sides, integral tubular sides, or detachable radiators. The transformer requires from 24 to 36 inches of clearance on all sides for adequate air circulation.

• Dry-type Self-cooled: Class AA. A dry-type transformer which is cooled by the natural circulation of air.

831 Auxiliary CoolingOne way to protect a transformer from overloads is to increase the transformer’s capacity with the use of auxiliary cooling. The most commonly used transformers with auxiliary cooling and their classifications follow:

• Liquid-immersed, self-cooled/forced-air-cooled: Class OA/FA. A forced-air-cooled transformer, FA, is basically an OA unit with fans and requires approxi-mately twice the space needed by an OA transformer. The transformer may be purchased with fans installed or with the option of adding fans later (OA/FFA). Typically, fans are thermostatically controlled.

• Liquid-immersed, self-cooled/forced-air-cooled/forced-air-cooled: Class OA/FA/FA. An increased level of fan cooling is provided for increased air flow.

• Liquid-immersed, self-cooled/forced-air-cooled/forced-liquid-cooled: Class OA/FA/FOA. An OA/FA unit is provided with a second stage of cooling by means of an oil pump. The FOA rating is intended for use only when both the oil pumps and fans are operating.

• Liquid-immersed, self-cooled/forced-air-forced-liquid cooled/forced-air-forced liquid cooled: Class OA/FOA/FOA. In this class there are two stages of fan/pump combinations to enhance cooling.

• Dry-type, self-cooled/forced-air-cooled: Class AFA. A dry-type transformer which has both a self-cooled rating with cooling obtained by the natural circu-lation of air and a forced-air-cooled rating with cooling obtained by the forced circulation of air.



832 Typical Cooling RatingsTypical rating increases for forced-air and forced-liquid transformers are listed in Figure 800-2. For example, an oil-filled 2500 kVA transformer with forced air (OA/FA) gives an additional 25% increase in kVA over the self-cooled oil-filled transformer (OA) which equals a total of 3125 kVA. If the transformer is also rated 55°C/65°C, there is an additional 12% increase. That is, the FA rating for the 2500 kVA transformer is 125% of 112% (140%) of 2500 kVA which equals 3500 kVA.

840 RatingsThere are various rating categories for transformers. The following ratings allow the transformer to perform efficiently and safely under specified conditions.

841 kVA RatingsSee Section 100, “System Design,” for standard transformer ratings and trans-former sizing information.

A transformer can be overloaded intermittently within limits without physically damaging the transformer or significantly reducing its life expectancy. See ANSI C57.91 for information on how to calculate the amount and the duration of over-load that a transformer can withstand without experiencing a loss of life expect-ancy. This standard also discusses how to increase the life expectancy of a transformer. For instance, liquid-filled transformers can withstand overloads of short duration because of the thermal properties of oil. The duration of the overload may be shorter than the time it takes the oil to heat past its rated temperature rise. See Section 843 below, for information on temperature rise.

Fig. 800-2 Cooling Ratings for Forced Air/Forced Liquid

Self-Cooled 55°C Rating (kVA)Percent Rating Increase with Auxiliary

Cooling (Over Self-Cooled Rating)

Class 1-Phase(1) 3-Phase(1) 1st Stage 2nd Stage

OA/FA 501-2499 501-2499 15% –

OA/FA 2500-9999 2500-11999 25% –

OA/FA 10000 & above 12000 & above 33 1/3% –

OA/FA/FA 10000 & above 12000 & above 33 1/3% 66 2/3%

OA/FA/FOA 10000 & above 12000 & above 33 1/3% 66 2/3%

OA/FOA/FOA 10000 & above 12000 & above 33 1/3% 66 2/3%

AA/FA 501 & above 501 & above 33 1/3% –

(1) Add 12% to all self-cooled ratings for 55°/65°C rated transformers



842 Primary and Secondary Voltage RatingsStandard nominal and maximum system voltages are included in manufacturers’ literature in compliance with ANSI C84.1. The voltage ratings specified are at no load and are based on the turns ratio of the transformer.

The voltage rating required for transformers is determined primarily by the system voltage available and the utilization voltage required. For the purpose of trans-former selection, the primary and secondary voltages are set by the system design. See Section 100, “System Design” for standard voltage ratings.

843 Temperature RiseA transformer should achieve a normal life at rated kVA if the specified tempera-ture rise is not exceeded and the ambient temperature does not peak above 40°C, or average more than 30°C during a 24-hour period. The temperature rise rating indi-cates how many degrees above the ambient temperature of 40°C (maximum) or above the average of 30°C during a 24-hour period the winding can tolerate while supplying 100% rated load without loss of life. The standard average winding temperature rise (by resistance test) for the modern liquid-filled power transformer is 65°C with a hot-spot temperature rise of 80°C. Liquid-filled transformers may be specified with a 55°C/65°C rise to permit 100% loading with a 55°C rise, and 112% loading at the 65°C rise. The dual rating transformer is recommended for most applications because a 5% increase in transformer cost provides an additional 12% in loading capacity.

Standard dry-type transformers are divided into three groups for temperature rise specification purposes.

1. Class 150°C limiting temperature insulation system (for temperature rise by resistance through 80°C) with component insulating materials including mica, asbestos glass fiber, and similar inorganic material.

2. Class 185°C limiting temperature insulation system (for temperature rises by resistance through 115°C) with component insulating materials including mica, asbestos, glass fiber, and other materials with thermal life at 185°C.

3. Class 220°C limiting temperature insulation system (for temperature rises by resistance through 150°C) with component insulating materials including sili-cone elastomer, mica, glass fiber, asbestos, and other materials with thermal life at 220°C.

Aging (deterioration) of insulation is a function of both time and temperature. Since temperature distribution is not uniform, components operating at the highest temper-atures will experience the greatest deterioration. Therefore, the hot spot temperature is very important for determining transformer aging.

The temperature rise for dry-type transformers does not necessarily have to be the same rating as the insulation class temperature. One can specify a high insulation class temperature rating and a low temperature rise to obtain extra life for a trans-former.



Ambient temperature influences the normal life expectancy of transformers. For quick approximation, the rated load of an oil-insulated self-cooled (OA) trans-former should be reduced by 1.5% for each degree C it operates above the average ambient temperature of 30°C. Average ambient temperatures should be determined over 24-hour periods with the maximum temperatures not more than 10°C greater than the average temperature. ANSI recommends that a 5°C margin be added to the actual average ambient temperature before derating or increase rating factors are applied. The rated load for forced-air-cooled (OA/FA, OA/FA/FA) and forced-liquid-cooled (FOA, FOW and OA/FOA/FOA) transformers should be reduced by 1% per degree C if the transformer operates above the average ambient temperature of 30°C. Conversely, the rated load for a self-cooled transformer can be increased by 1% per degree C if it operates below the average ambient of 30°C. The rated load of the forced-oil-cooled transformer can be increased by 0.75% per degree C if it operates below the average ambient temperature of 30°C.

The rated load for a dry-type, ventilated, self-cooled transformer can be increased or decreased by 0.6% for each degree C it operates above or below 30°C, respectively. The percent increase or decrease for the sealed, self-cooled transformer is 0.4% per degree C.

ANSI C57.92 is the guide for loading mineral-oil-immersed power transformers. ANSI C57.96 covers loading of dry-type distribution transformers. See ANSI C57.12 for more information on temperature rise.

844 Altitude

Effects of Insulation and Temperature at High AltitudeInsulation and temperature rise ratings of transformers are valid up to an altitude of 3300 feet. Transformers depend upon air for dissipation of heat losses, and because the air becomes less dense at higher altitudes, transformers installed at 3300 feet and higher must be derated. For a specified kVA rating and altitude, the manufacturer will derate the transformer per ANSI C57.12 and provide a derated transformer that meets the kVA requirements.

845 Basic Impulse Level (BIL)Basic impulse levels of insulation are reference levels (expressed in impulse crest voltage) that insulation in electrical apparatus must safely withstand during a tran-sient condition. The BIL is dependent on voltage class. A transformer primary will have a different BIL rating than the secondary unless both voltages are in the same voltage class. Higher than standard BIL ratings are available but are more expen-sive. Dry-type transformers usually have lower BIL ratings than liquid-filled trans-formers. However, dry-type transformers have BIL ratings that are the same as or greater than the BIL ratings of liquid-filled transformers if arrestors are installed on the dry-type transformers. Standard BIL values for various nominal system volt-ages are listed in Figure 800-3.



846 ImpedanceImpedance is usually expressed as a percentage value and is determined by the internal characteristics of the transformer (i.e., core loss, resistance, and reactance of windings). Because of cost, the usual practice is to accept manufacturers’ standards. However, it may be desirable to install transformers with greater than standard

Fig. 800-3 Standard BIL Values

TRANSFORMER BASIC IMPULSE INSULATION LEVELS USUALLY ASSOCIATED WITH NOMINAL SYSTEM VOLTAGE

Basic Impulse Insulation Level (KV)

Liquid Insulated

Nominal System Primary Voltage (KVrms) Power Distribution Dry Type

0.12 — 0.60 45 30 10

2.40 60 45 20

4.16 75 60 30

4.80 75 60 30

6.90 95 75 30

7.20 95 75 30

12.00 110 95 60

12.47 110 95 60

13.20 110 95 60

13.80 110 95 60

14.40 110 95 95

16.5 150 150 95

22.9 150 150 110

26.4 200 200 125

34.4. 200 200 150

43.8 250 250

46.0 250 250

66.0 350 350

67.0 350 350

69.0 350 350

115.0 450

138.0 550

161.0 650

230.0 750



impedance to limit the short-circuit duty on secondary switchgear, or to select a transformer with lower than standard impedance to aid motor starting by reducing the voltage drop. Attention should be given to equipment voltage requirements when heavily loading a transformer. The impedance of the transformer causes secondary voltage to decrease as the load increases. This voltage drop, combined with the drop due to cable resistance, could impair the performance of, and reduce the production from the utilization equipment. The larger the impedance value of the transformer, the greater the voltage drop during heavy loading.

For information on voltage drop see Section 134, “Feeder and Branch Circuit Systems.” To understand the effects of impedance on short-circuit duty, see Section 200, “System Studies and Protection,” and the appendix on the MVA method. Refer to Section 100, “System Design,” for typical manufacturers’ imped-ance values.

847 Secondary Circuit VoltageThe secondary voltage is determined by load characteristics, equipment availability and plant preference.

850 Winding ConnectionsThe typical winding connections for three-phase transformers are the wye-wye, delta-delta, wye-delta, and delta-wye. Consult Section 100, “System Design,” for a comprehensive discussion about the selection of different connections.

851 Angular Displacement (Nominal) between Voltages of Windings for Three-Phase Transformers

Angular displacement is defined as the angle between the high side phase voltage and the low side phase voltage. For the delta-delta and wye-wye transformers, there is no angular displacement. However, the delta-wye or wye-delta transformer has a 30 degree angular displacement. Angular displacement is of concern when connecting transformers in parallel. See Section 862, “Paralleling Transformers.”

Angular displacement is also important when selecting current transformer connec-tions for differential relaying on transformers (See Section 200, “System Studies and Protection,” for an explanation of differential relaying). If the transformer is connected delta-wye, the current transformers for differential relaying must be connected wye-delta (primary CTs connected wye and secondary CTs connected delta). This arrangement provides the differential relay with in-phase current from the primary and secondary sides and prevents nuisance tripping on external faults.

852 Series Multiple WindingsSeries multiple windings consist of two similar (multiple) coils in each winding that can be connected in series or parallel. Transformers with series-multiple windings are designated with an “X” or “/” between the voltage ratings, such as primary



voltage of “240 X 480” or “120/240.” If the series multiple winding is designated by an “X,” the winding can only be connected in series or parallel (not both). With the “/” designation, a mid-point is available in addition to the series or parallel connec-tion. For example, a 120 X 240 winding can be connected for either 120 (parallel) or 240 (series), but a 120/240 winding can be connected for 120 (parallel), 240 (series), or 240 with a 120-volt midpoint.

860 Design Characteristics and Their Application (Construction)

861 Voltage TapsVoltage taps on a transformer provide adjustment of the number of turns in the windings. These taps are typically provided on the high voltage side of the trans-former. This feature provides flexibility in compensating for low voltage and increases in the secondary due to changes in loading requirements or in the primary voltage. Voltage taps are either of the manually adjustable no-load type or the auto-matically adjustable under-load type.

For most applications, manually adjustable no-load voltage taps are adequate. These taps can be changed only while the transformer is de-energized. It is recommended to specify two, 2-1/2% steps above and two, 2-1/2% steps below. As an example, if the secondary voltage is 2-1/2% low, the use of the first 2-1/2% below tap will maintain the rated secondary voltage. If required, tap settings that allow up to 10-to-15% voltage correction in one direction (above or below) are available. No-load tap changers are used very infrequently where an over or under voltage must be corrected.

With double-ended substations (a lineup of switchgear fed from two transformers), it is usually acceptable to remove a transformer from service long enough to change the manually adjustable no-load voltage taps.

If tap changing under load is required, an automatic load tap changer should be specified. This type of tap changer should be specified only for unusual applica-tions when voltage control is critical and must be corrected often. The automatic load tap changer automatically provides additional voltage adjustment in incre-mental steps with continuous monitoring of the secondary voltage. Automatic tap changers are significantly more expensive than manually adjustable no-load tap changers.

862 Paralleling TransformersThe four requirements for paralleling transformers are as follows: 1) the phase rela-tionships between the high voltage and the low voltage must be the same; 2) the line-to-line voltage variation must not exceed ±10%; 3) the phase-to-neutral volt-ages must have the same ratios; and 4) the percent impedance of the transformers should be within 10% of each other (i.e., within 0.8% for an 8% impedance trans-former). The purpose of the fourth requirement is to minimize circulating current and to ensure that the load is shared equally by each transformer.



863 LocationIt is recommended that transformers and associated equipment be installed in unclassified (nonhazardous) locations whenever possible. If a transformer must be installed in a Class I area, the transformer and its accessories must be suitable for the classification of the area and be so labeled by a recognized testing laboratory, usually Underwriters’ Laboratories. See Section 300, “Hazardous (Classified) Areas,” for specific information on installing transformers in hazardous (classified) locations.

864 PaintingManufacturer’s standard paint should be allowed unless there are unusual condi-tions (primarily environmental) or a local preference. Use of non-standard paint adds to the cost.

865 TerminationIt is recommended that the transformer manufacturer supply the connectors and termination (e.g., cable lugs) to match their terminals to the electrical system. This assures that the transformers will be properly connected with the appropriate hard-ware.

866 Tertiary WindingsThree-phase transformers may have tertiary (third) windings to provide voltage for auxiliary power purposes. As an example, static capacitors (synchronous condensers) for purposes of power factor correction or voltage regulation, may be connected to the tertiary windings. The tertiary windings are sometimes connected in delta configuration to provide a circuit for the third harmonics of the exciting current.

870 AccessoriesThe type and extent of protection and monitoring accessories for a transformer are determined by factors such as the cost and importance of the unit versus the cost of the protection scheme. The following accessories (several of which are illustrated in Figures 800-4 through 800-10) either protect the transformer or are needed for routine inspection and maintenance.

871 Liquid Level GageThe liquid level gage (see Figure 800-4) is used to indicate the level of insulating oil in a tank with respect to a predetermined level (usually indicated at the 25°C mark.) The liquid level gage can be specified with contacts to alarm on a low liquid level. An excessively low level of liquid could lead to internal overheating and flashovers.



872 Fluid Thermometer, Dial TypeA dial-type fluid thermometer (see Figure 800-5), common to most liquid-filled transformers, measures the temperature of the insulating liquid at the top of the transformer tank. This device also indicates the peak liquid temperature with a reset-table pointer. The thermometer is only partially effective as a protective device because the thermal coefficient of the liquid is quite different from that of the wind-ings. The thermal time constant of the liquid is much longer than that of the wind-ings and hence the liquid temperature is more sluggish in its response to changes in loading losses than the windings. Furthermore, the thermometer reading is related to transformer loading only as long as the loading affects the temperature rise above ambient. Thus, the temperature reading will vary between being too conservative and too pessimistic, depending upon the rate of change of the load and the ambient conditions.

Fig. 800-4 Liquid Level Gage (Courtesy of Qualitrol)

Fig. 800-5 Dial Type Thermometer (Courtesy of Qualitrol)



Thermometers are usually specified with alarm contacts for providing remote warn-ings of abnormally high liquid temperatures. Thermometers with alarm contacts should be considered for all liquid-filled transformers. If provisions for future forced-air cooling are specified, winding temperature indicators with alarm contacts should be equipped with one to three adjustable contacts that operate at preset temperatures. For example, fans are usually turned on if the liquid temperature reaches 60°C. When the temperature reaches 90°C, a contact is actuated to alarm or to disconnect the transformer. That is, the fans are turned on at approximately 90% load, whereas the alarm is given at about 130% rated load. These approximate figures vary with design and the actual ambient temperature. The percent loadings will be somewhat lower at temperatures above ambient, and higher at ambient temperatures below 30°C. When applied to a 65°C rated transformer, the switch will operate at loading values of approximately 75% and 115%.

873 Pressure Vacuum GageThis gage (see Figure 800-6) indicates the pressure of the gas inside the tank space. It is used on transformers with sealed tanks. The pressure inside the sealed tank is normally related to the thermal expansion of the insulating liquid and varies with different loading conditions and ambient temperatures. This device can be equipped with alarms to detect excessive vacuum or positive pressure that could deform or rupture the tank. The need for pressure limit alarms is less critical when the trans-former is equipped with a pressure relief device. The pressure vacuum gage typi-cally has a scale range of ±10 psi and provides a means of continually monitoring the sealed system.

874 Pressure Relief Diaphragm in CoverThis cover-mounted pressure relief device (see Figure 800-7), not to be confused with the sudden pressure relay described below, operates to relieve dangerous pres-sure buildups from 1) high peak load, 2) long-time overloads, and 3) arc-producing faults. After the pressure has been released, the device resumes its former seating to assure a weather-tight seal, but its operation indicator must be manually reset. This device requires minimal maintenance. It is primarily used to protect the tank that houses the liquid. It can be equipped with alarm contacts in conjunction with a self-

Fig. 800-6 Pressure Vacuum Gage (Courtesy of ABB)



sealing relay and can be connected so that a remote warning device can be acti-vated, advising the operator of excessive pressure. Any operation of this relief device that was not preceded by overloading will indicate possible trouble in the windings. A pressure relief device is recommended for transformers rated 500 kVA and above.

875 Sampling DeviceSampling devices should be specified for oil insulated transformers. These devices allow access to the oil so that the oil can be checked for dielectric strength, mois-ture, and sludge buildup. Sampling devices are usually located on the side of the tank or as a part of the drain valve.

876 Pressure RegulatorThis accessory (see Figure 800-8) automatically maintains a positive-pressure nitrogen atmosphere above the oil. Nitrogen, supplied in cylinders, is admitted through the regulator to maintain positive pressure in the gas space above the oil to prevent the accumulation of water (from outside air) in the oil.

877 Provisions for Future Cooling FansTransformers normally are not specified with fans at initial installation, but often should be specified with provisions for future forced air cooling. Manufacturers can

Fig. 800-7 Pressure Relief Diaphragm Courtesy of ABB: Transmission and Distribution



provide the necessary hardware and equipment for future fan connection. This option ensures that minimal shutdown time will be required when installing the fans at a later date.

878 Sudden Pressure RelaysA sudden pressure relay (see Figure 800-9) is a pressure-sensitive relay used to initiate isolation from the electrical system (limiting damage to the transformer) if pressure in the tank rises abruptly. This device is mounted with its main pressure-sensing element in direct contact with the gas cushion in the tank of a liquid-filled transformer. When a fault occurs, a sudden increase in gas produces an abrupt

increase in pressure that actuates the contacts, and energizes the relay. The relay then trips the transformer off-line. This device detects internal shorted turns, faults to ground, and winding-to-winding faults. Since the operation of this device is closely related to actual faults in the winding, one should consider all risks involved in re-energizing a transformer that has been tripped off-line by a sudden pressure relay. The relay is designed to be insensitive to gradual changes in pressure due to changing load and ambient conditions. Sudden pressure relays are generally recom-mended for transformer sizes of 5000 kVA and above.

Fig. 800-8 Pressure Regulation w/N2 Blanketing



879 Neutral Current TransformerA bushing current transformer (see Figure 800-10) installed on the neutral bushing is required on a grounded transformer that has a ground fault relay. This feature provides the required signal to operate the protective relay.

Fig. 800-9 Sudden Pressure Relay Courtesy of ABB: Transmission and Distribution

Fig. 800-10 Bushing Current Transformer Courtesy of ABB: Transmission and Distribution



880 Grounding Resistors and Bushing Current Transformers

881 Grounding ResistorsGrounding resistors are used to limit the amount of fault current on the load circuit (See Section 900, “Grounding Systems,” for further information). It may be desir-able for the switchgear manufacturer to provide the resistor since the ground fault detection system, if specified, is usually located in the switchgear.

882 Bushing Current TransformersBushing current transformers (see Figure 800-10) installed on low-voltage and/or high-voltage bushings, are required if signals are needed for metering or operating protective relays. Typically, current transformers supplying signals to metering or protective relays on the load side of the transformer are supplied with the switch-gear.

883 Surge Capacitors/Lightning ArrestorsLightning protection is achieved by the process of intercepting lightning-produced surges and diverting them to ground or altering their associated waveshapes. Surge arrestors intercept the surge and divert it to the ground, whereas surge capacitors alter the shape of the steep incoming wavefront. Lightning is considered to be the most severe source of surge voltages.

The appropriate degree of surge protection depends on the degree of exposure to lightning, the size and importance of the transformer, and the type and cost of the arrestors. Lightning arrestors limit the overvoltage by providing a conducting path of relatively low impedance to ground. This low impedance to ground must not exist before the overvoltage appears, and it must disappear immediately after the voltage has returned to normal. Arrestors have a single gap, or several gaps in series, which will withstand the normal operating voltage but flash-over and become conductive at higher voltages. The three classes of arrestors are: station, interme-diate, and distribution which are listed in order of decreasing cost, protection, and quality of manufacture.

Station class arrestors are applied to both large (7.5 MVA and larger) and critical transformers. Intermediate class arrestors are applied to transformers between 225 kVA and 7.5 MA, and distribution class arrestors are applied to small dry-type and oil-filled distribution transformers.

If transformers are connected to bare overhead lines, they should be protected by surge arrestors. Ordinarily, if a liquid-insulated transformer is supplied by enclosed conductors from the secondaries of transformers with adequate primary protection, surge arrestors are not needed. To provide the best protection for the transformer, the surge arrestor should be mounted directly on, or as close as possible, to the transformer terminals. It is recommended that surge arrestors be installed on the primary of all substation transformers fed by uninsulated overhead lines.



Surge capacitors provide additional protection against overvoltages (surges). Trans-former windings can experience a very non-uniform distribution of a fast-front surge in the transformer. The capacitors “bend” the front of the surge so that the initial force from the surge is distributed over more turns. Surge capacitor protec-tion is also effective against voltage transients generated from circuit conditions (e.g., high frequency current interruption, prestriking, restriking, current limiting fuse operations, thyristor-switching, or ferroresonance). Surge capacitors, like surge arrestors, should be connected on, or as close as possible, to the transformer termi-nals.

884 Shop TestingTests required for verification of quality control before shipping transformers are covered in the Data Sheet Guide for Data Sheet ELC-DS-401.

Tests required for installation and commissioning of transformers are covered in Section 1400, “Electrical Checkout, Commissioning, and Maintenance.”

885 Economics—Evaluation FactorWhen economically evaluating transformers, both the initial cost of the equipment and the cost of energy losses over the lifespan of the transformer must be consid-ered. The sum of these two costs is the lifecycle cost. If a choice must be made among several transformers that all meet the technical requirements, the one with the lowest life cycle cost should be selected. (See ELC-DS-401 for formulas.)


891 Model Specifications (MS)There are no model specifications in this guideline.

892 Standard DrawingsThere are no Standard Drawings in this guideline.


*ELC-DS-401 Transformer Data Sheet

*ELC-DG-401 Transformer Data Sheet Guide



894 Appendices

895 Other ReferencesIEEE C57, Distribution, Power and Regulating Transformers.

ANSI/NEMA ST-20 Dry-Type Transformers for General Applications.

*API RP 14F Design and Installation of Electrical Systems for Offshore Production Platforms.

*Appendix D “Minimum Requirements for Dry-Type Transformers” (Eastern Region)




900 Grounding Systems

AbstractThis section provides guidelines and procedures for selecting grounding methods for generation and distribution systems. Advantages and disadvantages of each method are discussed and specific recommendations are provided. Procedures for system, equipment, lightning, and static grounding at Company installations in the United States are included.

How and where to ground electrical systems and what equipment to use are discussed. Methods of preventing static charge buildup and protection against the effects of lightning are covered. Engineering and physical principles, and manda-tory and recommended practices are included also.

Design parameters for the various grounding systems for onshore and offshore applications are provided as well as a list of references. Standard drawings of grounding details for equipment and instrumentation are included.

Contents Page


911 Grounding—An Overview

912 Design Parameters

913 Checklist

914 Selecting the System Grounding Point

920 System Grounding Background 900-5

921 Solidly Grounded Neutral

922 Low-Resistance Grounded Neutral

923 High-Resistance Grounded Neutral

924 Low-Reactance Grounded Neutral

925 Grounding Transformers

926 System Grounding Recommendations

930 Equipment Grounding Methods 900-14

931 Onshore Equipment Grounding

900 Grounding Systems Electrical Manual


932 Offshore Equipment Grounding

933 Common Equipment Grounding Applications

934 Control Room Instrument and Computer Equipment Grounding

935 Shipboard Equipment Grounding Installations

936 Ground Resistance Measurement

940 Lightning Protection Grounding 900-20

941 Structures

942 Electrical Equipment

950 Static Electricity Grounding 900-23

960 Sizing Components 900-23

961 Low-Resistance Grounding

962 High-Resistance Grounding






Note All figures reprinted from NFPA are reprinted with permission from NFPA 780, Standard for the Installation of Lightning Protection Systems, Chapter 6, Copy-right 1995, National Fire Protection Association, Quincy, Mass. 02269. This reprinted material is not the complete and official position of NFPA on the refer-enced subject which is represented only by the standard in its entirety.

Electrical Manual 900 Grounding Systems


910 IntroductionThis section provides guidelines for selecting and designing grounding systems. Issues discussed include the rationale for different system grounding methods as well as specific recommendations for both on- and offshore applications. System grounding, equipment grounding, lightning protection grounding, and static elec-tricity grounding are also discussed.

This section should be used as described below:

• Those who have never designed a grounding system should review this entire section as well as the appropriate sections of the National Electrical Code (NEC) and the National Electrical Safety Code (NESC). IEEE Standard 142 (the Green Book) is also a good reference.

• Those who need a review of the design of a grounding system for a particular application should review the section(s) pertaining to the specific application and, where appropriate, the model specifications and standard drawings.

• Those experienced in the design of grounding systems will find the checklist useful. This section also provides a source for applicable standards and refer-ences.

911 Grounding—An OverviewItems are grounded to protect personnel and equipment. The term “grounding” covers four separate functions:

1. System grounding, in which the neutral of a “Y” connected transformer or generator is grounded.

2. Equipment grounding, in which all metallic non-current carrying parts (which could become energized) are grounded.

3. Lightning protection grounding, in which tall vessels, structures, etc., are grounded; and surge arresters are used to protect equipment.

4. Static electricity grounding, in which tanks, lines, and piping (e.g., on truck and tank car loading stations) are grounded.

912 Design ParametersThe following design parameters must be established before a grounding system can be designed:

• Voltages: utility supply or generation, distribution, and utilization

• Environmental or site conditions: corrosive conditions, area classification, and soil resistivity

• Mean annual number of days with thunderstorms for the specific job site (avail-able from Isoceraunic Maps in NFPA 780 or IEEE Std 142)



Grounding design may be started after the following design items have been estab-lished:

• Preliminary system one-line diagram

• Power source characteristics: maximum ground-fault current available

• Load characteristics: critical processes and equipment that must remain on line during power system ground faults

The design generally requires documentation on:

• Specific equipment to be grounded• Facility layout (e.g., area and room layouts, plot plans)• Mechanical and electrical equipment details• Structural plans

913 ChecklistThe following checklist should be reviewed before completing the grounding design:

• Are steel structures (including pipe racks and buildings) connected to ground through at least two grounding conductors?

• Are all requirements of NEC Article 250 and NESC Section 9 satisfied?

• Has the criticality of process loads been evaluated? (possibly requiring the use of high-resistance grounding for critical loads)

• Are all system neutrals grounded at the origin of each voltage level? Are the neutrals of all loads ungrounded?

• Are all ground buses in switchgear and motor control centers grounded at both ends?

• Are the enclosures or frames of all items of equipment, such as motors rated 2300 volts and above, generators, switchgear, MCCs, and power transformers, installed with at least two equipment grounding conductors?

• Are all noncurrent-carrying metal raceways, conduits, cable armors, cabinets, junction boxes, electrical enclosures, vessels, and skids properly grounded?

• Is all electrical equipment located in hazardous (classified) areas provided with proper equipment grounding connections in accordance with NEC Article 500? Are all conduit connections either made up wrench-tight or bonded?



914 Selecting the System Grounding PointTwo basic rules dictate the selection of the system neutral grounding points in an electrical distribution system. Briefly, these are:

1. Ground at the source of each voltage transformation level; that is, at the trans-former or generator. Transformers or generator neutrals must be grounded at each voltage level to achieve the advantages of neutral grounding. Sometimes a specially designed grounding transformer is used to establish a system neutral.

2. Never ground a system neutral at the load.

920 System Grounding BackgroundThe following discussion is not intended to be a comprehensive description of system grounding. See IEEE 142 for detailed information.

OvervoltageOvervoltage conditions can cause deterioration of the insulation on electrical cables, motor windings, and other electrical equipment. Overvoltage conditions are a serious concern on ungrounded systems due to system transients caused by arcing ground faults and capacitive-inductive resonance in the power system. These situa-tions are avoided when systems are grounded properly.

There are four recommended system grounding methods: solid, low-resistance, high-resistance, and low reactance. However, it may be appropriate to install an ungrounded system (e.g., a single motor fed by three single-phase distribution trans-formers). The selection of the most efficient, safe, and economic system is the responsibility of the design engineer.

921 Solidly Grounded NeutralThe power system is solidly grounded when the neutral of the source is connected directly to ground without intentionally inserting any impedance in the path. This is illustrated in Figure 900-1.

Fault Current MagnitudeWhen a low-impedance ground fault (commonly called a “bolted” fault) occurs on a solidly grounded system, very high ground fault currents will flow. These currents are typically 10 to 20 times the full-load current of the source transformer(s) and 5 to 10 times the full-load current of the generator(s).

When arcing line-to-ground faults occur on 480 volt solidly grounded systems, the current magnitude is significantly less than the maximum bolted ground fault level since the arc resistance is relatively high. The fault, once established, is maintained as an arc through the ionized gases between the phase conductor and ground. The voltage required to sustain an arc is approximately 140 volts. As a result, the current magnitude of an arcing ground fault is approximately 40% of the bolted fault value on 480 volt systems. This must be considered when selecting the pickup values for



ground fault protective relays. See Section 600, “Protective Devices,” for recom-mended settings.

Since the voltage to sustain an arc is approximately 140 volts, an arcing ground fault is self-extinguishing on 208Y/120 volt systems (the line-to-ground voltage is 120 volts).

Fault DetectionTo detect ground fault currents, sensitive ground fault protective devices must be used. These devices may be applied in several different ways as illustrated in Figure 900-2:

• Ground return path. An overcurrent relay is located in the transformer or generator neutral connection to ground.

• Zero sequence method (core balance). A window-type (“donut type”) current transformer is used to monitor all current-carrying conductors.

• Residual ground method. An overcurrent relay is located in common return conductor of the phase current transformer secondaries.

• Ground sensor integral with circuit breakers. Ground fault protection is available packaged with phase overcurrent devices of the circuit breaker for systems 600 volts and below using any of the three fault sensing methods listed above.

These devices only operate on ground-fault currents and are insensitive to normal load or phase-fault currents. Their operating current level for ground faults can be as low as a few amperes to detect a low level arcing ground fault. The choice of a particular method will depend on the sensitivity required and the circuit-inter-rupting devices selected. See Section 600, “Protective Devices,” for additional information.

Fig. 900-1 Solidly Grounded Neutral



Line-to-neutral LoadsThe solidly grounded neutral system, as illustrated in Figure 900-1, is the only system to which line-to-neutral loads can be connected since the neutral is always at ground potential. Thus, low voltage systems may be used for both three-phase loads and single-phase line-to-neutral loads on both 480Y/277 volt and 208Y/120 volt three-phase, four wire systems.

OvervoltageSolidly grounded systems offer the opportunity for using lower voltage-rated (line-to-neutral voltage) surge arresters. Resistance grounded systems require higher line-to-line voltage-rated arresters. See IEEE Std 142, Chapter 1, for additional details.

Cost FactorsThe initial cost of solidly grounding the neutral is minimal on “wye” connected transformers. Cost is higher for delta-connected transformers because a grounding transformer is required to establish a neutral point (see Section 925 below). If sensi-tive ground-fault protection is required, this feature also adds to the cost. Evalua-tion of downtime costs must consider the effects of suddenly disconnecting a

Fig. 900-2 Ground Fault Protective Devices



portion of the electrical system when a ground fault occurs. These costs may be high for continuous processes or critical services.

922 Low-Resistance Grounded NeutralA low-resistance grounded neutral system has a low-resistance device (either a resistor or a single-phase grounding transformer with a resistor) inserted in the neutral connection to ground, as illustrated in Figure 900-3.

Fault Current MagnitudeGround resistors are sized to limit the current magnitude during a line-to-ground fault. The current should be limited to a value that will minimize burning damage at the point of fault, yet allow sufficient current to flow for operation of the ground fault relays. Burning damage is proportional to the energy, I2t, where I is the fault current in amperes and t is time in seconds. It is evident that damage is minimized if both current and time duration are kept to a minimum during a line-to-ground fault. For this reason, medium voltage systems with large motors are commonly grounded in this manner. A ground-fault current not exceeding 400 amperes is recommended. However, current may be increased or decreased to meet the requirements of a specific application. For example, a system with four parallel sources may suggest a limit of 200 amperes each, resulting in a total ground fault current of (4 x 200) 800 amperes at the fault. Typically, the ground-fault current magnitude is limited by the resistor to between 50 and 1000 amperes.

Fault DetectionWith the ground fault current limited by resistance, sensitive ground fault relays are required since the phase relays normally will not detect a ground fault. Sensitive zero-sequence relays, shown in Figure 900-2, are recommended on feeder circuits.

Fig. 900-3 Low-Resistance Grounded Neutral System



The ground return path method (Figure 900-2) may be used for transformers or generators. Residual ground relays may be used where they provide adequate sensi-tivity—typically 10% of the maximum ground-fault current.

OvervoltageWith the values of resistance normally used, the maximum line-to-ground voltages (including transients) during a line-to-ground fault are held to a minimum. Surge arresters must be rated for line-to-line voltage (versus line-to-ground).

Cost FactorsThe initial cost to provide low-resistance grounding of the system neutral includes the grounding resistor, the grounding transformer (if no wye-connection is avail-able), and the ground-fault relaying equipment. Costs to repair the faulted equip-ment may be much lower. For example, to repair a motor insulation failure may require only a coil replacement, whereas a similar failure on a solidly grounded system may require extensive repairs, or even a complete motor replacement. Since the faulted equipment is disconnected suddenly, downtime costs must be evaluated on the same basis as solidly grounded systems. The ground resistor on a low-resis-tance grounded system is normally rated for 10 second duty. To prevent resistor damage for some fault conditions (such as a ground fault between the transformer secondary terminals and the downstream switching device) either a primary discon-nect device (circuit breaker or a load-disconnect switch with a shunt trip) or a transfer trip to a transformer’s supply circuit breaker is required.

923 High-Resistance Grounded NeutralThe high-resistance grounded neutral system (Figure 900-4) has a high-resistance device inserted in the neutral connection to ground to limit the current for line-to-ground faults. The resistance device must be rated to carry continuously the maximum current which can flow (line-to-ground voltage divided by the resis-tance). The basic objectives of this grounding method are:

• To preclude automatic tripping of faulted circuits for the initial ground fault• To alarm the faulted condition• To limit transient overvoltages characteristic of ungrounded systems

High-resistance grounding is not recommended for most unattended locations.

Cost FactorsThe initial cost to provide a high-resistance grounded system includes the grounding equipment, and fault-locating equipment. High-resistance grounded neutral systems are applied in process industries and in other situations where control of transient overvoltages is desired, but where immediate interruption of power on occurrence of the first ground fault would cause significant economic loss.

Fault Current MagnitudeThe magnitude of the line-to-ground fault current at any point in a system is deter-mined by the value of the grounding resistor and the system charging current.



System charging currents result from the capacitance of insulated conductors in close proximity to grounded components, and from “lumped” capacitance (e.g., surge capacitors on motors and generators). System charging currents are defined by the capacitive reactance to ground (Xco) as shown in Figure 900-4. The current in the resistor (IR) should be equal to or greater than the total system charging current in order to limit transient overvoltages to a maximum of 250% of rated line-to-neutral voltage (See Section 962). The resistor is sized to limit fault current to the lowest possible level but still effectively limit system overvoltage. Increasing the allowable ground-fault current improves overvoltage control at the expense of increasing damage at the point of fault; decreasing the allowable ground-fault current reduces point-of-fault damage at the expense of greater overvoltage risk.

Line-to-ground fault current should be limited to 10 amperes (preferably 5 amperes) to control the burning at a fault. The system can operate normally until the fault is located and an orderly shutdown initiated. If fault currents greater than 10 amperes are permitted, sustained arcing may occur. This arcing will progressively damage the insulation or produce excessive ionized gases, particularly undesirable in a confined space. Systems with charging currents exceeding 10 amperes should be of the low-resistance grounded type.

Fault DetectionThe first ground fault will not automatically trip a faulted circuit. A second line-to-ground fault on another phase may create a line-to-line-to-ground fault. This will cause circuit breaker tripping if the first fault still exists. A ground detector should be provided to detect and alarm the presence of a line-to-ground fault. Locating the fault can be time consuming and require repeated feeder shutdowns. However, fault locating equipment and methods are available to avoid feeder shutdown and to

Fig. 900-4 High-Resistance Grounded Neutral System



make finding the ground fault easier. Ground-fault locating equipment places a traceable signal onto the grounded phase conductor; this aids in the rapid location of ground faults.

A pulsing current can be created with a contactor, such as shown by Figure 900-5, which shunts a part of the ground resistor to increase the ground fault by a factor of 1.5 to 2 (or more). The contactor, which is switched about every half second, produces a varying fault current that can be traced easily with a clamp-on ammeter. This system enables the fault to be located without de-energizing any circuits.

High-resistance grounding equipment can be purchased as a complete package from several manufacturers. These units are available for delta or wye systems. For a complete description of this type of fault detecting and locating equipment refer to manufacturers literature. General Electric Co., Model GEK-83750, DS9181 High-Resistance Grounding Equipment, is one such unit available.

OvervoltageThe high-resistance grounded neutral system controls overvoltage conditions possible in the power system. These transient overvoltages are limited to 250% of the rated line-to-neutral voltages. During the time a ground fault exists on the power system, system components are exposed to rated line-to-line voltages. Surge arresters and insulated cables must be appropriately rated.

924 Low-Reactance Grounded NeutralLow-reactance grounding of neutrals is not commonly used. Sometimes it is applied to generators to limit line-to-ground fault current to a level within generator mechanical capabilities. See the IEEE Green Book for more information.

Fig. 900-5 Fault Detection by Means of a Contactor



925 Grounding TransformersSometimes a neutral grounding point at the source is not readily available (e.g., a delta-connected transformer secondary). In these situations, a neutral can be estab-lished by using either a three-phase zig-zag grounding transformer or a three-phase (or three single-phase transformers) connected wye-delta. The operation of these grounding transformers is very similar. They both provide a low-impedance path for ground currents and a high-impedance path under normal operating conditions. Therefore, during normal conditions, only a small magnetizing current flows in the transformer windings. Refer to Chapter 6 of D. Beeman’s Industrial Power Systems Handbook for the theory of grounding transformers.

926 System Grounding RecommendationsThe system grounding method for each system voltage class should be selected from the choices listed below. The choice should be based on one or more of the characteristics of the specific grounding method that meet the specific job require-ments.

Solidly Grounded NeutralAppropriate system voltage ratings for solidly grounded neutrals are 600, 480, and 240 volts three-phase, three-wire, and 480Y/277 and 208Y/120 volts three-phase, four-wire.

Solidly grounded neutrals are recommended when:

• The system is a three-phase, four-wire system with loads (such as lighting) connected line-to-neutral. NEC requires the use of solidly grounded neutrals on 480Y/277 volt and 208Y/120 volt systems when line-to-neutral loads are supplied.

• The system voltage to ground must be held to 150 volts maximum (to meet the requirements of National Electrical Code, Article 250.)

• High-voltage systems 15 kV and above

Solidly grounded neutrals are not recommended when:

• The system serves continuous process loads where automatic tripping of ground faults by protective devices is not permissible.

• The system is rated 2.4 kV and above where rotating machines are connected directly at that voltage level.

High-Resistance Grounded NeutralAppropriate system voltage ratings for high-resistance grounded neutrals are 480 volt three-phase, three-wire, and 2400 volt through 4160 volt three-phase, three-wire.

High-resistance grounded neutrals are recommended when:



• The system is serving continuous process loads where an unexpected shutdown of any electrically driven component will result in shutdown of the entire process.

• Shutdown would result in a serious loss of product or production time.

• The safety of personnel or process equipment is threatened by unexpected shut-down.

When a high-resistance grounding method is selected, timely location and removal of the first ground fault is essential. The traceable signal feature is recommended to assist in the fault location procedures. If a second line-to-ground fault occurs before the first fault is located, feeder shutdowns may result (if the line-to-ground faults involve different phases).

Transformers with 2400 and 4160 volt ratings should be provided with high-resis-tance grounding if it is essential to prevent unplanned shutdown or if a single rotating machine is served by a captive transformer. A study must be performed to determine the system charging current and the effects on surge arrester selection. Consideration should be given to possible future changes in the system, including the installation of surge capacitors and other equipment and modifications that would affect the total system charging current.

Recommended practice is to use high-resistance grounded neutrals to limit ground-fault currents to approximately 5 amperes (10 amperes maximum). It is recom-mended also as a means of detecting and alarming ground faults.

Low-Resistance Grounded NeutralAppropriate system voltage ratings for low-resistance grounded neutrals are 2400 through 14,400 volts three-phase, three-wire.

Low-resistance grounded neutrals are recommended when:

• Motors 2300 volts or above are served. This method limits the damage to insu-lation and the stator iron if a motor winding faults to ground.

• The system serves noncontinuous process loads, or those with spares, when automatic tripping on a ground fault will not have an adverse effect on the process.

• Generators rated 2400 volts and above are used.

Transformers with 2400 to 14,400 volt wye-connected windings should be equipped with resistors sized to limit ground-fault currents to 400 amperes. Protective relaying should trip faulted feeders if a ground fault occurs. See Section 600, “Protective Devices,” for details on relay systems.

Recommended practice is to use low-resistance neutral grounding on 2400 through 14,400 volt systems to limit ground-fault currents to 400 amperes. Low-resistance neutral grounding is also recommended when the capacitive charging current is greater than 10 amperes.



930 Equipment Grounding Methods

Equipment Ground BackgroundEquipment grounding requires the connection to ground of all metallic noncurrent carrying parts of the wiring system and equipment. This includes metal raceways, conduits, cable armor, cabinets, junction boxes, switch boxes, transformer cases, frames of motors, enclosures of switchgear and motor control centers, metal struc-tures and buildings, and the frames and skids of packaged equipment containing electrical devices.

The primary purpose of equipment grounding is to limit the difference in potential between personnel and metallic objects that might accidentally become energized in the event of a short circuit or ground fault within the equipment or wiring system.

A second purpose is to provide a low-impedance return path for a ground fault so that protective devices will operate properly. High impedances within the equip-ment grounding system, due either to poor connections or inadequately sized conductors, may cause arcing or heating sufficient to ignite combustible materials or flammable gases or vapors.

Grounding electrode conductors for separately derived systems and service entrances should be copper and must be sized in accordance with NEC Table 250-94. See Figure 900-6. Equipment grounding conductors should also be copper and sized in accordance with NEC Table 250-95. See Figure 900-7. Note that the size of the equipment grounding conductor is based on the setting of the overcurrent device (which may be a low-pickup ground relay). The smallest recommended conductor size is 6 AWG.

Fig. 900-6 Minimum Sizes for Copper Grounding Electrode Conductors Reprinted with permission from NFPA 70-1999, National Electric Code®, copyright 1998. Cour-tesy of the National Fire Protection Association.

Service (Feeder) Conductor Size (AWG)

Minimum Size Grounding Electrode Conductor (AWG)

1/0 or smaller 6

2/0 — 3/0 4

Over 3/0 — 350 MCM 2

Over 350 MCM — 600 MCM 1/0

Over 600 MCM — 1100 MCM 2/0

Over 1100 MCM 3/0



931 Onshore Equipment GroundingThe grounding system for a large or complex plant may involve an extensive multi-loop network of equipment enclosures, structures, and buildings, ground grids or ground loops (sometimes referred to as a ground network) interconnected by cables to provide an overall plant grounding system. In some cases, the grounding system may be relatively simple, such as a single connection to a buried pipeline or ground rod. A ground loop or ground grid, consisting of buried cables with driven ground rods connected to the ground loops is normally installed around each substation, process unit, or building. All ground loops must be connected together. A typical installation would use #4/0 AWG bare copper wire for ground loops. The minimum size which can be used is #2/0 AWG, and the maximum recommended size is 500 MCM. Large loops may have intermediate connections between opposite sides to reduce the distance from the loop to individual grounded items. Specific require-ments for grounding systems are given in NEC Article 250. Detailed information is included in IEEE Std 142. Design and construction notes and details are indicated on Company Standard Drawings GD-P99734 and GF-P99735.

Fig. 900-7 Minimum Sizes for Copper Equipment Grounding Conductors Reprinted with permission from NFPA 70-1999, National Electric Code®, copyright 1998. Cour-tesy of the National Fire Protection Association.

Rating or Setting of Automatic Overcur-rent Device in Circuit Ahead of Equip-

ment, Conduit, etc., Not exceeding (Amperes) Minimum Size (AWG)

152030

141210

4060100

10108

200300400

643

500600800

210

100012001600

2/03/04/0

200025003000

250 MCM350 MCM400 MCM

400050006000

500 MCM700 MCM800 MCM



932 Offshore Equipment GroundingOne conductor in all single-phase power distribution cables should be utilized as an equipment grounding conductor, and the conductor should be identified with a green marking on all terminations throughout the system (e.g., a sleeve wire marker labeled “GROUND” or green electrical tape). Three-phase feeders supplying single-phase loads (directly or through sub-panels) should contain this equipment grounding conductor. This equipment grounding conductor should be utilized in addition to any other grounding means. The equipment grounding conductor, unlike the neutral conductor, may be grounded at multiple points. All devices in the system, including receptacles, lighting fixtures, etc., should be grounded with equip-ment grounding conductors.

Individual boxes, fittings, or enclosures used to enclose wire splices or as pull boxes do not necessarily have to be grounded with a ground wire. The box itself can be bonded, welded, or bolted to the structure or a suitably grounded structural member, in such a manner that a good and lasting electrical bond is formed. Threaded rigid conduit interconnections made up wrench tight or properly bonded are considered proper ground paths.

933 Common Equipment Grounding ApplicationsThe most common applications of equipment grounding include the following:

• Structures. Steel building frameworks, pipe racks, stacks, tall vessels, tanks, and similar installations should be grounded at a minimum of two points per structure with substantial connections to the grounding system grid, using #2/0 AWG minimum bare copper wire.

• Motors and Generators. Motor and generator enclosures should be connected to the grounding system. This connection is usually a separate grounding conductor from each machine enclosure to the ground grid. Large motors (over 600 volts) should have two connections to the plant ground loop, using #2/0 AWG minimum copper wire. However, this connection should be considered supplementary to the equipment grounding conductor because its purpose is to equalize potentials in the immediate vicinity of the machine. The equipment grounding conductor must be a mechanically and electrically continuous conductor routed with the phase conductors of the machine. This may be a conductor run with phase conductors inside a conduit or cable, a continuously threaded rigid conduit system, the metallic sheath of certain cables, or a cable tray system. See ELC-EG-1675. Separate equipment grounding conductors are recommended for system voltages of 2300 volts and above, especially for low-resistance or solidly grounded systems. The ground connection must provide a low impedance circuit from the machine enclosure to the electric system ground.

• Metallic-Sheathed and Metallic-Shielded Power Cables. Metallic sheaths and metallic shield of power cables should be continuous over the entire length and should be grounded at each end. If cables are spliced, continuity of the metallic sheath or shield at the splice is required. When metallic armor is used



over metallic sheath, the sheath and the armor should be bonded together and connected to the ground system at each end of the cable and at splices. The metallic sheath or armor type AC or MC cables can also be used as an equip-ment grounding conductor if its current-carrying capacity is verified by a nationally recognized testing laboratory (e.g., UL).

• Enclosures and Raceways. NEC requires that exposed metallic noncurrent-carrying enclosures of electrical devices be grounded. These include conduit, wireways and other similar wiring raceways. Where the continuity of the enclo-sure is assured by its construction, a ground connection at its termination points is adequate. If continuity is not assured by construction, adequate connections of all sections to the ground grid or bonding jumpers between all sections is required.

• Bus Boxes. Bus boxes should be equipped with a separate ground bus to termi-nate all grounding conductors. This ground bus must be bonded to the enclo-sure and also to the structure (or suitable grounded structural member). The ground bus must be physically and electrically separate from the “neutral” bus. The neutral bus, if necessary, must be electrically insulated from ground at this point.

• Enclosures for Electrical Equipment. Switchgear, motor control centers, and similar electrical equipment should include a ground bus. The ground bus must be bolted or otherwise connected directly to the equipment frame. This arrange-ment ensures that when the ground bus is connected to the ground loop, the equipment enclosure is also grounded. When the equipment consists of a lineup of two or more sections, two grounding connections to the ground grid, one on each end of the ground bus, are recommended. It is also recommended that power transformers be furnished with two grounding pads, one on each side, for making connections to the ground grid. The ground connections from major electrical equipment to the ground grid should be made using #2/0 AWG minimum copper wire.

• Lighting Panels. A separate ground block must be installed inside standard lighting panels to terminate all ground wires. This ground block must be bonded to the frame of the panel and also to the structure. The ground block must be physically and electrically separate from the “neutral” block. The neutral block is electrically insulated from ground at this point. The neutral block of a lighting panel is grounded on one point only—at the source or at the main panel. All sub-panel neutral blocks are not grounded within the sub-panel.

• Explosionproof Lighting Panels. Explosionproof lighting panels which do not have physical mounting space to include a separate ground block require special measures. Two methods which may be utilized are:

a. Install an explosionproof junction box on the side of the lighting panel. This box is to be connected to the lighting panel with rigid conduit made up wrench tight. Install a ground block within this box and bond the block to the junction box. A #6 AWG bare solid copper wire or a #6 AWG green



insulated stranded copper wire is to be installed from the ground block to a suitable lug that is bonded to the structure deck or a structural member. The individual ground conductors that enter the lighting panel terminal box are to be continuous and are to be terminated on the ground block.

b. Install a #6 AWG bare solid copper wire or a #6 AWG green insulated stranded copper wire in the terminal block section of the lighting panel and connect all ground wires to this wire with split-bolt connectors. This wire is to be terminated on the lighting panel frame. The other end is to be terminated with a suitable lug that is bonded to the structure deck or a structural member.

• Fences. Metal fences and gates enclosing electrical equipment or substations must be connected to the grounding system grid. See Standard Drawing GF-P99735 for details. This requirement is to protect personnel from electric shock hazard during a fault. The following factors should be considered: resistance of the station grounding system to ground, distance of the fence from grounding electrodes, and voltage gradients in the soil (to keep the “touch” and “step” voltage to a minimum). These factors are mostly encountered in large, high voltage substations designed by power utilities. For additional information, see IEEE Std 142 and IEEE Std 80.

• Ground-Resistance Measurement. Often it is necessary to measure the resis-tance of the grounding system to earth to determine if the value is within design limits. Methods of measuring ground network resistance are discussed in Section 936.

• Corrosion Problems. Copper is recommended for ground networks because of its resistance to corrosion and its high conductivity. Because of the galvanic couple between copper and steel, an extensive copper grounding system may accelerate corrosion of steel piping and other buried steel connected to the system. Where this condition exists, galvanized steel ground rods and insulated copper conductors should be used, but care must be taken to ensure that the ground electrodes do not corrode, which reduces their effectiveness. Cathodic protection of the ground electrodes and buried steel, using sacrificial anodes or impressed current, will alleviate this problem.

934 Control Room Instrument and Computer Equipment GroundingGrounding of control room instrumentation and process computers should be in accordance with ICM-MS-3651 and Standard Drawing GF-J1236. This drawing includes information on grounding the following:

• Cable shields• Computer, programmable logic controller (PLC) and UPS enclosures• Control panels• Intrinsic safety barriers• Thermocouples, RTDs, and other field devices• Instrument and computer power supply enclosures



• Instrument equipment racks and related steelwork

Each of the “low-frequency” grounds should be made by independent ground connections, insulated from each other and connected together at a single connec-tion point to the plant grounding grid. See ANSI/IEEE Std 142 for more informa-tion.

“High-frequency” grounding techniques and transient voltage surge suppression are covered in Company Specification ICM-MS-3651 and ANSI/IEEE Std 1100.

935 Shipboard Equipment Grounding InstallationsU.S. flag vessels must conform to U.S. Coast Guard regulations (see Code of Federal Regulations, Title 46, Subchapter J).

Since a ship’s hull is readily available as a grounding point, permanent power distri-bution circuits do not require a grounding conductor. If armored cable is used, the armor should be grounded. All equipment should be solidly grounded to the hull with separate conductors and as required by regulations.

All power distribution systems on tankers should operate with ungrounded neutrals, and ground detectors should be installed to indicate faults. Other types of ships may use power distribution systems with grounded neutrals.

936 Ground Resistance MeasurementFor new installations of grounding electrodes, it is recommended that tests be made of earth resistivity. Theoretically, it is possible to calculate the resistance to earth of any system of grounding electrodes. However, soil resistivity is dependent on soil material, moisture content, and temperature. The typical range of soil resistivity is between 500 and 50,000 ohm-centimeters. Seasonal changes cause soil resistivity at a given location to vary. See ANSI/IEEE 142, Chapter 4, for more information.

Formulas for calculating the resistance to earth of grounding electrodes are compli-cated and of little value. Many such formulas have been developed and may be useful as general guides, but the resistance of any given installation can be deter-mined only by test. Several methods of testing have been devised, varying in degree of accuracy. It is important that the measurement of grounding connection resis-tance be made at both the time of installation and at periodic intervals thereafter to determine the adequacy and permanence of the grounding connection. Precise measurements are not required because it is only necessary to know the order of magnitude of resistance—1, 10, 100, or 1000 ohms. These values indicate whether grounding is satisfactory for the particular installation or if improvement is neces-sary.

The common method of measuring the resistance of a grounding connection uses two auxiliary electrodes (i.e., two in addition to the one being tested). The resis-tance may be measured using a voltmeter and ammeter, a Wheatstone bridge with a slide-wire potentiometer, or self-contained instruments giving direct readings. Portable ground-testing instruments provide the most convenient and satisfactory



means for measuring the resistance of grounding connections. The megohmmeter used for measuring the insulation resistance of motors is not suitable for measuring grounding resistance because it will not measure low values of resistance.

Three methods of measuring and testing grounding connections are the Three-Point Method, the Ratio Method, and the Fall-of-Potential Method. For a full description of these methods, see ANSI/IEEE Std 81.

940 Lightning Protection Grounding

941 StructuresThe objectives of lightning protection are to avoid catastrophic equipment damage and to prevent personal injury. The energy of a lightning stroke can readily ignite flammable vapors or damage equipment. Lightning protection systems use air termi-nals (rods, masts, or overhead ground wires) to intercept lightning strokes and divert the lightning-produced current to ground through low impedance circuits.

The zone of protection for an air terminal or overhead ground wires is shown in Figure 900-8. All structures completely within the zone of protection may be considered protected from direct lightning strokes. For further guidance, see NFPA 780 and API RP-2003.

The major factors to be considered when deciding if lightning protection devices are required are:

• Frequency and severity of thunderstorms. See the map of lightning frequency in the U.S.A. in NFPA 780.

• Personnel hazards

• Inherent self-protection of equipment

• Value of the item or nature of the product that might be damaged by lightning-produced fire or explosion

• Possible operating loss caused by plant or equipment shutdowns

Most steel structures, offshore platforms, process columns, vessels, storage tanks, and vessels of a petroleum processing plant will not be appreciably damaged by direct lightning strokes because of the thickness of the steel used for these struc-tures. However, it is necessary to ground the taller structures adequately to prevent possible damage to reinforced concrete foundations and to provide a zone of protec-tion for electrical equipment in the immediate area. Bonding jumpers should be installed around all bolted tower sections. The jumpers may be bolted or thermally welded. The latter is preferred. API RP 2003 and NFPA 780 describe recommended practices for protecting structures against lightning.

At onshore plants, all equipment and structures exposed to direct lightning strokes should be grounded in accordance with the “Standard for the Installation of Light-ning Protection Systems,” NFPA No. 780. As a minimum, all structures 100 feet tall



or taller, or the tallest structure in the plant area if under 100 feet, and all stacks should be grounded. If any equipment or structures extend beyond the zone of protection, additional structures should be grounded. Ground rods and ground loops, in addition to those required for power system grounds, should be provided for lightning protection grounding. All ground loops should be connected together.

Steel storage tanks should be grounded every 100 feet along their perimeter, according to NFPA 780. The roofs of floating roof tanks should be bonded to side-walls for ground continuity in accordance with API RP 2003. No auxiliary ground need be provided for pressure vessels, piping, or similar equipment because these are inherently grounded.

942 Electrical EquipmentTo protect electrical equipment from damage, electric power distribution systems should have lightning or surge protection. Overhead lines can be shielded from lightning by the installation of overhead ground (static shield) wires to provide a “triangle of protection” for the phase conductors. Similarly, substations and outdoor switching equipment can be shielded by terminals or overhead static shield wires. These shielding devices must be connected to an adequate grounding system to be effective. Aerial cable normally will be protected by its messenger cable if the messenger is adequately grounded at frequent intervals. If the cable has a metallic

Fig. 900-8 Zone of Protection for an Air Terminal (a) or Overhead Ground Wire (b) (Used with permission from NFPA 780, Standard for the Installation of Lightning Protection Systems, Copyright 1995, National Fire Protection Association)



sheath or armor, the sheath or armor should be bonded to the messenger cable at each grounding point. Feeders consisting of cables in metallic conduit are essen-tially self-protecting, but conduits and metal sheaths should be properly grounded and bonded to the equipment at each end.

Where electrical equipment is connected to an electrical power distribution system exposed to direct lightning strokes or to voltage surges caused by lightning, it should be protected by suitable surge arresters. Arresters have the ability to inhibit current at rated power system frequency and voltage but to pass very high current at surge voltage levels. During the diversion of the surge, system voltages are controlled within the design capability of connected electrical equipment. The appli-cation of surge arresters for various equipment is addressed in IEEE Std 141 and Std 242. Arresters should be installed as close as possible to the equipment to be protected, and the arrester ground wire must be as short as possible and connected to the machine or transformer enclosure. The ground wire should have few if any bends and should have no sharp bends. See NEC Article 280 for additional informa-tion. Surge arresters are recommended for the following locations:

• At both high- and low-voltage terminals of distribution and power transformers if these terminals are connected to overhead lines that may be exposed to a direct lightning stroke

• At the junction of transformer feeder cables and exposed overhead lines for cable-fed transformers. Depending on the cable length and the arrester rating, surge arresters may be required at the transformer terminals as well; see Section 6.7.3 of IEEE Std 141-1993

• On exposed overhead lines, at each point where a connection to insulated cable is made

• At the terminals of motors fed from an exposed overhead line or supplied by a transformer fed from an exposed overhead line

• On the secondary side of a transformer fed from an exposed overhead line (for the protection of a group of motors connected to the secondary bus)

• Where electrical conductors enter a structure protected against lightning in accordance with NFPA 780

Surge capacitors are used to reduce the rate-of-rise of voltage surges caused by lightning and switching surges. They protect AC rotating machines and other equip-ment having low turn-to-turn insulation strength. They are usually applied in conjunction with surge arresters and are connected line-to-ground. Capacitor voltage rating must equal or exceed system line-to-line voltage, and the capacitors must be designed for surge-protection applications. The connection wiring between capacitor and phase conductors, and between the capacitors and ground, must be as short as possible.



950 Static Electricity GroundingStatic electricity is caused by the accumulation of electrical charges on materials and objects. The flow of electricity during static electricity generation and accumu-lation is small—in the range of microamperes. Usually static charges do not accu-mulate if the total resistance to ground is one megohm or less. When charges do accumulate, potential differences of thousands of volts may be produced. A primary manifestation of static electricity is the discharge or sparking of accumulated charges. Of particular concern is the static charge resulting from contact and separa-tion that occurs when flammable fluids flow.

Bonding and grounding of tank trucks, tank cars, container filling apparatus, etc., should be in accordance with API RP 2003 and NFPA 77. The size of the bonding conductor can be based only on mechanical strength as current flow is in microam-peres. Static grounds are connected directly to the grounding system. Bonding and grounding conductors should be copper (usually bare copper is recommended for both economy and ease of identification).

960 Sizing Components

961 Low-Resistance GroundingFor a low-resistance grounded system of 2.4 through 14.4 kV, the determination of the ohmic value of the grounding resistor, and hence the magnitude of ground fault current, is based on the following:

• Providing sufficient current for fast, selective performance of the system protective relaying scheme

• Limiting ground-fault current to a value that causes minimal damage to equip-ment at the point of a fault

Sizing of ResistorThe value of the resistor can be approximated with the formula given below (when the ground-fault current is small compared to the three-phase fault current for a fault at the same location). This is usually the case for the ground fault currents limited by the resistor to several hundred amperes.

(Eq. 900-1)

where:RN = Resistance of the neutral grounding resistor, in ohms

EL-N = Line-to-neutral voltage of source, in volts

IL-G = Line-to-ground current, in amperes

RN

EL N–

IL G–---------------=



If the grounding resistor is purchased concurrently with the transformer or switch-gear, only the current rating of the resistor (usually 400 amperes maximum) and the time rating (usually 10 seconds) need to be specified. The 10 second rating permits the ground-fault relay and the circuit-switching device time to operate before the resistor is damaged.

962 High-Resistance Grounding

Sizing of ResistorThe basic requirement of sizing a resistor used in a high-resistance grounding scheme is to select a resistor that provides a ground fault current equal to or greater than three times the system capacitive charging current of one phase.

The resistor current, IR, due to system capacitance can be defined as follows:

IR = 3 Ico

where:I co = System charging current of one phase

Thus, the minimum size of the grounding resistor is determined from the sum of capacitive charging currents of all equipment components in the system. This can be represented by the following formula:

3 Ico (surge capacitors) + 3 ICo (cables)

+ 3 Ico (motors and generators)

For 3 Ico (surge capacitors), see Figure 900-9

For 3 Ico (cables), see Figure 900-10

For 3 Ico (motors and generators), see Figure 900-11

Note Transformer capacitive charging currents are not included as they normally are negligible.

If the grounding resistor is purchased with a motor control center, the current rating of the resistor (usually 5 amperes) and the time rating, usually “continuous rating” should be specified.

Fig. 900-9 Line-to-Ground Fault Charging Currents (3 Ico) for Surge Capacitors

Voltage, kV C, ufd. 3 Ico, ma

0.48 1.0 313

2.4 0.5 784

4.16 0.5 1357

6.9 0.5 2253

13.8 0.25 2253



Capacitive Charging CurrentThe only accurate method of determining charging current for a given system is by direct measurement. Since measurement is not possible during the design phase, normal practice is to estimate the charging current, as above, and provide an adjust-able (tapped) resistor that allows several settings either side of the estimated value for field adjustment.

From the data in Figures 900-9, 900-10, and 900-11, an approximation of the total system charging current can be made and the size of the ground resistor can be selected. Typically, charging currents for 480 volt systems are less than 1 ampere; maximum of approximately 5 amperes. Systems of higher voltage should be limited to 10 amperes.

When the detailed design of a system is in progress, more refined calculations for motor and cable charging currents should be made. Motor and cable manufacturers normally will be able to supply accurate values of capacitance-to-ground per phase. Chapter 6 of Westinghouse Electrical Transmission and Distribution Reference Book is a good source for electric machine capacitance values (as a function of machine speed, type, size, and voltage rating).

Capacitive charging current can be calculated from the per-phase capacitance-to-ground value using the following equations:

(Eq. 900-2)

(Eq. 900-3)

where:IC = System charging current during a ground fault, in amperes

Ico = System charging current of each phase during normal system conditions (no ground fault) [I co], in amperes

VLL = System line-to-line voltage, in volts

Xco = Per-phase capacitive reactance, in ohms [Xco]

f = Frequency, in hertz

Co = Per-phase capacitance-to-ground, in microfarads (10-6 farads)

• Surge Capacitor Charging Current

The charging current for surge capacitors is significant for the values of capaci-tance normally used, as shown in Figure 900-9. The surge capacitors may easily be the largest single contributor to the total capacitive charging current.

Ic 3 Ico

3VLL

Xco------------------= =

Xco106

2πfCo----------------=



• Cable Charging Current

Insulated power cables can contribute a significant percentage of the total system charging current, second only to surge capacitors. Determination of charging current is based on cable size, length, insulation material, and thick-ness.

The values of ground fault charging current for insulated power cables as shown in Figure 900-10 are based on the insulation dielectric constant of PVC for 600 volt cables and the dielectric constant of EPR, XLPE or Butyl for 600 through 15,000 volt cables. Multiplying factors are also provided to calculate the charging current of cables with dielectric constants different from those listed.

• Motor and Generator Charging Current

Typical charging currents for motors and generators are as shown in Figure 900-11. The minimum charging current value is typical of high-speed machines (1800 rpm), and the maximum value is typical of lower speed machines (600 rpm) for the range of ratings normally selected at each voltage level.

• Transformer Charging Current

The transformers most commonly used in industrial systems are of core and coil construction; that is, the low- and high-voltage windings are concentrically placed around a rectangular cross section core. This design results in a very small value of distributed capacitance between the windings and ground. Thus the ground fault charging current usually is negligible in systems rated 15 kV and below.



*ICM-MS-3651 Installation Requirements for Digital Instruments and Process Computers

*ELC-MS-1675 Installation of Electrical Facilities



Fig. 900-10 Line-to-Ground Fault Charging Currents (3 Ico) for Cables

LINE-TO-GROUND FAULT CHARGING CURRENT (3 ICO) FOR SOLID-DIELECTRIC INSULATED CABLES (PER THREE-PHASE CIRCUIT)

Shielded 3 Ico, ma/1000 ft

Cable Size (AWG) 2.4 kV 4.16 kV 6.9 kV 13.8 kV

6 99 171 284 —

4 114 198 329 —

2 133 231 383 577

1 146 253 419 631

1/0 158 274 455 676

2/0 172 299 496 739

3/0 186 323 536 793

4/0 205 356 590 865

250 MCM 219 380 631 919

350 MCM 251 435 721 1045

500 MCM 291 505 838 1207

750 MCM 346 600 996 1424

1000 MCM 392 679 1126 1604

Unshielded cable in metallic conduit (typical):

480 V 13 ma/1000 ft

2.4 kV 63 ma/1000 ft

4.16 kV 109 ma/1000 ft

Unshielded cable in metallic cable tray (typical):

480 V 9 ma/1000 ft

2.4 kV 47 ma/1000 ft

4.16 kV 81 ma/1000 ft

Notes: 1. Multiply charging current by 1.2 for paper-insulated cable.2. The charging currents given above are for cables with a dielectric constant of 3.3. For other dielectric constants, multiply the

above by the actual dielectric constant and then divide by 3.3.3. Neglect charging current for bare, open-wire lines; current is negligible for lengths normally used in industrial distribution

systems.




973 Data Sheets (DS), Data Guides (DG) and Engineering Forms (EF)There are no data sheets, data guides or engineering forms for this guideline.


ANSI/IEEE StandardsANSI/IEEE Standard 32, IEEE Standard Requirements, Terminology, and Test Procedure for Neutral Grounding Devices

ANSI/IEEE Standard 45, IEEE Recommended Practice for Electric Installations on Shipboard

ANSI/IEEE Standard 80, IEEE Guide For Safety in Substation Grounding

ANSI/IEEE Standard 81, IEEE Guide for Measuring Earth Resistivity, Ground Impedance, and Earth Surface Potentials of a Ground System

ANSI/IEEE Standard 141, IEEE Recommended Practice for Electric Power Distri-bution for Industrial Plants

ANSI/IEEE Standard 142, IEEE Recommended Practice for Grounding of Indus-trial & Commercial Power Systems

Fig. 900-11 Line-to-Ground Fault Charging Currents (3 Ico) for Motors and Generators

Voltage, kV Motors, ma/1000 hp Generators, ma/MVA

Min. Max. Min. Max.

0.48 5 10 10 20

2.4 20 40 12 16

4.16 35 70 18 25

6.9 60 115 25 35

13.8 115 230 36 50

Notes: 1. The minimum charging current value for motors is typical of high speed motors (1800 rpm) and the maximum value is typical of lower speed meters (600 rpm) for the range of horsepower ratings normally selected at each voltage level.

2. Charging current values for generators rated 2,400 volts and above are for 1800 rpm air cooled machines in the range of 10-60 MVA.

*GD-P99734 Grounding Details — Grounding Electrodes

*GF-P99735 Grounding Details — Equipment Connections

*GF-J1236 Typical Ground System for Digital Instruments and Process Computers



ANSI/IEEE Standard 242, IEEE Recommended Practice for Protection and Coordi-nation of Industrial and Commercial Power Systems

ANSI/IEEE Standard 446, IEEE Recommended Practice for Emergency and Standby Power Systems for Industrial and Commerical Applications

ANSI/IEEE Standard 1100, IEEE Recommended Practice for Powering and Grounding Sensitive Electronic Equipment

Government RegulationsOccupational Safety & Health Administration (OSHA) Code of Federal Regula-tions, Title 29, Subpart S, 1910

Code of Federal Regulations, Title 46, Shipping, Office of the Federal Register

ANSI/NFPA Standards and CodesANSI/NFPA 70, National Electrical Code

ANSI/NFPA 70E, Standard for Electrical Safety Requirements for Employee Work-places

ANSI/NFPA 77, Static Electricity

ANSI/NFPA 780, Standard for the Installation of Lightning Protection Systems

NFPA Fire Protection Handbook

ANSI C2 National Electrical Safety Code

American Petroleum Institute Practices (API)

Miscellaneous ReferencesIndustrial Power Systems Handbook, Beeman, Donald, McGraw-Hill, 1st Edition 1955, Chapter 6: Neutral Grounding; 7: Equipment Grounding; and pages 426 through 433: Shock Hazards

Electrical Transmission & Distribution Reference Book, Westinghouse Electric Corp., 1964, Chapter 2: Symmetrical Components; 6: Machine Characteristics; 16: Lightning Phenomena; and 19: Neutral Grounding

RP 14F Design and Installation of Electrical Systems for Offshore Production Platforms

RP 540 Recommended Practice for Electrical Installations in Petro-leum Processing Plants

RP 2003 Protection Against Ignitions Arising Out of Static, Lightning and Stray Currents


1000 Installation of Electrical Facilities

AbstractSection 1000 covers general design and installation practices for electrical facilities, with reference to ELC-MS-1675, “Installation of Electrical Facilities,” as the general specification. The section also provides specific guidance for the design and installation of conduit systems, cable tray systems, and direct burial cable. An appendix is included in this manual which provides extensive information on the calculation of pulling tensions and installing and terminating cables. Guidance is given on the installation of switchgear, motor control centers, transformers, uninter-ruptible power supplies, and battery systems.

Contents Page


1020 Conduit System Design and Installation 1000-3

1021 Rigid Metal Conduit Systems

1022 PVC Conduit Systems

1023 Conduit Route

1024 Conduit Arrangement and Spacing

1025 Use of Seals and Drains

1026 Aboveground Conduit Support

1027 Underground Conduit Banks

1028 Conduit Bends and Pull Boxes

1030 Installing Electrical Conductors in Conduit Systems 1000-9

1040 Installation of Cable Tray Systems 1000-9

1041 Determination of the Cable Tray Route

1042 Cable Tray Arrangement

1043 Grounding and Bonding of Metallic Tray

1044 Supports for Cable Tray

1000 Installation of Electrical Facilities Electrical Manual


1045 Installation of Cable in Cable Tray Systems

1050 Conductor Terminations 1000-13

1051 Purpose

1052 Control of Electrical Stress With Terminations

1053 Terminator Requirements

1060 Direct Buried Cables 1000-15

1070 Installation of Electrical Equipment 1000-15

1071 Phasing and Phase Rotation

1072 Installation of Switchgear and Motor Control Centers

1073 Installation of Transformers

1074 Installation of UPS Systems

1075 Installation of UPS Batteries





1084 Appendices


Electrical Manual 1000 Installation of Electrical Facilities


1010 IntroductionThis section provides useful information pertinent to the design and installation of electrical facilities in addition to the information in ELC-MS-1675, “Installation of Electrical Facilities.” ELC-MS-1675 is usually given to electrical contractors as the general electrical specification. It should be modified to accompany the specific contract documents for construction. Several standard forms and drawings (listed at the end of ELC-MS-1675) which are related to the installation of electrical facilities are included in this manual.

When installing electrical equipment it is important to adhere to the requirements of the National Electrical Code (NEC) in most areas of the United States. In OCS areas offshore, API RP 14F is applicable and deviates from the NEC in a few places. In addition, Underwriters’ Laboratories (UL) and Factory Mutual (FM) have requirements for listed equipment which must be adhered to when the equipment is installed. It is becoming increasingly important that all electrical components be listed by UL, FM, or another nationally recognized testing laboratory (NRTL) in order to be accepted by the inspectors of the agency having jurisdiction. Problems sometimes arise when installing custom-designed equipment not covered by a specific standard (which, therefore, can’t be listed). In this case, the best course of action is to use listed (usually UL) components in the equipment. Check with local inspectors in advance of purchase to determine their applicable requirements.

For ships, installation is governed by classification societies and national authori-ties, such as the American Bureau of Shipping and the United States Coast Guard. Foreign regulations are often based on publications written by the International Electrotechnical Commission (IEC).

Standard specifications, drawings, and forms related to this section are listed in Section 1080. One of these specifications, ELC-MS-4377, is a standard electrical item list (P-item list) which describes bulk electrical materials by manufacturer and model. This specification should accompany drawings which specify electrical items by referring to the P-item number (rather than a detailed material list). Some locations have their own standard electrical material list. For those areas which do not have a list, the recently revised version is included and can be modified to meet local preferences.

1020 Conduit System Design and InstallationThis section discusses the most common types of conduit systems in use. Conduit bank design, the types of supports, installation, and layouts of both aboveground and underground systems are discussed. Section 100, “System Design,” should be consulted before choosing the type of conduit system and before sizing conduit systems.

ELC-EF-70, “Conduit and Wire Schedule,” is used for listing each conduit in an electrical installation and the number, type and destination of wire pulled in each conduit. It is created during the design phase of a project and used during the construction phase when installing wire. It also serves as a wire pulling schedule.



On large projects, it may be desirable to generate these schedules with a computer. The form is included as a model for developing computer forms or for direct use.

The following sections cover several important features of both above and below-ground conduit installations.

1021 Rigid Metal Conduit SystemsFor refinery and chemical plants, the most frequently used system for providing power from the source to the load is wire in rigid metal conduit. The most common conduits are galvanized steel, PVC-coated galvanized steel, and aluminum (usually copper free). PVC-coated galvanized steel and aluminum conduit have superior corrosion resistance and are appropriate for more corrosive environments, however, they are more expensive than standard galvanized conduit. Intermediate metal conduit (IMC) is not recommended for hazardous (classified) areas or areas not environmentally controlled. The minerals Management Service does not allow the use of IMC in hazardous (classified) areas offshore.

1022 PVC Conduit SystemsThe use of PVC conduit systems in underground concrete encased duct banks is increasing. The advantages of PVC for underground applications are; low initial cost, ease of installation, ability to be manually bent into wide-radius sweeping turns (rather than small radius bends), low coefficient of friction (for pulling), and corrosion resistance. PVC does not have the same strength as rigid steel, but strength is added by the concrete reinforcement which protects the conduit.

Usually, PVC conduit systems should be designed with a transition to rigid steel conduit before the PVC conduit stubs up above grade (to provide mechanical strength at grade level).

One disadvantage of PVC conduit systems is that the conduit cannot serve as the ground return path for equipment grounding and a separate ground wire must be installed in the PVC conduit. Another disadvantage of PVC conduit systems is the loss of the shielding effect obtained from steel conduit which results in the increased possibility of induced noise. Also, PVC conduit cannot be used in classi-fied areas.

1023 Conduit RouteIn general, the best route to use is the most direct route which avoids high fire risk areas. In both above- and belowground systems, careful consideration should be given to avoiding interferences (e.g., piping and hidden underground structures). In facilities with poor documentation, it is sometimes worthwhile to do exploratory excavation along the proposed routes prior to excavating for the installation of new underground conduits. This will minimize unknown interference problems and reduce installation costs.



Abovegrade conduit routes often parallel piping in trenches or on overhead pipe racks. When installing conduit in this manner, position the conduit to minimize any interference during subsequent pipe removal or installation.

For both underground and abovegrade installations, install conduits away from sources of heat such as furnaces, steam lines and heat exchangers. Underground conduit should never be routed close to parallel steam lines. Steam line crossings should be made at right angles whenever possible. High temperatures can cause cables inside conduits to fail prematurely.

1024 Conduit Arrangement and SpacingWhen multiple conduits are organized into a group aboveground, or a duct bank belowground, there are specific conduit spacing requirements which are based on the voltage and current of the enclosed conductors. These spacing requirements (found in ELC-MS-1675) are designed to prevent induced voltage which might cause improper system operation in low level control and monitoring circuits.

Adequate space should be left between abovegrade conduits to allow installers to thread on fittings which are larger in diameter than the conduit and to allow removal of the covers from fittings. Sufficient space should be left around conduit seals to allow access for pouring.

Conduit spacing has an effect on the heating of conductors within duct banks. If there are multiple power circuits in a duct bank, a derating factor must be applied to the ampacity of the insulated conductors in the conduits in the bank. The National Electrical Code provides some guidance in computing the derating factors. However, computer programs are available which take into account load factor, soil thermal resistivity, ambient temperature, and the configuration of the adjacent conduits in order to determine safe ampacities.

AMPCALC, a computer program which calculates cable ampacities in duct banks, is available from Calcware in Houston, Texas. Their phone number is (713) 973-7032. The program is based on the Neher-McGrath method and can handle over 100 conduits with different sized conductors and currents in a duct bank.

1025 Use of Seals and DrainsConduit seals are required in conduits when an area classification change occurs. The seals can be placed on either side of the area classification change, but no fitting is allowed between the seal and the point at which the conduit leaves the Division 1 or Division 2 boundary. Refer to Section 300 for additional seal require-ments.

On a large project it is common practice to wait until the project is electrically complete before pouring the seals. All seals are then poured at one time. Once seals are poured, it is recommended that they be painted red or otherwise marked to indi-cate that the sealing compound has been poured.



Seals in vertical conduit runs should be provided with drains. Drains must also be installed in the low points of conduit runs where water might accumulate. For outdoor, aboveground installations, drain seals should be installed where conduits enter enclosures from the top. This prevents water from entering enclosures through conduit. It is preferable to design systems so that conduits enter enclosures from the side or bottom to avoid water entry.

1026 Aboveground Conduit SupportAboveground conduit usually is supported by steel channel (e.g., Unistrut). NEC Article 346, gives the maximum spacing between supports, based on conduit size.

Conduit support should be checked carefully during the construction phase. Conduit should not be able to be moved easily with hand pressure. Conduit in over-head conduit systems should be checked carefully to ensure conduits are secured to the supports.

When supporting conduit from structural members in high vibration areas, clamp-on beam clamps should be used judiciously since they tend to loosen with vibration.

It is important to observe the metallurgy of the supports and the conduit to avoid galvanic corrosion. For example, corrosion will result if aluminum conduit is secured directly to steel. Special isolation pads are available to eliminate this problem.

Supporting conduits from adjacent conduits is not allowed in most cases (Reference NEC 300-11). Conduit should be supported from structural members at proper inter-vals. Often additional rigidity of a conduit group can be obtained if adjacent conduits are tied together at intermediate points, however, this can not take the place of structural support. Conduits must not be supported from process piping. It is permissible to support them from pipe support structures if proper clearances are observed.

1027 Underground Conduit BanksRouting of underground conduit banks must be decided early in the project since underground banks usually are installed before abovegrade plant construction is done. Careful consideration must be given to the number and size of the under-ground conduits since it is difficult (and very costly) to modify or expand the system once the concrete is poured.

If there are several conduits in a concrete duct bank, the spacing and position of the conduits must be maintained during the pouring of the concrete. This usually is accomplished with plastic spacers or by tying the conduit to the surrounding rein-forcing bar (rebar) cage with wire ties.

Figure 1000-1 illustrates a typical underground conduit bank. For larger banks (particularly those with non-metallic conduit), a rebar cage is required to provide strength for the duct bank (particularly if there will be heavy vehicular traffic over the bank). A civil engineer should be consulted for the design of large banks to



ensure the proper sizing and arrangement of the rebar and the proper compressive strength of the concrete.

Figure 1000-1 shows pile supports under a concrete-encased conduit bank. Piles are often required in poor soil areas where the conduit may settle or sink. A civil engi-neer should be consulted concerning the necessity and details of any required pile support systems.

An often overlooked consideration in underground conduit systems is drainage. Conduits should be sloped toward a low point so that water will drain from the conduit. Often, the drainage will flow into a pull box equipped with a drywell which allows the water to percolate into the soil. Sometimes large pull boxes or basements into which water from conduits will drain, are equipped with sump pumps.

It is good practice to mark the top few inches of concrete-encased duct banks with red iron oxide mixed with concrete. This provides a warning for future excavators that they are digging up an electrical installation. Although the initial cost is greater, repairing systems damaged by excavators can be very expensive (in addi-tion to down-time and personnel safety factors). It is recommended that permanent, underground duct bank markers be visibly embedded at grade level along the path of the duct bank.

1028 Conduit Bends and Pull BoxesThe recommended maximum number of bends in a conduit run, either above-ground, or belowground, is specified in ELC-MS-1675. Figure 1000-2 summarizes

Fig. 1000-1 Typical Underground Conduit System



these requirements, as well as the allowable bending radii for different types of conductors.

Note that conduit bodies (such as LB condulets) which are suitable for 600 volt wire usually are not suitable for medium voltage cable because they do not meet the bending radii requirements for larger diameter cables. To change directions in a medium voltage conduit run and to meet the bending radius requirement of the medium voltage cable, usually a conduit bend of the proper radius or a large pull box which allows the proper bending radius is required. Where cable is pulled out of and back into an enclosure, the distance between the exit and entrance points must be at least four-times the minimum bending radii of the cable. LB- and C-type fittings usually do not meet this requirement (and would constitute an NEC viola-tion if used).

To limit the number of bends in underground conduit, pull boxes are used. It is usually more cost effective to use a precast pull box of a standard design than to have one custom poured in place. Precast pull boxes are available in sizes ranging from 12 inches x 18 inches x 12 inches to 10 feet x 12 feet x 4 feet. All that usually is required for installing a precast pull box is excavating the hole and installing the box prior to installing the duct bank which connects to the box.

Covers of pull or junction boxes used for over 600 volt cable must be permanently marked “Danger High Voltage Keep Out” in 1/2" minimum letters.

Fig. 1000-2 Maximum Pulling Distances, Degrees of Bend and Minimum Bending Radius for Specific Conductor Types in Conduit

Conductor Type 600V 5 kV Shielded 5 kV Unshielded 15 kV

Maximum Pulling Distance

300 ft. 400 ft. 400 ft. 400 ft.

Maximum Degrees of Bend for Runs 300 Foot or Less

315 Deg. 180 Deg. 180 Deg. 180 Deg.

Maximum Degrees of Bend for 400 Foot Run

180 Deg. 180 Deg. 180 Deg. 180 Deg.

Minimum Bending Radius

6 x OD 30 in. 8 x OD 30 in.

Maximum Single Bend 90 Deg. 90 Deg. 90 Deg. 90 Deg.



1030 Installing Electrical Conductors in Conduit Systems

IntroductionMost land-based electrical installations use insulated conductors pulled in rigid metal conduit although the use of cables in cable tray is increasing. During the installation of conductors in conduit, it is important that proper procedures for pulling are followed and that maximum pulling tension and jam ratios are not exceeded. This is of particular importance when installing medium voltage insu-lated conductors.

A reproduction of “Installation Practices for Cable Raceway Systems” by the Okonite Company is included as Appendix E. It provides excellent guidelines for determining the maximum allowable tension and sidewall pressure limitations for a given pull, as well as information on the proper equipment to use and precautions to take.

1040 Installation of Cable Tray SystemsSection 100, “System Design,” discusses how to choose among the different types of cable tray and provides an example of how to calculate the allowable wire fill necessary to meet NEC requirements.

The use of cable tray and cables is often a less expensive alternative to conduit systems. Cables can be added to the tray easily and economically. When circuits are routed from one area to another as a group, a cable tray system can often be installed for less than wire and conduit. Cable tray is used extensively on offshore platforms.

The installation requirements for cable tray systems are found in the NEC Article 318. Figure 1000-3 illustrates a typical “ladder”-type cable tray system.

Cable tray is available in different materials. These materials include: galvanized steel, stainless steel, aluminum, and fiberglass. The choice of material should be based on the degree of strength and corrosion resistance which is required.

A major disadvantage of a cable tray system compared to an underground conduit, is that cable in tray is more susceptible to fire and mechanical damage.

1041 Determination of the Cable Tray RouteThe main considerations in designing cable tray routes are the same as any cable routing—keeping the route as short as possible while avoiding high fire-risk areas and keeping the tray away from hot equipment. Cable tray routing should be deter-mined at the same time as the piping routing, since the tray is usually fairly large in cross section and could interfere with piping or be damaged during pipe installation if the routings are not carefully planned. Also, supports can be dual purpose—supporting pipe and cable tray (which minimizes overall costs).



1042 Cable Tray ArrangementTrays may be either stacked or placed side by side. Generally, cable tray systems are stacked with different voltage levels, signal levels and intrinsically safe circuits separated (in different trays). It is important to avoid mixing low-level signals (such as thermocouple leads) and high-level power cables in the same tray. Information regarding separation requirements between signal levels can be found in ELC-MS-1675, “Installation of Electrical Facilities.”

Cables installed in cable tray must be suitable for use in cable tray systems. NEC Article 318-3 lists the cables suitable for installation in tray. Most wire which is normally installed in conduit is not suitable for use in tray. For example, individual conductors of AWG 12 THW are not suitable for use in tray. NEC Article 318 requires that single conductors be larger than 1/0 if used in tray, and they must be of a type suitable for use in tray. Smaller conductors may be used if they are in a suit-able multi-conductor cable.

Cable cannot be stacked indiscriminately in cable tray. Specific rules concerning layering cables in the same tray are given in NEC Article 318. For example, multi-conductor cables which are 4/0 or larger must be in a single layer (with no other cables on top of them). Multi-conductor cables with conductors smaller than 4/0 may be layered if the maximum cross sectional area fill is not exceeded. Large, single conductors, above 1/0, are usually installed in a single layer. Violations of Article 318 can result in the overheating of circuits.

Fig. 1000-3 Typical Aboveground Cable Tray System



1043 Grounding and Bonding of Metallic TrayMetallic tray must form a complete system that is electrically and mechanically continuous and grounded as required by Section 318-7(a) of the NEC. When installed in this manner, metallic tray is allowed to serve as the equipment grounding conductor (to carry fault current back to the service transformer or gener-ator ground). Metallic tray may be used as a part of a continuous ground path between the service point and end devices served by cables in the tray.

1044 Supports for Cable TrayThe most common methods of supporting cable tray include the following: direct mounting on fixed objects (e.g., pipe racks), suspension below a horizontal surface (e.g., ceiling, beam or deck), often by threaded rods supporting horizontal members on which the tray is fastened, and supporting the tray by welded steel channel or angle supports which are welded or bolted to other rigid structures (such as decks, pipe supports, and building walls).

Typical support methods are shown in Figures 1000-4 and 1000-5.

To prevent exceeding the maximum allowable deflection, refer to the cable tray manufacturer’s literature for recommended weight loading of the tray. Tray supports must be installed at close enough intervals to prevent exceeding specified maximum deflections (both vertical and horizontal).

Fig. 1000-4 Cable Tray Supported on Pipe Racks



1045 Installation of Cable in Cable Tray SystemsCare should be taken when installing cables in cable tray to prevent nicking or scraping the cables.

Additional recommendations for cable tray installations are as follows:

• Do not bend cables beyond the minimum allowed bending radii

• Do not allow cables to droop over sharp edges of the cable tray

• After installation, protect cables from damage during construction. Do not allow welding above uncovered cable tray or lifting of equipment above the cable tray

• Do not allow pipe or tubing to be installed in, or supported by cable tray. See NEC 300-11

• Use U/V resistant cable-ties to hold cables in place

• Always place all three phases of a three-phase circuit in the same tray to avoid induction heating

• Ensure that each cable is installed in the appropriate tray

(That is, trays of the same power level.) Low voltage cables (below 600 volts) cannot be mixed with higher voltage cables and low signal level cables should not be mixed with power conductors. Maintain the separations between signal levels listed in ELC-MS-1675 to prevent signal interference.

Fig. 1000-5 Typical Cable Tray Anchoring



1050 Conductor Terminations

1051 PurposeFigure 1000-6 illustrates the preferred compression-type of two-hole lug conductor termination for large (1/0 AWG and larger), non-shielded and shielded power conductors. Crimp-type (compression-type) lugs require special crimp dies specific to each lug size or range. They are preferred in both low and medium voltage appli-cations since they do not loosen over time like some bolted connections. Termina-tions should provide the following basic electrical and mechanical functions:

• Low resistance electrical connection of conductors to electrical equipment

• Physical support and protection of the end of the conductor insulation, shielding, overall jacket and armor

• Effective control of electrical stresses for medium voltage applications (by posi-tion of both internal and external insulation)

• Grounding of shields

1052 Control of Electrical Stress With TerminationsFigure 1000-7 illustrates various types of medium voltage shielded cable termina-tions used for indoor and outdoor terminations. The additional insulation level and shape serves as a means of electrical stress relief. If a termination at these higher voltages did not provide electrical stress relief, the combination of longitudinal and radial electrical stresses would focus at the shield end and eventually would cause

Fig. 1000-6 Two-hole Lug Cable Termination



insulation failure. The most common method for reducing the electrical stress is to gradually increase the insulation to form a cone. The shield is then carried up the cone surface and terminated behind the largest part of the cone. The energy stored between the shield and the conductor is dissipated over an increasing volume of insulation (the cone), reducing the potential for electrical discharge. Discharge corona can form ozone which can cause the insulation to fail.

1053 Terminator RequirementsCable terminators must provide adequate current carrying capacity. Also, they must be of the same material as the conductor or be approved specifically for the combi-nation of materials, and must provide the required insulation level. Most termina-tors should be of the two-hole lug-type as shown in Figure 1000-6. This type of terminator provides good resistance to loosening when subjected to vibration. The size of the terminator should be considered when sizing junction boxes of medium voltage motors and termination compartments in switchgear.

Exposed lugs may be taped, but (for most applications) the additional tape is a conservative measure and not required if the lug mounting point meets the required spacing from grounded surfaces and other phases (for the voltage level of the system).

Care should be taken not to overheat shrinkable termination kits during application. Cable faults can result from overheating heat-shrink products. Heat-shrinkable stress relief termination kits (such as Raychem) are recommended for both indoor and outdoor medium voltage installations. Skirts are added to outdoor terminators

Fig. 1000-7 Typical Medium Voltage Terminations



to increase tracking resistance. Some prefer the use of porcelain terminators (which are more expensive and physically larger than the heat shrinkable variety).

1060 Direct Buried CablesCables can be buried directly when the potential for cable damage is minimal, provided the cable is a type approved for direct burial applications. NEC Article 300-5, provides specific requirements for the direct burial of cables. These require-ments include minimum coverage, grounding, splices and taps, protection from damage, and backfill. The locations of direct burial cables should be clearly labeled so that construction equipment does not damage the cable. One recommended method for labeling the cable location is to use metallic tape (such as that used for labeling buried plastic lines). The cable can then be found by using a metal detector. Direct burial cables rated over 2000 volts nominal should be shielded and provided with an external ground path.

The minimum depth for direct burial of cables is 24 inches, but, for safety and reli-ability, depths of up to five feet are recommended. Cables should be buried with a sand backfill immediately surrounding them. Proper spacing between cables is important for separation of signal levels and for heat dissipation. When using direct burial cable, a route should be selected that offers the least potential for future damage. Cables should be located to minimize crossing process pipes and other obstructions. Once buried, cables are difficult to repair.

1070 Installation of Electrical Equipment

1071 Phasing and Phase RotationIn electrical system installations it is important to maintain the identity of the three phases throughout the system, from source to load. The three phases are commonly referred to as the A phase, the B phase, and the C phase. This is very important when tying systems together, when parallelling systems, and when predicting motor rotation. The three phases feeding the facility must be identified.

Once the phases are identified at the power source, it is necessary to determine which conductor is phase A, B, and C at every bus in the system. This identification is usually accomplished by color. Phase A is identified by the color black, phase B with red, and phase C with blue. When connecting the conductors from the utility or generator to the first switchgear bus, the phases must be connected to the corre-sponding buses. In the U.S., the convention for connection of the three phases to the bus is to connect phase A, B, and C from top to bottom, left to right, or front to back when facing the front of the switchgear.

It is recommend that outgoing feeder cables be taped with black, red, and blue tape at the switchgear and at all termination points. The proper phase is connected to the designated bus for that phase (according to the convention) at each downstream switchgear, MCC, transformer, and other electrical equipment. Therefore, the



phasing is indicated throughout the system. This can eliminate problems with motor rotation and the operation of other electrical equipment.

In some cases, it is important to know the phase sequence of the system. The phase sequence determines which phase-to-neutral voltage peaks first, second, and third. The most common phase sequence is A, B, C. It is necessary to know the phase sequence of the power source to predict the direction of motor rotation, to allow proper connection of semiconductor power convertors (such as UPS systems and variable speed drives), and to parallel systems. If the phase sequence is not known, obtaining correct motor rotation of three phase motors is not a serious problem. In order to change the rotation of the motor, all that is necessary is to interchange any two of the power lead termination points.

1072 Installation of Switchgear and Motor Control CentersSwitchgear and motor control centers usually arrive in two or more vertical sections. If these sections are to be stored, they should be moved inside and the space heaters energized to prevent condensation.

The foundation for switchgear and MCC units must be level. The most common design for onshore installations uses steel sills embedded in concrete. The switch-gear may be bolted or welded to this channel or bolted directly to the concrete (normally using expansion-type anchors). In severe earthquake zones, different anchoring designs are required to allow flexing of the anchor (instead of breaking) during earthquakes.

Before finalizing the location of (and securing) switchgear or MCC units, the distances to nearby equipment should be checked and compared to the requirements of NEC Articles 110-16 and 110-34. These articles specify the required working space around electrical equipment based on voltage to ground. It may be possible to adjust the position of the equipment to meet NEC requirements if it does not meet them as initially positioned. After switchgear has been interconnected, it is very difficult and expensive to move.

If conduits stub up below the switchgear or MCC, early checks should confirm that conduits stub up below the vertical section in which the cable is to be terminated.

When all sections are set in place, the shipping splits must be fastened together in accordance with the manufacturer’s instructions. Often, wooden blocks or styro-foam packing (found inside relays) must be removed.

The buses between adjacent sections, including ground buses, must be connected together. Ascertain that all bus bolts are torqued to the values specified by the manu-facturer. When a bolt has been properly torqued, it should be marked to indicate that it has been checked. See Section 1400 for a bolt torque checklist. The proper torquing of bus bolts is extremely important to eliminate high resistance connec-tions which could result in overheating and eventual failure.

For insulated bus systems, it is necessary to tape or otherwise insulate all field-connected bus splits. Sometimes manufacturers supply boots which can be applied in the field.



Once adjacent bus sections have been connected, the control wiring must be connected using switchgear-grade wire. The point-to-point connections between the shipping splits shown in the vendors drawings must be followed.

Often, vendors install shorting bars on the current transformer terminal strips which require field interconnection wiring. These shorting bars are installed to prevent CT secondary overvoltages from occurring if the switchgear is energized without making the field interconnection wiring. Once the interconnection wiring to these strips is completed, the shorting bars must be removed to allow the CT circuits (for relaying or metering) to function properly.

The next step after the interconnection of control wiring is to terminate the power wiring. In medium voltage systems using shielded cable which passes through window CTs, it is important to bring the ground shield back through the CT before terminating it. There is an illustration of this method in Section 600. The use of termination kits for stress relief of medium voltage cable is discussed in this section.

After all terminations have been made, the entire system should be tested. It is usually desirable to have a manufacturer’s representative test the operation of relays and switchgear breakers. Others can perform the basic electrical testing (e.g., mego-hmmeter testing of the bus and cable). Section 1400 discusses the tests which should be performed prior to commissioning switchgear and MCCs.

1073 Installation of TransformersDry-type transformers should be stored in an environmentally protected location if not installed and energized soon after delivery. If oil-filled power transformers are to be stored for considerable lengths of time prior to energization, the internal pres-sure should be monitored. It is desirable to maintain positive internal pressure to prevent the entrance of moisture. A pressure-regulated nitrogen cylinder may be used to increase the internal pressure to 2-3 psi above atmospheric pressure. The pressure should be monitored on a monthly basis to detect leaks.

In most cases, oil-filled transformers arrive on site filled with oil and ready to install. If the oil must be installed on site, it is best to have a manufacturer’s repre-sentative perform the filling operation. This must be performed carefully with special equipment to avoid the possibility of moisture entering the transformer.

If transformers are moved to the site by a crane or cherry picker, spreader bars should be used to prevent damage to the lifting lugs. Care should be exercised to prevent damage to the cooling fins, which are the most delicate part.

Onshore transformers are often mounted on concrete pads. It is important that the pads are level. One common method of anchoring transformers to pads is to embed steel channel in concrete and either weld, or bolt the transformer base to the channel. The manufacturer’s mounting instructions should be followed. In earth-quake-prone areas, it is important to have flexibility in the anchoring system as discussed in Section 1072.

Transformers should be installed where there is adequate ventilation. They generate heat and should not be installed where heat can build and cause failure of electrical



components. Debris should not be placed on operating transformers since it can interfere with heat removal and possibly become a fire hazard.

Transformer enclosures should be grounded. If the secondary neutral is grounded, it is recommended that the conductor connected to the neutral be connected to the enclosure as well as ground (ground rod, metal deck, or grounding electrode system). Case grounding is important for personnel safety, and ground connections should be ensured.

Once transformers are mounted, primary and secondary connections must be termi-nated. On large transformers, the connecting cables can be quite heavy. The weight of cables should not be borne by the transformer terminals (e.g., porcelain insula-tors). This can be avoided by installing cable strain relief clamps or ties when primary and secondary junction boxes are used. It is recommended that sufficient cable lengths be left on each of the three conductors inside the junction box to facili-tate phase swapping. The primary and secondary terminal lugs should be torqued to the proper values when the cables are connected. When closing junction boxes, ensure that all bolts are installed to prevent the entrance of water.

Prior to energizing an oil transformer, a dielectric breakdown test should be performed on the transformer oil to ensure that it has the proper insulation quality. This can be performed with a field test instrument, but usually is best handled by a specialized laboratory. A final check should be made with a megohmmeter on all transformers prior to initial energization. See Section 1400 for further details on testing and commissioning transformers.

The correct voltage taps should be selected on any tap changers prior to initial ener-gization. Tap changers should be padlocked after the correct settings are verified.

1074 Installation of UPS SystemsUPS systems usually are provided with sheet metal cabinets similar to those used for switchgear and MCCs. They should be mounted on a level surface with suffi-cient space around the enclosure for adequate ventilation. It may be necessary to mount large UPS systems in air conditioned rooms to aid in heat dissipation.

Most UPS systems produce noise when they are energized. They should be installed where this noise will not be an annoyance.

When installing UPS systems, the cabinets should be checked carefully for packing notes, spare fuses, wiring harnesses which have been disconnected, breakers which have been turned on (or off), and instructions from the manufacturer.

Most UPS systems have internal ventilation fans which may run continuously or periodically (controlled by a thermostat). These fans draw air from the outside of the enclosure and pass it through the enclosure. It is important that filters be installed prior to energizing the equipment to prevent dust buildup on hot internal surfaces. Dissipation of heat in UPS systems is of prime importance for long life of solid state components. Careful attention should be paid to the function of all venti-lation systems associated with heat removal.



Sometimes the UPS system cannot be energized until the associated battery has been commissioned. It often is desirable to have a manufacturer’s representative on site for startup. The manufacturer’s operating manual should be read carefully before attempting to start up a UPS system.

Careful attention should be given to UPS system grounding requirements; the incoming line, the cabinet, the DC output, the battery bus, and the AC output. Each of these systems/components has its own grounding requirements which must be followed explicitly.

Wiring inside UPS systems often carries high currents, and specified torques should be ensured on all terminations. Even small control wire terminations should be checked for proper tightness prior to energization.

The cabinets should be kept closed after energization. Heat sinks are often at line voltage (not grounded). This is an important safety consideration when working inside energized cabinets.

When the UPS is initially energized, float and equalize voltage settings of the battery charger should be carefully set to the manufacturer’s specifications. This is important for proper battery operation.

After energization, UPS functions should be tested in accordance with the manufac-turer’s recommendations. Battery charging, static switching to the bypass source, synchronization detection between the UPS output and the bypass source, and indi-cations on the UPS panel should be checked for proper operation.

1075 Installation of UPS BatteriesBatteries may arrive either dry or filled with electrolyte. If they arrive dry, it is important to fill the batteries with electrolyte and place them on charge fairly quickly. If the batteries need to be stored for a month or more, consult the manufac-turer’s manual for maximum storage time and other conditions. The time of receipt, time in storage, and time of initial charge should be recorded.

Filling batteries with electrolyte (sulfuric acid for lead calcium batteries and potas-sium hydroxide for NiCd batteries) can be dangerous unless proper safety precau-tions are taken. Suitable goggles, gloves, boots and aprons should be worn; eyewash water and neutralization substances should be available during the filling operation. Consult a safety engineer for further information regarding detailed procedures which should be followed.

The battery rack should be assembled prior to filling the batteries. The batteries are then placed in the racks and the cells interconnected. The battery cables are then connected to the charger, and the batteries are placed on charge after they are filled.

Specification ELC-MS-4744, “Electrical System Checkout and Commissioning,” discusses battery commissioning in detail. It is important to set the float and equalize voltages to the manufacturer’s recommended values. These voltages prevent excessive gassing and maintain full charge.



See Section 1300 for additional information on batteries (and particularly the effects of temperature extremes). Battery rooms should be well ventilated to prevent buildup of explosive mixtures of hydrogen.

Logs should be maintained recording the specific gravity and cell voltage of the battery cells on a monthly basis. This will allow a comparison of the values to deter-mine if there are problems with any of the cells.

1080 ReferencesThe following references are readily available. The ones which are marked with an asterisk (*) are included in this manual or are available in other manuals.




1084 Appendices

* ELC-MS-1675 Installation of Electrical Facilities

* ELC-MS-4377 Standard Electrical Items (P-Items)

* GD-P87601 Standard Signs and Markers for Underground Cables

* GF-P99544 Standard Mountings for Outdoor Welding Outlets with Circuit Breakers

* GB-P99711 Standard Name Plate Bracket for XP Push Button Station

* GD-P99716 Standard Conduit Connections at Motors Overhead and Underground Conduit Construction for Installing in Class I, Division 1 and Division 2 Areas

* GD-P99734 Standard Grounding Details, Grounding Electrodes

* GF-P99735 Standard Grounding Details, Equipment Connections

* GF-P99935 Standard Steel Support Details for RG5 and Aluminum Conduit

ELC-EF-70 Conduit and Wire Schedule

* Appendix E Installation Practices for Cable Raceway Systems




* API RP 540 Recommended Practice for Electrical Installations in Petro-leum Processing Plants.

* API RP 14F Design and Installation of Electrical Systems for Offshore Production Platforms.

ANSI/IEEE 45 IEEE Recommended Practice for Electric Installations on Shipboard.

McPartland, J. F. National Electric Code Handbook (19th Edition). New York: McGraw Hill, 1987

Appleton Appleton NEC 1987 Code Review. Chicago, Illinois 1987

Chevron Corporation 1100-1 March 2001

1100 Wire and Cable

AbstractThis section provides guidance in the selection of wire and cable for power, lighting, control, instrumentation, and communication circuits. The construction details of the conductors, insulation, shielding, jackets, and armor for the various wire and cable types are described. Areas of concern in wire and cable system design are discussed and typical cables commonly specified are described and illus-trated. This section, along with Section 100, “System Design” provides guidance in the selection of wire and cable to provide reliable, safe, and economical service. The determination of cable ampacities and voltage drop is discussed in Section 100, “System Design.”

Contents Page


1111 Checklist

1112 Components of Wire and Cable

1113 Areas of Concern in Specifying Wire and Cable

1120 Construction of Wire and Cable 1100-21

1121 Conductors

1122 Insulation

1123 Outer Jackets

1124 Armors

1125 Shielding

1130 Special Wire and Cable 1100-32

1131 Instrument and Telemetering Cables

1132 Power and Control Tray Cable (Type TC)

1133 Power Limited Tray Cable (Type PLTC)

1134 High Temperature Cable, Flame Retardant Cable and Fire Cable

1135 Thermocouple Extension Cable

1136 Computer Cable

1100 Wire and Cable Electrical Manual

March 2001 1100-2 Chevron Corporation

1137 Fiber Optic Cable

1138 Shipboard Cables, Submarine Cables, and Submersible Pump Cables

1140 Typical Wire and Cable Specified 1100-39

1141 Medium Voltage Power Conductors

1142 Low Voltage Power and Lighting Conductors

1143 Low Voltage Control Cable

1144 Instrumentation, Control, and Alarm Cable

1145 Thermocouple Extension Cable

1146 Flame Retardant Cable

1147 High Temperature Cable

1148 Fire Hazard Area Cable

1150 Glossary 1100-41

1151 Definitions

1152 Abbreviations and Acronyms






Electrical Manual 1100 Wire and Cable


1110 IntroductionThis section of the Electrical Manual provides guidelines for the selection of wire and cable. The guidelines apply to installations in the United States. For foreign projects, the applicable foreign codes and standards must be consulted.

The issues discussed in this section include, wire and cable construction details, important selection considerations, special wire and cable, and wire and cable typi-cally specified by the Company.

When using this section, the following alternate approaches are suggested, depending upon the reader’s familiarity with the topic:

• If the reader has minimum experience selecting wire and cable, it is recom-mended that the entire section be reviewed, as well as Section 100, “System Design,” and Section 200, “System Studies and Protection”

• If a review is needed on the selection of wire and cable for a special applica-tion, review the section on “Special Wire and Cable” and the appropriate Company specification, as applicable

• If the reader is experienced in the selection of wire and cable, the checklist may be useful

• This section of the manual also provides a source for applicable standards and references

1111 ChecklistThe following checklist should be reviewed before completing the selection of wire and cable:

1. Is the cable construction suitable for the intended service?

2. Is the voltage rating adequate?

3. Is the number of conductors in accordance with design requirements?

4. Does the NEC (API RP 14F for offshore locations) allow the cable type to be used in the proposed installation method?

5. Is the insulation level suitable for the grounding system and ground fault clearing time?

6. Is the insulation type suitable for the intended service and consistent with Company recommendations?

7. Is the conductor adequately sized for mechanical strength, short-circuit condi-tions, load current (including any derating, particularly for ambient tempera-ture), voltage drop due to load current, and voltage drop due to inrush current?



1112 Components of Wire and Cable

ConductorThe conductor, usually copper, provides a low impedance path for the flow of elec-tric current. Some important considerations are size (current carrying capacity), flexibility (soft or annealed and stranding) and cost.

Solid Conductor. A solid conductor is a single conductor of solid circular construc-tion. Solid conductors come in a wide range of sizes. Due to the lack of flexibility solid conductors are more common in sizes below No. 0 AWG for aerial line appli-cations, and below No. 8 AWG in insulated conductor applications.

Stranded Conductor. A stranded conductor is composed of a multiple wires grouped together to form a single conductor. Stranded conductors are typically used where improved flexibility is desired for handling and installation.

Concentric Stranding. Stranded conductors are usually arranged in concentric layers around a central core. Figure 1100-1, detail A, shows different concentric stranded conductors with a progressively larger number of wires. Typically each concentric layer is spun in opposite directions, and may be referred to as having a reverse lay progression. Depending upon the application and need for conductor flexibility concentric stranded conductors are available in a variety of ASTM Classes: A, AA, B, C and D.

Bunched Stranding. A bunched conductor consists of a group of wires all twisted together in the same direction without regard to physical location, to form a single conductor. Like concentric stranded conductors, bunched conductors are available in a variety of ASTM Classes: I, J, K, L, M, O, P and Q.

Rope-Lay Stranding. A rope-lay stranded conductor is a concentric stranded conductor where the strands (sub-strands) that makeup the various layers are them-selves stranded. Each sub-strand may in-turn be configured in a concentric or bunched manner. Rope-lay stranded conductors are available in a variety of ASTM Classes: G, H, I, K, and M. Figure 1100-1, detail B, shows an assortment of rope-lay strand configurations.

Figures 1100-1 and 1100-2 illustrate various conductor configurations.

InsulationThe insulation provides isolation of the conductor from other conductors and from ground. The thickness of the insulation (usually specified in mils) is determined by the voltage rating of the cable. Important considerations for determining the type of insulation include, flexibility, chemical and flame resistance, system grounding method, type of installation, and cost. Commonly used insulating materials are EPR (ethylene propylene rubber), XLPE (cross-linked polyethylene), PVC (polyvinyl chloride) and PE (polyethylene).



Jacket; Individual, Overall; Outer ArmorJacket and armor serve as protection for the electrical insulation components and the conductors during installation and while in service. In particular, they may provide mechanical protection during installation, provide hard service protection, act as a barrier to oil, water and chemicals, and afford resistance to fire, sunlight, and the effects of weather. They may also provide resistance to ozone, fungus, bacteria, insects, and rodents. In addition, they may distribute electrical stresses and charges and increase electrical safety.

Materials such as polyvinylchloride (PVC), polyethylene, chlorosulfonated polyeth-ylene (CSP, “Hypalon”), polychloroprene (PCP, “Neoprene”) or nylon jackets may be applied over individual conductors or as an overall jacket on a multi-conductor cable.

Armor is often applied over the cable assembly core and, sometimes, over the overall jacket. The armor may consist of interlocked steel, corrugated metal sheath, braided wire or lead sheath. An overall extruded jacket (PVC or CSP) may be applied over the armor where corrosion and moisture are of concern.

Fig. 1100-1 Conductor Stranding Courtesy of Okonite Wire and Cable



Fig. 1100-2 Cable Conductors Courtesy of ABB Transmission and Distribution

(a) Standard concentric stranded (b) Compact round

(c) Non-compact sector (d) Compact sector

(e) Annular stranded (rope core) (f) Segmental

(g) Rope stranded (h) Hollow core



Figure 1100-3, 1100-4, 1100-5, 1100-6, and 1100-7 illustrate typical jacketed and armored cable.

Fig. 1100-3 Commonly Used Shielded and Nonshielded Power Cable Courtesy of Okonite Wire and Cable



Fig. 1100-4 Typical Instrument Cable Construction Courtesy of Houston Wire and Cable



Fig. 1100-5 Typical PLTC Cable Construction Courtesy of Houston Wire and Cable



Fig. 1100-6 Typical Telemetering Cable Construction Courtesy of Houston Wire and Cable



Fig. 1100-7 Typical Thermocouple Cable Construction Courtesy of Houston Wire and Cable



Shield (Power Cable)Shielding of electric power cable confines the potential field of the cable to the insu-lation of the conductor. It is accomplished by means of a nonmetallic conductor shield and a combination nonmetallic and metallic insulation shield.

A nonmetallic strand shield is normally used on all conductors which are rated over 2000 volts. The strand shield may be a semiconducting tape or an extruded semi-conducting material applied over the conductor (extruded is preferred). Its purposes are to eliminate air spaces between the conductor and the insulation and to provide a uniform circular surface, which eliminates voltage stress concentration at the indi-vidual conductor strands. Voids or stress concentrations at the conductor could result in corona and, in time, dielectric failure. The strand shield material must be compatible with both the conductor and the insulation material.

The insulation shield is made up of a nonmetallic extruded semiconducting layer and a nonmagnetic metallic layer. The insulation shield has the following functions:

• To confine the potential field within the cable• To obtain symmetrical radial distribution of voltage stress within the dielectric• To limit radio interference• To reduce shock hazards

The nonmetallic insulation shield is normally applied over the insulation on all conductors rated over 2000 volts that have a metallic shield. This semiconducting tape or extruded semiconducting layer (extruded is preferred), is designed to elimi-nate voltage stress concentrations between the insulation and the metallic shield, particularly at the edges of the metallic shielding tape.

Metallic shields take one of the following forms:

• Nonmagnetic tapes, usually copper• Concentric wires, usually copper• A combination of tapes and wires

Section 1125, “Shielding” discusses metallic shields for power cable in detail.

Shield (Control and Instrument Cable)When an installation is prone to electromagnetic interference (EMI), particularly radio frequency interference (RFI), and cross-talk from either internal or external sources, some form of cable shielding will be required.

EMI, caused by external magnetic fields radiated by power circuits, can be reduced by twisting the wires of each circuit. Installing these cables in steel conduit will provide additional shielding.

RFI, caused by external electric fields radiated by a voltage source, can be reduced by providing an overall shield (over all the conductors) if the shield is effectively grounded.



Cross-talk, caused by the superimposing of signals carried on one wire pair to another wire pair, can be reduced by providing individual shields on each wire pair and twisting each wire pair. The individual shields must be effectively grounded.

An overall shield (or an individual pair or triad shield) usually consists of Aluminum-Mylar tape (normally with a tin-plated copper drain wire) providing 100% effective shielding coverage. Figures 1100-4, 1100-5, 1100-6, and 1100-7 illustrate individual and overall shields.

1113 Areas of Concern in Specifying Wire and Cable

Conductor Material and Minimum SizeConductor material can be copper or aluminum; however, Company practice is to use copper conductors. Copper conductors are required by the Minerals Manage-ment Service (MMS) in offshore outer continental shelf (OCS) areas. Conductors should be stranded to provide flexibility (except AWG 12 and 14 conductors used for power and lighting; thermocouple extension wire; and communication wire). All insulated copper wire is to be annealed in accordance with ASTM B3 and have Class B stranding in accordance with ASTM B8. Bare copper wire is to be soft-drawn in accordance with ASTM B3, with Class B stranding in accordance with ASTM B8. Overhead bare copper wire may be medium-hard-drawn for added rigidity. Medium voltage cable conductors can be either concentric-stranded in accordance with ASTM B8 or compact-round-stranded in accordance with ASTM B496.

The Company recommended minimum conductor size for mechanical strength is as follows:

Power and lighting (600 V max) 12 AWG

Single conductor control (120 V) 14 AWG

Single pair or triad for instrument 16 AWG

Multi-conductor cable for instru-ment/control

18 AWG

5 kV - 1/C nonshielded power cable 8 AWG (Min. size available)

5 kV - 1/C shielded power cable 8 AWG (Min. size available)

15 kV - 1/C shielded power cable 2 AWG (Min. size available)

Ground loop cable 2/0 AWG

Cable from ground loop to MCC,switch-gear, transformers, tall stacks/vessels, substation fence and pipeway columns.

2/0 AWG

Cable from ground loop to large motors, cable trays and enclosures.

4 AWG



Minimum Conductor Size for Short-Circuit DutyUnder short-circuit conditions, the temperature of the conductor rises rapidly. Then, due to thermal characteristics of the insulation, sheath and surrounding materials, it cools slowly after the short-circuit condition is removed. Failure to check the conductor size for short-circuit heating could result in permanent damage to the cable insulation due to disintegration of insulation material. The disintegrating insu-lation may give off smoke and combustible vapors. These vapors may ignite if suffi-ciently heated. Also, the cable insulation or sheath may be expanded to produce voids, leading to subsequent failure. This is especially serious in 5 kV and higher voltage cables.

Minimum conductor sizes for various short-circuit currents and clearing times are shown in Table 79 of IEEE Std 141. The ICEA initial and final conductor tempera-tures (see ICEA P-32- 382) are shown for the various insulations. Table 76 of IEEE Std 141 gives conductor temperatures (maximum operating, maximum overload, and maximum short-circuit current) for various insulated cables. Vendor curves based on ICEA are also available for checking cable fault duty. Refer to Section 100, “System Design” for wire and cable sizing.

Maximum Emergency Overload TemperatureNormal loading limits of insulated wire and cable are based on many years of prac-tical experience and represent a rate of deterioration that results in the most econom-ical and useful life of cable systems. The rate of deterioration is expected to result in a useful life of 20 to 30 years. The life of cable insulation is approximately halved and the average rate of thermally-caused service failures approximately doubles for each 5°C to 15°C increase in average daily cable temperature. Additionally, it is generally not cost effective to use a cable above its rated ampacity for extended periods, owing to its increased resistance since losses increase in proportion to the square of the current. It is generally more economical, when losses are considered, to install larger cables.

As a practical guide, ICEA has established maximum emergency overload tempera-tures for various types of insulation. Operation at these emergency overload temper-atures should not exceed 100 hours per year, and such 100-hour overload periods should not exceed 5 during the life of the cable. Table 78 of IEEE Std 141 provides uprating factors for short-time overloads for various types of insulated cables. The uprating factor, when multiplied by the nominal current rating for the cable in a particular installation, will give the emergency or overload current rating for the particular insulation type. Note, however, that unless marked with higher tempera-ture limits, the terminals of devices rated 100 amperes or less are limited to oper-ating temperatures of 60°C. Likewise, unless otherwise marked, devices rated in excess of 100 amperes are limited to 75°C. Refer to Section 100, “System Design” for wire and cable sizing.

AmpacityConductor current-carrying capacity (ampacity) is defined as the current a conductor can safely carry continuously without damage to the conductor, insula-tion, and coverings.



Installation Conditions. Restricting the heat dissipation by installing the conduc-tors in conduit, cable sheaths, duct, trays or other raceways lessens the current-carrying capacity.

The ampacities of wire and cable for different installation conditions, under the jurisdiction of the NEC, are tabulated in NFPA-70, (NEC) Tables 310-16 through 310-19 for 0-2000 volt applications and Tables 310-69 through 310-84 for solid dielectric insulated conductors rated 2001 through 35,000 volts. These tables are derived from IEEE S-135, ICEA Power Cable Ampacities, which replaces the old ICEA P-46-426 (1962) two-volume edition, and can be used to determine ampaci-ties of cable installations not covered by the NEC. Other ICEA publications describing methods of calculation and tabulation of ampacities are ICEA S-19-81/NEMA WC3-1986, ICEA S-61-402/NEMA WC5-1986, ICEA S-65-375/NEMA WC4-1983, ICEA S-66-524/NEMA WC7-1986 and ICEA S-68-516/NEMA WC8-1986. Many cable vendors publish ampacities of various types of cable using methods of calculation generally conforming to ICEA P-54-440/NEMA WC51-1979. One example of a vendor’s detailed treatment of ampacity is in the Okonite Company Bulletin 781 for 5kV and 15kV cable in underground duct, direct burial, conduit, cable tray and air.

The ampacities of commercial shipboard cables for offshore platforms are given in IEEE Std 45. For guidance in sizing cables for offshore DC motor applications in drilling rig service, consult the International Association of Drilling Contractors (IADC) Interim Guidelines for Industrial System DC Cable for Mobile Offshore Drilling Units (IADC-DCCS-1).

Heat generated by the current through the conductor, retained by confining the conductors in a raceway, and introduced by above-normal ambient temperature, is the major factor affecting conductor current-carrying capacity. Other factors limiting the amount of current a conductor can safely handle are as follows:

• Conductor size. The larger the cross-sectional area, the greater the current-carrying capacity.

• Insulation. The maximum temperature rating of the insulation material should never be exceeded on a continuous basis.

• Ambient temperature. The higher the ambient temperature, the less current is required to reach the maximum temperature rating of the insulation.

• Number of conductors. Heat dissipation is lessened as the number of individu-ally insulated conductors (bundled together or installed in conduit) is increased.

• Underground installation. Heat transfer from the cable or conduit is much lower in concrete and soil than in air. Soil type, soil temperature and proximity of other conduits and cables must be considered.

Temperature Derating Factor. NEC Tables 310-16 through 310-19 give ampaci-ties based on ambient temperatures of 30°C and 40°C. At ambient temperatures above or below these, an ampacity correction (derating) factor must be used. These derating factors are shown at the bottom of each of the NEC tables already cited (except as indicated in NEC Article 318 for cable trays). The derating factor multi-



plied by the ampacity of a particular conductor at ambient results in a reduced conductor ampacity. If more than three conductors are installed in a raceway or cable, the ampacities must be reduced in accordance with Note 8 following Table 310-19 of the NEC. Medium voltage, solid dielectric cable ampacities given in NEC Tables 310-69 through 310-76 are based on ambient temperatures of 40°C. Tables 310-77 through 310-84 are based on ambient earth temperatures of 20°C for under-ground use. For temperatures other than these ambients, the derating of ampacities must be calculated in accordance with the formula indicated in Note 1 following Table 310-84 of the NEC and as defined in IEEE S-135 (ICEA P-46-426).

To determine the proper wire size for a particular load refer to Section 100 of this manual.

InsulationBasic insulating materials are either organic or inorganic. Most insulations are clas-sified as organic. Mineral-insulated (MI) cable employs the one generally available inorganic insulation (MgO).

The following insulations are in common use:

• Thermosetting compounds, solid dielectric• Thermoplastic compounds, solid dielectric

Less common insulations include:

• Paper-laminated tapes• Varnished cloth, laminated tapes• Mineral insulation, solid dielectric

Most of the basic materials listed in Figure 1100-8 are modified by compounding or mixing with other materials to produce desirable and necessary properties for manu-facturing, handling, and end use. The thermosetting (rubber-like) materials are mixed with curing agents, accelerators, fillers, and anti-oxidants in varying propor-tions; cross-linked polyethylene (XLPE) is included in this class. Generally, smaller amounts of materials (in the form of fillers, anti-oxidants, stabilizers, plasticizers, and pigments) are added to the thermoplastics.

Fig. 1100-8 Properties of Commonly Used Insulating Materials

Common Name Chemical Composition Electrical Physical

Thermosetting

Crosslinked polyethyleneEPR

PolyethyleneEthylene propylene rubber(copolymer and terpolymer)

ExcellentExcellent

Excellent Excellent

ButylSBROil base

Isobutylene isopreneStyrene butadiene rubberComplex rubber-like compound

Excellent Excellent Excellent

Good Good Good



Insulation Comparison. Aging factors (namely heat, moisture, and ozone) are among the most destructive to organic-based insulations. The following compari-sons can be made to gage the properties of different insulations:

1. Relative Heat Resistance. Figure 1100-9 indicates the effect of temperature on the hardness of insulating materials. Of particular interest is the rapid change in the hardness of polyethylene and cross-linked polyethylene insulations above 100°C.

2. Heat Aging. Elongation of an insulation (or jacket) when subjected to aging in a circulating air oven is an acceptable measure of heat resistance. The air oven test at 121°C called for in some specifications is severe, but provides a rela-tively quick method of grading materials for possible use at high conductor temperatures or in hot-spot areas. Oven aging at 150°C is many times more severe than the 121°C test and is used to compare materials with superior heat resistance. Temperature ratings of common insulations are shown in Table 76 of IEEE Std 141 and in tables of NEC Article 310-13.

SiliconeTFE(1)

Natural rubberNeopreneClass CP rubber(2)

Methyl chlorosilaneTetrafluoroethyleneIsopreneChloropreneChlorosulfonated polyethylene

GoodExcellentExcellentFairGood

GoodGoodGoodGoodGood

Thermoplastic

PolyethylenePolyvinyl chlorideNylon

PolyethylenePolyvinyl chloridePolyamide

ExcellentGoodFair

GoodGoodExcellent

(1) For example, Teflon or Halon(2) For example, Hypalon

Fig. 1100-8 Properties of Commonly Used Insulating Materials

Common Name Chemical Composition Electrical Physical

Fig. 1100-9 Typical Values for Hardness vs. Temperature



3. Ozone and Corona Resistance. Exposure to accelerated conditions, such as high concentrations of ozone, aids in measuring a material’s ultimate ozone resistance. In one such test, standardized by the Insulated Cable Engineers Association, butyl is exposed to 0.03% ozone for 3 hours at room temperature. Other tests for ozone include, air oven tests followed by exposure to ozone and exposure to ozone at higher temperatures. Insulations exhibiting superior ozone resistance under accelerated conditions are silicone, polyethylene, XLPE, EPR, and PVC. These materials are essentially inert in the presence of ozone (but not of corona discharge).

Corona discharge produces destructive thermal effects and forms ozone and other ionized gases. Although corona resistance is a property associated with cables over 600 volts, in a properly designed and manufactured cable, damaging corona is expected to be absent at operating voltage. Ethylene propy-lene rubber (EPR) exhibits less susceptibility to such discharge activity than PE and XLPE.

4. Moisture Resistance. Insulations such as XLPE, high density polyethylene, and EPR exhibit excellent resistance to moisture (as measured by standard industry tests of ICEA). The electrical stability of these insulations in water (as measured by capacitance and power factor) is very good. However, if the degradation phenomenon known as treeing is present, it will be accelerated by contact with water. This phenomenon occurs in solid dielectric PE and is more prevalent in PE and XLPE than in EPR.

5. Insulations in General Use. Insulations in general use for 2 kV and above, are shown in Table 76 of IEEE Std 141. Solid dielectrics of both plastic and ther-mosetting types are in common use. Laminated constructions such as paper and varnished cambric cables are declining in popularity because of higher installed cost and the difficulty in making reliable terminations. NEC Table 310-13 lists various types of insulated wire according to their type, maximum operating temperature, application and insulation thickness.

Cable DesignThe selection of power cable for specific applications is based on the following properties:

• Electrical. Conductor size, type and thickness of insulation, resistance, specific inductive capacitance (dielectric constant), and power factor

• Thermal. Compatibility with ambient and overload temperatures, thermal expansion, and thermal resistance

• Mechanical. Toughness and flexibility of jacketing or armoring; resistance to impact, crushing, abrasion, and moisture

• Chemical. Stability of materials when exposed to oils, flame, ozone, sunlight, acids, and alkalies

To conform with the NEC, state and local codes which are under the jurisdiction of a local electrical inspection authority, cables usually require evidence of approval



for the intended service by a nationally recognized testing laboratory such as Under-writers Laboratories Inc. (UL). Some cable types are discussed in the following paragraphs.

Low Voltage Cables. Low voltage power cables are rated at 600 volts, and are used on system voltages of 120, 208, 240, 277, 480, and 600 volts.

Low voltage cable generally consists of conductors with a single extrusion of insu-lation of a specified thickness. However, in some applications, where additional physical protection is required, a jacket may be included over the insulation.

The selection of 600 volt power cable is usually based less on electrical require-ments than on physical requirements such as resistance to external forces (e.g., crush, impact, and abrasion). Good electrical properties are required for wet loca-tions.

600 volt XLPE compounds are usually filled (carbon black or mineral) to further enhance the toughness of conventional polyethylene. The combination of cross-linking the polyethylene molecules through vulcanization plus fillers produces supe-rior mechanical properties. Vulcanization eliminates polyethylene’s main weakness: a relatively low 105°C melting point.

For mechanical protection, rubberlike insulations such as EPR are often provided with outer jackets, usually of polyvinyl chloride, neoprene, or CSP rubber (such as Hypalon). However, the newer EPR insulations have improved physical properties and do not require an outer jacket for mechanical protection. A list of the more commonly used 600 volt cables follows.

• Polyvinyl chloride-insulated, without jacket: Type THW, for 75°C maximum operating temperature in wet or dry locations and Type THHW for 75°C in wet locations or 90°C in dry locations

• Polyvinyl chloride-insulated, nylon-jacketed: Type THWN, for 75°C maximum operating temperature in wet or dry locations and Type THHN for 90°C in dry and damp locations only. (This cable is usually dual-rated THWN/THHN)

• XLPE-insulated, without jacket: Type XHHW, for 75°C maximum operating temperature in wet locations and 90°C maximum in dry and damp locations and XHHW-2 for 90°C in dry and wet locations

• EPR-insulated, with or without jacket: Type RHW for 75°C maximum oper-ating temperature in wet or dry locations and Type RHH for 90°C maximum in dry and damp locations

Medium Voltage Cables. Medium voltage, Type MV power cables have solid extruded dielectric insulation and are rated from 2001 volts to 35,000 volts. Single conductors and multiple conductor cables are available with nominal voltage ratings of 5, 8, 15, 25, and 35 kV.

Medium voltage cables generally consist of the conductor, extruded semicon-ducting strand shield, extruded insulation, extruded semiconducting insulation shield, metallic shield and an overall jacket.



EPR and XLPE are the most commonly used insulating compounds for Type MV cables; however, polyethylene and butyl rubber are also used. The maximum oper-ating temperatures are 90°C for EPR and XLPE, 85°C for butyl rubber, and 75°C for polyethylene.

Type MV cables may be installed in raceways in wet or dry locations. They must be specifically approved for cable tray installation, direct burial, exposure to sunlight, and messenger-supported cable.

Multi-conductor MV cables that also comply with the requirements for metal-clad (Type MC) cables are labeled Type MV and Type MC and may be installed in conduit, in cable trays or by direct burial.

Voltage DropA working knowledge of voltage drop calculations is required not only to meet NEC requirements, but also to ensure that the voltage applied to utilization equipment is maintained within proper limits. Due to the phasor relationships between voltage and current, as well as resistance and reactance, voltage drop calculations require a working knowledge of trigonometry to make exact computations. Fortunately, most voltage drop calculations are based on assumed limiting conditions, and approxi-mate formulas are adequate. Refer to Section 100, “System Design”, for details of voltage drop calculations.

Wire and Cable CostsEconomics are an important factor in the selection of wire and cable. Figure 1100-10 illustrates the relative cost comparison for various types of cable. Actual prices will vary according to market conditions.

Wire and Cable in Classified AreasFor selection of wire and cable and installation methods to be used in hazardous (classified) areas, refer to Section 300, “Hazardous (Classified) Areas.”

Wire and Cable GroundingFor proper grounding of cable shields and metallic sheaths/armor refer to Section 900, “Grounding Systems.”

InstallationFor a discussion on wire and cable installation refer to Section 1000, “Installation of Electrical Facilities.” For additional guidance on installation, cable connectors, terminations, splicing devices, and techniques, refer to IEEE Std 141, Chapter 11. See API RP 14F, Section 4, for offshore installations.



1120 Construction of Wire and Cable

1121 ConductorsInsulated conductors for electrical power transmission are composed of either copper or aluminum. Copper is used in almost all wire and cable because of its high conductivity. Copper has the highest electrical conductivity of all commercial metals except silver, therefore, smaller conductor diameters are possible. It is manu-factured in a wide range of tensile strengths, affording adequate strength and the necessary flexibility. Copper is required for all conductors installed in offshore OCS areas.

Aluminum has a lower conductivity than copper and requires a larger conductor. It is, however, lighter in weight, resulting in lower weight loading for given ampacity.

Some prime considerations in the selection of conductors are flexibility, size, shape, and cost.

CoatingsIf a copper conductor is to be rubber-insulated, a protective coating of pure tin, or an alloy of tin and lead, is applied over the copper to prevent the sulphur in the rubber from attacking the copper. Otherwise, a separator of paper or cotton serving must be used. Untinned or bare copper conductors are generally used with such insulations as varnished cambric, polyethylene, polyvinyl chloride, and asbestos.

FlexibilityFlexibility is achieved by annealing and stranding conductors. Annealing is a process in which copper wire is exposed in an inert atmosphere, or vacuum, to temperatures up to 600°F. Annealing increases the ultimate elongation of the wire by about 2500% and its electrical conductivity by about 3%. Copper wires and cables are usually manufactured in one of three tempers: hard-drawn, medium-hard, or soft-annealed. Hard-drawn wire has the highest tensile strength and the lowest elongation; soft-annealed provides the greatest elongation and the lowest tensile strength; medium-hard wire is the intermediate between these two. There is little difference in the conductivity of wires of different tensile strengths.

StrandingStranding provides added flexibility. Insulated conductors sized 10 AWG and larger are stranded (unless otherwise specified); sizes 12 AWG and smaller (with the exception of flexible cords and fixture wire) are usually solid. Instrument wire, except for thermocouple extension wire, is usually stranded.

Several varieties of stranding are achieved by varying the number, size, and arrange-ment of the individual wires comprising the conductor, thus permitting the desired



Fig. 1100-10 Relative Costs of Cable



degree of flexibility. The various forms of conductor construction in order of increasing flexibility are as follows:

1. Solid

2. Concentric-stranded

3. Bunched-stranded

4. Rope-lay-stranded

Figure 1100-11 provides stranding and application information for ASTM conduc-tors.

ASTM Classes of StrandingOnly ASTM solid and class B stranding are normally used in Company practice. ASTM class letters set guidelines for cable flexibility.

Conductor ConstructionDifferent types of conductor construction are illustrated in Figure 1100-2; however, of the four constructions shown, only annular strand is normally used in Company practice.

Fig. 1100-11 Application of ASTM Stranding Classes

Construction Class Use

Concentric Lay AA Bare Overhead

A Flexible bare: Slow burning and/or weather resistant (WP) cables

B Insulated conductors (Types RHW, TW, RR, VC, etc.)

C Special (Some RR, Machine Tool Wire)

D Very Special—high flexibility

Rope-Lay with Concentric Members

G Portable cables

H Portable cables on take-up reels Types (W & G)

Rope-Lay with Bunched Members

I Apparatus Cable and Motor Leads

K Portable Cables (SJO, SO)

M Welding Cable

Bunch Stranded I,J,K For sizes 7 AWG - 20 AWG

L,M,O For sizes 9 AWG - 20 AWG

P.Q For sizes 16 AWG - 20 AWG



Wire GagesThe American Wire Gage (AWG) is used almost exclusively in the United States for electric wire sizes 4/0 and smaller. The AWG is retrogressive; that is, a larger number denotes a smaller wire. For sizes larger than 4/0, the wires are designated by MCM (thousand circular mils).

The following approximations can be made using American Wire Gage measure-ments:

• An increase of 3 gage numbers (e.g., from No. 10 to 7) doubles the cross-sectional area and weight, and, consequently, halves the DC resistance

• An increase of 6 gage numbers (e.g., from No. 10 to 4) doubles the diameter

• An increase of 10 gage numbers (e.g., from No. 10 to 1/0) increases the area and weight by 10 and reduces the DC resistance by a factor of 10

• AWG 10 wire has a diameter of approximately 0.10 inch, a cross-sectional area of approximately 10,000 CM, and (for standard annealed copper at 20°C) a resistance of approximately 1.0 ohm per 1000 feet

• The weight of AWG 2 copper wire is approximately 200 pounds per 1000 feet

• Figure 1100-12 gives the dimensions and weights for AWG wire sizes. The weights and dimensions are given for solid conductor copper wire. Weights are based on a copper density of 8.89 grams per cubic centimeter. Solid wire weights should be increased by two percent to obtain the weights for stranded wire

1122 InsulationNo single type of insulation has been developed to meet all requirements. Instead many types are used, with each best suited to the service for which it is designed.

The type of insulation used for electrical wire must be carefully considered in selecting cable for a specific application. Selection depends upon voltage rating, load, operating conditions, and price.

Voltage limitation is the prime consideration in selecting the appropriate insulation. All insulations are designed and constructed to withstand a stated voltage without damage under given conditions. No wire or cable will operate for its expected life at voltages higher than those for which it was designed. Using a greater insulation thickness extends the life but cannot satisfy all requirements of a higher voltage stress; an insulating medium with the necessary characteristics inherent in its general properties must be used.

Another important consideration is the insulating material’s ability to withstand destructive natural and chemical elements and still provide the electrical and mechanical protection for which it is designed.

Space limitation is sometimes an additional factor influencing the choice of insula-tion.



The various types of insulation presently used may be divided into three major classes: rubber compounds, plastic compounds, and varnished cambric. Figures 1100-8, 1100-9, 1100-13, and 1100-14 provide information on the properties and uses of various insulating materials.

Rubber and plastic materials have good electrical properties, relatively low weight, and good mechanical properties. Rubber insulations are more elastic than plastic insulations. However, plastic insulations are mechanically stronger than rubber insu-lations at normal temperatures. Most rubber materials are cross-linked. Except for polyethylene, plastic materials are usually not cross-linked.

Fig. 1100-12 Comparison of Wire Gages



Cross-linked rubber and plastic materials do not melt when heated and are called thermosetting materials. Rubber and plastic materials that are not cross-linked are called thermoplastic materials. When thermoplastic materials are heated, they soften and eventually melt. At low temperatures thermoplastic materials stiffen and, if the temperature is sufficiently low, become brittle. Therefore, mechanical properties of thermoplastic materials are more dependent on temperature than are thermosetting materials.

NEC-1987 Table 310-13, lists various types of insulations according to their trade name, type letter, maximum operating temperature, application, insulation type, conductor size range, insulation thickness, and outer covering. Brief descriptions of several types of insulation follow.

Rubber Compounds

Ethylene Propylene Rubber (EPR). EPR, referred to by the NEC as type RHH/RHW, is a synthetic rubber material. The compounds are rated for 90°C dry locations (RHH) and 75°C wet and dry locations (RHW). It is flexible and will

Fig. 1100-13 Size Range and Corresponding Voltages

ICEA

Size Voltage

Rubber 18 & over14 & over8 & over6 & over2 & over1 & over

0-600601-20002001-50005001-80008001-15,00015,001-28,000

Cross-linked Polyethylene, (XPLE) 14-10008-10006-10002-10001-10000-1000

0-20002001-50005001-80008001-15,00015,001-28,00028,001-35,000

Ethylene Propylene Rubber, (EPR) 4-10008-10006-10002-10001-10000-1000

0-20002001-50005001-80008001-15,00015,001-28,00028,001-35,000

Polyvinyl Chloride (PVC) 18 & over 0-600

Polyethylene (PE) 14-10008-10006-10002-10001-10000-1000

0-20002001-50005001-80008001-15,00015,000-28,00028,001-35,000



Fig. 1100-14 Typical Values of Properties of Insulation Materials



retain its flexibility at low temperatures. EPR differs from many other rubber mate-rials because it is resistant to ozone. EPR is also resistant to most acids, bases, and other chemicals, but not to mineral oils. Its weather resistance is also good. EPR has excellent electrical properties and can be used for 600 volt, 5 kV and 15 kV power wiring systems.

Silicone Rubber. Silicone rubber is a synthetic rubber compound with excellent temperature resistance properties. It is designed for long life and continuous opera-tion at temperatures ranging from -60°C to 150°C without losing its high flexibility. It is also ozone and corona resistant, minimizes moisture absorption, and remains stable in wet or moist locations. It has a high dielectric strength. Although it is flame-retardant, it will burn. However, when it burns it forms a nonconducting ash which, when held in place by an outer braid, continues to serve as an insulator. This type of insulation is used for power (600 volt maximum), control, and instrument circuits in critical fire hazard areas.

Plastic Compounds

Polyvinyl chloride (PVC). PVC thermoplastic is available in several compounds to meet specific temperature conditions of THW, THWN, THHW, and THHN applica-tions. The compounds are rated for 75°C for wet and dry locations (THW and THWN), 90°C for dry locations (THHN) and 75°C for wet and 90°C for dry loca-tions (THHW). PVC insulation is resistant to oils, acids, sunlight, ozone, flame, and moisture and possesses excellent electrical properties. It is used on power, lighting, and control wiring (600 volt maximum), but it is not suitable for DC applications above 40 volts in wet locations.

API RP 14F recommends EPR, XLPE or thermosetting insulation for DC services above 40 volts DC in wet locations to reduce the possibility of electro-osmosis or electrical endosmosis, which deteriorate the insulation.

Polyethylene (PE). Polyethylene is a heat-and light-stabilized thermoplastic. It is recommended up to a maximum operating temperature of 75°C. It has low dielec-tric loss characteristics and is highly resistant to moisture, ozone, most chemicals, oil, and flame. PE insulation is thinner and can eliminate the need for an outer covering, thus saving space. PE insulation is used on instrument and control cables (300 volt or 600 volt maximum). It is no longer available at the 5 kV and 15 kV levels, having been replaced by EPR and XLPE.

Superior dielectric characteristics make low density (high molecular weight) poly-ethylene a much better insulating material than high density polyethylene. However, high density polyethylene makes an excellent, tough jacket material.

Cross-linked Polyethylene (XLPE-NEC type XHHW). XLPE is made by cross-linking polyethylene. This insulation is available for 600 volt, 5 kV or 15 kV power systems but its use for new 5 kV or 15 kV systems is not recommended because of numerous incidents of premature failure. Cross-linked polyethylene compounds are rated 75°C for wet and 90°C for dry locations (XHHW) and 90°C for wet or dry locations (XHHW-2). XLPE is a relatively stiff material at normal temperatures, but



it will not stiffen further at temperatures as low as 0°C. XLPE is resistant to acids, bases, and several chemicals but should not be used in contact with mineral oils.

Varnished cambric. Varnished cambric (NEC Type VC) VC insulation consists of a cotton or linen tape treated with varnish or resin and linseed oil and applied heli-cally around the conductors, with a suitable compound applied between the layers. It is highly resistant to heat, operating at temperatures up to 85°C. It is moisture, oil, and grease resistant, has high dielectric strength and low loss, and is highly flexible. Maximum operating voltage is 28,000 volts for grounded neutral systems. Where space is limited, the thinner walls of varnished cambric insulation afford a cable of smaller outer diameter. This type of insulation wire is no longer used by the Company. It has been replaced by EPR- or XLPE-insulated wire.

1123 Outer JacketsOuter jackets used on electrical cables and wires may be divided into two catego-ries:

• Rubber Jackets• Plastic Jackets

Rubber Jackets

Neoprene. Neoprene jackets are used on power cables in mining applications, on portable cable, and on welding cable.

Polychloroprene (PCP). Polychloroprene sheaths are tough and resistant to abra-sion, oil, fire, ozone, weather, rot fungus, bacteria, and corona. The normal useful operating temperature range is 75°C to -40°C, but heat resistant grades with ratings up to 90°C are available.

Chlorosulfonated Polyethylene (CSP). CSP (trade name, Hypalon) is a synthetic rubber material with properties similar to chloroprene rubber. This type of jacket is used on 600 volt, 5 kV, and 15 kV power cables and instrument cables where addi-tional abrasion resistance, fire retardation, or chemical resistance is desired.

Plastic JacketsPolyvinyl chloride (PVC). Polyvinyl chloride thermoplastic is a synthetic resin which provides resistance to oils, acids, alkalies, sunlight, heat, weather, and abra-sion. It is relatively low in cost. The temperature range is approximately -50°C to 105°C, depending on the particular compound chosen. It is widely used for jackets of power, control, signal, aerial, street lighting, and direct burial cables. It is also widely used in shipboard cables, which demand a highly resistant and protective jacket. PVC compounds should be black for outdoor use, since black resists deterio-ration by ultraviolet rays. This improves weather resistance. PVC is not recom-mended for jackets on cables to be used in underwater service.

Nylon. Nylon is used as an extruded covering to protect individual insulations. It is applied in thin films to improve the primary insulation’s resistance to abrasion, oil, gasoline and solvent. It is springy, but a thick application causes loss of flexibility.



Its temperature range is -20°C to 105°C. Nylon coverings are used primarily for cables in gasoline stations, shipboard control cables, and on THHN and THWN wire.

For properties of various types of outer jacket materials refer to Figure 1100-15.

1124 Armors

Corrugated Metal Sheath. Longitudinally welded and continuously extruded corrugated sheaths (usually aluminum) offer mechanical protection superior to and at a lower weight than interlocked armor. Aluminum or copper sheaths may be used as the equipment grounding conductor for many cables, either alone or in parallel with a grounding conductor within the cable; proper cable connectors must be used and the sheath must be capable of carrying sufficient current as specified by the NEC and to provide accurate relaying without damaging the cable .

Corrugated sheaths are recommended for pliability and increased radial strength. This sheath offers maximum protection from moisture and liquid or gaseous contaminants. An overall extruded nonmetallic jacket must be used over the metal sheath for direct burial, embedment in concrete, or in areas with environments that are corrosive to the metal sheath.

Lead Sheath. A lead sheath is used in cables for underground installation to protect a varnished cambric or rubber insulation from moisture. An extruded jacket may be applied over the lead for corrosive protection or protection from gouging and soil electrolysis. Because of the decline in use of varnished cambric insulation, lead sheaths are rarely used today.

Fig. 1100-15 Properties of Cable Jacket Materials

MaterialAbrasionResistance Flexibility

Low Temperature

Heat Resistance

Fire Resistance

Neoprene Good Good Good Good Good

Class CPrubber(1)

Good Good Fair Excellent Good

Polyethylene

low densityhigh densitycross linked

FairExcellentGood

PoorPoorPoor

PoorPoorPoor

FairGoodExcellent

PoorPoorPoor

Polyvinylchloride

Fair Good Fair Good Fair

Polyurethane Excellent Good Good Good Poor

Nylon Excellent Fair Good Good Fair

Note Chemical resistance and barrier properties depend on the particular chemicals involved. The question should be referred to the cable manufacturer.

(1) For example, Hypalon



Braided Wire Armor. Braided, basket weave metal armor is constructed of fine metal wires of galvanized steel, aluminum, or bronze. This type of armor is used extensively on shipboard cables to provide lightweight mechanical protection in accordance with IEEE Std 45.

Interlocked Armor. Bronze, galvanized steel, or aluminum rounded and inter-locked tapes protect cables from damage (during and after installation) and are applied directly over the outer jacket. Interlocked armor provides mechanical protection against compression and impact. A jacket can be added over the armor for moisture and corrosion resistance. Interlocked armor is not recommended for Company installations. It is being replaced by the corrugated metal sheath.

1125 Shielding

Power Cable ShieldingRefer to Figure 1100-3 for a typical shielded MV cable. A shielded electric power cable uses conducting or semiconducting layers, closely fitted or bonded to the inner and outer surfaces of the insulation, to confine the electric field of the cable to the insulation surrounding the conductor. In other words, the outer shield confines the electric field to the space between the conductor and the shield. The inner (strand shield) stress relief layer is at or near the conductor potential. The outer (insulation) shield is designed to carry the charging currents. The conductivity of the shield is determined by its cross-sectional area and its resistivity (in conjunction with the semiconducting layer). The metallic shield must be effectively grounded as described in Section 900, “Grounding Systems.”

By their close bonding to the insulation surface, the stress control layers at the inner and outer insulation surfaces present a smooth surface to reduce the stress concen-trations and minimize void formation. Ionization of the air in such voids can progressively damage certain insulating materials, eventually to the point of failure.

The purposes of an insulation shield are as follows:

• Reduces shock hazard (when properly grounded)• Confines the electric field within the cable• Equalizes voltage stress within the insulation, minimizing surface discharges• Protects cable from induced potentials• Limits electromagnetic interference (EMI/RFI)

In a shielded cable, the equipotential surfaces are concentric cylinders between the conductor and the shield. The voltage distribution follows a simple logarithmic vari-ation, and the electrostatic field is confined entirely within the insulation. The lines of force and stress are uniform and radial and cross the equipotential surfaces at right angles, eliminating any tangential or longitudinal stresses within the insulation or on its surface.

The equipotential surfaces for the unshielded system are cylindrical, but not concen-tric with the conductor, and cross the cable surface at many different potentials. For unshielded cable operating on 4160-volt systems, the tangential creepage stress to



ground at points along the cable may be several times that recommended for creepage distance at terminations in dry locations. Surface tracking, burning, and destructive discharges to ground could occur; however, properly designed nonshielded cables (as described in the NEC) limit the surface energies.

Control and Instrument Cable ShieldingControl and instrument cable shielding usually consists of a layer of conducting material completely covering the core of cable conductors. This conducting mate-rial can be nonmetallic or metallic. If nonmetallic, it should be supplemented by a metallic conductor of sufficient conductivity to provide effective shielding.

A cable shield over an individual pair, or an overall shield, has several functions, including the following:

• To reduce shock hazard

• To protect the cable from extraneous, induced potential

• To limit electromagnetic interference (EMI), particularly radio interference (RFI)

• To confine the electric field generated by the conductors

For control and instrument cable shielding, induced potentials and EMI (particu-larly RFI) are of particular interest because cables are frequently operated in areas of high disturbance by high voltage power conductors. If the surges, caused by changes in the operating state of these high voltage conductors, are permitted to induce a voltage on the control cable conductors, control errors (and even severe damage to apparatus supplied by the cable) may result.

The most common shielding method for control and instrument cables consists of an Aluminum-Mylar tape applied helically over the cable core. This type of shield provides 100% coverage and can be applied in the same manner as a helical tape on a power cable. A drain wire in intimate contact with the shield throughout the length of the cable (used for grounding the shield) should be provided.

The individual pair shields and the overall shield of each instrument cable must be grounded in accordance with Company Specification ICM-MS-3651 and Standard Drawing GF-J-1118.

1130 Special Wire and CableIt is recommended that all cables be listed by a nationally recognized testing labora-tory (NRTL) such as Underwriters’ Laboratories (UL).

1131 Instrument and Telemetering Cables

Instrument CableAlthough similar to other cables used to interconnect electronic devices, instrumen-tation cables are specifically designed for ease of installation, for transmitting



signals and energy with minimal interference, for maximum durability, and to comply with recognized industry standards.

Electrical interference is minimized by twisting conductors in a tight lay configura-tion to counter the effects of electromagnetic interference (EMI). In multi-pair cables, a staggered lay is employed to reduce cross talk. Where critical signal inputs could be affected by EMI, particularly radio frequencyinterference (RFI), an Aluminum-Mylar tape shield over each pair is the recommended remedy. See Section 1125 for further details.

Instrument cables are designed to minimize mechanical failures. Jacketing, insula-tion, conductors, and shielding are all selected to resist damage from water absorp-tion, chemical and oil contamination, bending, pulling, crushing, cutting, abrasion, and temperature extremes.

Multi-conductor instrumentation cables are manufactured in a wide range of sizes, shielding techniques, and insulation material to meet the technical requirements of different types of equipment and installations. Cables used for communications, instrumentation, control, and data transmission are all included in this category. Most of these cables are designed to protect a desired signal—reducing hum, noise, and cross talk. Effective shielding designs and insulating techniques maintain signal integrity over a wide diversity of conditions and environment. Figure 1100-4 shows typical instrument cable construction. For shielding techniques, refer to Section 1125.

Instrument cable is available in single pair, single triad, multi-pair or multi-triad cable construction and must comply with NEC Article 725. Reference Specifica-tion, ELC-MS-3551. Instrument cable can be installed in cable tray, in metallic or nonmetallic conduit (above or belowground), or as aerial cable supported by a messenger wire. Cable used for fire protective signaling systems must comply with NEC Article 760. For instrument cables installed in cable tray, refer to Section 1133, “Power Limited Tray Cable (Type PLTC).”

Telemetering CableThis cable is used in telemetry, remote control, pilot relay operations, and communi-cation circuits where superior electrical characteristics (shielding from electromag-netic and electrostatic interference) are required. This type of cable is particularly suited for applications where the cable will normally transmit low level DC or communication signals, but where there is also a need for emergency transmission of 110 volt AC signals as well. The cables are shielded to protect against electrical interference from external sources. These cables are available with either PVC or PE outer jackets. The PVC-jacketed cables are more flexible and are flame-retar-dant; however, the PE-jacketed cables have superior resistance to cracking when flexed at low temperatures. Figure 1100-6 shows various types of telemetering cable construction.



1132 Power and Control Tray Cable (Type TC)Power and control tray cable (Type TC) is a factory assembly of two or more insu-lated conductors (with or without associated bare or covered grounding conductors) under a nonmetallic sheath, approved for installation in cable trays and raceways or where supported by a messenger wire. The insulated conductors of Type TC tray cable are available in sizes 18 AWG through 1000 MCM copper and sizes 12 AWG through 1000 MCM aluminum. The outer sheath is a nonmetallic material that is flame-retardant and resistant to oil, sunlight (if specified) and moisture. A metallic sheath is not permitted either under or over the nonmetallic sheath. When installed in wet locations, Type TC cable must be resistant to moisture and corrosive agents.

Use of Type TC tray cable is permitted (1) for power, lighting, control, signal, and communication circuits; (2) in cable trays, in raceways, or supported by a messenger wire; (3) in cable trays in hazardous (classified) locations under specific conditions outlined in Articles 318, 501, and 502 of the NEC. Type TC tray cable must not be installed (1) where exposed to physical damage; (2) as open cable on brackets or cleats; (3) where directly exposed to rays of the sun, unless identified as sunlight-resistant; or (4) by direct burial, unless identified for such use.

The cables are marked TYPE TC. The allowable ampacity of the conductors is defined in NEC Articles 400-5 and 318-11.

1133 Power Limited Tray Cable (Type PLTC)Type PLTC nonmetallic-sheathed, power-limited tray cable is a factory assembly of two or more insulated conductors under a nonmetallic jacket. The insulated conduc-tors are available in sizes 22 AWG through 16 AWG. The conductor material is copper (solid or stranded). Insulation on the conductors is suitable for 300 volts. The cable core is either (1) two or more parallel conductors, (2) one or more group assemblies of twisted or parallel conductors, or (3) a combination thereof. A metallic shield or a metallized foil shield with drain wire(s) is permitted either over the cable core, over groups of conductors, or both. The outer jacket material is nonmetallic and flame-retardant, and resistant to oil, sunlight, and moisture.

Type PLTC cable is designed for use in Class 2 or 3 circuits (in accordance with NEC Article 725) as instrumentation, process control and computer cable transmit-ting low level signals. The cable is marked TYPE PLTC and can be installed in cable trays or raceways, supported by messenger wires, or directly buried (if the cable is listed for this use). The cable can also be installed in cable trays in hazardous (classified) locations under specific conditions specified by Articles 318, 501, and 502 of the NEC.

Figure 1100-5 illustrates the construction details of typical power limited tray cables.



1134 High Temperature Cable, Flame Retardant Cable and Fire Cable

High Temperature CableAsbestos insulations (NEC Type A or AA) are used for high temperature applica-tions, particularly in dry locations, up to 200°C.

Silicon rubber has good chemical-, moisture-, and oil-resistant properties. It is best known for its resistance to heat and can be used for conductor temperatures as high as 125°C.

Teflon-insulated (FEP) wire can be used for conductor temperatures up to 200°C. Teflon-insulated (as well as silicone rubber insulated) wire is recommended where high heat and contact with oil, water, or chemicals are expected. Both FEP and sili-cone-rubber-insulated wires are more expensive than ordinary insulations.

Pyrometer wiring is available with many types of insulation. For general processing plant use, PVC insulation with a PVC jacket is recommended for applications below 105°F. For higher temperatures, silicone, mica, Teflon, fiberglass, or combinations thereof are recommended.

Flame Retardant CableInsulated conductors and cables that will be installed in a cable tray and all cables used offshore must pass a flammability test. The flame test is used to ensure that in the event of a fire in or around the cable, the conductors or cables will not transmit the fire to another area. All single conductors and multi-conductor cables must pass the UL vertical tray flame test, which is identical to IEEE 383, to be approved for cable tray use.

Insulated conductors and cables that pass this flame test are identified by the following legends, which are imprinted on the outer surface of a single conductor or on the jacket of a cable.

• Type PLTC, for 300 volt power-limited tray cable

• Type TC, for 600 volt power and control tray cable

• For CT Use or For Use in Cable Trays, for single conductors, Type MV cables, Type MC, or any other specific cable constructions that have passed the vertical tray flame test

Type MC cables without an outer covering do not require flame testing because the metallic sheath prevents propagation. Type MC cables with a nonmetallic outer covering are tested and will carry the above legend if the jacket is flame retardant. Consult API RP 14F, Section 4.4d(5) for flammability tests required for cables used in OCS areas offshore.

Fire CableSI fire cable is designed for use with critical motors (mainly MOVs) and controls that must be operable during a fire. These cables can operate at over 2000°F without failing. The cable is constructed with nickel conductors, silicon dioxide insulation,



and an outer stainless steel sheath. Consult API RP 14F, Section 9.7b(1) for require-ments of cables used for fire pumps in OCS areas offshore.

1135 Thermocouple Extension CableThermocouple extension cable consists of single-pair or multi-pair twisted, shielded, solid conductor, 300-volt rated cable. Reference ELC-MS-3552 for further informa-tion. Figure 1100-7 shows a typical construction. Thermocouple extension cable conductors must match the specific type of thermocouple (see ANSI/MC 96.1, Temperature Measurement Thermocouples): one iron and one constantine conductor for use with ANSI/ISA type J thermocouple probe, one chromel and one alumel conductor for higher temperature ANSI/ISA type K thermocouple probes. Other conductor materials are available for very high temperature applications. Various types of insulation are used: PVC, silicone rubber mica tapes, glass braid, and Teflon tapes. Teflon should be used in fire hazard areas. Where individual or overall shielding is required, an Aluminum-Mylar tape shield can be used to provide 100% coverage for excellent shielding effectiveness. A copper drain wire in intimate contact with the shield throughout the length of the cable is provided for grounding the shield. Various types of jackets (PVC, CSP or PE), are used over individual pair and over multi-pair cable. The jacket required depends on the installation—for example, 90°C PVC for normal use, 105° PVC for fire hazard areas, or Hypalon for PLTC-type cable.

1136 Computer CableWhere high-speed transmission is required, as in computer and other data processing systems, the interconnecting cable must have the following specific char-acteristics:

• Low mutual capacitance to allow for longer transmission distances

• Low attenuation losses to prevent distortion of pulses caused by reduced peak voltage and rise time

• Low propagation delay to allow high propagation velocity, thereby maintaining peak voltage and signal shape

• Proper characteristic impedance to prevent mismatch with that of the system receiver, thereby avoiding electrical reflection that can distort signal strength and decrease quality

Vendor catalogs should contain data on the preceding parameters.

The basic construction features of a few computer cables are as follows:

• Coaxial cable. One 22 AWG copper conductor, either solid or stranded, bare or tinned; foam polyethylene insulation; bare or tinned copper braid shield; overall PVC jacket; impedance as required; rated for 30 volts and 60°C

• Twin axial cable. Same as coaxial cable except with two twisted conductors



• Synchronous EIA interface cable. Fourteen conductors, tinned copper; foam polyethylene insulation; individual and overall Aluminum-Mylar tape shields; overall PVC jacket; rated for 30 volts and 60°C

• IEEE 488 interface cable. Six twisted pairs and 11 single 26 AWG conduc-tors; PVC insulation;overall tinned copper braid; overall PVC jacket; rated for 300 volts and 80°C

Vendors’ catalogs must be consulted to define the specific requirements because of the specialized nature of this type of cable.

1137 Fiber Optic CableFiber optic cable has been developed to replace the usual copper wire cable in many communication and instrument cable applications. It offers numerous advantages for the transmission of signals and data with complete freedom from EMI. The cables are rugged enough for many applications and installation conditions. They can be installed in conduit, cable tray, underground duct, by direct burial or as aerial cable with messenger wire support.

Fiber optic cables offer long distance transmission without the use of repeaters. They provide wide bandwidth, light weight, and high-density signal channels. Fiber optic cables can be used for a variety of applications—including communications, data transmission, instrumentation, and process control.

The individual optical fiber is the signal transmission medium and is very similar in function to an individual optical wave guide. The fiber has an all-dielectric struc-ture consisting of a central circular transparent core that propagates the optical radi-ation and an outer cladding layer that completes the guiding structure. For low-loss transmission, the fiber is typically polymer-clad silica (PCS) with a core of silica glass and cladding of glass or polymer material. To achieve high signal bandwidth, the core region has a varying or graded refractive index. The four major fiber parameters used in selecting the proper cable for an application are bandwidth, attenuation, numerical aperture (NA), and core diameter. These parameters should be defined in vendors’ catalogs.

1138 Shipboard Cables, Submarine Cables, and Submersible Pump Cables

Shipboard CableCommercial shipboard cable as specified in IEEE Std 45 is permitted by API RP 14F, Section 4.4, to be installed in classified locations on offshore platforms. This cable is not recognized by the NEC for onshore installations. Cable construction, in general, consists of copper stranded conductors; PVC, EPR, XLPE or silicone rubber insulation with maximum temperatures of 75, 90, 90, and 100°C, respec-tively, conductor shielding as required, and PVC or CSP jacket. A basket weave armor of bronze or aluminum is applied over the outer jacket. An overall PVC or CSP jacket can be added, and is required for offshore classified area applications. Refer to IEEE Std 45, Section 18 for additional construction details.



In general, application of commercial shipboard cable is as follows:

• 600 volt maximum power and lighting: PVC, EPR, or XLPE insulation• 2 kV and 5 kV power: EPR or XLPE insulation, shielded as required• 600 volt control cable: PVC, EPR, or XLPE insulation• Instrument cable: PVC insulation

Refer to Section 19 of IEEE Std 45 and Section 4.4 of API RP 14F for more appli-cation details.

For cable installation details refer to Section 20 of IEEE Std 45, Section 4 of API RP 14F, and Section 1000, “Installation of Electrical Facilities.”

Submarine CableSubmarine cables are used to supply power from shore to offshore platforms and from offshore platform to offshore platform. Voltage levels of 5 kV and 15 kV are common; higher voltage systems are occasionally used. Obviously, construction must be highly resistant to undersea environments. Typical construction is as follows: three-stranded copper conductors (and, normally, an equal number of groups of communications pairs); extruded semiconducting strand screen; 133% EPR or XLPE insulation; extruded semiconducting insulation screen; and copper tape shield over individual conductors; cabled together with jute or polypropylene fillers; an asphalt-impregnated jute or PE bedding layer; galvanized steel wire armor, and an overall jacket which is resistant to underwater environments.

For more details and application information refer to the vendors’ catalogs or contact vendors. Sample specifications for 5 kV and 15 kV submarine cable are included in Chevron U.S.A., Eastern Region-EL&P’s “Electrical Construction Guidelines for Offshore Marshland and Inland Locations.”

Submersible Pump CableSubmersible pump cable is used to supply power to submersible pumps in oil wells and in similar applications where temperatures may reach 300°F (149°C) and pres-sures up to 5000 psig. Cable voltage ratings from 2 kV to 5 kV are typical. IEEE Standard 1018 and 1019 may be used as guides. The basic construction of some types of submersible pump cables is as follows:

• Flat Oil Well Cable (5 kV). This cable consists of flat, parallel construction of three solid copper conductors, layers of fused Kapton (a Dupont film), a layer of EPR insulation, a moisture-resistant rubber compound overall jacket, and two layers of galvanized steel armor. It is for use where the ambient tempera-ture is up to 350°F (177°C) and is manufactured in Sizes 6 AWG to 2 AWG.

• Round Armored Downhole Cable (3 kV). This cable consists of three coated and stranded copper conductors, center strand filled; EPR insulation; when required, a solid copper, polyester-coated instrument conductor; moisture-resis-tant rubber compound jacket; and galvanized steel interlocked armor. It is for use at temperatures up to 240°F (116°C) and is manufactured in Sizes 6 AWG to 1 AWG.



• Round Armored Downhole Cable (3 kV). This cable has the same construc-tion as round armored downhole cable except that the insulation is a polypropy-lene-based compound suitable for temperatures up to 190°F (88°C). It is manufactured in Sizes 6 AWG to 1 AWG.

For more details and application information on downhole cable, refer to vendors’ catalogs or contact the vendor.

1140 Typical Wire and Cable SpecifiedThe following descriptions apply to typical wire and cable used in Company onshore facilities. For description of cables typically used offshore refer to API RP 14F.

1141 Medium Voltage Power ConductorsTypical practice is to use UL-listed single conductor, copper, 5 kV or 15 kV, type MV-90, shielded, 133% EPR insulated cable in accordance with ELC-MS-2447. It is installed in aboveground or underground conduit and as messenger-supported aerial cable. When installed in cable tray or in direct burial systems, UL-listed multi-conductor armored cable type MC-MV90 is used with a corrugated welded or extruded aluminum sheath. A jacket over the armor may be required for moisture and corrosion resistance and direct burial. Nonshielded cable may be used in systems operating at 2.4 kV and in certain non-critical 5 kV services provided that they meet the requirements of NEC Articles 310-6 and 7.

1142 Low Voltage Power and Lighting ConductorsTypical practice is to use UL-listed, single conductor, copper, 600 volt rated wire. It is purchased without a Company specification, as follows:

• Type THW: 75°C, UL-83, 600 volt, PVC-insulated for dry and wet locations.

• Type XHHW: 75°C, UL-44, 600 volt, XLPE-insulated for wet locations; 90°C (UL) for dry locations.

• Type THHN/THWN with nylon jacket, UL-83, 600 volt, PVC-insulated for dry and wet locations at 75°C (UL) and for dry locations at 90°C (UL).

• Type RHH/RHW with or without jacket, UL-44, 600 volt, EPR-insulated for dry and wet locations at 75°C (UL) and for dry locations at 90°C (UL). To be used on special applications where superior electrical characteristics and/or flexibility at low temperatures is required.

These wires can be installed in aboveground and underground conduit. If flame retardant, single conductor cable of sizes 250 MCM and larger can be installed in cable tray.



Multi-conductor cables containing Types XHHW or THHN/THWN conductors may also be provided with a flame retardant jacket for use in cable tray. This is discussed in Section 1146.

Type MC 600 volt armored cable with a corrugated welded or extruded aluminum sheath is recommended for exposed cable tray or direct burial installation.

1143 Low Voltage Control CableTypical practice is to use UL-listed single conductor, copper, 600 volt rated wire of the types indicated in Section 1142. It is run in aboveground or underground conduit. The minimum conductor size is 14 AWG for 120 volt AC motor control.

It is recommended that multi-conductor control cable comply with ELC-MS-3553. The minimum conductor size is 16 AWG for 120 volt AC motor control. When installed in cable tray, the outer jacket must be flame retardant.

1144 Instrumentation, Control, and Alarm CableTypical practice is to use single pair, single triad, multi-pair or multi-triad cable in accordance with ELC-MS-3551. Single pair or triad is run in conduit. A minimum of 18 AWG is recommended for mechanical strength.

Multi-conductor cable can be run in conduit or in cable tray (if labeled TC); the minimum recommended wire sizes are 20 AWG. Multi-conductor cable may be used as aerial cable when messenger-supported.

1145 Thermocouple Extension CableTypical practice is to use single pair or multi-pair twisted, shielded, and 300 volt rated. It is recommended that cables meet the requirements of ELC-MS-3552. The minimum sizes are, 16 AWG for single pair in conduit and 18 AWG for multi-pair in conduit or in cable tray.

1146 Flame Retardant CableThe typical practice is to use PVC or CSP (Hypalon) outer jackets that are resistant to flame, oil, sunlight and moisture on all cables installed in cable tray. Cables should pass the UL 383 vertical tray flame test and be identified as to usage (i.e., “Type TC”, “Type PLTC”, or “for TC use”).

1147 High Temperature CableThe typical practice for high temperature areas is to use silicon rubber or teflon insulations. For temperatures above 200°C, glass reinforced mica tapes are recom-mended.



1148 Fire Hazard Area CableThe typical practice in fire hazard areas is to use insulation of mica tapes and glass braid impregnated with a silicone finish on instrument, thermocouple and control circuits in accordance with ELC-MS-3551, 3552, and 3553.

1150 Glossary

1151 Definitions

Ampacity: Current carrying capacity of electric conductors, expressed in amperes.

Annealed: Copper wire softened and made flexible through a process employing exposure to high temperature in a vacuum or inert gas.

Armor: A metallic covering placed over the wire or cable to afford mechanical protection from abrasive conditions and impact damage.

AWG: (American Wire Gage). A system for classifying sizes of cable conductors, in which the higher numbers represent the smaller conductor diameters.

Braid: A weave of organic or inorganic fiber used as a protective outer covering or as an inner braid for binding and insulation over a conductor or group of conductors.

B & S: (Brown and Sharpe Gage). A wire diameter standard that is the same as the AWG system.

Bunch Stranding: A method of twisting individual wires to form a finished, stranded conductor. Specifically, a number of fine wires are twisted together in a common direction, without regard to exact position, and with a uniform pitch (twist per unit of length).

Cable Filler: The material used in multi-conductor cables to occupy the interstices of the insulated conductors, thus forming a rounded core.

Circular Mil Area: The area of a conductor equal to the square of the diameter in mils (0.001 inches). This measure is also known as the cross-sectional area of a wire. (See definition of Cross-Sectional Area.)

Concentric Stranding: A method of stranding wire in which a conductor is composed of a central core surrounded by one or more layers of helically-laid wires. Usually, all wires are of the same size and the central core is a single wire.

Corona: An electrostatic discharge at high voltage resulting from ionization, which is detrimental to the dielectric material and outer coverings of cables.

Cross-Sectional Area: The sum of the cross-sectional areas of the component wires. In determining wire sizes, the circular mil area of one of the strands is deter-mined and multiplied by the total number of strands in the conductor.

Dielectric: A medium or material which, when placed between conductors at different potentials, permits only a small or negligible current to flow through it.



The term dielectric is almost synonymous with electrical insulation, which can be considered the applied dielectric.

Dielectric Constant: That property of a dielectric which determines the electro-static energy stored per unit volume for unit potential gradient. Usually a numerical value given relative to a vacuum. This value is an indication of losses in the cable during operation. Higher values indicate higher losses.

Dielectric Strength: The ability of an insulating material to resist rupture by elec-trical potential. The maximum voltage which a dielectric can withstand for a short time without breakdown or rupture. Usually expressed as volts per mil.

Direction of Lay: The lateral direction in which strands or the elements of a cable run over the top of the cable as they recede from the observer. It is expressed as right- or left-hand lay.

Drain Wire: A bare conductor, usually in a metallic shielded instrument cable, used to connect the shield to ground.

Extrusion: A process consisting of flowing plastic insulation material through forming dies, and subsequently cooling the insulation material in a homogeneous solid cylinder around the wire.

Flex Life: The resistance of a conductor to fatigue failure when bent repeatedly.

Insulation: A nonconducting material used to prevent leakage of current from a conductor and to isolate a conductor from other conductors, conducting parts, or from ground.

Jacket: A covering, (usually thermoplastic or thermosetting material, sometimes fabric reinforced), applied over the insulation, core, metallic sheath, and (some-times) the armor of a cable.

Mil: One-thousandth of an inch; used in the U.S.A. to measure wire or cable diam-eter.

Operating Voltage: The voltage at which a cable is actually used. It is usually expressed in volts rms.

Ozone: A form of oxygen produced by the passage of electrical discharges or sparks through air. It is detrimental to cable insulations and outer coverings.

Rope-Lay Stranding: A method of stranding wire in which a conductor is comprised of a central core made of a group of wires that are either concentric or bunched-stranded, and surrounded by one or more helically-laid groups of wire, which are also stranded in the manner of the center core. This type of stranding differs from concentric stranding only in that the main strands are themselves stranded. This type of stranding offers the highest degree of flexibility.

Serving: Wrapping applied over the core of a cable to hold it in a cylindrical configuration before it is jacketed or armored. The commonly used materials are filaments, fibers, yarn, and tape. The serving is for mechanical protection and not for insulating purposes.



Sheath: An outside covering that protects a cable from mechanical injury or from the harmful effects of water, oils, acids, and chemicals.

Shield: A conductive layer placed around an insulated conductor or group of conductors to prevent electrostatic or electromagnetic interference between the enclosed wires and external fields. This shield can be braided or served wires, foil wrap, foil backed tape, a metallic tube, or conductive vinyl or rubber. When a metallic braid of tinned or bare copper is applied over the insulated conductors, the shielding effectiveness is in direct proportion to the amount of coverage, usually expressed in percentage.

Stranded Conductor: A conductor composed of a group of bare wires twisted together.

Temperature Rating: The maximum temperature at which the insulating material may be used in continuous operation without degradation of its basic properties.

Treeing: Treeing is a gradual deterioration of insulation developed under voltage stress. The name “treeing” is derived from the branched appearance of the deteriora-tion channels on the affected insulation.

Twisted Pair (or Triad): A twisted pair (or triad) cable is comprised of two (or three) insulated conductors twisted together and coded for easy circuit identifica-tion, made firm by filler material and finished with a common protective covering. This type of construction usually is employed for instrumentation and communica-tion cables.

Voltage Rating: The highest voltage that may be continuously applied to a wire or cable in conformance with ICEA Standards. Voltage rating is given as phase-to-phase voltage.

1152 Abbreviations and Acronyms

A - Ampere

AC - Alternating Current

ANSI - American National Standards Institute

API - American Petroleum Institute

ASTM - American Society for Testing and Materials

AWG - American Wire Gage

B&S - Brown and Sharpe (Gage)

CM - Circular Mil

CSP - Chlorosulfonated Polyethylene (Hypalon)

DC - Direct Current

EMI - Electromagnetic Interference

EPR - Ethylene Propylene Rubber





1162 Standard DrawingsThere are no standard drawings in this section.

ICEA - Insulated Cable Engineers Association

IEEE - Institute of Electrical and Electronics Engineers

ISA - Instrument Society of America

MC - Metal Clad

MCM - Thousands of Circular Mils (or kcmil)

MI - Mineral Insulated

MV - Medium Voltage

NEC - National Electrical Code

NEMA - National Electrical Manufacturers Association

NFPA - National Fire Protection Association

NRTL - Nationally Recognized Testing Laboratory

OSHA - Occupational Safety and Health Administration

PCP - Polychloroprene (Neoprene)

PE - Polyethylene

PLTC - Power Limited Tray Cable

PVC - Polyvinyl Chloride

RFI - Radio Frequency Interference

RMS - Root Mean Square

TC - Tray Cable

UL - Underwriters Laboratories

XLPE - Cross-Linked Polyethylene

*ELC-MS-2447 5 kV and 15 kV Insulated Power Cable

*ELC-MS-3551 Instrument and Control Cable Single and Multi-pair (or Multi-triad) Construction

*ELC-MS-3552 Twisted and Shielded Thermocouple Extension Cable Single and Multi-pair Construction

*ELC-MS-3553 600 Volt Multi-conductor Control Cable



1163 Data Sheets (DS), Data Guides (DG) and Engineering Forms (EF)There are no data sheets, data guides or engineering forms with this section.


American Petroleum Institute Practices (API)API RP 14F, Design and Installation of Electrical Systems for Offshore Production Platforms

API RP 540, Recommended Practice for Electrical Installations in Petroleum Processing Plants

American Society for Testing and Materials (ASTM)ASTM B1, Specification for Hard-Drawn Copper Wire

ASTM B2, Specification for Medium-Hard-Drawn Copper Wire

ASTM B3, Specification for Soft or Annealed Copper Wire

ASTM B8, Specification for Concentric-Lay-Stranded Copper Conductors, Hard, Medium-Hard, or Soft

ASTM B33, Specification for Tinned Soft or Annealed Copper Wire for Electrical Purposes

ASTM B172, Specification for Rope-Lay-Stranded Copper Conductors Having Bunch-Strand Members, for Electrical Conductors

ASTM B173, Specification for Rope-Lay-Stranded Copper Conductors Having Concentric-Strand Members, for Electrical Conductors

ASTM B174, Specification for Bunch-Stranded Copper Conductors for Electrical Conductors

ASTM B189, Specification for Lead-Coated and Lead-Alloy-Coated Soft Copper Wire for Electrical Purposes

ASTM B496, Specification for Compact-Round-Concentric-Lay-Stranded Copper Conductors

Association of Edison Illuminating Companies (AEIC)AEIC CS5, Specifications for Thermoplastic and Cross-linked Polyethylene Insu-lated Shielded Power Cables Rated 5 Through 46 kV.

AEIC CS6, Specifications for Ethylene Propylene Rubber Insulated Shielded Power Cables Rated 5 Through 69 kV.

Institute of Electrical and Electronic Engineers (IEEE)ANSI/IEEE, Standard 141, IEEE Recommended Practice for Electric Power Distri-bution for Industrial Plants.



IEEE, Standard 135, IEEE Power Cable Ampacities

ANSI/IEEE Standard 45, IEEE Recommended Practice for Electric Installations on Shipboard.

ANSI/IEEE Standard 383, IEEE Standard for Type Test of Class IE Electric Cables, Field Splices, and Connections for Nuclear Power Generating Stations.

IEEE Standard 1018, IEEE Recommended Practice for Specifying Electric Submersible Pump Cable, Ethylene-Propylene Rubber Insulation.

IEEE Standard 1019, IEEE Recommended Practice for Specifying Electric Submersible Pump Cable, Polypropylene Insulation.

Instrument Society of America (ISA)ASI/ISA RP 12.6, Installation of Intrinsically Safe Systems for Hazardous (Classi-fied) Locations

ANSI MC 96.1, Temperature Measurement Thermocouples

Insulated Cable Engineers Association (ICEA)ICEA P-32-382, Short-Circuit Characteristics of Insulated Cable.

ICEA P-45-482, Short-Circuit Performance of Metallic Shields and Sheaths of Insu-lated Cable.

ICEA P-54-440, Ampacities-Cables in Open-Top Cable Trays.

ICEA S-19-81, Rubber-Insulated Wire and Cable for the Transmission and Distribu-tion of Electrical Energy.

ICEA S-61-402, Thermoplastic-Insulated Wire and Cable for the Transmission and Distribution of Electrical Energy.

ICEA S-65-375, Varnished-Cloth-Insulated Wire and Cable for the Transmission and Distribution of Electrical Energy.

ICEA S-66-524, Cross-Linked-Thermosetting-Polyethylene-Insulated Wire and Cable for the Transmission and Distribution of Electrical Energy.

ICEA S-68-516, Ethylene-Propylene-Rubber-Insulated Wire and Cable for the Transmission and Distribution of Electrical Energy.

ICEA S-82-552, Instrumentation Cables and Thermocouple Wire.

National Fire Protection Association (NFPA)ANSI/NFPA 70, National Electrical Code

Underwriters Laboratories, Inc. (UL)ANSI/UL 44, Rubber-Insulated Wires and Cables.

ANSI/UL 62, Flexible Cord and Fixture Wire.



ANSI/UL 83, Thermoplastic-Insulated Wires and Cables.

ANSI/UL 1569, Metal-Clad Cables.

ANSI/UL 1581, Reference Standard for Electrical Wires, Cables, and Flexible Cords.

UL 13, Outline of Proposed Investigation of Power-Limited Circuit Cable. July 1978.

ANSI/UL 1072, Medium-Voltage Power Cables.

ANSI/UL 1277, Electrical Power and Control Tray Cables with Optional Optical-Fiber Members.

Miscellaneous:Beeman, Industrial Power Systems Handbook. “Calculation of Voltage Drop.” New York: McGraw-Hill, 1955.

IADC-DCCS-1 Interim Guidelines for Industrial System DC Cable for Offshore Drilling Units.


1200 Lighting

AbstractThis section provides technical and practical guidance for the design and selection of lighting systems. It defines and describes lighting, different types of light sources, factors to consider when selecting lamps and fixtures, and the design, layout, and maintenance of lighting systems. Design considerations including acceptable lighting levels for specific areas, economic factors, safety issues, and different methods for determining the number and layout (location) of fixtures are also discussed.

Contents Page


1211 Section Guide

1220 Light Sources (Lamps) 1200-3

1221 Incandescent Lamps

1222 Fluorescent Lamps

1223 High Intensity Discharge Lamps

1224 Lamp Designations

1230 Fixture Selection 1200-8

1231 Area Classification

1232 Luminous Efficacy and Lumen Depreciation

1233 Color

1234 Cost

1235 Temperature

1236 Lamp Starting and Restarting

1237 Ballasts

1238 Fixture Materials

1239 Voltage Levels

1240 Lighting System Design 1200-21

1200 Lighting Electrical Manual


1241 Distribution of Light

1242 Lighting Methods

1243 Illumination Level

1244 Lighting Level Reduction

1245 Emergency Lighting Systems

1246 Company Experience with Lighting Systems

1250 Lighting Calculations and Fixture Layout 1200-25

1251 Area Lighting

1252 Lumen Maintenance Factor (LMF)

1253 Watts-Per-Square Foot Method

1254 Iso-Footcandle Method

1255 Fixture Layout Using Iso-Footcandle Charts

1256 Fixture Layout Using Iso-Footcandle Tables

1260 Maintenance Considerations 1200-44

1270 Glossary of Terms 1200-45






Electrical Manual 1200 Lighting


1210 IntroductionGood lighting systems provide two primary benefits in a facility: personnel safety and efficiency of operations. All decisions involving lighting system design and selection must take into consideration these two factors. This section contains infor-mation that provides guidance for selecting appropriate lighting systems. It also provides guidance for analyzing the efficiency of existing systems and for analyzing systems maintenance.

1211 Section GuideThe following guide directs the user to the appropriate sections.

If unfamiliar with different types of lamps, Section 1220, “Light Sources (Lamps)” should be reviewed. General information is provided about incandescent, fluores-cent, and different high intensity discharge (HID) lamps. HID lamp types include mercury vapor, metal halide, and high pressure sodium. This section is not intended to be used for the selection of lighting fixtures.

Section 1230, “Fixture Selection,” should be used as a guide in selecting the type of fixture. Factors discussed that influence fixture selection are: area classification, color rendition, luminous efficacy and lumen depreciation, cost, temperature, and lamp starting and restarting time. Three other factors should be considered when specifying fixtures: ballast, fixture materials, and voltage level.

Section 1240, “Lighting System Design,” reviews the many considerations involved in lighting design. These considerations include the type of light distribution, lighting methods, illumination levels, and emergency lighting systems. Many OPCOs have standardized particular fixtures. For these applications, the recom-mended illumination levels listed in API RP 540, Section 6, “Electrical Installations in Petroleum Refineries,” and API RP 14F, “Design and Installation of Electrical Systems for Offshore Production Platforms,” should be used to determine the neces-sary footcandle levels. Company experience is also outlined for many applications.

Section 1250, “Lighting Calculations and Fixture Layout,” can be used to deter-mine the number of fixtures and their layout. Topics discussed are: area lighting, lumen maintenance factor (LMF), and three computational methods, with two examples using the iso-footcandle method.

Section 1260, “Maintenance Considerations,” discusses relamping, cleaning fixtures, and cleaning lighted surfaces.

1220 Light Sources (Lamps)The primary purpose of an electrical light source is the conversion of electrical energy into visible light. The effectiveness with which a lamp accomplishes this is expressed in terms of lumens emitted per watt of power consumed, or luminous effi-cacy.



For an idea of the relative luminous effectiveness of common light sources, consider that a 60-watt incandescent lamp (A-19 medium base soft-white) emits about 900 lumens in comparison to a 60-watt fluorescent lamp (cool white) which emits about 5600 lumens. This is roughly six times the lumens per watt of the incandescent lamp. In addition, the fluorescent lamp has a ten-times longer life than the incandes-cent lamp. To obtain the predicted long life of any lamp, it must be mounted according to the manufacturer’s instructions. Some lamps can only be mounted in a vertical position; others, only in a horizontal position. Some have a requirement for the base to be up, others for the base to be down. The most common types of light sources and their associated groups are shown below.

1221 Incandescent LampsThe filament lamp produces light by heating a wire filament to incandescence, which generates energy in the form of light and heat. The most common filament material is tungsten. All filament lamps emit a large quantity of heat with generally less than 5% light energy emitted. Both the life and light output of an incandescent lamp are determined by the filament temperature. The higher the temperature for a given lamp, the shorter the life. However, the larger the diameter of the filament wire, the hotter the lamp can operate. This results in more light output, which in turn means higher efficacy. To illustrate this, consider that a 150-watt, 120-volt lamp produces approximately 34% more light than three 50-watt, 120-volt lamps. Incan-descent lamps have a rated average life of about 1000 hours and radiate about 14 to 20 lumens per watt. Vibration and shock should be eliminated as they can greatly reduce lamp life. Incandescent lamps are available with virtually unbreakable shells and filaments where high vibration or rugged duty is required.

As a general rule, incandescent lamps should be operated at rated voltage. Over-voltage operation produces higher wattage, higher efficacy, and higher light output, but results in a shorter life. Undervoltage, while increasing lamp life, causes a reduction in wattage, efficacy, and light output. A voltage as little as 5% below normal results in a loss of light of more than 16%, with a savings in wattage of only 8%. Since the lamp cost is almost always small compared with the cost of the power to operate the lamp, the increased lamp life which accompanies reduced voltage does not compensate for the loss in light output. Maintaining the proper voltage is an important factor in obtaining good performance from lamps and lighting installa-tions.

Type Group

Incandescent Filament

Fluorescent Fluorescent

Mercury Vapor High Intensity Discharge

Metal Halide High Intensity Discharge

High Pressure Sodium (HPS)

High Intensity Discharge



1222 Fluorescent LampsThe fluorescent lamp contains mercury vapor at low pressure with a small amount of inert gas for starting. When voltage is applied, an “arc” discharge is produced by current flowing through the mercury vapor. The discharge generates ultraviolet radi-ation which excites the fluorescent powders on the inner wall of the lamp, which in turn emit light.

Like most gas discharge lamps, fluorescent lamps must be operated in series with a ballast. The ballast produces the required voltage to start and operate the lamp and the required current to produce the desired light output.

Fluorescent lamps have a rated average life of about 20,000 hours when operated for a minimum of 3 hours per start. The lamps radiate about 74 to 84 lumens per watt.

The average lamp life for fluorescent lamps is affected by the number of on-off operations. A rule-of-thumb is that each lamp start reduces the average lamp life by 3 hours. This might imply that fluorescent lamps should be operated continuously during the day to save lamp life rather than being turned off when not in use to save energy. However, the light should be turned off to save energy because approxi-mately 80% of the life-cycle cost of a fluorescent lamp is for electrical energy. The life of F40 and F30 lamps, operating on rapid start ballasts when burned 3 or more hours per start, is not appreciably affected by the number of starts. All burned-out lamps should be removed promptly to prevent the auxiliary equipment from over-heating. Depreciation in light output of the fluorescent lamp is due chiefly to a gradual deterioration of the phosphor powders and a blackening of the inside of the tube. In the last hours of lamp life, a dense deposit develops at the end of the lamp where the electrode is deactivated. This effect is especially marked if the lamp is allowed to flash on and off before it is replaced.

Low voltage, as well as high voltage, reduces efficiency and shortens fluorescent lamp life. This is in contrast with filament lamps, where low voltage reduces effi-ciency but prolongs life. Low voltage and low ambient temperatures may also cause starting difficulties with fluorescent luminaires.

A large voltage dip or reduction in line voltage affects the stability of the arc. The reaction to a voltage dip depends on the lamp type and ballast characteristics. For 40-watt, T-12 lamps, the line voltage can drop to the values illustrated in the table below before the lamps will extinguish:

Type Percent of Normal Voltage

Preheat 75

Rapid-start series-sequence 80

Instant-start lead-lag 60

Instant-start series-sequence 50



1223 High Intensity Discharge LampsHigh intensity discharge (HID) lamps that are commonly used include mercury vapor, metal halide, and high pressure sodium. The light producing element of these lamps is a stabilized arc discharge contained within an arc tube. Light is produced by the passage of an electric current through a vapor or gas rather than through a tungsten wire. The applied voltage ionizes the gas and permits current to flow between two electrodes located at opposite ends of the lamp. The electrons which comprise the current stream, or “arc discharge,” are accelerated to tremendous speeds. When they collide with the atoms of the gas or vapor, they temporarily alter the atomic structure, and light is produced from the energy generated as the atoms return to their normal state.

Low pressure sodium lamps are not recommended because of very poor color rendi-tion and high operating costs.

Mercury Vapor LampsMost mercury vapor (MV) lamps are constructed with two envelopes, an inner envelope (arc tube) which contains the arc, and an outer envelope which: (a) shields the arc tube from outside drafts and resulting changes in temperature; (b) usually contains an inert gas which prevents oxidation of internal parts; (c) provides an inner surface for a coating of phosphors; and (d) acts as a filter to remove certain wavelengths of arc radiation.

A significant part of the energy radiated by the mercury arc is in the ultraviolet region. Through the use of phosphor coatings on the inside surface of the outer envelope, some of this ultraviolet energy is converted to visible light by the same mechanism employed in fluorescent lamps.

Mercury lamps used in open-type fixtures can cause serious skin burn and eye inflammation from shortwave ultraviolet radiation if the outer envelope of the lamp is broken or punctured and the arc tube continues to operate. For this reason, non-enclosed fixtures should be specified with self-extinguishing lamps that will auto-matically extinguish if the outer envelope is broken or punctured. Self-extin-guishing lamps cost about twice as much as standard lamps.

Metal Halide LampsMetal halide (MH) lamps are very similar in construction to mercury lamps. The major difference is that the metal halide arc tube contains various metal halides in addition to mercury and argon.

Almost all varieties of available “white-light” metal halide lamps produce color rendering which is equal or superior to the presently available phosphor coated mercury lamps. Metal halide lamps are also available with phosphors applied to the outer envelopes to further modify the color.

Most metal halide lamps require a higher open-circuit voltage to start than corre-sponding wattage mercury lamps. Therefore, they require specifically designed ballasts.



Metal halide lamps are constructed of a glass envelope with an internal arc tube made of quartz. These arc tubes operate under high pressure (6 to 7 atmospheres) at a very high temperature (up to 900°C). The arc tube may unexpectedly rupture due to internal causes or external factors, but most commonly ruptures when the lamp is operated beyond its rated life. If the arc tube ruptures, the glass envelope surrounding the arc tube can break, allowing particles of extremely hot quartz from the arc tube and glass fragments from the glass envelope to be discharged into the fixture enclosure and surrounding area. This circumstance creates a risk of personal injury or fire. Metal halide lamps should always be used in enclosed fixtures with lens/diffuser material which is able to contain fragments of hot quartz or glass.

To reduce the potential hazard of ruptured arc tubes, use metal halide lamp manu-facturers with proven lamps. Additional precautions to use to reduce the likelihood of arc tube rupture are:

1. Turn continuously operating lamps off once a month for at least 15 minutes. Lights which are close to the end of their design life likely will not restart. This procedure will reduce the chance of arc tube rupture caused by continuously operating lamps burning beyond the end of rated life.

2. Relamp fixtures at or before the end of their rated life. Allowing lamps to operate beyond their design life increases the possibility of arc tube rupture.

Like mercury vapor lamps, metal halide lamps can cause serious skin burn and eye inflammation from shortwave ultraviolet radiation if the outer envelope of the lamp is broken or punctured and the arc tube continues to operate. When using open-type fixtures, self-extinguishing lamps that automatically extinguish when the outer envelope is broken or punctured should be specified.

High Pressure Sodium LampsIn a high pressure sodium (HPS) lamp, light is produced by electric current passing through sodium vapor. The arc tube contains xenon as a starting gas. Special ballasts are required which incorporate starting voltages in the range of 2250 to 4000 volts to strike the arc. These high strike voltages can result in high temperatures which could possibly create problems in classified areas. HPS lamps do not incorporate a starting electrode or heater coil as do mercury vapor and metal halide lamps.

Arc tube rupture is not a problem with high pressure sodium lamps since the arc tube is made of ceramic material. Shortwave radiation is also not a concern with high pressure sodium lamps.

1224 Lamp DesignationsLamp designations follow a system authorized by the American National Standards Institute (ANSI). All designations begin with a letter that identifies the type of HID lamp: “H” for mercury, “M” for metal halide, and “S” for high pressure sodium. This letter designation is followed by an ANSI assigned number which identifies the electrical characteristics of the lamp and, consequently, the ballast. After the number, two arbitrary letters identify the bulb size, shape, and finish, but do not



identify the color. Additional letters are used by individual manufacturers for special designations.

1230 Fixture SelectionA thorough understanding of the purpose for a lighting system must be established before the various selection factors can be evaluated. Figure 1200-1 lists fixture types and typical applications in order of preference for locations that require maximum light output at the lowest possible operating cost. On offshore platforms where power is generated and the physical layout prevents full use of light output, mercury vapor fixtures are often preferred. They give better color rendition and have lower installed costs in situations where some of the light is lost due to shadows. When several possible fixture types have been chosen, a review of the features of each one can be made to complete the selection process.

Fig. 1200-1 Light Fixture Selection (1 of 2)

Light Fixture Type

Application Incandescent Fluorescent MV MH HPS

Outdoor:

Entrance Illumination 4 2 3 1

Wall Illumination 2 1

Ladder Illumination 3 2 1

Emergency Lights 2 4 3 1 (with instant restrike)

Area Floodlighting 3 2 1

Walkways 4 3 2 1

Roadways 1

Corridors 2 4 3 1

Canopy Lighting 1

Heliports 2 1

Indoor:

Small Store Rooms 1 2

Exit Lights 1

Stairways 2 1

Bulkheads 1

Emergency Lights 2 1

Offices 1

Control Rooms 1

Living Areas 2 1



1231 Area ClassificationArea classification must be determined before selecting lighting fixtures. Refer to Section 300 of this manual for guidance in determining area classification and Section 340 for specific lighting fixture considerations. Refer to the area classifica-tion drawing of the facility in which the lighting fixture is to be installed to identify the proper area classification.

The fixture temperature must not exceed the ignition temperature of flammable gases or vapors present. See Figure 1200-2 for temperature identification numbers and T-Ratings for typical fixtures.

1232 Luminous Efficacy and Lumen DepreciationOne of the two primary factors used in fixture selection is the luminous efficacy (lumens per watt) of the light source. The other primary factor is the initial cost of the fixture. For fixtures that have a long life, the luminous efficacy, which relates directly to the operating cost of the lamp, usually will govern the selection process. These factors usually do not govern fixture selection when shadows prevent full use of light output or when power is generated at very low cost (e.g., on offshore plat-forms).

Lumen depreciation is a reduction in normal light output that is unique to each type of lamp. It is an important factor during the design and fixture layout process. For example, the light output of a mercury vapor lamp at the end of rated life will only be about 50% of its original light output. By comparison, the light output of high pressure sodium and fluorescent lamps at the end of rated life will be about 80% of their original light output.

Luminous Efficacy and Lumen Depreciation SummaryFigure 1200-3 and Figure 1200-4 summarize the luminous efficacy and lumen depreciation for different light sources.

Corridors 2 1

Switchgear Buildings 1

High Bay Area Lighting 3 2 1

Warehouses 3 2 1

Notes: 1. Number indicates order of preference, 1 being the most preferred.2. See Section 1230, “Fixture Selection,” for discussion of limited-light applications and low-cost power usage.

Fig. 1200-1 Light Fixture Selection (2 of 2)

Light Fixture Type

Application Incandescent Fluorescent MV MH HPS



1233 ColorIn some applications, color rendition is the dominant factor in fixture selection. For example, metal halide fixtures are typically used in the canopy area of service stations because of the pleasing visual effect of the light. Metal halide lamps use more energy per lumen output and have a shorter life than high pressure sodium lamps, but the visual attractiveness obtained by using metal halide lamps outweighs their added operating cost.

Mixing high pressure sodium with metal halide or mercury vapor is not recom-mended because of the contrasting colors. Mixing luminaires becomes a problem when color rendition is important—for example, for distinguishing colors, for reading, and when performing precision, task-oriented activities. Mixing luminaires also presents a maintenance problem during relamping, when time is lost locating the correct lamps.

Incandescent Filament LampsIncandescent light closely resembles natural sunlight, with good color rendition.

Fluorescent LampsThe color produced by a fluorescent lamp depends upon the blend of phosphors used to coat the wall of the tube. There are different “white” and color spectrum

Fig. 1200-2 Technical Data: Temperature Identification Numbers of Typical Fixtures (Courtesy of Appleton Electric Company)



fluorescent lamps available with their own particular coloration. “White” lamps have good color rendering properties.

High Intensity Discharge (HID) LampsA discussion of the color aspects of HID lamps follows.

Mercury Vapor (MV) Lamps. The color spectrum of “clear” mercury lamps is deficient in red and has a preponderance of blue and green. This results in marked distortion of object colors, and makes mercury vapor lamps undesirable when the appearance of colors is important. This deficiency can be overcome by using “deluxe white” (color-corrected) lamps in which fluorescent phosphor coatings are added to the lamps to improve color rendering. MV lamps have poorer color rendi-tion than MH lamps, but better color rendition than HPS lamps. MV lamps are best used for general lighting (street, industrial, and flood-lighting) where color rendering is not extremely important or where the full output of an HPS lamp will not be utilized because of shadowing.

Metal Halide (MH) Lamps. The color spectrum of “clear” metal halide lamps is equal to or superior to phosphor-coated mercury vapor lamps. Phosphor coatings can be added for better color. MH lamps are best used where color rendering is important and in general lighting where only a few fixtures are required.

High Pressure Sodium (HPS). The color spectrum of high pressure sodium lamps consists of white light with a yellow-orange tone. HPS lamps are best used for

Fig. 1200-3 Efficacies for Various Light Sources (from The IESNA Lighting Handbook Reference and Application, Ninth Edition. Courtesy of IESNA)



Fig. 1200-4 Lumen Depreciation Factor (LDF) (from “Philips Lighting Guide to High Intensity Discharge Lamps" Printed 8/91, publication # P-2685, pages 7, 12, and 16. Courtesy of the Philips Lighting Company.)



general lighting of large areas where good color rendition is a secondary consider-ation.

1234 CostHigh pressure sodium lamps are usually the best economic choice for lighting large areas, primarily because of their low operating cost and long life. Such areas include: floodlighting, general area lighting, road way lighting, and warehouse lighting. Metal halide is the second most cost effective choice for outdoor lighting, followed by fluorescent. Mercury vapor fixtures should not be used in new installa-tions due to poor luminous efficacy and high lumen depreciation (which results in high operating costs) except for specific locations as discussed below. In fact, it may be cost effective to retrofit existing mercury vapor installations with high pressure sodium lamps.

At locations where power is purchased or generated at low cost and physical layout prevents full use of light output, metal halide or mercury vapor fixtures may be more cost effective. An economic evaluation should be performed.

Fluorescent lamps are often the preferred choice for enclosed areas, especially for control rooms, office buildings, and laboratories with low ceiling clearance. High pressure sodium lamps are often preferred for warehouses and indoor process areas. Incandescent lamps should be used sparingly, and only for specialty applications (e.g., emergency lighting) or where lighting is used infrequently and the initial fixture cost is low compared to alternative lighting fixtures.

Fluorescent LampsFigure 1200-5 shows a cost analysis for energy-saving versus standard efficiency fluorescent lamps. This analysis indicates that energy-saving lamps should be speci-fied even when the time value of money is as high as 20%. Energy-saving lamps are more cost effective because the average lamp life is long (almost 7 years) and energy represents more than 80% of the life cycle cost (LCC) of operating lamps.

High Intensity Discharge LampsFigure 1200-6 shows a cost analysis to light a 50,000 square foot area to an illumi-nation level of 5 footcandles. The analysis is based on using Class I, Division 2 (UL-844) fixtures, with an energy cost of $0.08/KWH, and 4000 burning hours per year. For different costs of power and labor, ratio actual costs to the costs used in this example (e.g., $0.04/KWH/$0.08/KWH=$4,864.00 annual operating cost). The undiscounted life cycle cost (LCC) of using HPS lamps in this example is approxi-mately $300,000. By comparison, the undiscounted LCC of MV lamps is more than $720,000. This cost does not consider the added cost of source equipment (trans-formers and panelboards) for the MV lamp option (with a connected load of 82 KW versus 30 KW for the HPS option). In addition, more conduit, wire, and lamp stan-chions are required for the MV lamp option. The metal halide option is also a better choice economically than mercury vapor.

Figure 1200-7 illustrates another example in which one HPS, MV, or MH fixture provides a maintained minimum illumination of 5 footcandles. In this example, the



MV option has the lowest initial cost and the lowest LCC even when the time value of money is over 20%.

Figure 1200-8 demonstrates a retrofit example in which MV lamps are presently in use. An initial investment of approximately $96,000 will be required to retrofit to HPS or $104,000 to retrofit to MH. Based on a 10-year LCC, the option to retrofit with HPS yields a savings even when the time value of money is as high as 12%. Retrofitting with MH is not a cost effective option. This also is true when using a 20-year LCC. However, when the cost of energy is below $0.05/KWH, it is not cost effective to change out the MV lights. An economic analysis should be performed for each possible situation.

Fig. 1200-5 Cost Analysis: Comparison of Fluorescent Lamps—Energy Savers vs. Standard Lamps

F40CW Standard F40 Energy Saver

Number of Luminaires Required 1.00 1.00

Initial Lumens Per Lamp 3,150.00 2,775.00

Estimated Lamp Life (Hrs) 20,000 20,000

Average Lamp Replacements/yr 0.15 0.15

Lamp Net Cost After Discount ($/lamp) 1.24 1.72

Lamp Input (watts/lamp) 40.00 34.00

Total Connect Load (W) 40 30

Relamp Labor/lamp @$50/hr 10.00 10.00

Annual Operating Cost ($)

Relamp Cost: Lamps 0.19 0.26

Relamp Cost: Labor 1.50 1.50

Energy Cost 9.60 8.16

Total Annual Operating Cost 11.29 9.92

20 Year Operating Cost ($)

Relamp Cost: Lamps 3.72 5.16

Relamp Cost: Labor 30.00 30.00

Energy Cost 192.00 163.20

Total 20 Year Operating Cost 225.72 198.36

20 Year Life Cycle Cost ($–discounted)

8% Discount Rate 110.81 97.38






Fig. 1200-6 Cost Analysis: High Intensity Discharge Fixtures

High Intensity Discharge Fixtures

Basis:

50,000 Sq Ft Area; Illuminated to 5 fc4,000 Burning Hrs Per Yr; Energy Cost = $0.08/KwhArea Class: Class I, Division 2, Group D

150 W HPS 175 W MV 175 W MH

Number of Luminaires Required 160 357 200

Initial Lumens Per Lamp 16,000 8600 14,000

Lumen Maintenance Factor 0.60 0.50 0.55

Total Lumens 1,536,000 1,535,000 1,540,000

Estimated Lamp Life (hrs) 24,000 24,000 10,000

Avgerage Lamp Replacements/yr 27 60 80

Lamp Net Cost ($) 27 16 29

Luminaire Input (watts/fixture) 190 230 230

Total Connected Load (kw) 30.40 82.11 46.00

Fixture Cost ($) 350 310 300

Installation Labor/Fixture @ $50/hr 150 150 150

Relamp Labor/Lamp @ $50/hr 10 10 10

Initial Installation Cost ($)

Fixture Cost 56,000 110,670 60,000

Labor Cost 24,000 53,550 30,000

Total Initial Cost 80,000 164,220 90,000


Relamp Cost: Lamps 729 952 2,320

Relamp Cost: Labor 270 595 800

Energy Cost 9,728 26,275 14,720

Total Annual Operating Cost 10,729 27,822 17,840


Relamp Cost: Lamps 14,580 19,040 46,400

Relamp Cost: Labor 5,400 11,900 16,000

Energy Cost 194,560 525,504 294,400

Total 20 Year Operating Cost 214,540 556,444 356,800

20 Year Life Cycle Cost ($–undiscounted) 294,540 720,664 446,800


8% Discount Rate 225,615 542,332 332,451

10% Discount Rate 202,896 483,338 294,623

12% Discount Rate 185,198 437,382 265,155

20% Discount Rate 143,525 329,173 195,770



Fig. 1200-7 Cost Analysis: High Intensity Discharge Fixtures

High Intensity Discharge Fixtures

Basis:

Equal Number of Fixtures; Illumination Minimum to 5 fc;4,000 Burning Hrs Per Yr; Energy Cost = $0.08/kwh;Area Class: Class I, Division 2, Group D

70 W HPS 100 W MV 175 W MH

Number of Luminaires Required 1 1 1

Initial Lumens Per Lamp 5800 4200 14,000

Lumen Maintenance Factor 0.60 0.50 0.55

Total Lumens 3,480 2,100 7,760

Estimated Lamp Life (hours) 24,000 24,000 10,000

Avgerage Lamp Replacements/yr 0.17 0.17 0.40

Lamp Net Cost ($) 29 19 29

Luminaire Input (watts/fixture) 102 132 230

Total Connected Load (kw) 0.10 0.13 0.23

Fixture Cost ($) 325 215 300

Installation Labor/Fixture @ $50/hr 150 150 150

Relamp Labor/Lamp @ $50/hr 10 10 10

Initial Installation Cost ($)

Fixture Cost 325 215 300

Labor Cost 150 150 150

Total Initial Cost 475 365 450


Relamp Cost: Lamps 4.80 3.20 11.60

Relamp Cost: Labor 1.70 1.70 4.00

Energy Cost 32.60 42.20 73.60

Total Annual Operating Cost 39.10 47.10 89.20


Relamp Cost: Lamps 97 63 232

Relamp Cost: Labor 33 33 80

Energy Cost 652 844 1,472

Total 20 Year Operating Cost 782 941 1,784

20 Year Life Cycle Cost ($–undiscounted) 1,257 1,306 2,234


8% Discount Rate 1,006 1,004 1,662

10% Discount Rate 923 904 1,473

12% Discount Rate 859 827 1,325

20% Discount Rate 707 644 978



Fig. 1200-8 Fixture Retrofit Cost Analysis

Replace Existing Mercury Vapor (MV) FixturesBasis:

50,000 Sq Ft Area; Illuminated to 5 fc4,000 Burning Hrs Per Yr; Energy Cost = $0.08/kwhArea Class: Class I, Division 2, Group D

150 W HPS 175 W MV 175 W MHNumber of Luminaires Required 160 357 200Initial Lumens Per Lamp 16,000 8,600 14,000Lumen Maintenance Factor 0.60 0.50 0.55Total Lumens 1,536,000 1,535,000 1,540,000Estimated Lamp Life 24,000 24,000 10,000Avgerage Lamp Replacements/yr 27 60 80Lamp Net Cost ($) 27 16 29Luminaire Input (watts/fixture) 190 230 230Total Connected Load (kw) 30.40 82.11 46.00Fixture Cost ($) 350 0 300Installation Labor/Fixture @ $50/hr 150 0 150Relamp Labor/Lamp @ $50/hr 10 10 10Initial Installation Cost ($)Fixture Cost 56,000 0 60,000Engineering 6,000 0 6,000Installation Labor Cost 24,000 0 30,000Remove MV Fixtures ($50/fixture) 9,850 0 7,850Total Initial Cost 95,850 0 103,850Annual Operating Cost ($)Relamp Cost: Lamps 729 952 2,320Relamp Cost: Labor 270 595 800Energy Cost 9,728 26,275 14,720Total Annual Operating Cost 10,727 27,822 17,84010 Year Operating Cost ($)Relamp Cost: Lamps 7,290 9,520 23,200Relamp Cost: Labor 2,700 5,950 8,000Energy Cost 97,280 262,752 147,200Total 10 Year Operating Cost 107,270 278,222 178,40010 Year Life Cycle Cost ($–undiscounted) 203,120 278,222 282,25010 Year Life Cycle Cost ($–discounted)8% Discount Rate 167,746 186,689 223,55710% Discount Rate 161,686 170,955 213,46912% Discount Rate 156,390 157,201 204,64920 Year Life Cycle Cost ($–discounted)8% Discount Rate 201,048 273,162 279,00510% Discount Rate 187,070 236,866 255,73112% Discount Rate 175,882 207,816 237,10414% Discount Rate 166,814 184,270 222,006



1235 TemperatureTemperature can affect the installation and operation of light sources in many ways. Ambient temperatures can affect the lumen output of some fixtures. Self-generated heat in excess of that which is designed to be dissipated by the fixture can damage the ballast, lamp, base, and fixture. Ballast life is very sensitive to high ambient temperatures. For high ambient temperature areas, it may be more cost effective to use fixtures with remote-mounted ballasts, even though the initial costs for fixtures with integral ballasts may be lower. Fixtures must be mounted according to manu-facturers recommendations to correctly dissipate heat.

Incandescent Filament LampsOperation of lamps under conditions which cause excessive bulb and base tempera-tures may result in softening of the base cement and loosening of the base. In extreme cases, the fixture and adjacent wiring can be damaged. Care should be taken to ensure that the correct wattage lamps are installed in fixtures. Most fixtures are designed to dissipate a specific quantity of heat generated by the lamps. Over-voltage conditions or the use of lamps of higher wattage than the manufacturer’s rating can cause slight or severe damage. The use of incorrect wattage lamps may also affect light distribution by fixtures since the focal point will not be correct for reflectors.

Fluorescent LampsTemperature is an important factor in the performance of fluorescent lamps. The temperature of the bulb wall has a substantial effect on the amount of ultraviolet light generated by the arc; therefore, light output is significantly affected by the temperature and movement of the surrounding air. For maximum efficiency, bulb wall temperatures should be within a range of 100° to 120°F. Light output decreases about 1 percent for each 1-degree drop in bulb temperature below 100°F, and decreases a like amount for each 2-degree rise between 120° to 200°F.

When fluorescent lamps with “P” ballasts are installed, fixtures must be able to dissipate the heat which is generated. Insulation around the fixture, or a fixture installed in a high ambient temperature area, can cause the ballast protection to cut in and out, turning the lamp off and on unpredictably.

Low temperatures may also cause starting difficulty. This normally is not a problem with indoor applications, but can become a significant problem outdoors.

For outdoor applications, fluorescent lamps designed for outdoor use are recom-mended because of their high lumen output. In order to maintain high output in cold climates, the lamps must be enclosed. Enclosing the lamps shifts the peak output to a lower ambient temperature. When using lamps in cold weather without a surrounding enclosure, best results will be obtained from T10J lamps specifically designed for use in low air temperatures.

High Intensity Discharge LampsThe lumen output of the enclosed arc-tube type lamp is not significantly affected by ambient temperature. However, to insure immediate starting at low temperatures,



many HID lamps require a ballast which has a higher open-circuit voltage than that of a standard ballast designed for a temperature-controlled environment.

Because HID lamps have a long life, operating temperatures are particularly impor-tant. The effect of heat is partly a function of time, and the longer the life of the lamp, the greater the possibility of damage from high temperature. Excessive bulb and base temperatures may cause the following conditions: lamp failure, unsatisfac-tory performance due to softening of the glass, damage to the arc tube from mois-ture being driven out of the outer envelope, softening of the basing cement or solder, or corrosion of the base, socket, or lead-in wires. The use of any reflecting equip-ment that might concentrate heat and light rays on either the inner arc tube or the outer envelope should be avoided.

1236 Lamp Starting and RestartingLamp starting and restarting can be an important consideration if there is a signifi-cant time delay before light output can be achieved. This factor can be important in remote locations, or in an industrial setting where an unsafe condition may exist after a power dip if light is not restored immediately. Of all luminaires, metal halide lamps take the longest time to restart and reach full power output after a power failure.

Incandescent LampsIncandescent lamps achieve immediate light output upon starting and restarting.

Fluorescent LampsFluorescent lamps should be equipped with rapid-start ballasts which provide imme-diate starting and restarting characteristics.

High Intensity Discharge (HID) LampsAll HID lamps need time to reach full output and stable color. If the arc is extin-guished after this warm-up, the lamp will not relight until it is cooled sufficiently to lower the vapor pressure of the gases to a point where the arc will restrike with the available voltage.

Some ballasts can be equipped with a restart circuit that will provide sufficient starting voltage to overcome the higher vapor pressure of the gases. Ballasts equipped with restart circuits provide full light output immediately upon restoration of power. Battery-powered emergency lighting systems may be required for outages which are longer than momentary outages.

Epoxy encapsulated ballasts should be considered for high humidity areas and corrosive environments. The epoxy protects the ballast from possible contaminants.

Mercury Vapor (MV) LampsThe time from initial starting to full light output at ordinary room temperature varies from 5 to 7 minutes. Restrike time (including cooling time until the lamp will restart) varies between 3 and 6 minutes.



Mercury vapor lights with an auxiliary quartz lamp are available. The incandescent quartz lamp lights immediately when the circuit is restored. When the MV lamp attains 75% of its rated output, a current sensing relay turns the quartz lamp off. Quartz lamps operate at temperatures which are above those allowed for Class I, Division 1 or 2 areas.

Metal Halide (MH) LampsThe warm-up time for MH lamps is slightly less than that of MV lamps, varying between 2 and 5 minutes. Since MH arc tubes operate at higher temperatures than MV lamps, the time to cool and lower the vapor pressure of the metal halide lamp is longer, varying between 10 and 20 minutes.

High Pressure Sodium (HPS) LampsThe lamp warm-up time for HPS lamps is between 3 and 4 minutes, and full light output is reached in approximately 10 minutes. Because the operating pressure of a high pressure sodium lamp is lower than that of a mercury lamp, the restrike time is shorter, between 0.5 and 1 minute. Ninety percent of full light output is reached in 3 to 4 minutes. HPS lamps can be equipped with a special feature called “Instant Restrike” for convenience (or for use as emergency lighting) when uninterrupted illumination is required. With this feature, some light is available immediately. Light output reaches 30% of full output after 1/2 minute. Full light output is achieved in about 3 minutes.

Lamp Start and Restrike SummaryFigure 1200-9 summarizes the lamp starting and restrike times for the various HID light sources.

1237 Ballasts

Fluorescent LampsThe components of a typical rapid start ballast consist of a transformer-type core and coil, power capacitor, thermal protective device, and a potting compound (such as asphalt) containing a filler (such as silica). The average ballast life at a 50% duty cycle and proper operating temperature is about 12 years.

In the United States and Canada, it is mandatory that all fluorescent lamp ballasts be thermally protected internally. The thermally protected Underwriters’ Laboratory approved ballast is marked or labeled as “Class P.” Ballasts should also be listed by

Fig. 1200-9 Lamp Start and Restrike Time (in Minutes)

Type of Lamp

MV MH HPS Incandescent Fluorescent

Start Time 5-7 2-5 3-4 immediate immediate

Restrike Time 3-6 10-20 0.5-1(1) immediate immediate

(1) Also available with instant restrike.



the Certified Ballast Manufacturers Association (CBM). All CBM listed ballasts are also UL listed. CBM publishes sound ratings for ballasts.

High Intensity DischargeThe Constant Wattage Autotransformer “CWA” lead circuit ballast is the preferred choice for most HID installations. It consists of a high reactance autotransformer with a capacitor in series with the lamp. The capacitor allows the lamp to operate with better wattage stability if branch circuit voltage fluctuates. Other advantages of the CWA ballast are a high power factor, low-line extinguishing voltage, and lower line starting currents. Fixtures with ballasts other than CWA will require approxi-mately 60% more starting current than operating current. The CWA features allow maximum loading on branch circuits and provide more cost-effective HID lighting systems.

1238 Fixture MaterialsFixture material may be an important consideration in the selection of lighting fixtures, especially in marine environments. Underwriters’ Laboratories Standard UL-595 covers marine-type electric light fixtures. Outdoor fixtures for use on ship-board or offshore platforms should be UL-595 listed.

1239 Voltage LevelsThe voltage level of the electrical supply is discussed in Section 100, “System Design.” Incandescent and fluorescent fixtures normally are supplied with 120 volts. HID fixtures can be supplied at 120, 208, 240, 277, or 480 volts. Many loca-tions have standardized a particular voltage level. This practice should be investigated before selecting fixtures. Many locations prefer 120 volts for all fixtures for safety considerations, easier phase balancing, and reduced inventories of fixtures and ballasts.

1240 Lighting System DesignBefore the system design process can begin, the following design parameters must be determined: area classification, fixture selection, and voltage level. In addition, the following project design tasks must be completed: facility layout, mechanical equipment plans, structural plans, and emergency escape routes.

The design of any lighting installation involves the consideration of many vari-ables. These variables include: (1) lighting for detailed work, (2) flood lighting, (3) task-oriented lighting, and (4) emergency lighting. The lighting system should be designed to provide slightly more than the initial desired light to allow for lamp deterioration and dirt accumulation on the fixture lens (i.e., maintenance factor and luminaire depreciation factor). The lighting system should also be designed to provide the desired quantity of light at the particular location and in the proper visual plane. The amount of glare produced, the ease of installation and mainte-nance, and environmental suitability (e.g., indoors, outdoors, and hazardous loca-tions) should all be considered during the design phase.



1241 Distribution of LightThe distribution of light is divided into five classes: direct, semi-direct, general-diffuse (or direct-indirect), semi-indirect, and indirect.

• Direct lighting provides 90 to 100% of its light downward, and while it often is most efficient, it usually results in glare.

• Semi-direct lighting provides 60 to 90% of its light downward, with a general decrease in glare and increase in seeing comfort.

• General-diffuse (direct-indirect) lighting systems provide approximately equal components of up-light and down-light. This system emits very little brightness in the direct-glare zone. The efficiency of the system depends largely on the reflectances of all the room surfaces. This system is widely used in labo-ratories and offices.

• Semi-indirect lighting provides 60 to 90% up-light and depends on light being reflected from the ceiling and walls. This type of lighting system is used when reflected glare from room surfaces must be minimized.

• Indirect lighting systems provide 90 to 100% up-light and produce the most comfortable light. However, they have the lowest utilization of the five classes and often are difficult to maintain. Indirect lighting is preferred for control rooms with CRT monitors.

1242 Lighting MethodsTo provide the necessary quantity and quality of light for lighting system applica-tions, three types of lighting are used.

• General lighting should provide overall, uniform lighting with special atten-tion focused on the areas along walls. The lighting level at the wall should be comparable to that at the center of the room. An example of this is in the bunk areas of living quarters.

• Localized general lighting is used in areas where higher illumination levels are required. This often can be obtained by increasing the output of the general lighting system in the particular area.

• Supplementary luminaires are used to provide higher levels of illumination in small or restricted areas.

The illumination of vertical surfaces often requires special considerations to provide uniformity and, in those cases where the vertical surface is behind a transparent cover, to prevent reflected glare. Where vertical surfaces are adjacent to sources of high luminance, acceptable brightness ratios should be maintained to help avoid eye-strain caused by a large difference in brightness between the task area and the background.



1243 Illumination LevelCompany experience has shown that the lighting levels listed in API RP 540, Section 6, “Electrical Installations in Petroleum Refineries,” and API RP 14F, “Design and Installation of Electrical Systems for Offshore Production Platforms,” are adequate and are recommended for Company installations.

1244 Lighting Level ReductionIn the interest of energy conservation, lighting levels which exceed the standard recommendation should be reduced. Levels listed for office areas are based on the 1974 guidelines of the Federal Energy Administration. Persons with uncorrectable visual difficulties and those performing difficult visual tasks may require supple-mental lighting. When supplemental lighting is provided in the form of desk or floor lamps, the lamps should be selected and placed so that minimum glare is introduced.

Lighting level reductions often are made by removing fluorescent lamps from fixtures. Even if all lamps are removed from a fluorescent fixture, energy is still consumed by the ballasts. Certain considerations and precautions must be made when removing fluorescent lamps:

1. With the exception of Slim-Line (Instant-Start) lamps, all lamps connected to a given ballast should be removed. Removing only a portion of the lamps from a ballast can cause damage to the ballast from overheating. Most four-lamp fixtures operate from two ballasts, with two lamps on each ballast. Removing only one or three lamps from this type of fixture is not a safe practice. Either all four lamps should be removed or two lamps operating from the same ballast should be removed. UL rating and manufacturer’s warranties are normally invalidated if the above steps are not followed. There is one exception to this rule: any number of lamps can be removed from a Slim-Line (Instant-Start) fixture providing the fixture is equipped with circuit-interrupting lampholders as required by UL. If maintenance personnel are uncertain about the lampholder type, technical assistance should be obtained before lamps are removed.

2. When lamps are removed from a fixture, a potential voltage remains at the sockets which could be dangerous. A suitable protective cap should be used or the sockets should be taped with high temperature tape. All maintenance personnel who are likely to be working on or cleaning these fixtures should be made aware of this potentially dangerous condition.

3. As a general rule, the power factor in a given installation will not drop below 90% provided that no more than one-half of the lamps are removed. Discon-necting additional lamps lowers the power factor further, resulting in higher currents and possible utility charges for excessive use of reactive power.

4. A ballast will continue to draw current after all lamps are removed (except for fixtures with circuit-interrupting lampholders), resulting in wasted energy and possible overheating of the ballast. For example, measurements taken on a four-lamp, 40 watts-per-lamp, Rapid-Start fixture show that each ballast uses 10



watts of power with all lamps removed. Therefore, if practical, and especially if the reduction in lighting level is to be permanent, the ballast should be discon-nected from the power source.

1245 Emergency Lighting SystemsEmergency lighting is used during power failures and provides illumination by silhouetting objects. It should be provided in control rooms, at critical instrument locations, in large electrical substations, in mechanics shops, and in laboratories. Emergency systems are used to evacuate personnel, to provide light to shut down controls and equipment, and to maintain a level of illumination adequate for safety and security. It may also be required to illuminate equipment for plant startup following a power outage. Local, city, state, and federal codes may require emer-gency lighting for special areas where personnel work. Applicable codes should be reviewed carefully.

The power source for emergency lighting systems should be separate from the normal electrical source. If the same power source is used for both normal and emergency lighting, a power outage would render the emergency lighting useless. Emergency lighting power sources include engine generator sets, UPS, and batteries. If normal power is lost, light should automatically be provided in areas where the loss of light might cause personnel hazard.

1246 Company Experience with Lighting Systems

Industrial LightingHigh pressure sodium lamps are preferred for most outdoor onshore lighting appli-cations because of their lower initial capital investment and operating costs. MV or MH fixtures should be considered for offshore locations where power is locally generated (often at lower cost/KWH) and where obstructions may shadow areas (requiring more fixtures regardless of the individual fixture output). There are some applications where only a few fixtures are required or where color rendering is of primary importance. In these situations, metal halide or color-corrected mercury vapor fixtures may be preferred.

Service Station LightingMetal halide lighting is almost exclusively used for outdoor lighting at Chevron service stations. The better color rendering properties of metal halide help to main-tain the Company image and improve sales. Normally, high pressure lighting is used for tank truck loading racks and warehouse lighting.

Roadway and Parking LotHigh pressure sodium lighting normally is preferred for roadways and parking lots.

Offshore PlatformsMercury vapor and metal halide (and occasionally high pressure sodium) lamps are used for area lighting and lighting the interiors of large buildings. Fluorescent



lighting is used indoors (and at times outdoors) for area lighting, particularly where low profile fixtures are needed because of low ceiling heights.

Control Room LightingControl rooms or other rooms equipped with CRTs should be designed with indirect lighting to reduce glare. Wall-mounted or suspended indirect fluorescent fixtures with adjustable light level controls are preferred. Fluorescent lighting with para-bolic louvers (to reduce glare) can also be used for general lighting. Incandescent spot lighting can be used for task lighting. An effort should be made to prevent light penetration from other work spaces. All surfaces in control rooms should be nonre-flective.

Aviation LightingMetal halide or color-corrected mercury vapor systems are preferred for most heli-port lighting applications on offshore platforms because of their superior quality of light. Fluorescent fixtures may be required for low profile applications. Incandes-cent fixtures equipped with long-life lamps are used for landing lights.

1250 Lighting Calculations and Fixture LayoutThe three most common methods used to determine the number of fixtures required to provide the necessary maintained illumination for an area are: the lumen method, the point-to-point method, and the iso-footcandle method. The watts-per-square foot method is used for estimating purposes very early in a project or during the concep-tual phase of a project.

Generally, the lumen method is used in calculations where fixtures are installed in an enclosed space (like a room). The point-to-point method is commonly used in calculations for outside applications where reflected light is not a factor. However, either method may be used for indoor or outdoor locations. The IES Handbook and the Westinghouse Lighting Handbook contain detailed, step-by-step processes for using these two methods.

Most lighting design done by the Company is for exterior (outdoor) lighting, prima-rily for area lighting and floodlighting. This section explains two lighting-calcula-tion methods: the watts-per-square foot method for conceptual design, and the iso-footcandle method for general outdoor applications.

1251 Area LightingArea lighting for a particular operating company location should be standardized as much as possible. Designs should produce uniform and efficient lighting levels and facilitate cost-effective maintenance.

FloodlightingThe difference between floodlighting and area lighting is the aiming angle. The greater the aiming angle, the greater the area illuminated; however, light output directly beneath the fixture will be lower. Since the objective of floodlighting is to



maintain only 1 to 2 footcandles at grade, the best method is usually to angle fixtures at 60 degrees from horizontal and install them at heights of about 25 feet.

The area illuminated by floodlights can be varied by using different beam widths. This is particularly useful when the light must be directed to a specific area where an individual lighting fixture cannot be installed. Standard floodlight beam widths are specified by NEMA as follows:

Variables in Area LightingBy understanding and properly addressing the variables discussed below, an effec-tive lighting design can be achieved.

1. Fixture Reflector. The purpose for the reflector is to direct light down, as opposed to out. Figures 1200-10 and 1200-11 are iso-footcandle tables for fixtures with and without reflectors. Since the objective of area lighting is to provide light at grade level, reflectors should be used in most applications. Figure 1200-12 provides a conversion table for lamps other than high pressure sodium lamps.

2. Mounting Height. Both Figures 1200-10 and 1200-11 demonstrate that the lower a fixture is mounted, the brighter the area directly below the fixture. However, as the fixture height is lowered, the amount of peripheral light decreases. When selecting mounting height, it should be kept in mind that the objective of area lights is to achieve a fairly high illumination level directly below fixtures, and that relatively low mounting heights facilitate maintenance.

3. Angled Mounting. Angle stanchion mount fixtures are available to direct the light to one side so that fixtures need not be directly above the area to be illumi-nated. It is more efficient to mount a fixture directly above an area, but if this is not possible, angled mounts work well.

4. Angled Reflector. Angled reflectors serve the same purpose as angled mounts. A good application for an angled reflector is for fixtures mounted adjacent to buildings. Since minimal light is needed on the side of the building, as much light as possible should be directed to the area needing illumination.

NEMA TYPE BEAM SPREAD (degrees)

1 10 - 18

2 18 - 29

3 29 - 46

4 46 - 70

5 70 - 100

6 100- 130

7 130 and up

Electrical Manual

1200 Lighting


September 1990

Fig. 1200-10 Footcandle Table—Typical HPS Fixture, Standard Reflector, No Guard (See Figure 1200-12 to convert HPS footcandle values to MV or MH) Cour-tesy of EGS Electrical Group (formerly Appleton Electric)

1200 LightingElectrical M

anual

September 1990

1200-28Chevron Corporation

Fig. 1200-11 Footcandle Table—Typical HPS Fixture, No Reflector, No Guard (See Figure 1200-12 to convert HPS footcandle values to MV or MH) Courtesy of EGS Electrical Group (formerly Appleton Electric)



1252 Lumen Maintenance Factor (LMF)As lamps age, lumen output deteriorates (lumen depreciation). Dirt depreciation is the lamp depreciation associated with dirt on the lamp, lens, and reflector. Together, lamp depreciation and dirt depreciation constitute the lumen maintenance factor (LMF). Figure 1200-13 provides the recommended lumen maintenance factors to apply to various types of fixtures.

Fig. 1200-12 Conversion Table for HPS to MV or MH Courtesy of EGS Electrical Group (formerly Appleton Electric)

Fig. 1200-13 Lumen Maintenance Factors (1 of 2)

Type of Fixture Lumen Maintenance Factor

Incandescent

-Indoor 0.60

-Outdoor 0.70

Fluorescent

-Indoor 0.55

-Outdoor 0.60

Mercury Vapor

-Indoor 0.40

-Outdoor 0.50

High Pressure Sodium

-Indoor 0.55



For example, a 70-watt HPS fixture with a standard reflector and no guard, mounted 8-feet high, will provide 10 footcandles of initial illumination in a 5-foot radius. By applying the LMF of 0.6 for HPS fixtures, the illumination level design basis is 6 footcandles (10 x 0.6) near the end of rated life. If the minimum recommended illu-mination level is 12 footcandles, two 70-watt HPS fixtures spaced 5-feet apart would provide the required illumination.

1253 Watts-Per-Square Foot MethodThe watts-per-square foot method works well to determine the appropriate number of lighting fixtures required and to estimate the total lighting loads for determining initial calculations during the conceptual phase of a project.

To use this method, a six-step process is outlined below:

Step 1. Determine the illumination level for the area(s) in question.

Step 2. Determine the total square footage of the area to be illuminated from the preliminary plot plan.

Step 3. Determine the type of lighting fixture to use from Figure 1200-1, Light Fixture Selection.

Step 4. Determine the watts per square foot from Figure 1200-14.

Step 5. Obtain the total wattage required by multiplying the watts per square foot (from Step 4) by the area to be illuminated (from Step 2).

Step 6. Determine the total number of fixtures required by dividing the total wattage required (from Step 5) by the wattage of each lamp (from Step 3).

1254 Iso-Footcandle MethodThe iso-footcandle lighting-calculation method works well for outdoor locations, but is not well suited for indoor applications. Figure 1200-15 shows an iso-foot-candle chart for a 70-watt HPS fixture with a standard dome reflector mounted at an elevation of 8 feet. Iso-footcandle charts show lines of equal footcandles that will be produced by a specific fixture at a given height. These curves are created from photometric test data, and are representative of the lamp’s actual output. Iso-foot-candle charts are useful as they can be superimposed on the design plot plan and relocated until satisfactory light levels are achieved. Iso-footcandle charts (IFCs)

-Outdoor 0.60

Metal Halide

-Indoor 0.45

-Outdoor 0.55

Fig. 1200-13 Lumen Maintenance Factors (2 of 2)

Type of Fixture Lumen Maintenance Factor



may be hard to obtain for a specific fixture and often have to be scaled to match the plot plan. An alternative to the iso-footcandle chart is the iso-footcandle table, which is readily available from most fixture manufacturers. Using this data, iso-footcandle levels can be placed on the plot plan.

Sections 1255 and 1256 present two examples that illustrate the layout of lighting fixtures using the iso-footcandle method.

Fig. 1200-14 Chart for Determining Watts per Square Foot



1255 Fixture Layout Using Iso-Footcandle ChartsFigure 1200-16 shows a plot plan of a tank truck loading dock, including area clas-sification. The facility consists of a pump pad, an elevated valve manifold platform, an MCC, walkways, and a parking lot.

The first step for fixture layout is to determine the proper illumination levels for the various areas. The lighting levels listed in Figure 1200-17 were chosen from API RP 540, Section 6.

High pressure sodium fixtures have been selected since they have the highest lumen efficacy and adequate color rendering. The first decision is whether to use flood-lights or area lights. The pump pad and valve platform could be adequately lit with two floodlights. A better choice, however, is to use three or four area lights because a uniform light level over the entire area (including the two stairways) can be achieved. Logical locations for the area lights would be the perimeters of the pump pad and the valve platform. In particular, placing a luminaire on an 8-foot stanchion near each stairway would light both the platform and the stairs. The 8-foot height also provides ease of relamping. Using the lumen method, three 70-watt HPS lamps will provide adequate light for the pump pad and elevated platform. The next step is to use the detailed iso-footcandle method.

An iso-footcandle chart (drawn to plot-plan scale) for a 70-watt HPS fixture mounted 8-feet high is shown in Figure 1200-18. The values are for initial foot-candle levels. A lumen maintenance factor of 0.6 for HPS lamps (from Figure 1200-13) will reduce the radiated light shown on the chart by a factor of 0.6.

Pump Pad and Elevated Valve PlatformThe iso-footcandle chart (drawn to the scale of the plot plan) is now located at the top of each stairway, and one more fixture is located to provide the three fixtures called for in the lumen method. Figure 1200-19 shows the iso-footcandle lighting level of the three fixtures. One more fixture is needed near the valve wheels on the tank-side of the platform to achieve a reasonably uniform 5 footcandles (including lumen maintenance factor) on the pump pad and valve platform.

WalkwayThe walkway requires a minimum of 1 footcandle. An iso-footcandle chart (IFC) is superimposed on the plot plan to locate the fixtures along the walkway. Using 70-watt HPS fixtures mounted at 8 feet, the result is one fixture, 15 feet from the valve platform, and two more at 25-foot intervals at the loading dock area. Figure 1200-20 shows the results.

MCCNote that the walkway fixtures do not provide adequate light at the MCC where a minimum of 5 footcandles is required. Another fixture should be located to one side of the MCC. The location in Figure 1200-21 was chosen for two reasons: first, to light the face of the MCC at an angle from the side so an operator standing in front of the MCC will not receive any glare from glass-instrument faces; and second, to



Fig. 1200-15 Iso-Footcandle Chart for Stanchion Mount Fixture Courtesy of EGS Electrical Group (formerly Appleton Electric)



provide some light on the guard posts to the side of the MCC so that a person walking from the MCC to the parking area will see the posts.

Fig. 1200-16 Plot Plan for Fixture Layout Using Iso-Footcandle Charts

Fig. 1200-17 Desired Lighting Levels for Areas in Figure 1200-16

Area Lighting Level (footcandles)

Pump Pad 5

Elevated Valve Platform 5

Stairs 5

Area of Loading Dock 10

Paved Walkways 1

Instruments and Gages 5

Parking Area 1



Loading DockThe illumination level on the loading dock needs to be much higher than other areas. By inspection, the 70-watt HPS will not provide adequate lumen output per fixture. In addition, the canopy above the loading rack is 15 feet above grade. By choosing a 100-watt HPS pendant-mounted fixture with a 4-foot pendant, plus the fixture length of 1 foot, the fixture height is 10 feet above grade. Figure 1200-22 shows the IFC drawn to scale for this fixture, superimposed on the plot plan. Two fixtures are located to provide the desired 10 footcandles in the loading area. The area of the overhang normally will be occupied by a tanker truck and will only receive partial lighting.

Parking LotThe final area to be illuminated is the parking lot. Floodlights should be used for this application since the area is larger and light levels need not be uniform or high. A single, 150-watt HPS floodlight, mounted 20 feet above grade (as shown in Figure 1200-23) will provide the necessary lighting levels across the parking area and is high enough that so it will not blind people walking to the loading dock from the parking area.

1256 Fixture Layout Using Iso-Footcandle TablesIso-footcandle tables can also be used to determine fixture locations. Figure 1200-10 is an iso-footcandle table for a 70-watt HPS fixture with a reflector. The table indicates the amount of light at grade level from a light source mounted at a given height.

Fig. 1200-18 Diagram of Iso-Footcandle Chart for 70 Watt HPS Plot-Plan Scale

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1200-36Chevron Corporation

Fig. 1200-19 Pump-Pad Platform Lighting Level

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Fig. 1200-20 Walkway Lighting Levels

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Fig. 1200-21 MCC Lighting Levels



When using iso-footcandle tables, the best method to overlap light output from different sources must be determined in order to achieve desired light outputs. For instance, assume it is necessary to light a circle of 5-foot radius to 5 footcandles. One 70-watt HPS fixture with a reflector, mounted at 8 feet, will light a 5-foot radius circle to 6 footcandles (after a 60% maintenance factor is applied). See Figure 1200-24 (top). Therefore, one fixture will fulfill the requirement.

Assume the area to illuminate is 10 feet by 20 feet. Two 70-watt HPS fixtures, spaced 15 feet apart, will do the job. When two fixtures are adjacent, the resulting footcandle level is the sum of the contributions from each fixture. For example, the sum of the contributions at the center of the 10-foot by 20-foot area is approxi-mately 6 footcandles. See Figure 1200-24 (bottom).

To illustrate the iso-footcandle table method, Figure 1200-25 shows a plot plan where two gasoline pumps are to be installed in an area adjacent to a pipeway. The area classification is shown by hashed marks representing a Class I, Division 2, Group D area. Two new walkways and a small parking lot are to be added. The only existing lights in the area are the streetlights on the road and the floodlights by the existing pump station. A lighting survey has shown that the existing illumination where the new facilities are to be installed is essentially zero. To determine the lighting levels in Figure 1200-25, refer to API 540, Section 6.

High pressure sodium fixtures are used for this application since they have the lowest life-cycle cost and adequate color rendering for the application.

To design the lighting system, divide the new area into four sections: (a) the parking lot, (b) the walkways, (c) the pumps, and (d) the pump manifold.

Parking LotA 250-watt, HPS widebeam floodlight, mounted at a height of 25 feet and aimed at 60 degrees, illuminates an oval shaped area 70 feet by 50 feet to approximately 1 footcandle. Because of the lumen maintenance factor, two floodlights will be required to adequately light the 75-foot by 65-foot parking lot to an illumination level of about 1 footcandle (2 x 1 fc x 0.6 = 1.2).

Mounting both floodlights on a single pole (compared to two poles) in the middle of the right side of the parking lot will reduce costs. The fixtures are aimed at 60 degrees to the opposite corners of the parking lot. There may be shadow areas that may not achieve 1 footcandle, but most of the lot will be adequately illuminated.

With most multiple floodlight designs, it is virtually impossible to avoid shadow areas and still achieve a cost-effective design. Lighting design pamphlets available from major lighting manufacturers can be used as guides.

WalkwaysFor standardization purposes, 70-watt HPS fixtures mounted at a height of 8 feet will be used throughout the facility. Standardization simplifies the design, construc-tion, and maintenance of the facility. From Figure 1200-10, about 1 footcandle can be maintained (including the lumen maintenance factor) for a horizontal distance of

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Fig. 1200-22 Loading Dock Lighting Levels

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Fig. 1200-23 Parking Lot Lighting Levels



12.5 feet. Fixtures will be separated by 25 feet. One fixture is installed on the paved walkway, 12.5 feet from the parking lot. Four more are installed along the walkway toward the new pumps, 25 feet apart. Along the 225 foot walkway towards the pump station, a fixture is installed 12.5 feet from the intersection of the two new walkways and eight more are installed along the walkway towards the pump station, 25 feet apart.

PumpsSeventy-watt HPS fixtures spaced 12.5 feet apart (one per pump) will provide the required 5 footcandles of illumination.

Fig. 1200-24 Lighting Level at a Radius of 5 ft. Circle (top) and Lighting Level at Center of 10 ft. by 20 ft. Area (bottom)

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Fig. 1200-25 Iso-Footcandle Plot-Plan: Example Showing Iso-Footcandle Table Method



Manifold AreaThe general area to be illuminated around the pump is approximately 50 feet by 50 feet. One 250-watt HPS floodlight on a 25-foot pole will sufficiently light the general area to approximately 1 footcandle and keep the fixture out of the classified area.

1260 Maintenance ConsiderationsIf a regularly scheduled maintenance program is not followed, the effectiveness of a lighting system can be substantially reduced. Proper maintenance is usually more economical than allowing the system to operate at low efficiency.

A good maintenance program involves: (1) replacing lamps, (2) cleaning fixtures, and (3) cleaning lighted surfaces.

Replacing Lamps (Relamping)Two different approaches may be taken in relamping programs: (1) replace lamps as they extinguish, or (2) replace all lamps at one time (group replacement). The first approach, individual lamp replacement, is usually the least cost-effective method. The labor portion of the relamping program typically dominates the total cost. When the labor cost is not the largest portion of relamping cost, the first approach is the more economical (e.g., on offshore platforms.)

A group replacement scheme can be developed for a given installation by consid-ering the cost of labor and lamps, lamp life, and the effect of work interruptions. A commonly used criterion for group replacement is: When 20% of the original lamps have failed, the entire installation is relamped. This approach cannot be used if fixtures provide light for specific locations.

The time between replacements may vary somewhat because of variations in system voltage and operating schedules. Overvoltage or undervoltage should be suspected if the replacement interval is several months shorter than normal.

Cleaning FixturesIn some instances, dust and other foreign material on lighting equipment can reduce the lighting level by 30% in only a few months. The type of ventilation and cleanli-ness of the surrounding area determine the required cleaning intervals. It is impor-tant to clean fixtures regularly. If fixture cleaning is coordinated with group lamp replacement, maintenance costs usually can be kept to a minimum.

Fig. 1200-26 Desired Lighting Levels for Iso-Footcandle Areas in Figure 1200-25

Area Lighting Level (footcandles)

Pump Pad 5

Pump Manifold/General Area 1

Walkways 1

Parking Lot 1



Cleaning Lighted SurfacesCleaning interior lighted surfaces usually is an important maintenance factor. If an illumination survey indicates less than the design level illumination after lamp replacement and fixture cleaning, the lighted surfaces may need painting or cleaning. However, a check should be made first to insure that low voltage is not the problem.

1270 Glossary of TermsAverage Luminance: The average brightness of a luminary at a given angle, expressed in candles per square inch or footlamberts.

Ballast: An electromagnetic device used to control starting and operating condi-tions of electric discharge lamps.

Brightness: See luminance.

Brightness Ratio: See luminance ratio.

Candela: Unit of luminous intensity (preferred over the term candle).

Candle: Unit of luminous intensity (candela is preferred).

Candlepower: Luminous intensity expressed in candelas.

Dekalux: 10 lux (0.929 footcandles.)

Electric discharge lamp: A lamp in which light is produced by passing an arc current through a vapor or gas.

Fixture: A full assembly of lamp, ballast (if necessary), socket, holder, diffuser, lens and guard. The term luminaire is used interchangeably with fixture.

Footcandle: The unit of illumination used in the United States. It is equal to the illumination of a surface area of 1 square foot on which there is a uniformly distrib-uted flux of 1 lumen. One footcandle equals 10.76 lux or 1.076 dekalux.

Footlambert: The unit of luminance (brightness).

Glare, Direct: Glare resulting from high brightness in the field of vision.

Glare, Disability: Glare which reduces visibility and causes discomfort.

Glare, Discomfort: Glare that produces discomfort, but does not necessarily reduce visibility.

Illumination: The quantity of light (lumens) falling on a given surface area.

Lumen: The unit of luminous flux. The amount of light flux radiated into a solid angle by a uniform light source. In practice, it is the unit of light output that lamp manufacturers identify on their specification sheets.

Lumen maintenance: Data, usually given in graph form, showing the effect of age on the output of a lamp.



Luminaire: A complete lighting unit which consists of a lamp with components to distribute light, the parts to protect and position the lamps, and the parts to connect the lamps to the power supply.

Luminance: Brightness, the luminous intensity of a surface in a given direction, per unit of projected area of the surface.

Luminance ratio: The ratio of brightness between any two areas in the field of vision.

Luminous Efficacy: The ratio of luminous flux (lumens) output to electrical power (in watts) input for a lamp, expressed in lumens per watt.

Luminous flux: The time rate of flow of light, expressed in total output of a light source in lumens.

Lux: The International System Unit (SIU) of illumination, equal to the illumination on a surface area of 1 square meter on which there is a uniformly distributed flux of 1 lumen. One lux equals 0.0929 footcandles.

Mounting height: The distance from the work plane to the center of the lamp.

Reflectance: The fraction of the total luminous flux incident on a surface that is reflected.

Work plane: The plane where the task under consideration is located and where the recommended illumination is required.


1281 Model Specifications (MS)There are no specifications for this section.

1282 Standard DrawingsThere are no standard drawings in this guideline.

1283 Data Sheets (DS), Data Guides (DG), and Engineering Forms (EF)*ELC-EF-484 Lighting Schedule

*ELC-EF-599 Lighting Standards, Flood Ltg. Fixtures & Mtg. Details

*ELC-EF-600 Standard Lighting Poles, Fixtures, and Receptacle Mountings



1284 Other ReferencesAmerican National Standard Practice for Industrial Lighting (ANSI/IES RP-7)

American National Standards Practice of Office Lighting (ANSI/IES RP-1)

*American Petroleum Institute RP 14F, “Design and Installation of Electrical Systems for Offshore Production Platforms”

*American Petroleum Institute RP 540, “Recommended Practice for Electrical Installations in Petroleum Processing Plants”

Code for Safety to Life from Fire in Buildings and Structures, ANSI/NFPA No. 101

Electrical Construction Guidelines for Offshore, Marshland, and Inland Locations, revised August 1988, CUSA Eastern Region Production Department

ANSI/IEEE Std 45, “IEEE Recommended Practice for Electric Installations on Shipboard”

IES Lighting Handbook, 1984 Reference Volume and 1987 Application Volume

IES RP 12, “Recommended Practice for Marine Lighting”

National Electric Code, ANSI/NFPA 70

U.S. Coast Guard Regulations, Federal Register Title 33, July 1, 1987, “Pollution Prevention - Regulations for Marine Oil Transfer Facilities,” Paragraph 154.570, Lighting, and Paragraph 155.79, Deck Lighting. Washington, DC

Westinghouse Lighting Handbook, Revised May, 1978 (No longer published)


1300 Auxiliary Power Systems

AbstractThis section describes auxiliary power systems in industrial plants and provides guidelines for specifying the most commonly used equipment for auxiliary power systems. It also lists and describes various disturbances and outages in power systems, their effects, and methods for managing them.

Contents Page


1311 Scope

1320 Types of Disturbances and Outages 1300-3

1321 Power System Disturbances

1322 Power System Outages

1330 Solving Power Problems 1300-5

1331 Disturbance Problems

1332 Outage Problems—Emergency and Standby Systems

1340 Equipment Used for Auxiliary Power Systems 1300-6

1341 Common Equipment

1350 Power Conditioning Equipment 1300-16

1351 Power Synthesizer

1352 Motor-Generators

1353 Uninterruptible Power Supply (UPS)

1354 Dual Feeds

1355 Summary


1361 Model Specifications



1300 Auxiliary Power Systems Electrical Manual



Electrical Manual 1300 Auxiliary Power Systems


1310 IntroductionGenerally, the most convenient and economical source of electric power is a local electric utility (commercial power). The quality and reliability of the power is, in most cases, adequate and acceptable. Some locations, notably offshore, are not served by local utilities. Certain types of equipment, facilities, plants, and processes require high quality electric power and reliability that cannot be met by commercial power. In these situations the most cost effective method of supplying power (at the required standards) must be determined. This may require adding power condi-tioning equipment, requesting the electric utility to install additional or parallel facilities, or installing an emergency or standby power system.

1311 ScopeThis section identifies the common types of power deficiencies that can occur and outlines the steps that can be taken to minimize or eliminate their effect on opera-tions. A full engineering analysis of all types of power conditioning equipment and emergency and standby power systems is beyond the scope of this section. However, a brief discussion of the various alternatives is presented. This section also provides descriptions and general guidelines for specifying and sizing equip-ment that is commonly used for auxiliary power systems.

1320 Types of Disturbances and OutagesThis section provides a brief description of possible power system disturbances and outages.

1321 Power System Disturbances

Transient and Oscillatory OvervoltageVoltage spikes may exceed 200 to 400% of rated rms voltage, with durations of 0.5 to 200 microseconds. They may be oscillatory up to 16.7 milliseconds at frequen-cies of 0.2 to 5 kHz and higher. Voltage spikes are caused by lightning, power network switching, and operation of large, on-site motor loads.

Electric common-mode noise is an in-phase change in voltage that appears equally on each conductor to ground, and is caused by electromagnetic or electrostatic induction from the surroundings. Normal-mode noise is a change in voltage appearing differentially between conductors. It is caused by unequal electromag-netic or electrostatic induction between the conductors and their surroundings.

The effects of transient and oscillatory over-voltages are generally limited to systems which include computers (e.g., microprocessors and process controls.) Oscillatory transients can cause damage to both hardware and software. The damage can result in errors, omissions, program upsets, and downtime. Conven-tional power, control, and instrumentation systems generally are not affected by oscillatory transients due to the relatively slow response time and the high BIL levels of the equipment.



Momentary Under- or Over-voltageUnder- and over-voltage conditions are either below 80 to 85% or above 110% of rated rms voltage, respectively. They have durations of 4 to 60 cycles, depending on the type of power system and on-site distribution. They are caused by power system faults, large load changes (possibly seasonal), and power system equipment malfunctions.

The effects of under- or over-voltage depend upon the length and severity of the voltage disturbances. At the lower end of the 4 to 60-cycle range, computer systems and some types of sensitive high speed instrumentation and control systems will be affected. The effects would be similar to those that occur in transient and oscillatory disturbances except that hardware damage seldom occurs. As the duration of the disturbance increases, more conventional types of power equipment are affected. Depending upon the severity of the under-voltage, relays and contactors may drop out, protective systems may initiate shutdowns, and control system readouts may go off scale. Generally, power utilization equipment is not affected by short duration disturbances. For instance, motors will continue to run (ride through), because of inherent inertia, with only a slight increase in slip (induction) or torque angle (synchronous). However, motors may stop because their starter contacts open due to low voltage. High-Intensity Discharge (HID) lighting (e.g., mercury vapor and high-pressure sodium), will extinguish if the voltage drops below certain levels. See Section 1200, “Lighting,” for additional details.

1322 Power System Outages

Momentary OutageA momentary outage is a short-duration power failure caused by the opening of a protective device as a result of a transient fault or overload and restored by auto-matic reclosure of the protective device or automatic transfer to an alternate source. The timing of reclosure can range from 0.5 to 60 seconds. The first reclosure usually occurs in less than 10 seconds. Some circuit protective devices are set for three or four automatic reclosures before lockout. Automatic transfer can occur in a time as short as four milliseconds (1/4 cycle) if a static transfer switch is used.

Automatic reclosure of utility system protective devices or automatic transfer to an alternate source is seldom fast enough to prevent shutdown of the supplied equip-ment when momentary outages occur. If the reclosure is too fast, many transient conditions will not clear, and a second momentary outage or a lockout will result. Depending on the facility, momentary outage problems can range from a minor annoyance to a serious hazard and financial loss. (Certain facilities may require planned orderly shutdowns to prevent equipment damage, loss of production, or product rejection.) Personnel safety should also be considered if HID lighting is involved (due to the restrike time).

Permanent OutageA permanent outage is a complete, sustained power failure due to a protective device opening as a result of (1) a fault, (2) an electrical system equipment failure,



or (3) incorrect operation of power system protective equipment. In all cases, power system operating personnel must respond before power can be restored. Outage time can range from a few minutes to days.

The effects of permanent outages are much the same as momentary outages except that production losses may become more significant. Startups can be difficult and lengthy after a long shutdown. Personnel safety could also become a problem with a total blackout.

1330 Solving Power Problems

1331 Disturbance ProblemsSolving power system disturbance problems is accomplished by evaluating the degree of power conditioning required.

First, a study should be conducted to identify the extent and nature of the power problems. The study should begin with the installation of power disturbance recording equipment. Normal system instrumentation is generally not capable of recording high speed transients and oscillations. An analysis of the power source operating records is needed to develop a complete power profile of the system. The study should continue for a reasonable period of time to ensure that the nature and magnitude of the system disturbance problems are identified.

Second, when the power profile of the system is complete, the cause of the system disturbances should be determined. (Keep in mind that the source of the disturbance could be at the power source or the facility’s distribution system.) Knowing the source of the disturbance is important to ensure that power conditioning equipment is installed at the most effective locations.

The imperfections in available power, the necessity for continuous equipment opera-tion, and the “clean” power requirements of the equipment define the extent of the power conditioning required to solve power disturbance problems. The various methods of power conditioning and their effectiveness are examined below.

1332 Outage Problems—Emergency and Standby SystemsThe effects of an outage may range from tolerable to completely unacceptable regardless of whether the outage is momentary or permanent. A careful study should be made to determine if an emergency or standby power system is necessary for personnel safety, process control, continuous equipment operation, or orderly plant shutdown.

Emergency systems are characterized by continuous (or rapidly available) electric power of limited time duration which is supplied by a separate system. Emergency systems may be supplemented by standby power systems to increase the supply time.



Standby power systems should have the following features:

1. An alternate source of electric power (separate from the normal power source).

2. Starting and regulating controls (for on-site standby generation).

3. Controls (manual or automatic) that transfer loads from the normal to standby or alternate source.

See Section 100, “System Design,” for details regarding whether an emergency and/or a standby system is required.

1340 Equipment Used for Auxiliary Power SystemsOnce it has been established that an emergency or standby power system is required, a study should be conducted to determine the proper system and hardware needs. The following questions should be answered before a decision is made.

1. What are the power requirements? Is highly reliable and/or high quality power required for process controls or computers, or is commercial quality power acceptable?

2. Is power required for only a short length of time for an orderly shutdown, or must power be provided until normal power is restored to prevent equipment or personnel hazards or financial losses?

3. Must power be available under “no-break” conditions or are momentary outages acceptable? What frequency of outages are acceptable?

4. Can several facilities be supplied from a single alternate source?

5. Can the provider of normal power (the utility) improve the reliability of its service? If so, at what cost? (Utilities usually charge customers for the cost of facilities that use power in excess of what is normally required for standard service). Customers may also be charged amortization and/or standby costs for additional equipment.

6. What is the outage history of the normal source (quantity and duration of outages)? Is the quality of service improving or deteriorating? Is the utility matching load growth with new plants, or must old plants carry a greater burden?

1341 Common EquipmentIn most industrial plants, an auxiliary power system independent of the utility power source is needed to provide uninterrupted emergency or standby power. See Section 100, “System Design” for further information.

The four most common systems used in industrial plants as auxiliary power are:

1. Generators

2. Storage Battery Systems



3. Uninterruptible Power Supplies

4. Unit Equipment (primarily for emergency lighting systems)

For more information, see IEEE Std 446, “Recommended Practice for Emergency and Standby Systems for Industrial and Commercial Applications.”

Generators

Engine-Generators. Diesel engine-generators (as shown in Figure 1300-1) are commonly used in industrial plants to provide emergency or standby power. Diesel generators are available in sizes up to several MW. Properly designed engine-gener-ators can start and accept full load in less than 10 seconds. The fuel cost is rela-tively low and fire and explosion hazards are less for a diesel engine-generator than for a gasoline engine-generator. Provisions must be made for automatic starting of the engine, automatic transfer of the load to the generator and fuel storage. For sizing generators, see Section 100, “System Design.”

For standby service, the diesel engine-generator should be specified to conform to the following conditions, it must be capable of operating at 110% of nameplate kW rating for 1 hour in every 18 hours with the generator full-load rating not exceeding 60%-80% of the engine’s maximum continuous rating. Caution! The generator normal operating load should not be less than 50% of the diesel engine nameplate

Fig. 1300-1 Typical Diesel Engine-Driven Generator Permission granted by Caterpiller, Inc.



rating. Operation at less than 50% will cause carbon buildup in the engine and decrease reliability. Removable, thermostatically controlled, electric immersion-type crankcase oil and water jacket heaters should be specified for use in cold weather climates. Fuel will also need to be heated in cold climates. Naturally aspi-rated engines are preferred over turbocharged engines.

Natural gas-fueled engines are used where natural gas or LP gas is readily available (such as on offshore platforms). They have a long life and are quick starting after extended shutdown periods. For details of natural gas engines, refer to the Driver Manual.

Gasoline engine-generators may be appropriate for installations up to 100 kW but are not recommended for offshore and metropolitan applications. Other advantages of gasoline engine-generators are:

• Rapid startup• Low initial cost• High operating costs• Gasoline is hazardous to store and handle• Low mean time between overhauls

Steam Turbine-Driven Generators. Steam turbine drivers are an alternative to engine-driven generators where steam is available. Many refineries utilize steam turbine-driven standby generators. Some problems can be expected if these are used. Governors can be a source of trouble, causing the turbine to overspeed and trip on startup. Damage to turbines may occur because of wet steam if the steam trapping is not adequate. Both of these problems can become more serious in cold climates. The decision to use a steam turbine should be carefully considered. See the Driver Manual for information on selecting a steam turbine.

Storage Battery SystemsA storage battery system is the most dependable system for providing DC power for emergency or standby power for loads (e.g., communication equipment, emer-gency lighting systems, fire and gas detection systems, and switchgear control power). A storage battery system consists of rechargeable batteries and a battery charger.

For sizing batteries and battery chargers see Section 100, “System Design.”

Batteries and battery chargers for DC power supplies should be specified in accor-dance with the attached Specification, ELC-MS-4802 and DC Power Storage Battery System Data Sheet, ELC-DS-4802.

The three types of batteries most commonly used are:

1. Lead-acid flooded cell batteries (lead-calcium and lead-antimony)

2. Sealed, valve regulated lead acid (VRLA) batteries

3. Nickel-cadmium batteries



Lead-Acid Flooded Cell Batteries. Lead-acid flooded (or wet) cell batteries use sulfuric acid and water as electrolyte and include lead-antimony and lead-calcium alloy plate designs. Detailed comparisons are shown in Figures 1300-2 and 1300-3.

Fig. 1300-2 Recommended Battery Type

Location<100 Discharges (To Final

End Voltage)>100 Discharges (To Final

End Voltage)

Controlled Temperature Environment

Lead-calcium Lead-antimony

Uncontrolled Temperature Environment

Nickel-cadmium Nickel-cadmium

Inside Office Area Sealed Lead-calcium Lead-antimony in Adjacent Battery Room

Fig. 1300-3 Comparative Features of Lead-calcium, Lead-antimony, Sealed VRLA and Nickel-cadmium Batteries (1 of 2)

Lead-Acid Nickel-cadmium

Lead-calcium Lead-antimony Sealed VRLA

Gassing Gases on float/equalize

Gases on float/equalize

Gases recombine inside battery

Does not gas on float. Does gas on high rate

Corrosive Fumes Yes Yes No No

Spillage Hazard Yes Yes No Yes

Temperature Range 32-85°F without freeze hazard or loss of life

32-85°F without freeze hazard or loss of life

32-80°F without freeze hazard or loss of life

-50-115°F without freeze hazard or loss of life

Freezing Problems Yes, when discharged

Yes, when discharged

Yes, when discharged

Only at -50°F or below

Volts/Cell, Nominal 2.0 2.0 2.0 1.2

Energy Density 10-25 WH/Lb Slightly less than lead-calcium

Low end of lead-calcium

20 WH/Lb

Mechanical Ruggedness

Good Good Good Better than lead-calcium

Maintenance Requirements

Quarterly Quarterly Quarterly Quarterly

Relative Cost Based on 20-Year Battery

100% 105% 140-200% 160-300%

Shelf Life When Filled and Not on Charge

6 mo.-1 yr. 6 mo.-1 yr. 6 mo.-1 yr. Indefinite, very long



Lead-calcium batteries may be used for many applications. They have a longer shelf life and are less expensive than lead-antimony batteries. Both of these are less expensive than sealed VRLA and nickel-cadmium batteries. Lead-calcium batteries require fewer equalizing charges and charge more efficiently than lead-antimony batteries. However, lead-calcium batteries cannot tolerate discharge cycling as frequently as lead-antimony batteries.

Lead-acid type batteries do not tolerate elevated temperatures and, therefore, are recommended only for use in temperature-controlled environments. The life of a lead-acid battery is reduced by 50% for each 15°F above 77°F. Lead-acid batteries require low voltage disconnects to prevent full discharge, from which they cannot be recharged economically.

Lead-Acid Sealed Batteries. Sealed, valve-regulated lead acid (VRLA), lead-calcium batteries have a minimum amount of electrolyte which is absorbed in the absorbtive glass mat (AGM) separator material or contained in a gel. Gas is not emitted under normal usage, therefore, water normally does not need to be replaced.

Specific Gravity Changes to indi-cate state of charge

Changes to indi-cate state of charge

Changes (cannot monitor)

Stays constant, does not indicate charge state

Cycling Capability Average 100 cycles to end of voltage

Good, 500 cycles to end of voltage

Average 100 cycles to end of voltage

Very good, 2000 or more in lifetime

Ability to With-stand Complete Discharge

Poor, severely reduces life



Very good, no damage on complete discharge

Ventilation Requirements

Required, gases on float/equalize

Required, gases on float/equalize

Not required under normal conditions

Required, gases on high rate

Special Room Required?

Yes, normally Yes, normally Temperature controlled

Yes, normally

Frequency of Use Widely used About 10-20% About 30-50% Use is low, mainly due to high cost

Disposal Normal battery disposal

Normal battery disposal

Normal battery disposal

Hazardous waste disposal

Years in Field Application

40+ years 75+ years 8 years in U.S. 40+ years

Life to 80% Capacity with Minimum Cycling

15-20 years 15-20 years 5-15 years (Depending upon design)

20+ years

Note Additional comparative battery data is available in API RP-14F.

Fig. 1300-3 Comparative Features of Lead-calcium, Lead-antimony, Sealed VRLA and Nickel-cadmium Batteries (2 of 2)

Lead-Acid Nickel-cadmium

Lead-calcium Lead-antimony Sealed VRLA



The advantages of sealed lead-calcium batteries are:

• No need to add water• Can be installed without venting provisions• Can be tilted without spilling electrolyte

The disadvantages of the sealed VRLA batteries are:

• More expensive than wet cell, lead-calcium batteries• Same temperature degradation as other lead-acid cells• Subject to thermal runaway due to overcharging and electrolyte dryout• Same limited cycling as other lead-calcium cells• Approximate 5-year life• May vent on high overcharge rates

Nickel-Cadmium Batteries. Nickel-cadmium batteries are made with nickel-cadmium plates in an electrolyte solution of potassium hydroxide and pure water.

Except for standby switchgear control power applications, nickel-cadmium batteries are not frequently used in on-shore plant applications. Their initial cost is more than lead-acid batteries, but their cost per amphour, per year, may be less. More cells are required for a nickel-cadmium battery than for a lead-acid battery of the same voltage. The nominal nickel-cadmium cell voltage is 1.2 volts, compared to 2.0 volts for lead-acid batteries.

In offshore platform operations, nickel-cadmium batteries are recommended for most applications (except for engine cranking service where lead-acid batteries are used). Nickel-cadmium batteries have a longer life, are more ruggedly constructed, and are more tolerant of elevated temperatures. They can be charged after a full discharge (common during platform evacuations), they can withstand ten times as many discharge cycles, and they require less maintenance. The nickel-cadmium cell also has a much lower self-discharge. As a result, if a nickel-cadmium battery is not discharged with an external load, it will remain charged for a longer time than a lead-acid battery.

Nickel-cadmium batteries can tolerate much harsher temperatures than lead-acid batteries. Nickel-cadmium batteries can operate more efficiently at much lower temperatures than lead-acid batteries. The life of a nickel-cadmium battery is mini-mally affected by temperatures up to 115°F. Pocket plate, as opposed to sintered plate, cells should be specified. Sintered plate cells are subject to thermal runaway.

Battery Chargers. A battery charger converts AC voltage into a regulated DC voltage. Battery chargers are selected to deliver a float charge to maintain a battery at full charge and will restore it from a discharged state to a fully charged state within a specified period of time. The charger keeps the battery fully charged at all times so that the battery will be available during failures of normal power. In this system, the battery does not supply load current unless the charger is overloaded or



shut down. The special features that distinguish a battery charger from a conven-tional rectifier are:

1. Close output voltage regulation over the full range of rated-output current and input voltage

2. Current-limiting capacity (including discharged batteries)

3. Automatic switching from a voltage-regulating mode to a current-regulating mode at preselected values of output current

4. Stable output when connected to a fully charged or discharged battery

SCR type battery chargers are most commonly used.

Charging methods. Several charging methods are available. The choice of method depends primarily on the service intended for the battery system. The most common charging methods are:

1. Float

2. Trickle

3. Equalizing

Float charging. Float charging is a condition where the battery is permanently connected to a constant potential charging device from which the battery receives its charge, and delivers energy on demand. This method is used for uninterruptible power supply (UPS) systems.

Trickle charging. Trickle charging is continuous, constant current charging at a low rate. Trickle charging, at a rate which is several times the rate of self-discharge, is used primarily for emergency and standby systems.

Equalizing charging. Because of minor differences among individual cells in lead-acid batteries, not all cells in a multi-cell battery display identical current efficien-cies in charge and discharge. As a result, the state of charge of the cells becomes unbalanced when charged by constant potential methods. Therefore, batteries are periodically overcharged with an “equalizing” charge commonly consisting of a 110% constant current charging for a period of approximately 25-30 hours (depending on the battery design and application).

Uninterruptible Power Supplies For AC PowerThe primary function of an uninterruptible power supply (UPS) is to provide crit-ical loads with uninterrupted clean, and stable AC power. (Clean and stable is defined as having minimal harmonic distortion and being free of transients and voltage swings.)

For sizing UPS systems see Sections 124, 134, and 135 in “System Design”.

UPS systems utilize standby storage batteries to provide clean AC power for a limited time during power outages. If power is not restored, the UPS will shut down when the batteries are nearly discharged. The UPS may provide power for critical



systems to allow orderly shutdowns and to provide for personnel safety. The typical UPS system is solid state, contains a battery charger, storage batteries, a static inverter, and a static transfer switch. The battery is sized to provide the system standby time requirements (typically 15 minutes to 4 hours).

UPS systems should be specified in accordance with Specification ELC-MS-2643, “Solid State AC Uninterruptible Power Supply,” and Data Sheet, ELC-DS-2643.

Under normal operation, the AC power supplies the rectifier and the battery charger which provides DC input power to the static inverter and charges the battery. The inverter supplies power to the AC load through a transformer, if required. Because this is the normal mode of operation, any power disturbance that may occur in the incoming AC line will not be transmitted to the AC load. With this system, the AC output of the inverter can, therefore, be of better quality than the normal AC power source. If the UPS fails or is overloaded, it will be bypassed automatically through a static transfer switch to the internal bypass circuit.

If a fault occurs on a downstream branch circuit that exceeds the inverter’s capa-bility (normally about 150% of rated current), the output will be transferred from the inverter to an AC bypass through a static transfer switch. The transfer is neces-sary as the inverter is normally incapable of supplying the energy necessary to clear a fault. Upon sensing a fault, the SCR’s in the static transfer switch will begin conducting in 1/2 cycle. For a period of 2-1/2 to 6 cycles, the UPS inverter output and the bypass will be in parallel, supplying fault current. After 6 cycles, the inverter-output circuit breaker opens and fault current is supplied by the bypass. Since most short circuits are ground faults and most UPS branch circuits are protected by circuit breakers, the short circuit condition will persist for about 3 - 10 cycles. During the fault time period of between 0.05 to 0.2 seconds, all UPS branch circuits will be subject to the effects of the fault, notably a low voltage condition.

The magnitude and location of the fault will determine the voltage drop on the system. The duration of the voltage drop depends upon the time the protective device takes to clear the fault. If branch circuits are protected by current limiting (CL) fuses and if the fault current is within the current limit range, a faulted branch will clear in less than one-half cycle. Voltage dip is minimized by the fast action of the CL fuse. (See Section 124 and 645 for more discussion on the UPS branch circuit protection.)

A UPS inverter should be capable of supplying fault current for 1/2 cycle, the time necessary for a CL fuse to clear a fault and not transfer to the bypass.

If a transfer has been made and the system has stabilized, an automatic retransfer to the inverter is advised. All manufacturers provide the automatic retransfer feature.

A manual external bypass switch is recommended to allow switching the load to the AC line, which isolates the inverter and static switch for maintenance. The manual bypass switch should have make-before-break contacts to permit bypass of the load without any interruption.

The UPS may consist of single (see Figure 1300-4) or multiple modules (see Figure 1300-5). It is recommended that the isolated redundant system with two sets



of batteries be used for most systems where the process is critical and instrumenta-tion cannot operate properly on utility power. This system is suitable for loads with dual power supplies. Each UPS is sized to carry the entire load and each UPS supplies an input to the dual power supply.

Although more expensive than a single system, the isolated redundant system is more reliable for providing power to instrumentation, and may be justified for crit-ical processes where the instrumentation requires continuous higher quality power than that which is available from normal power. (See Figures 1300-4 and 1300-5.)

Fig. 1300-4 Non-Redundant UPS Configuration with External Maintenance Bypass



Fig. 1300-5 Isolated Redundant with Individual Batteries and External Maintenance Bypass



If a standby generator is provided, the UPS system should be connected to the standby bus to reduce the required capacity of the batteries.

Unit EquipmentTwo types of unit equipment are available for emergency lighting: AC emergency lighting inverter units and self-contained individual emergency lighting units. In AC emergency lighting inverter units, utility power is fed directly to the lighting load via a transformer and a static switch. The inverter is normally off and the batteries charged. When utility power fails, a high speed circuit detects the failure and simul-taneously turns on the inverter (battery powered) and disconnects the utility input with the static switch. When utility power is restored, the static switch simulta-neously turns off the inverter and transfers the lighting load back to the utility source without interruption of power to the load.

AC inverter units are used primarily for providing emergency lighting power when there are no standby generators for emergency power or when standby high inten-sity discharge lamps are used in the emergency lighting system. High intensity discharge lamps that have been illuminated will extinguish with power interrup-tions, and will not relight for 10 minutes or more (if not provided with instant restrike). See Section 1200, “Lighting.”

AC Emergency Lighting Inverter Units (ACELIU) cost less than UPS systems but do not provide the same quality of power. However, they do provide continuous power upon failure of utility power. They can be used for emergency lighting and other loads (such as P.A. systems) which do not require high quality power.

Completely self-contained individual emergency lighting units are also available. These units usually contain the following: a trickle charger, an inverter, a battery (normally nickel-cadmium), a solid state switch, an indicator lamp, and a test switch. They are used for emergency exit signs and emergency lighting fixtures. These units are used where economics do not justify a central supply system such as that described above. They typically supply emergency light for up to 1-1/2 hours.

1350 Power Conditioning EquipmentThe following methods should be considered to modify and improve incoming power waveforms by clipping, filtering, isolating, increasing, or decreasing the voltage before delivering power to the equipment.

Isolation transformers can prevent power system noise from disturbing sensitive equipment. They should be installed as close to the protected equipment as possible. The isolation transformer will reduce common-mode noise and electro-magnetic interference (EMI). It does not provide protection from normal-mode tran-sients, regulate line voltages, or reduce distortion. Transformer taps allow higher or lower output voltage levels to be set. The transformer should have the capability to sufficiently attenuate electrical noise. An electrostatically shielded isolation trans-former is very effective in reducing common-mode noise.



For protecting computer-controlled data processing systems, pre-engineered power systems should be considered. They contain the following isolation and distribution equipment: (1) an isolation transformer with an electrostatic shield and voltage adjustment taps, (2) a main circuit breaker with a shunt trip feature, (3) a circuit breaker panel, and (4) an insulated, shielded flexible conduit with appropriate wiring and receptacles for the equipment to be serviced. The system is portable, and can be placed close to the system being protected, and provides power that is almost free of spikes and transient disturbances.

Transient-voltage surge suppressors are devices (usually solid state) that reduce transient disturbances (spikes) on supply lines to sensitive equipment without reducing line voltage below its steady state value. Surge suppressors clip high voltage spikes and transients. They do not provide protection from noise, voltage sags, long-term high voltage, or voltage spikes that do not exceed the clamping limits.

To ensure better voltage regulation, feeders should be designed with the impedance as low as possible to minimize voltage drops, and the electrical loads should be balanced on the phases.

For an existing system, an alternative is to install a line-voltage regulator. A line-voltage regulator maintains steady state voltage within desired operating limits and permits reduction of transient voltage disturbances of short duration. The inherent limitations of a typical regulator allow short-term variations to be transmitted to the load and offer no protection from waveform distortion.

The following power conditioning methods offer the most dependable means of delivering power without spikes, noise, and voltage fluctuations by creating a new, completely isolated power output waveform.

1351 Power SynthesizerAn AC magnetic power synthesizer uses pulse transformers, inductors, and capaci-tors to create the desired AC output waveform. The system is virtually maintenance free and will maintain power during a loss of input power for one cycle.

1352 Motor-GeneratorsMotor-generators are one of the oldest methods for providing high quality power. These are often used where 400 Hz power is required. A motor draws power from the utility line to drive an alternator, which in turn supplies power to the equipment. The inertia stored in the rotor provides power for several cycles or longer after a loss of input power and helps maintain power during the transfer to a standby power source. Some motor-generators are equipped with a flywheel to increase the stored inertia. The disadvantages of motor-generator sets include relatively complex starting mechanisms and control circuits, as well as possible variations in frequency.



1353 Uninterruptible Power Supply (UPS)The UPS is the most expensive power conditioning system. It requires a large initial investment, considerable space (dependent to a large extent on battery back-up time), and maintenance costs can be high. See Section 1341 for more details.

1354 Dual FeedsA third alternative for protection from momentary under or over voltage distur-bances is dual feeders with a magnetic synthesizer. Two independent power sources are used in conjunction with a static switch (capable of switching in a nanosecond) and a magnetic synthesizer that will maintain power during the switching time to provide constant voltage power. Reliability is dependent on the available power sources.

1355 SummaryThe alternatives for power conditioning range from circuit modifications to total isolation of sensitive equipment from the power system. The following table summarizes and compares the effectiveness of the more common methods of reducing power system disturbance problems. (See Figure 1300-6.)

The above information is intended only as a brief summary of the various methods of power conditioning. Many variations and options are available within the various categories.


1361 Model Specifications



* ELC-MS-2643 Solid State AC Uninterruptible Power Supply

* ELC-MS-4802 DC Power Battery Storage System

* GF-P-99972 One Line Diagram 480V Emergency Power System

* ELC-DS-2643 Solid State AC Uninterruptible Power Supply Data Sheets




(1) These improvements do not suppress disturbances but can make the load less sensitive to voltage disturbances.

API RP 14F, Design and Installation of Electrical Systems for Offshore Production Platforms

API RP 540, Recommended Practice for Electrical Installations in Petroleum Processing Plants

ANSI/IEEE Standard 446, IEEE Recommended Practice for Emergency and Standby Power Systems for Industrial and Commercial Applications.

* ELC-DG-2643 Instructions for Solid State AC Uninterruptible Power Supply Data Sheet

* ELC-DS-4802 DC Power Storage Battery System Data Sheet

* ELC-DG-4802 Instructions for DC Power Storage Battery System Data Sheet

Fig. 1300-6 Comparison of Power Conditioning Methods

Method

Condition

Transient and Oscillatory Over-voltage

Momentary Under-voltage or Over-voltage

Balanced load on three-phase supply with improved grounding

Some improvement(1) Some improvement(1)

Surge suppressor, filters, and light-ning arrestors combined

Suppresses most voltage spikes No effect

Shielded isolation transformer Eliminates most source voltage spikes; does not eliminate load-generated spikes

No effect

Line-voltage regulator Eliminates some source voltage spikes; does not eliminate load generated spikes

Some, depending on regulator response time

Magnetic synthesizer Eliminates all voltage spikes Eliminates most, depends on capability to maintain generated power during voltage fluctuation

Motor-generator Eliminates all voltage spikes Eliminates most, depends on capability to maintain generated power during voltage fluctuation

Uninterruptible power supply Eliminates all voltage spikes Eliminates all under- and over-volt-ages, and spikes

Dual feeders No effect Eliminates most under- and over-voltage

Note The above information is intended only as a brief summary of the various methods of power conditioning. Many variations and options are available within the various categories. Refer to the text for details.



ANSI/IEEE Standard 484, IEEE Recommended Practice for Installation Design and Installation of Large Lead Storage Batteries for Generating Stations and Substa-tions.

ANSI/IEEE Standard 485, IEEE Recommended Practice for Sizing Large Lead Storage Batteries for Generating Stations and Substations.

IEEE, Diagnosing Power Quality Related Computer Problems, Transactions Indus-trial Applications

ANSI/NFPA 70, National Electric Code

ANSI/NFPA 101, Code for Safety to Life from Fire in Buildings and Structures.

ANSI/UL924, Emergency Lighting and Power Equipment

Linden, Handbook of Batteries and Fuel Cells, N.Y., McGraw-Hill, 1984.


1400 Electrical Checkout, Commissioning, and Maintenance

AbstractThis section establishes requirements for the checkout and commissioning of newly installed or upgraded electrical systems. It discusses preventive maintenance of elec-trical systems and equipment. Inspection and Testing checklists are provided. Company equipment specifications and data sheets for factory check-out and testing of most equipment are also in this section.

Contents Page

1410 General 1400-3

1411 Scope

1412 Safety

1413 Documentation

1420 Testing Methods 1400-4

1421 Visual Inspection

1422 Insulation Testing

1423 Insulating Liquid Testing

1424 Protective Device Testing

1425 Impedance and Resistance Measurements

1426 Infrared Inspection

1427 Transformer Fault-Gas Analysis

1428 Functional Testing

1429 Operational Testing

1430 Factory Testing 1400-9

1440 System Check-Out and Commissioning 1400-9

1400 Electrical Checkout, Commissioning, and Maintenance Electrical Manual


1450 Maintenance 1400-10




1463 Data Sheet (DS), Data Guide (DG) and Engineering Forms (EF)


Note All figures reprinted from NFPA are reprinted with permission from NFPA 70B, Electrical Equipment Maintenance, Copyright 1987, National Fire Protec-tion Association, Quincy, Mass. 02269. This reprinted material is not the complete and official position of NFPA on the referenced subject which is represented only by the standard in its entirety.

Electrical Manual 1400 Electrical Checkout, Commissioning, and Maintenance


1410 GeneralElectrical equipment and systems are inspected and tested during the various phases of a facility’s life. Initially, factory acceptance tests should be conducted to ensure that equipment conforms with specifications and industry standards. Electrical systems should then be checked and commissioned as part of the construction and start-up phases of a project. Finally, operating facilities require ongoing mainte-nance, inspection and testing.

1411 ScopeThis guideline discusses recommended methods for checking and testing electrical equipment and systems. Company specifications covering factory tests for different types of electrical equipment are referenced. Detailed references are also provided.

For check out and commissioning of a complete electrical facility, use of Specifica-tion ELC-MS-4744, “Electrical Systems Check-out and Commissioning,” is recom-mended. This specification covers the inspection and testing requirements for newly installed or upgraded electrical systems. It is comprehensive and may be tailored to the user’s specific requirements.

For guidance in developing an Electrical Preventive Maintenance (EPM) program, refer to NFPA 70B, “Recommended Practice for Electrical Equipment Mainte-nance.” This may be used in conjunction with facility operating experience for developing an EPM program.

1412 SafetyMany tests performed on electrical equipment involve the use of imposed high volt-ages and special test equipment.

A comprehensive safety program should be in operation before testing electrical equipment or systems. Safety procedures must be designed to prevent injury to both test and non-test personnel, as well as ensure that damage to equipment and plant shutdowns do not occur. Only qualified personnel should be permitted to participate in any test program and only proper test equipment should be used.

1413 DocumentationProper documentation of all inspections, tests, and maintenance performed is very important. During facility construction, field personnel need to follow the progress of check-out and commissioning activities so that system and plant start-ups may be scheduled in a timely manner. Test data must be recorded so that personnel may evaluate any problem areas that are detected at the time of the test or later. Also, comparison of test data throughout the life of equipment may be used to track dete-rioration and predict failures.



1420 Testing MethodsThe following discusses the basic inspections and tests which are performed on most electrical facilities. Detailed information on these testing methods can be found in Chapter 18 of NFPA 70B, “Recommended Practice for Electrical Equip-ment Maintenance.”

1421 Visual InspectionVisual inspection is critical. It includes comparing equipment and systems with design drawings, inspecting for foreign objects and contaminants, and checking for changes in appearance over time. Visual inspections should be performed during factory tests, facilities commissioning and plant maintenance.

1422 Insulation TestingInsulation failure is the most common cause of failure of electrical equipment. Insu-lation may deteriorate due to aging, environmental factors, voltage stresses, or mechanical and thermal damage. Insulation is tested by placing a test potential across the insulation and comparing the readings to a reference standard.

DC Voltage (Potential) TestingDC voltage testing is the most commonly used method for testing insulation. It is less stressful to the insulation than AC voltage testing, therefore, less potential for damage exists. Test equipment for DC voltage testing is smaller and more readily available than AC voltage testing equipment. Since DC insulation testing is easy to perform, it is the preferred method to gage insulation deterioration. Test data obtained from DC testing may be used to track insulation resistance over time. Insu-lation resistance or megohmeter testing is performed by applying 500 to 5,000 V DC across the insulation. An ohmmeter which reads directly in megohms is used as the potential source. Megohmeter testing is easy to perform and is used extensively during all phases of equipment testing, facility check-out and commissioning, and plant maintenance. Megohmeter readings may be charted and used to detect deterio-ration in insulation systems. Since temperature and humidity can affect the megoh-meter readings, the changes in readings must be carefully analyzed before deciding the insulation has deteriorated.

Insulation resistance values are affected by temperature and should be corrected to a base value for proper comparison. The temperature correction is made according to the equation R = K (1 + KV) as defined in ELC-MS-4744. One rule of thumb is that insulation resistance should be at least one megohm per 1,000 V of insulation rating, with a minimum of 1 megohm. Clean dry insulations will normally test higher than this value.

The DC high potential test is performed by applying voltage across an insulation at or above the DC equivalent of the AC peak voltage. It may be applied as either a dielectric absorption test or a step-voltage test. In either case, a DC high potential test set with kilovolt and micro-amp meters is used.



When applied as a dielectric absorption test, the maximum voltage is applied gradu-ally over a period of about 1 minute, and leakage current readings are taken each minute, for 5 minutes thereafter. The insulation resistance may be calculated from the applied voltage and the resulting leakage current.

When applied as a step-voltage (hi-pot) test, test voltage is increased in a number of equal increments until maximum test voltage is reached, with each voltage applied until the leakage current stabilizes. A leakage current reading is taken at each interval, and a voltage versus leakage current plot is developed. If a sharp increase in leakage current occurs, the test should be discontinued. Insulation may be evalu-ated from the absolute insulation resistance at each voltage step, the change in insu-lation resistance with voltage, and whether or not a sharp increase in leakage current occurs at higher test voltages. Care should be taken in comparing previous plots and data, as results are subject to variations in temperature and humidity. See Specification ELC-MS-2469, “DC High Potential Testing of Medium Voltage Cable and Electrical Equipment,” for more information.

Step-voltage field tests are typically performed on medium voltage cables and equipment. Some facilities do not perform high voltage field testing on transformer or rotating electric machinery windings due to concerns of overstressing the insula-tion. However, high-pot testing is recommended for medium voltage systems (except for transformers) during maintenance turnarounds to uncover insulation weaknesses while they can be repaired.

Whenever high potential testing is performed, care should be taken to ensure that insulation is not overstressed. A rule of thumb is to perform commissioning tests at 75% of factory test voltage and maintenance tests at 65% of factory test voltage.

Sometimes it is useful to calculate the polarization index for rotating electric machinery, transformers and cable. The polarization index is the ratio of the insula-tion resistance after 10 minutes to the value after 1 minute of potential application. A low value indicates that the insulation is probably moist or dirty. The value usually should be above 2 (resistance at 10 minutes divided by resistance at 1 minute). Comparison of polarization index values over time can help identify deteri-orating insulation and prevent failures.

AC Potential TestingAC high potential tests are performed by subjecting insulation to high AC voltages for a brief period (approximately 1 minute). The insulation is evaluated on a “pass or fail” basis. Actual failure or excessive leakage current is considered a “fail” eval-uation. AC high potential field testing is not recommended since AC voltage testing is sometimes a destructive test.

Insulation power factor testing, which is used to determine the power loss through insulation, is another AC voltage test which may be performed on all types of insu-lating materials. This test, however, is not commonly performed in the field. Evalua-tion of test results is based on the comparison to previous tests. An increasing power factor is a sign of insulation deterioration.



1423 Insulating Liquid TestingElectrical equipment insulating liquids should be tested on a regular basis by performing a series of tests on liquid samples. Figure 1400-1 lists the tests most commonly performed, the corresponding ASTM test method, and the typical accep-tance criteria.

Equipment normally is received from manufacturers already filled with oil and sealed. Therefore, only a dielectric breakdown test is usually required during commissioning activities. Should the insulating liquid not pass the breakdown test or exhibit marginal qualities, additional tests may be required to determine the reason. Maintenance tests usually should include dielectric breakdown and neutral-ization number tests as well as a visual examination.

If samples are sent to a laboratory for testing, it may be practical to have a series of tests run, including a test for PCBs. When tests indicate that insulating liquids have deteriorated, they should be either reconditioned or replaced.

1424 Protective Device TestingProtective devices should be tested for both acceptance and maintenance purposes. The extent and frequency of testing required is dependent on the type of device and

Fig. 1400-1 Insulating Liquid Tests and Acceptance Criteria Courtesy of NFPA 70B, Recommended Practice for Elec-trical Equipment Maintenance. See note on page 1400-1.

Test ASTM TestMethod

Minimum Test Criteria

Typical New Liquid Values

Acidity D1534-64 or D1902-64 Same as Neutralization Number Below

Color, ASTM D1500-64 (1968) 4.0 Max. (Oil)2.0 Max. (Askarel)

1.0 Max. (Oil andAskarel)

Dielectric BreakdownVoltage

D877-67 (DiskElectrodes) orD1816-67(VDE Electrodes)

22 kV Min. (Oil)25 kV Min. (Askarel)

26 kV (Oil) 30 kV(Askarel)

Examination, Visual, Field

D1524-69 (PetroleumOils) or D1702-65(Askarels)

Should not be cloudy,dirty, or have visible wateror contaminants

Clear

Interfacial Tension(Oil Only)

D971-50 (1968) (RingMethod) or D2285-68(Drop Weight)

18 Dynes/Cm. Min. 35 Dynes/Cm. Min.

NeutralizationNumber

D974-54 (1968) or D664-58

0.40 Max. (Oil)0.014 Max. (Askarel)

0.04 Max. (Oil)0.014 Max. (Askarel)

Power Factor D924-65 (1969) 1.8% Max. (Oil)2.0% Max. (Askarel)

0.1% Max. (25°C) (Oil).2–.5% Max. (25°C) (Askarel)



the installation. The manufacturer’s recommendations should be followed (as a minimum).

Protective relays should be calibrated and tested during equipment commissioning and every two to three years thereafter. Overloads in motor starters should be checked for correct sizing during commissioning. Circuit breaker and switch testing should also be performed. Circuit breaker time-travel analyses should be performed to ensure that the operating mechanisms of medium voltage breakers function prop-erly. Fuses generally are not tested (except for continuity). In addition to acceptance and routine testing, protective devices should be thoroughly inspected and tested following their interruption of fault level currents.

Protective relays normally are tested by injection of secondary currents and volt-ages. Trip circuits should be disabled if the relay is left in its case to prevent opera-tion of other trip circuit devices. Test currents and test voltages are applied on the secondary side of current and potential transformers and typically require only a 5 ampere test current source and a 120- volt test voltage source. Sometimes, it is desirable to test relays with their corresponding instrument transformers. In this case, a large current source and/or high voltage source must be applied on the primary side of the transformers, which makes the testing considerably more diffi-cult. Ground fault and differential relays installed with zero sequence current trans-formers normally should be tested using primary injection to ensure predictable performance of the relay/CT combination.

1425 Impedance and Resistance Measurements

Contact Resistance TestingThe resistance across closed circuit breaker and switch contacts must be kept low to minimize localized heating and the resulting reduction in contact and insulation life. A test set with a direct readout in microhms may be used. Otherwise, a DC current may be passed through the contacts and the resultant millivolt drop measured. Contact resistance testing normally should be performed on large, low-voltage and medium-voltage breakers and switches. If contact resistance is greater than 250 microhms, the contacts should be replaced. This test is applicable to equip-ment field testing, equipment commissioning and equipment maintenance.

Ground System Impedance TestingInstallation and maintenance for a low impedance equipment ground system is very important. Maintaining a low resistance from grounding electrodes to earth is also important. Instruments are available which measure the impedance of the complete equipment ground current loop or just the grounding path. Grounding electrode to earth resistance usually is measured with a ground resistance test set. This test must be performed by personnel familiar with the appropriate equipment, or the readings can be incorrect. Generally, the total impedance to earth from any point which is intentionally grounded, should be less than one ohm. Ground system impedance testing should be performed during facility commissioning and maintenance testing. In addition, visual inspection of the ground system should be an ongoing



activity to ensure that connections are tight and grounding conductors are undam-aged.

1426 Infrared InspectionInfrared inspections are performed on operating electrical equipment to detect elevated temperatures or hot spots. Hot spots can be caused by both bad connec-tions or overloaded equipment. Early detection of these hot spots can help prevent equipment deterioration which could result in failure or plant shutdown. Various types of infrared “guns” are available for performing this type of inspection. The work may be performed in-house, but it is normally more cost effective to have it done by outside contractors. Typically, a contractor will perform a more thorough inspection.

Infrared inspections should be performed whenever hot spots are suspected. Adequate results will be achieved if the equipment being tested is carrying at least 40% of the rated current.

1427 Transformer Fault-Gas AnalysisThe analysis which determines the percentage of combustible gases present in the nitrogen cap of sealed and pressurized oil-filled transformers can provide informa-tion regarding the likelihood of an impending fault. Combustible gases are produced by arcing or excessive heating below the transformer oil level. A special test set (with a readout in percent of combustible gas) should be used to analyze a sample of the transformer’s nitrogen. Normally, the nitrogen will contain less than 0.5% combustible gases. If a problem develops, this amount can increase by a factor of 20 to 30. Figure 1400-2 provides an evaluation of fault-gas analysis test results.

Fig. 1400-2 Fault-Gas Analysis Evaluation Courtesy of NFPA 70B, Recommended Practice for Electrical Equipment Maintenance. See note on page 1400-1.

Percentage of Combustible Gas Evaluation

0.0 to 1.0 No Reason for concern. Make tests at regularly scheduled intervals.

1.0 to 2.0 Indication of contamination or slight incip-ient fault. Make more frequent readings and watch trend.

2.0 to 5.0 Begin more frequent readings immedi-ately. Prepare to investigate cause by internal inspection.

Over 5.0 Remove transformer from service and conduct internal inspection.



1428 Functional TestingPrior to placing any equipment or system in service, it should be given a complete functional test. The functional test should closely simulate actual operating condi-tions, except the power busses should not be energized. Functional testing should include verifying the proper operation of all protective devices, interlocks, control circuits, and automatic transfer schemes. Functional testing should be performed during factory tests and when commissioning new or reconditioned electrical facili-ties.

1429 Operational TestingAfter the start-up of new equipment or systems, a series of operational tests should be conducted. Usually, this involves comparing the performance of the equipment or system against design criteria. For example, motors and generators should be performance tested at the manufacturer’s plant and during field start-up. Mechan-ical and electrical performance data are compared against design tolerances. Voltage levels, real and reactive power flows, and other operating conditions must be verified for the entire power distribution system. All maintenance programs should include tracking of equipment operating conditions. Operational testing is applicable to all phases of a facility’s life. Operational testing includes factory testing of equipment, acceptance testing following plant commissioning, and moni-toring operating conditions as part of the maintenance program.

1430 Factory TestingA comprehensive check-out and testing program at the manufacturer’s plant of any new or refurbished electrical equipment is critical. In general, visual inspection, insulation testing, protective device testing, resistance measurements, functional testing, and operational testing should be conducted at the manufacturer’s plant.

Factory testing requirements should be included with the purchase order docu-ments. Generally, testing requirements should be based on industry standards (such as those published by IEEE, ANSI, NEMA, and API). Company specifications in Section 2000 provide recommended factory tests for various equipment.

1440 System Check-Out and CommissioningIt is critical that a facility be completely checked and tested prior to energization. This will allow for a smooth start-up, minimize damage to equipment and property, and minimize the possibility of injury to personnel. This will also minimize unex-pected shutdowns and increase run time.

Specification ELC-MS-4744, “Electrical Systems Check-out and Commissioning” is a comprehensive inspection and testing program. Inspection and testing check-lists are included with this specification. The commented version identifies how the document can be tailored to meet particular needs.



1450 MaintenanceMaintenance of an electrical facility and the required spare parts should be consid-ered during the design phase of a project. Plant operating personnel should be consulted for preferred system configurations and existing maintenance procedures. The resulting designs should reflect maintenance and operating requirements.

During the construction phase of a project, major equipment must be maintained in accordance with manufacturers’ guidelines. If not, the warranty may be nullified. A preventive maintenance program for storing equipment should be in place prior to the receipt of any items. Typical activities to include in this program are: protecting equipment from the environment, ensuring that space heaters are energized, rotating the shafts of motors and generators, checking the charge on activated storage batteries, and ensuring that manufacturers’ storage requirements are met.

As soon as a facility is placed in service, the preventive maintenance program should be expanded. A suitable comprehensive Electrical Preventive Maintenance (EPM) program needs to be established during the construction phase. The benefits of an EPM program include measurable results (such as reduced repair costs and shutdown time.) Another less tangible benefit is improved productivity resulting from a safer workplace. NFPA 70B, “Recommended Practice for Electrical Equip-ment Maintenance,” provides a comprehensive guide for establishing an effective EPM program. Included in this reference are sample record sheets which may be used to record inspections, test data, and maintenance actions taken. Another refer-ence source is Westinghouse’s four-volume set “Electrical Maintenance Hints.”

1460 ReferencesThe following references are readily available. Those marked with an asterisk(*) are included in this manual or are available in other manuals.


1462 Standard DrawingsThere are no Standard Drawings in this section.

*ELC-MS-2469 DC High Potential Testing Medium Voltage Cable and Elec-trical Equipment

*ELC-MS-4744 Electrical Systems Checkout and Commissioning

*DRI-EG-3547 Inspection and Testing of Large Motors and Electrical Genera-tors



1463 Data Sheet (DS), Data Guide (DG) and Engineering Forms (EF)

1464 Other ReferencesANSI C2, National Electrical Safety Code

ANSI/IEEE C57.13.1, Guide for Field Testing of Relaying Current Transformers

API Guide for Inspection, Chapter XIV—Electrical Systems

API RP 14F Design and Installation of Electrical Systems for Offshore Production Platforms

ASTM D-877, Test Method for Dielectric Breakdown Voltage of Insulating Liquids Using Disk Electrodes

ASTM D-1816, Test Method for Dielectric Breakdown Voltage of Insulating Oils From Petroleum Origin Using VDE Electrodes

ANSI/IEEE Standard 4, Techniques for High Voltage Testing

IEEE Standard 51, IEEE Guiding Principles for Dielectric Tests

IEEE Standard 62, IEEE Guide for Field Testing Power Apparatus Insulation

IEEE Standard 64, IEEE Guide for Acceptance and Maintenance of Insulating Oil in Equipment

ANSI/IEEE Standard 81, IEEE Guide for Measuring Earth Resistivity, Ground Impedance, and Earth Surface Potentials of a Ground System

IEEE Standard 118, IEEE Standard Test Code for Resistance Measurement

IEEE Standard 120, Master Test Code for Electrical Measurements in Power Circuits

ANSI/IEEE Standard 400, Guide for Making High- Direct-Voltage Tests on Power Cable Systems in Field

ANSI/NFPA 70, National Electrical Code

ANSI/NFPA 70B, Electrical Equipment Maintenance

Gill, A.S. (Electrical Equipment Testing and Maintenance)

Westinghouse (Electrical Maintenance Hints)

*ELC-EF-645 High Potential Test Record Sheet


1500 Adjustable Speed Drives

AbstractThis section discusses the application of low voltage (LV) and medium voltage (MV) adjustable speed drives. It covers basic theory of drives, when to apply an adjustable speed drive and the economic benefits of drives. Also discussed are the steps involved with selecting and installing drives. Specific studies, like rotor dynamic and harmonic analysis are also briefly described. Finally, testing, commis-sioning and maintaining drives is covered.

Contents Page

1510 Background & Selecting Drive Applications 1500-3

1511 What is an Adjustable Speed Drive and How Does It Work?

1512 Low Voltage Induction Motor ASDs

1513 Medium Voltage Induction Motor ASDs

1514 Synchronous Motor ASD

1515 Control Methods

1516 When To Apply An ASD

1517 Economics

1520 Applying (Specifying and Installing) Drives 1500-17

1521 Systems Integration

1522 Front-End Engineering

1523 Specifying Equipment

1530 Applying Low Voltage Drives 1500-24

1531 LV Type Drives

1532 LV Drive Specification

1533 Drive Features and Application Considerations

1534 Rectifier and Input Section

1535 Control Section

1536 Inverter and Output Section

1500 Adjustable Speed Drives Electrical Manual


1537 Reliability

1538 Motor Considerations

1539 Drive Retrofit Applications

1540 Applying Medium Voltage Drives 1500-38

1541 Induction-Motor Drive Types

1542 LCI Synchronous-Motor Drive

1543 MV Drive Configurations

1544 MV Drive Specification

1545 Considerations for MV Drive Applications

1546 Motor Considerations

1550 Considerations for Electrical Distribution System 1500-54

1551 Effects on the Drive

1552 Effects on Other Equipment

1553 Harmonic Analysis

1560 Rotordynamic Studies 1500-59

1561 Lateral Critical Speed Analysis

1562 Torsional Analysis

1563 Pulsation and Structural Resonance Analysis

1570 Miscellaneous Information 1500-66

1571 System Testing

1572 Commissioning and Startup

1573 Training

1574 Maintenance and Spare Parts

Electrical Manual 1500 Adjustable Speed Drives


1510 Background & Selecting Drive Applications

1511 What is an Adjustable Speed Drive and How Does It Work? Most AC induction or synchronous motors applied in petrochemical facilities or commercial applications operate at one fixed speed. This speed is established by the frequency of the power source connected to the stator and the design of the motor, i.e., the number of magnetic poles. The relationship between motor speed, power frequency, and number of poles is given by Equation 1500-1.

RPM = 120f/P(Eq. 1500-1)

where:f = frequency in Hertz

P = number of magnetic poles

For example, from Equation 1500-1 the speed of a two-pole motor on a 60 Hz power system is 3600 RPM.

Since speed is directly proportional to the frequency, the speed can be adjusted by changing the power frequency. This is accomplished using power electronics by supplying the motor from a frequency converter known as an adjustable speed drive (ASD).

Figure 1500-1 shows a block diagram of a typical ASD. First, an ASD rectifier (or line converter) converts the 60 Hz AC power to DC power. Then filtering (either an inductor or capacitor), applied on the DC section, smoothes the DC ripple and helps decouple the rectifier and inverter sections. The inverter (or machine converter) changes the DC power back to AC at the frequency needed to obtain the desired motor speed. To maintain the desired V/Hz ratio, the inverter output voltage is normally adjusted proportionally with frequency, thereby keeping the motor magnetic field within design limits and providing the required performance charac-teristics. Inverter output filters may also be used, to reduce the harmonic distortion of the output voltage to levels acceptable for the motor, or provide reactive power necessary for operation of the drive.

Fig. 1500-1 Basic ASD Block Diagram

‘



The devices used to convert power from AC to DC in the rectifier and from DC to AC in the inverter are solid state switches, such as diodes, transistors, or thyristors. These devices switch in a programmed sequence and time to fabricate the required voltage and current waveforms. The sequential switching of these devices is known as commutation. Each device is described below, and symbols for commonly used devices, are shown in Figure 1500-2.

DiodesDiodes are the simplest and most reliable switching devices which are commonly used in the rectifier section of an ASD. These devices turn on (and conduct) when “forward biased” (anode is positive with respect to cathode) and turn off naturally at current zero after the bias voltage changes polarity. However, these devices are uncontrolled in that they can not be switched on or off at any desired point with respect to the voltage waveform. Thus, because they can not be used to control the voltage amplitude or frequency in a power converter output, their use is limited.

Thyristors (also known as SCRs)Thyristors or (for the purpose of this guideline) silicon controlled rectifiers (SCRs) can be turned on via a gate signal at any time the device has a forward bias (positive voltage from anode to cathode). Once forward biased, only a momentary trigger signal to the gate is required to turn the device on and cause it to conduct. The time, on the waveform, that the device is turned on is selected by the control system to provide the voltage or frequency output desired. However, this device must wait for the next current zero to naturally turn off after the gating signal is removed. For an inverter device, turn-off must either be accomplished by forcing the current to zero or by managing the load power factor to facilitate natural current zeros for switching, i.e., load commutation. For a rectifier SCR, turn-off is typically when the instantaneous value of the line voltage drops below the rectifier output voltage or when an SCR on a different phase (with higher anode voltage) is gated on. There is

Fig. 1500-2 Commonly Used Solid State Switching Devices for Power Converters. Courtesy of Toshiba International.



no other way to turn it off. These devices can be used in all sizes of ASDs, but today are commonly used in large medium-voltage induction and synchronous motor drives.

GTO ThyristorsThe gate turn-off (GTO) thyristor has the added feature of a controlled (or forced) turn-off. A GTO can be switched on and off at high frequencies, making them suit-able for pulse width modulated control (discussed later). Like an SCR, a GTO gate signal need only be triggered momentarily to turn the device on. Conduction will continue until current falls to zero, or a turn-off signal is applied to the gate. These devices are normally used in the machine converter of large medium voltage induc-tion-motor drives as an alternative to load commutation using conventional thyris-tors mentioned above.

TransistorsTransistors have the advantage of being switched on or off very rapidly and are commonly used in low voltage (460V or 575V) ASDs. For now (1996), the voltage ratings available are not high enough for medium voltage ASD applications unless transformers are used to provide acceptable (output) voltage levels. Alternatively, bridge cells can be connected in series to provide the necessary output voltage (See Section 1513, Harmony Power Cell drive). Since the late 1960s bipolar junction transistors (BJTs) have been used for low voltage induction motor ASDs. However, in the past couple of years, insulated gate bipolar transistors (IGBTs) have evolved and become the device of choice. Compared to BJTs (1 - 2 kHz switching frequen-cies), IGBTs provide faster switching frequencies (2 - 20 kHz), lower gating power requirements, smaller overall drive physical size, and improved drive output charac-teristics.

The configuration of the switching devices (SCRs shown) for the simplest ASD arrangement is a six-pulse bridge configuration as shown in Figure 1500-3. The six thyristors in the rectifier or in the inverter each complete one switching sequence for each cycle of power frequency, giving a total of six pulses every cycle and hence the designation as a six-pulse drive. Twelve-pulse and higher bridge configu-rations are common for larger horsepower drives. The higher pulse number offers the advantage of lower harmonic distortion to minimize effects on the electrical system and the motor. Harmonics will be discussed in more detail in Section 1550.

1512 Low Voltage Induction Motor ASDsLow voltage (LV) drives are typically used with motors up to approximately 1000 HP. However, some manufacturers are building LV drives up to 2500 HP, which can be more economic than a medium-voltage drive. Above about 500 HP an output transformer and a medium-voltage motor are normally used with the LV drive.

Three basic types of low voltage induction motor ASDs are in use today. These types are variable voltage inverter (VVI), current source inverter (CSI), and pulse width modulated (PWM) inverter as shown by Figures 1500-4, 1500-5, and 1500-6,



respectively. VVI and CSI-type drives have virtually disappeared from the market-place for new drive applications below 600VAC input.

Fig. 1500-3 Typical Six-Pulse ASD Configuration

Fig. 1500-4 Variable Voltage Inverter Drive. Courtesy of Toshiba International.

Fig. 1500-5 Current Source Inverter Drive. Courtesy of Toshiba International.



The VVI drive uses a thyristor-controlled (phase-delayed) rectifier to convert AC to a variable DC voltage. The DC is filtered by a capacitor, and the stored capacitive charge helps maintain a stable DC voltage. A thyristor controlled inverter converts the DC voltage to an AC voltage at the required frequency.

The CSI drive also uses a thyristor-controlled rectifier to convert the AC voltage to a variable DC voltage (and current). The DC ripple is smoothed by an inductor, and the stored energy from the inductor helps maintain a stable DC current. The DC current is converted to an AC current at the required frequency by a thyristor-controlled inverter.

The PWM drive uses a full-wave bridge rectifier (using simple diodes or a fully gated-on SCRs) to change the AC supply voltage to a constant DC voltage. As with the VVI drive, the DC voltage is filtered with a capacitor (and with some manufac-turers, also an inductor), which also helps maintain a stable voltage. A transistor-controlled inverter changes the DC voltage to AC. In this case, IGBTs are used. Notice in Figure 1500-6 the output voltage is a square wave formed by individual pulses. The pulse width is varied to produce the required voltage magnitude. Also, notice the current is nearly sinusoidal compared to the VVI and CSI drives in Figures 1500-4 and 1500-5.

1513 Medium Voltage Induction Motor ASDsMedium voltage induction motor drives range in sizes from 400 HP to 15,000 HP. High speed (super synchronous) drives have been applied up to 11,000 rpm. As the speed of the drive increases, the HP size that can be applied decreases, due to rotor fabrication limits. The Company has applied conventional speed (up to 3600 rpm) induction-motor drives up to 10,000 HP and high speed drives up to 3,500 HP and 11,000 rpm.

Fig. 1500-6 Pulse Width Modulated Drive. Courtesy of Toshiba International.



Three basic types of medium-voltage ASDs are in common use today: the LCI IM drive, the GTO drive, and the Harmony Power Cell drive. The load commutated inverter induction motor (LCI IM) drive is shown in Figure 1500-7. This is a current-source drive, and uses a thyristor controlled rectifier and inverter. A large capacitor is installed on the inverter output to provide the leading power factor necessary for load commutation. A forced commutation scheme (rectifier commu-tated inverter) is used to operate the drive at startup and at very low speeds until sufficient voltage on the motor is developed to allow load commutation.

The GTO induction motor drive can use several configurations, either as a voltage-source or a current-source drive. Figure 1500-8 shows a typical configuration for a current-source GTO drive using a thyristor-controlled rectifier bridge and a GTO thyristor inverter bridge. The DC link reactors smooth the DC ripple. The inverter output filter capacitor, which reduces harmonic distortion, is much smaller than the one required for the LCI induction motor drive. In this case, a large capacitor is not necessary for load commutation because the GTO thyristors can be completely controlled and switched on and off as required. This ASD normally functions as a PWM-type drive, similar to the low voltage drive described above, but at a lower switching frequency.

The Harmony Power Cell drive topology is shown in Figure 1500-9. Each cell is a static PWM power converter, capable of receiving input power at 480VAC, 3 phase, 50/60Hz and delivering that power to a single-phase output. A typical power cell is shown in Figure 1500-10. Each cell consists of a 6-pulse diode rectifier, DC bus capacitors, and a single-phase inverter using IGBT switching devices. (The Power Cell is identical to a 480V PWM-type ASD, except the output is single phase instead of 3 phase.) All inverters of each cell are continuously conducting, so the output converter never has to block against output voltage.

The output of the power cells are connected in series to provide the necessary output voltage, i.e., 3 cells for 2300V, 5 cells for 4160V, and 8 cells for 6600V. The input transformer is a multi-winding transformer, with the appropriate phase shift to

Fig. 1500-7 Load Commutated Inverter Induction Motor Drive. Courtesy of Ansaldo Ross Hill.



Fig. 1500-8 GTO Induction Motor Drive. 1987 IEEE. Used with permission from IEEE Paper No. PCIC-87-45.

Fig. 1500-9 Harmony Power Cell Drive Topology. 1995 IEEE. Used with permission from IEEE 95-CH 35840-b/95/0000-0231.



cancel most of the harmonic currents drawn by the power cells, so that the primary currents are nearly sinusoidal. Diodes are used on the line converter and IGBTs on the output single-phase bridge. The power cells all receive commands from one central controller. The PWM control of each cell per phase is synchronized with the other cells to provide synchronized 3-phase conduction, which is different from the conventional 6- or 12-Pulse PWM controllers. The net effect is the 3-cell, 2300V drive is equivalent to an 18-pulse drive; the 5-cell, 4160V drive is equivalent to a 30-pulse drive and the 8-cell, 6,600V drive is equivalent to a 48-pulse drive.

1514 Synchronous Motor ASDSynchronous-motor drives are normally used for very large motors, typically 10,000 HP and up to 50,000+ HP. High speed synchronous-motor drives have been applied up to 50,000 HP and 5,000 rpm. The Company has applied synchronous-motor LCI drives up to 15,000 HP and 6,000 rpm.

The synchronous-motor drive in common use today is the LCI type (Figure 1500-11). The rectifier and inverter are thyristor controlled. The motor field excitation is supplied from a thyristor-controlled exciter to provide a leading power factor which is required for load commutation. A forced commutation scheme, similar to the LCI IM drive, is used to start the drive and bring it up to a minimum speed where sufficient motor voltage is developed for load commutation. The

Fig. 1500-10 Schematic of a Power Cell. Courtesy of Robicon.



exciter control is turned on at start to provide field excitation even at zero speed, so the motor is always synchronized with the machine converter, even during startup.

1515 Control MethodsA common control strategy for ASDs uses a Volts/Hertz scheme to control speed and torque (see Figure 1500-12). In this scheme both the frequency and strength of the motor magnetic field are established with a single speed input command. Main-taining a constant V/Hz ratio (for example, for a 460V motor, at nameplate value: 460V/60Hz = 7.66 V/Hz) produces a constant value of magnetic field strength in the motor, which means rated torque is available at any speed. Speed regulation (for most drives) is better than 1 percent for the full operating speed range. This tech-nique has been used for many years in both synchronous and induction motor drives. It works very well for most applications within the Company such as pumps, compressors, and fans which require fast (but not instantaneous) response times for speed changes.

A relatively new control method for induction motors now gaining wide use is the Flux-vector Control Scheme (Figure 1500-13). This more complex drive-control scheme allows independent control of the motor Volts/Hertz and torque producing

Fig. 1500-11 Synchronous Motor Drive. Courtesy of Ansaldo Ross Hill.

Fig. 1500-12 Typical Volts/Hertz Control Block Diagram. Courtesy of Reliance Electric.



current. Flux-vector control provides very accurate speed regulation, high dynamic response, and excellent torque control. Both open-loop and closed-loop (requiring tachometer or rotor position reference feedback) schemes are available. The open-loop flux-vector control scheme is preferred for applications where incremental improvement in speed regulation, starting torque, low-speed high torque output, and dynamic response is preferred over the traditional V/Hz. Open-loop control is also preferred for retrofit applications, since no tachometer feedback signal is required, making the installation less complex. Speed regulation, with open-loop control, is 0.1 percent. Closed-loop control, with rotor position feedback, always improves the speed regulation (0.01 percent), torque-response damping, and zero-speed (starting) torque relative to open-loop (encoderless) drive control.

Flux-vector control technology is a good option for those applications requiring very accurate speed control, fast response and constant or high torque loads, espe-cially at lower speeds.

1516 When To Apply An ASDASDs can offer several benefits over fixed speed motors: reduced power consump-tion, reduced maintenance costs, soft start, and improved process control and enhancements (described below). Adjusting the speed of a pump, compressor, fan, or other equipment is a more efficient way of controlling flow compared to control valves, dampers, etc. Control of key process variables, such as inlet pressure, or flow rate, becomes a viable alternative to discharge flow throttling, recycle control with control valves and recycle coolers, or other forms of volume control such as cylinder unloaders, valve pockets, etc. This is normally the predominant reason for applying an ASD. Maintenance costs are typically lower for an ASD than for

Fig. 1500-13 Flux Vector Control Scheme Block Diagram. Courtesy of Reliance Electric.



mechanical flow control devices. Also, where frequently started fixed speed motors are applied, the ASD provides a soft start for longer life of the motor and lower maintenance costs as well as reduced impact on the electrical system. The ASD can also provide fast and accurate responses to changes in flow requirements giving optimum process control. ASDs can be an option to gas or steam turbines where emissions are a concern or steam is in short supply.

Company ExperienceChevron Canada Resources (CCR) has applied over 130 low voltage ASDs (from 3 to 800 HP) on a wide variety of applications (positive displacement water injection and process circulating pumps, condenser fans, centrifugal pumps, vapor recovery rotary compressors, reciprocating compressors, and oil pumping jack units). Process enhancements, due to ASD control flexibility have far exceeded power savings. Process enhancements have included turndown as well as supersynchro-nous speed capability as the various processes have required more throughput. CCR uses a rule-of-thumb that 50 percent of their processes have the potential for ASDs.

Most ASD applications within the Company are centrifugal loads such as pumps, compressors, and fans. There are some constant torque applications such as conveyors, positive displacement pumps, agitators and compressors. Production facilities offer several opportunities for applying constant torque ASD applications:

• Positive displacement water injection and amine circulating pumps and acid gas injection reciprocating compressors (applied at 900 rpm).

• Styrene plants offer many constant torque ASD applications for reactor feed pumps, pelleters, and agitators.

For constant torque applications, special precautions for motor cooling must be taken when operating at low speeds, because the motor current is near rated, but the cooling air flow from the shaft mounted fans is reduced in proportion to speed. In these applications, if very slow speeds are required, a motor designed for the application is required. This may include an externally mounted fan to provide motor cooling at low speeds. Most motor manufacturers have retrofit kits for installing externally mounted fans.

Use of ASD with Electric MotorIt is difficult to generalize when an ASD with an electric motor should be used. However, if the required flow varies, an ASD should be considered. The greater the variation in flow requirements and the longer the duration of reduced flow, the more cost effective an ASD will be. Each application must be reviewed individually to determine if an ASD makes sense. Some typical applications which should be considered are feed pumps, recycle centrifugal compressors, refrigeration compres-sors, reflux pumps and cooling tower fans. Reciprocating compressors are also becoming candidates for ASDs. For drives applied to reciprocating-type driven equipment, pulsation dampening systems may be necessary to accommodate the range of pressure pulsation frequencies. See Section 1560 for more details on pulsa-tion analysis.



Most Common Uses for ASDsThe following is a general guide for the most common ASD applications:

Centrifugal Machinery. Centrifugal pumps and compressors are ideal applica-tions. However, feed pumps and compressors usually operate in systems with a high static head component, which limits, or in extreme cases prohibits, variable speed control. For applications where the system resistance is mainly dynamic (or frictional), such as recycle pumps and compressors, or cooling tower fans, the ASD is an ideal match.

Axial compressors, which are becoming more common in process applications, are similar to centrifugals in their general characteristics, except that blade vibration analysis must take into account torque harmonics. This may result in portions of the speed range becoming unavailable for steady state operation due to potentially damaging resonances.

Mechanical Handling. Constant torque loads, such as conveyors, and other mechanical handling equipment, controlled by ASDs may offer some attractive control advantages. However, at lower speeds, motor torque may be limited by available cooling if the cooling fan is output shaft driven. External blowers may be necessary to stay within stator winding and bearing temperature limits.

Positive Displacement Machinery. Positive displacement machinery, including reciprocating and screw pumps and compressors, need special consideration due to several possible interferences with multiple excitation frequencies and multiple system natural frequencies. Use of ASDs in these circumstances is relatively rare, but it is an emerging technology. The advice and counsel of a specialist is recom-mended for these applications.

1517 EconomicsIn general, the plant process engineers or the facility control systems engineers at the Company’s locations have the required background on the various operating processes to develop the economic-evaluation scenarios for ASD applications. However, these engineers are often not familiar with benefits or the practical aspects of adjustable speed drives. They are also not familiar with applying the affinity laws for centrifugal equipment as applied with ASDs.

A simple example will demonstrate how the use of an ASD rather than mechanical means to control flow will save energy costs. Figure 1500-14 shows a simplified fixed speed pump system with flow adjusted by control valves. Figure 1500-15 shows a typical pump system with flow controlled by an ASD.

The affinity laws given in Figure 1500-16 describe the behavior of centrifugal loads. Notice the flow varies directly with speed and head (pressure) as the square of the speed, while the power varies as the cube of the speed. Reducing the speed to 60 percent reduces the flow to 60 percent and the power input to 21.6 percent of normal, which can provide substantial energy savings. In practice, this degree of power reduction does not occur because the system static head and losses require the motor to operate at a speed greater than 60 percent to provide 60 percent flow.



Fig. 1500-14 Simplified Fixed Speed Pump System Using Control Valves

Fig. 1500-15 Typical ASD Controlled Pump System



However, the power reduction is still significant compared to using a control valve or inlet vane to restrict flow as will be shown later by an example.

Figure 1500-17 compares the percent energy consumption versus speed for a pump using either a control valve or an ASD with a relatively high static head and a rela-tively low static head. As the flow requirements decrease, the savings with an ASD increase. The energy savings with an ASD are less if the system has a relatively high static head, but continue to be substantial at reduced flow in either case. If the pump runs at reduced flow a majority of the time, an ASD will save sufficient energy to have an adequate payout period. The higher the HP application, the better the payout, since the drive cost per HP decreases as the size increases. If the pump runs near 100 percent of rated flow most of the time, an ASD is probably not justi-fied.

Figure 1500-18 shows an example of a pump with the flow reduced by using a control valve while Figure 1500-19 shows the same pump with flow reduced by changing the speed with an ASD. The motor output is 25 HP with the pump at normal flow. The output reduces to 22.5 HP when the flow is reduced to 70 percent of rated by adjusting the control valve. If the flow is reduced to 70 percent by adjusting the speed with an ASD, the motor output is 15.7 HP for a net reduction of 6.8 HP or 5.1 KW over the control valve case. At seven cents per KWH this saves $3,127 per year if the pump operates full time at 70 percent flow. The estimated installed cost for the ASD is $9000. The payout time is roughly three years for this example.

Fig. 1500-16 Affinity Laws for Centrifugal Equipment



The actual payout for a potential ASD application can vary significantly, depending on the system parameters, the load profile (percent of normal flow versus time), the HP size, and the cost of power. The payout for this example is longer than many applications, because the relatively high static head increases the energy require-ments as previously discussed. Notice the speed is only reduced to 85 percent of rated to obtain a 70 percent flow due to the high static head in this example. Appli-cations with payouts of one to two years or less are reported by some users. Finally, the local electric utility may offer rebates for installing energy efficient equipment, which can substantially reduce the payout time.

1520 Applying (Specifying and Installing) DrivesThe application of adjustable speed drives begins with front end (or preliminary) engineering to assist in equipment specification and system integration. Front-end engineering consists of specifying the proper drive, motor, and associated equip-ment (if required); and integrating the drive and motor into the existing electrical distribution system. A properly integrated system is imperative for successful and reliable operation of the drive and electrical system. Consideration must be given to conditions that the electrical system imposes on the drive, e.g., transient over-voltage or voltage sags that can result in nuisance trips of the drive. The drive gener-ates harmonics which can affect reliable operation of other electrical equipment on

Fig. 1500-17 Power Consumption of a Pump with Flow Regulated by a Control Valve versus an ASD



the system (like nuisance trips or equipment failure) and can also create additional KW core losses in motors and transformers fed from the same system as the drive.

1521 Systems IntegrationSystems integration is the function of coordinating the project, usually from concep-tion through startup and commissioning. A systems integrator needs to be experi-enced in the application of ASDs and usually specifies the equipment and performs most of the detail engineering as well as prepares the startup and commissioning plans. Systems integration is best done by a consultant specializing in the ASD busi-ness. Unfortunately, few engineering firms have the necessary experience in applying drives. Engineering firms will usually copy the previous, successful design even though conditions may be different or real improvements and optimiza-tions could enhance the new application. Careful review of their design and prompting the engineer to consider new ideas, features and improvements is often necessary to get the full benefit of the drive.

Fig. 1500-18 Example Pump Performance with Flow Reduced by a Control Valve



Some facilities that have applied many drives have built up their own expertise and have their own engineers that do the systems integration. Most engineering, procure-ment and construction (EPC) contractors have few, if any, qualified engineers who perform this function. Many installations use a hybrid approach to systems integra-tion, in which multiple people perform parts of the process. No matter how it is accomplished, systems integration will occur. If the job is done well, the ASD system will be nicely integrated. If not, there may be preventable incidents, equip-ment failures or process upsets during the first year (or more) of operation. The steps in systems integration are shown in Figure 1500-20. The level of effort for each step will depend on the size of the drive and the critical nature or complexity of the application.

Depending upon the size of the ASD application, some of the steps described in Figure 1500-20 are not appropriate. Figure 1500-21 takes the system integration steps and provides guidance in using the steps for low voltage and medium voltage applications. The harmonic and rotordynamic studies require particular expertise and should only be performed by qualified engineering firms that specialize in these fields.

Fig. 1500-19 Example Pump Performance with Flow Reduced by an ASD



Fig. 1500-20 Systems Integration Steps (1 of 2)

1 1a. Define operation parameters of the driven equipment (study hydraulic parameters of system and pump to determine HP size and speed range).

1b. Determine the economic benefits for applying the ASD.

2 Develop a process control strategy for controlling the speed of the driven equipment and integrate process or equipment safeguards into the drive control logic.

3 Determine (by field verification) baseline harmonic distortion levels (both voltage and current) on the electrical system and establish acceptance criteria for the drive application.

4 Develop a conceptual electrical system design by using a one line diagram to determine compati-bility with the existing electrical system and for further economic evaluation. The one line diagram should include:

• drive configuration

• equipment sizes

• cable lengths

• wireway method

5 5a. Develop an impedance diagram of the system, including:

• drive equipment

• utility source

• plant distribution system

• plant local generation including capacitances:

– capacitance power factor correction capacitors

– surge and transient recovery voltage (TRV) capacitors

– cable capacitance

• other harmonic generators such as other drives and UPSs

5b. Perform a computer simulated harmonic analysis of the entire electrical distribution system and compare the results with the project’s harmonic distortion acceptance criteria, IEEE Std 519, and additional requirements discussed in Section 1550.

6 Prepare equipment specifications and data sheets for the drive, motors, and all associated equip-ment (transformers, filters, circuit breakers, contactors, etc.)

7 7a. Analyze lateral and torsional rotordynamics of the rotating system assembly (motor, driven equipment, coupling, and gear box), discussed in Section 1560.

7b. For reciprocating applications perform the following analyses:

• piping pulsation analysis for full frequency (speed) range of fundamentals and harmonics

• piping mechanical structural vibration analysis for full range of frequency and gas pressure pulsation induced vibration

• foundation and supporting structural vibration analysis for full frequency range of lateral and torsional forcing functions

8 Do a reliability review (reliability-centered maintenance or failure modes and effects analysis) of the drive system for critical applications, where trip-free operation is needed.



9 Perform detail engineering of the complete system including:

• drive

• electrical system

• driven equipment

• process control

10 Develop a spare parts list based on the results of the reliability review study, long lead items, and achieving a low mean time to repair (MTTR).

11 Witness factory testing of the drive and motor.

12 Provide for training of the plant operating, maintenance, and technical personnel.

13 Prepare a startup and commissioning plan to include a thorough field test of:

• the drive

• the process control system

• the driven equipment

14 Determine harmonic distortion levels (by field measurements) of the installed system with the drive at various operating conditions ( minimum and maximum source impedance) to verify computer simulated results and verification of the acceptance levels.

15 Determine torsional effects by metering the coupling of the installed system during system commis-sioning.

Fig. 1500-21 Systems Integration Steps for LV and MV Applications (1 of 2)

Activity LV Application MV Application

Define operating parameters and economic evaluation

✓ ✓

Develop a process control strategy ✓ ✓

Determine baseline harmonic distortion levels and acceptance criteria for drive application

✓ ✓

Develop a conceptual system design

≥ 250 hp ✓

Develop an impedance diagram and perform a harmonic analysis

For applications, where harmonic-producing loads are ≥ 1/5 the size

of the substation or on systems with pf correction capacitors

✓

Prepare equipment specification and data sheets

✓

(This step can be streamlined through a supplier alliance)

✓

Perform a lateral and torsional rotordynamic analysis

≥ 500 hp ≥ 500 hp

Perform a reliability review study For critical applications For critical applications

Fig. 1500-20 Systems Integration Steps (2 of 2)



1522 Front-End EngineeringRegardless of the size of the drive application, a certain amount of preliminary engi-neering is essential. It will almost always include a harmonic audit of the electrical distribution system to determine baseline harmonic voltage and current levels. Harmonic distortion acceptance criteria must also be established for the electrical system. Section 1550 and IEEE Std. 519 provides guidance in establishing the acceptable distortion levels. For industrial plants, the point of common coupling (PCC) should be the plant substation bus supplying power to the drive. A computer-simulated harmonic analysis is necessary to estimate the voltage harmonic distor-tion on the system, produced by the drive. For simple or small horsepower applica-tions, the drive manufacturer may be able to provide this service. For large horsepower drives or applications where the size of the drive is greater than one-fifth the capacity of the substation, more extensive engineering may be necessary. This extensive engineering will consist of service from the drive manufacturer, the driven equipment manufacturer, and a drive integrator. In some cases a special consultant may be required to perform the harmonic analysis, and to evaluate the need for and the design of harmonic mitigation equipment. Section 1550 discusses the electrical distribution system and harmonic considerations.

Perform detail engineering ✓

(This step can be streamlined through a supplier alliance)

✓

Develop a spare parts list ✓

(Spare parts inventory can be reduced through a supplier alli-

ance)

✓

Witness factory testing of the drive and motor

For critical applications and ≥ 500 hp (considered by some as the

most important implementation step

✓

Provide for training of plant oper-ating, maintenance and technical personnel

✓

(critical to the success of using drives in the plant)

✓

Prepare a startup, commissioning and system testing plan

✓ ✓

Measure harmonics (field measure-ments) of the system after the drive is in service

For applications, where harmonic-producing loads are ≥ 1/5 the size

of the substation or on systems with pf correction capacitors

✓

Determine torsional effects by metering the coupling during commissioning

Not applicable If the factory tests indicate a poten-tial resonance problem

✓ = Activity applies to this application.

Fig. 1500-21 Systems Integration Steps for LV and MV Applications (2 of 2)

Activity LV Application MV Application



Additional consultation may be necessary for lateral and transient torsional analysis studies. Also, consideration must be given to pressure pulsations and resonances in reciprocating applications and structural resonances in foundations and support structures. Often these studies are performed by the driven equipment manufacturer, and are also performed by a third party consultant specializing in lateral and torsional analysis, to provide verification of the results from the equipment manu-facturer. Rotordynamic studies are discussed in more detail in Section 1560.

1523 Specifying EquipmentSpecifications for both low voltage (LV) and medium voltage (MV) drives are discussed in Sections 1530 and 1540. Specification ELC-MS-4371, with data sheets (ELC-DS-4371) for LV drives can be found in Volume 2 of the Electrical Manual. A model specification for MV drives (ELC-MS-5008) can also be found in Volume 2 of the Electrical Manual.

Before specifying drive equipment (input or output transformers, input or output filters, drive and motor), a sufficient amount of front-end engineering must be completed in order to determine the HP size, speed range, process control strategy, structural and machinery natural frequencies, input and output harmonic filtering needs, voltage transformation needs, motor type, and motor branch circuit length. All of these parameters must be evaluated to adequately specify equipment and to determine the full scope of equipment supply.

A computer-simulated harmonic analysis will determine if input filtering is required. Specifying input or output filters requires the expertise of a specialist. An input filter, improperly sized, can possibly be overloaded by existing system harmonics or by future drives if not considered during the initial design.

If an input transformer is required, a rectifier duty transformer with suitably rated ground wall insulation (for common mode voltage) is needed. For most LV applica-tions, a standard premium efficiency TEFC motor should be used. For some LV applications and many MV applications, an inverter-duty motor may be required, depending upon system configuration and drive type. Some of the features of inverter-duty motors include: higher voltage rated stator insulation, rotor cage modi-fications to reduce heating effects of induced harmonic currents, insulated bearings to eliminate the effects of shaft currents, and a modified cooling system. Other motor features can include auxiliary fan cooling. If available, motors that operate below their first lateral critical speed should be specified (see Section 1560).

When selecting the voltage rating of the drive and equipment, the amount of current involved and the insulation rating of the motor are the significant factors. Generally, 1200 amperes is considered a reasonable high-end current rating. Exceeding 1200 amperes will normally lead to the next higher voltage rating. For motor insulation ratings, there is a desire to stay below 6,900V when possible, since at 6,900V and above, the cost of the motor makes an abrupt change and at these voltage ratings corona and partial discharge of the stator windings becomes a common failure mode for motor failures. Figure 1500-22 provides a guide for selecting voltage ratings.



1530 Applying Low Voltage DrivesMost of the industrial or commercial drives applied in the Company’s world-wide facilities will consist of low voltage (LV) drives with voltage ratings of 375VAC (Europe and Far East, 50 Hz), 460VAC (US) and 575VAC (Canada). Sizes of LV drives typically range from fractional to 1000 HP, with some specialized manufac-turers building LV drives up to 2500 HP. LV drives are virtually all PWM-type, and consist of either general purpose speed control (V/Hz control) or flux-vector (torque-producing current) control. Software is used to select either general purpose or flux-vector control. Some manufactures use open-loop control and others use closed-loop control (with a speed reference or rotor position feedback signal) to accommodate the flux-vector control technology.

1531 LV Type DrivesLV drives, manufactured today, are designed and built with diode or silicon controlled rectifier (SCR) line converters for the rectifier section and insulated gate bi-polar transistors (IGBT) for the inverter section. The control method for switching the IGBT devices on the inverter is by pulse width modulation (PWM). The general purpose drive uses a volts per hertz (V/Hz) proportional control. For constant torque control, the V/Hz ratio (programmable function) is a constant value to provide constant torque (and variable HP) over the speed range. For variable torque control, the V/Hz pattern can be programmed to follow a non-linear square-function characteristic curve, to provide variable torque output (reduced torque at reduced speed) for centrifugal loads. General purpose drives provide very good speed and torque control for most (if not all) applications found in the Company’s facilities. Output speed is controlled based on a V/Hz basis, and speed regulation is better than +/- 1 percent up to 10:1 speed range.

Flux-vector control provides a much tighter speed and torque regulation since the torque-producing current is delivered from the drive, based on a complex drive algo-rithm, and specific programmed motor parameters. Some drive manufacturers require rotor position or speed feedback (closed-loop control) from an encoder device, monitoring the shaft of the motor. Other manufacturers have sophisticated software algorithms that do not require encoder feedback (open-loop control) to

Fig. 1500-22 Typical Drive Voltage and HP Ratings

Drive Voltage HP Range

460 and 575 up to 650

460 and 575 with Input & Output Transformers

600 - 2,500

2,400 650 - 5,000

4,160 650 - 20,000

6,900 10,000 - 30,000

13,800 25,000 - 50,000+



produce flux-vector control. Speed regulation for open-loop control is 0.1 percent. Closed-loop, flux-vector control is preferred for applications requiring very high performance torque requirements with tight speed regulation throughout the speed range and especially at low speeds. Speed regulation for closed-loop control is ± 0.01 percent, up to 100:1 speed range, and matches the performance of dc drives.

1532 LV Drive SpecificationELC-MS-4371 is a specification with data sheets (ELC-DS-4371) and a data sheet guide (ELC-DG-4371) to assist in specifying LV drives. Some features of the speci-fication will be dependent upon the electrical system that supplies power to the drive. If a specification is being developed by an EPC contractor, the plant engineer or an engineer familiar with the plant’s electrical system should be consulted during the preparation of the specification. If a supplier alliance exists with a drive manu-facturer, the specification should be developed hand-in-hand with the manufacturer to have the best opportunity for success.

Things to consider in the application of the drive include:

• Electrical system voltage considerations (transient overvoltage and voltage sags, normal plant operating voltage level, existing system harmonic profile, source impedance, and existing capacitors),

• Sensitive electronic equipment, fed from the same source as the drive, may require special filtering or special drive design to mitigate the effects of the drive-produced harmonics,

• Maintenance, spare parts, and training requirements, and

• Preference for a single manufacturer.

General considerations when specifying the drive include:

• Sufficient design margins (components applied to 50 percent of ratings) for the power switching devices (transistors, diodes, SCRs) and other power compo-nents (capacitors, resistors, inductors) applied to 75 percent of ratings,

• Temperature and dust considerations for the drive enclosure,

• Noise produced (by the drive and motor),

• Harmonics (effects on the motor and electrical system),

• Type of motor specified or existing motor for retrofit applications (inverter-duty motor, winding insulation voltage rating, temperature rise, insulated bear-ings, etc.),

• Input or output filter to control harmonics and high dv/dt voltage wavefronts due to IGBT PWM inverters,

• Motor location considerations include: Area classification for motors in hazardous areas, and severe-duty locations (washdown areas),



• Driven equipment requirements: speed/torque requirements (constant or vari-able), speed range, HP size.

• Consideration for testing the motor & drive, in the factory, through the complete speed and torque range.

When specifying the speed range of the application, careful consideration should be given to the operating process needs. The specified speed range should not be so overly conservative that it forces the selection of the next higher horsepower rated motor. For example, assume that preliminary process conditions call for a 3:1 speed range (1200 to 400 rpm) for a constant torque application, resulting in the selection of a 75 HP motor. For conservative purposes (because the time had not been spent to define operating conditions), a 6:1 speed range (1200 to 200 rpm) is specified. At the lowest speed (200 rpm), the stator winding temperature is expected to exceed the temperature rating of the insulation, so a 100 HP motor and drive are specified. Later it was confirmed that the lowest operating speed is 400 rpm. The cost of the higher HP motor and drive could have been averted had the motor and drive been specified for the true operating conditions.

Specification considerations are discussed in more detail below, and in specification ELC-MS-4371, and the Data Sheet Guide, ELC-DG-4371.

1533 Drive Features and Application ConsiderationsDrive features to consider when evaluating manufacturers include: rectifier and input section, control section, inverter and output section, reliability, and motor considerations. These features are discussed in detail, below.

1534 Rectifier and Input SectionLV drive manufacturers use either diode or SCR switching devices for the line converter. Diode converters are more reliable than SCR converters since the MTBF of diodes is significantly higher than of SCRs. For those using SCRs, the devices are gated fully on during normal operation.

Overvoltage ProtectionAll drives have input overvoltage protection to protect the rectifier switching devices and other power components. When the voltage exceeds the setting, the drive will trip with no time delay. The overvoltage sensing is done on the dc bus, and the trip setting is determined by the rating of the switching devices that are used in the drive. Most manufacturers use either 1200VPEAK or 1600VPEAK switching devices. A trip will be initiated if a switching surge, lightning induced surge, or the substation bus voltage rises to the overvoltage trip setting. As an example, a drive with 1600VPEAK rated devices may be set to trip at approximately 570VAC, corresponding to a DC bus voltage of 810VDC:

810Vdc ÷ = 573Vac

Drives with rectifier switching devices rated at 1200 VP may be protected to trip at a lower setting and can be more susceptible to nuisance tripping. If nuisance trip-

2



ping is a problem, either an input isolation transformer can be applied (with the appropriate output voltage taps) or an input line reactor can be selected to minimize the chance of nuisance tripping. 1600VPEAK switching devices are recommended, to improve the reliability of the line converter.

Undervoltage (UV) Ride-ThroughOther considerations for the input (rectifier section) are undervoltage (UV) ride-through and harmonic reduction. All drives have provisions for UV ride-through. How it is accomplished, varies by manufacturer. It is important to understand the specific characteristics of the drive and determine if it provides the needed ride-through performance. When evaluating UV ride-through, both the power section and the control section must be examined. The minimum recommended capabilities for the UV ride-through for both the power and control sections are: a voltage sag of 100 percent of rated line voltage for 0.5 second (30 cycles), and a sag of 50 percent of rated voltage for 1 second (60 cycles). During an UV ride-through, the motor speed will coast down until the under voltage condition passes. Some drive manufacturers accomplish the ride-through with a drive-regulator function, which allows inertia in centrifugal loads to be used to maintain DC bus voltage. Other drive manufacturers use a pause and automatic restart feature, in which the drive is programmed to turn the inverter back on (when voltage returns), catch the motor as it coasts down (flying start), and ramp back up to the last speed command. This should enable the drive to ride-through a voltage sag for a second or more. If the undervoltage condition lasts too long (several seconds) the drive should be programmed to trip (shut down), since other electrical equipment in the plant or facility will shutdown (due to opening of motor contactors). An automatic drive-startup provision is a standard drive feature, and can allow for a programmed DCS or PLC staggered startup of multiple machines if desired.

Harmonic ReductionA computer-simulated harmonic analysis is necessary to estimate the voltage harmonic distortion on the system, produced by the drive. For simple or small horse-power applications, the drive manufacturer may be able to provide this service. Harmonic mitigation features include: in-line input reactors, input R-L-C filters, and/or a 12-pulse (or higher) rectifier section. The front-end engineering study should include: collecting baseline harmonic data, establishing the acceptance criteria of the harmonic distortion levels, determining (by computer simulated harmonic analysis) the system harmonic distortion as a result of the drive, and eval-uating the need for harmonic mitigation (filter), if necessary to meet the acceptance criteria.

Protection from Input Line TransientsMetal oxide varistors (MOV) are normally applied on the input of the drive to protect the power switching semiconductors from input line transients. The MOV must be sized for the voltage peak and energy associated with the highest expected transient wave. In areas of high lightning activity, this is a special concern and should be carefully reviewed by the drive manufacturer. The common failure mode of MOVs is a shorted condition, and since MOVs are normally applied line-to-line,



a failure will result in a line-to-line fault and a blown fuse or a trip of the input circuit breaker.

Input Short Circuit RatingThe short circuit rating of an LV drive is low (typically 22 kA or less) and is normally not equipped with an input fuse or circuit breaker. A fused disconnect switch or circuit breaker is usually a user-supplied item and must be selected to provide adequate short circuit protection and isolation (disconnect means) for the drive. Current limiting, UL Class CC or J fuses are recommended for the input line protection, when current limitation is required, and provide adequate short circuit protection for sources with a short circuit duty up to 200 kA.

1535 Control Section The control section generally includes the rectifier controller, the inverter controller, and the drive status, trip, and alarm interface panel. The controller should be a completely digital microprocessor system. The rectifier controller is the least complex for drives with diode bridge rectifiers. For drives with SCR bridge rectifiers, the controller is slightly more complex. The SCR gating is controlled to gradually raise the voltage during the power up period, to slowly charge the dc link capacitor and avoid overcharging and damaging the capacitors. After the capacitor is fully charged, the SCR is gated fully on, applying full voltage, and remains fully gated during normal operation.

The inverter section is much more complex and includes the pulse width modula-tion microprocessor controller. The pulse width is varied to vary the voltage to the motor. Narrow pulses give low voltage and wide pulses give higher voltage output. The high switching speed of the PWM controller and IGBTs allow for the output current to closely approximate a sinusoid, see Figure 1500-6. This allows the motor to run quieter, more efficiently and cooler, with reduced harmonics.

Programming of the drive is with a key pad and liquid crystal display. Application parameters, based on pre-programmed setpoints for selected applications (i.e., centrifugal pump, fan, conveyor, etc.) are preferred to simplify setup. Override provisions should be available to change any preprogrammed parameter. All suppliers offer many alarm and trip functions, the settings of which should be care-fully selected and completely verified during system commissioning. Undervoltage ride-through should be carefully set up. The limitations of the undervoltage ride-through of the logic control should also be understood and carefully applied and tested.

1536 Inverter and Output SectionLV drive manufacturers use IGBT power semiconductor switching devices in the inverter bridge. IGBTs are used because they allow the motor to run quieter and more efficiently. The introduction of IGBTs allowed the PWM controller to switch the transistors at higher frequencies than bi-polar transistor and other semicon-ductor switching devices. Carrier frequencies of IGBT can exceed 20 kHz. The



carrier frequency or switching speed of the IGBT has many effects. As the carrier frequency exceeds about 2 kHz, the ampere rating of the device may require derating, depending upon the heat sink and cooling capability of the drive design and the HP rating of the drive. Higher carrier frequencies up to about 6 kHz reduce motor losses and acoustic noise, but can lead to rotor shaft currents and bearing failure (see Motor Considerations in Section 1530).

The voltage rating of the inverter-section IGBTs can be lower than that of the recti-fier section devices, since the inverter is not subjected to transient voltages from the input power source. The IGBT should be applied to no more than 57 percent of the device rating. For 480V systems, this means a 1200VPEAK rated device with an applied blocking voltage of x 480Vac = 680Vdc.

The drive provides motor branch circuit and motor overload and short circuit protec-tion. When setup with the appropriate motor parameters, the drive will limit output current to the full load current rating of the motor. A motor overload trip, due to a process-related overload is not possible since the drive is inherently current limiting. No additional motor overload protection (to satisfy NEC requirements) is needed.

Short circuit protection is also incorporated in the drive controls. The pickup setting is preselected. The instantaneous short circuit current is limited by the inverter to a magnitude, normally 200 to 300 percent of drive rated current. Ground fault protec-tion is also incorporated in the drive controls. Drive manufacturers provide different ground fault protection features. Most drives are setup, as a standard, to sense and trip on ground faults. The pickup level differs between drive manufacturers, but are normally low enough to trip on high resistance ground current levels. Many of the Company’s facilities have high resistance grounded (HRG) 480V substations that supply power to drives. The drive should be setup to operate reliably with the HRG source, and not trip. The recommended setup is for the substation HRG resistor tap to be set to limit ground fault current to 2-5 amperes (depending upon system charging current), and the drive ground fault sensor to alarm (not trip) at 2 ampere, minimum (if available). For solidly grounded sources, the drive ground fault trip should be set to trip at 10 amperes.

Installations with long (motor branch circuit) cable lengths may require output line reactors or R-L-C (filter) circuits at the motor terminals to limit the high-peak voltage wave at the motor terminals. The high-voltage standing wave is dependent upon the dv/dt characteristic of the IGBT and the characteristic impedance of the cable. The voltage rating of the motor insulation is also a factor. Insulation voltage rating for standard NEMA frame motors (<600V) is ≤1000VPEAK with a 2 micro-second rise time. NEMA standard inverter-duty motors have insulation voltage rating of ≤1600VPEAK with a 0.1 microsecond rise time. The minimum cable length without correcting for voltage standing waves will vary from drive manufac-turer. Some manufacturers incorporate minimum on-time logic or other means for limiting the high dv/dt effects. The drive user manual should be consulted for wiring installation instructions. If an output inline reactor is used to limit the magni-tude of the voltage wave, it is normally sized for 3 percent of the load (motor) impedance at full load. Other in-line reactor specifications include: 1600VPEAK voltage insulation rating, Class H insulation temperature class (with Class F temper-

2



ature rise), air or iron core, air cooled copper winding. If flux-vector control is required by the load, the reactor size may need to be limited to 1 percent or less, if the drive software cannot include this impedance in the motor-impedance model (flux-vector algorithm). Some manufacturers prefer to use a filter at the terminals of the motor to shunt the high voltage waves. These filters can have quite high surface temperatures, since they continuously conduct high frequency current. Special consideration is necessary when these are applied in Class I Division 2 locations, since the surface temperature of the filter must be less than 80 percent of the autoi-gnition temperature of the hazardous material involved. The preferred location for filters is at the drive.

Electrostatic shielded (conducting material such as aluminum, copper, or steel) cable is often recommended by the drive manufacturer for the motor branch circuit (power) conductors if sensitive equipment or analog instrumentation and control circuits are located near the drive-output cable route. The motor control cables may also require electrostatic shielded cable to protect against noise induced problems. Shielded power cable is also recommended for multiple drive circuits routed in the same cable tray to minimize the “cross coupling” noise between the cables of different drives. The shield should be grounded at both the drive and motor (although some manufacturers recommend grounding at one end to eliminate any noise associated with circulating currents). Cables installed in conduit or armored cables are inherently shielded. Multiple, nonshielded motor circuits should not be installed in a single conduit. Type THHN cable is not recommended for drive output circuits because of the lower dielectric strength of the PVC insulation (tested to UL-83) compared with thermoset insulated cables built to UL-44 insulation thick-ness and test values.

Output harmonic considerations are not as much a concern with IGBT drives, due to the relatively low harmonic current distortion produced. Some additional motor heating is to be expected with IGBT drives and should be considered when sizing the motor.

1537 ReliabilityMany factors affect the reliability of LV drives. Both drive equipment and external components or systems (input power source, motor, motor branch circuit) will affect reliability. Achieving high reliability is dependent upon attention to drive features that contribute to the greatest number of internal drive failures caused by external sources. The drive section that results in the highest number of trips (including those initiated from external causes, from highest to lowest) is as follows: inverter section, rectifier section, cooling section, control section, and dc bus section. Manufacturers that build drives with component or system design margins that achieve high reliability will likely cost more than drives with marginal design margins. Figure 1500-23 identifies recommended ratings, components, or settings for the various drive sections for 460V class drives. For 375V and 575V class drives, the voltage ratings can be directly proportioned and the settings and comments can be directly applied.



1538 Motor Considerations Motors applied with ASDs must be evaluated for certain features. This applies both to new installations and drive retrofits using existing motors. The main consider-ations are motor stator insulation voltage rating and motor (stator, rotor, bearings,

Fig. 1500-23 Recommended Drive Ratings and Features for 460V Class Drives

SECT

ION

Component or FeatureRecommended Rating or

Setting Comments

RECT

IFIE

R

Diode or SCR Power Switching Devices

1600VPEAK Rectifier generally has a high MTBF and simple control logic, but nuisance trips occur too frequently due to voltage spikes from the input-power source. Reliability can be signifi-cantly increased by using the recommended voltage rating for the switching devices.

Undervoltage Ride-Through Zero Volts for 0.5 Sec. and 50% Voltage for 1 Sec

All drives have this feature, however improper settings often defeat or disable its effective-ness. Ensure the settings are properly programmed and test the ride-through during commissioning.

INVE

RTER

IGBT Switching Devices 1200VPEAK 2 kHz Switching Freq.

Devices should be selected that are applied at no more than 57% of the device rating. Switching speeds should never exceed 4 kHz unless motor noise is a concern. Higher switching frequencies cut into device temper-ature and current margins and can cause motor shaft currents and bearing failures.

Ground-fault alarm 2 Ampere (depending upon capacitive charging current)

For drives supplied from a high resistance ground source.

Output Filter Depends on Motor Cable Length (see Mfg. Installa-tion Instructions)

Cable characteristic impedance and dv/dt characteristic of IGBTs can cause high magni-tude output voltages at motor terminals and result in winding failure.

CON

TRO

L Power Supply Not Applicable Dual input option, or UPS for critical systems

Undervoltage Ride-Through Not Applicable Test undervoltage ride-through

COO

LIN

G Fans Not Applicable Redundant fans or sufficient temperature-cooling margins should exist to allow for continuous drive operation with one fan failure. A fan failure should initiate an alarm.

DC

BU

S Power Components Applied to 75% or less of device rating

Components should be selected that are applied at no more than 75% of the component rating.



and lubrication) thermal rating. These considerations and cause and effects are summarized in Figure 1500-24.

Motor Sizing and SelectionMotors size should be based on satisfying all of the following criteria:

1. Winding temperature rise of 90°C (above a 40°C ambient) at worst operating condition, and 80°C rise for normal operating speed range (80 percent of the

Fig. 1500-24 Motor Considerations for LV Drive Applications

Motor Considerations Cause & Effects Recommendations

Stator Winding-InsulationVoltage Rating

High-voltage wavefronts at motor terminals due to fast-switching IGBTs and (motor feeder) cable charac-teristic impedance.

Limit motor branch circuit lengths to manufacturer’s recommendation, or install a filter at the inverter output if effective (otherwise at the motor terminals), or specify 1600 volt-rated stator winding insulation, or specify an inverter duty motor per MG-1, Section IV, Part 31.

Motor Thermal Rating Motor-fan cooling is reduced at speeds below full speed. Cooling air flow is proportional to rpm. Constant torque (constant current) applications result in an increase in motor temperature with a decrease in motor speed. Variable torque (centrifugal pump) applications result in a lowering of motor temperature as the speed is lowered since torque (current) is proportional to rpm2. However, at some reduced speeds the motor temperature increases due to ineffi-ciencies in air cooling. This increase in motor temper-ature (initially for constant torque and gradually for variable torque applications) can affect stator winding insulation, rotor, bearings, and bearing lubri-cation integrity. Harmonic currents also result in higher stator and rotor heating.

Specify a limit for stator winding temperature rise to 90°C (above 40°C ambient). This is equivalent to Class B + 10°C rise. If the stator winding temperature rise is expected to exceed 90°C, specify the next higher HP-size motor or retrofit the motor with an auxiliary (externally mounted) fan. The cost to retrofit a motor with an auxiliary fan is not usually economic unless the motor size is increased two sizes above the stan-dard-rated motor. These are generally constant torque applications with a speed range greater than 6:1.

Class I Division 2 Area Classifications

Higher motor surface temperatures will be experi-enced on drive-controlled motor versus motors on sine-wave power.

TEFC motors are recommended for all Class I Division 2 applications, however the motor surface tempera-ture cannot exceed 80% of the ignition temperature of the gas or vapor involved during normal operation. For some applications, the next higher size motor may be required to meet this requirement. Other methods for reducing the surface temperature of the motor are externally mounted fans. Explosion-proof motors should be avoided, unless specifically required for the application.

Shaft Currents Shaft currents are caused by voltages induced on the motor rotor by fast-rising PWM voltage pulses and the fluctuating neutral (common mode) voltage of the inverter output. The switching frequency of the PWM controller is a significant factor. A capacitative effect results between the rotor shaft and the grounded motor frame (and bearing enclosure). At speeds above 300-400 rpm, bearings will ride on a thin film of insulating lubricant, resulting in an undergrounded rotor. If the fluctuating neutral voltages (common mode voltage of the inverter output) reaches a certain magnitude, a discharge current will flow, damaging the bearing race. PWM converters operating at carrier frequencies higher than 5 kHz may require insulated bearings.

Keep PWM switching frequencies below 4 kHz. Alter-natively, insulate both bearings to eliminate the current path. Other corrective measures to consider are to incorporate minimum on-time PWM logic or other means (snubber circuits) for limiting the high dv/dt. Additionally, a filter installed at the drive output or at the motor terminals can reduce the shaft-to-bearing housing voltages. Other considerations are to ground the inverter output (motor side) to shift the common mode voltage to the rectifier (input side).



operating time). Consider a 105°C rise (zero design margin) for applications in which the worst case operating condition is unlikely to occur or will only occur for 1 percent of the operating time.

2. Bearing temperature rise of 45°C (above a 40°C ambient) at worst operating condition. Consider a 55°C rise (zero design margin) for applications in which the worst case operating condition is unlikely to occur or will only occur for 1 percent of the operating time.

3. NEC T-Code for the area classification

Figure 1500-25 is a guide in selecting motor HP ratings for new drive applications requiring standard motors with NEMA Class A or B torque characteristic (see Figure 1500-31 for retrofit applications). Both the drive manufacturer and driven equipment manufacturer should confirm the motor size. In addition, the motor and drive manufacturers should always be consulted to verify that the ASD application is suitable for their equipment. Motors, built to the latest IEEE Std 841 and DRI-MS-1824 are recommended for drive applications. IEEE Std 841 motors offer many of the design features that are suitable for drive applications. Two inverter-duty design features that are not included in an IEEE 841 motor are 1600VPEAK rated winding insulation and insulated bearings.

(1) Motor standard rating is based on 60 Hz sine-wave power.(2) Premium Efficiency (PE) Motors meet the energy Policy Act of 1992 (NEMA MG-1-1993 refers to PE motors as “energy efficient”).

An auxiliary fan, retrofitted to the motor frame, can be evaluated for applications with a wide speed range, versus increasing the size of the standard motor. This option is usually not economical unless the motor HP size is increased two sizes above the standard-rated motor.

Constant torque applications are the most severe for motor service. Figure 1500-26 shows the relationship between voltage, horsepower, torque, and current versus speed for constant torque, applications.

Fig. 1500-25 Typical Motor Sizes for ASD Applications

Speed Range

Motor Size(1)

Variable Torque Applications(Centrifugal Loads)

Motor Size(1)

Constant Torque Applications

2:130 - 60 Hz

Premium Efficiency (2) TEFC Motor W/ 1.0 SF Premium Efficiency TEFC Motor W/ 1.0 SF

3:120 - 60 Hz

Premium Efficiency TEFC Motor W/ 1.15 SF Premium Efficiency TEFC Motor W/ 1.15 SF

4:115 - 60 Hz

Premium Efficiency TEFC Motor W/ 1.15 SF Premium Efficiency TEFC Motor W/ 1.15 SF, one size above standard motor

6:110 - 60 Hz

Premium Efficiency TEFC Motor W/ 1.15 SF, one size above standard motor


10:16 - 60 Hz


Premium Efficiency TEFC Motor W/ 1.15 SF, two sizes above standard motor



High speed applications (above synchronous speed) for low voltage motors are common. Most motors can operate above normal nameplate speed. Four pole, 1800 rpm, motors can typically be operated to 2700 rpm, and six pole, 1200 rpm, motors up to 2400 rpm. Two-pole, 3600 rpm, NEMA-frame motors are likely to be closer to their first lateral critical speed. The maximum speed varies greatly between frame sizes and models. Motor manufacturers should be consulted for actual maximum operating speed, especially with two-pole motors.

Motor Sizing ExamplesFor variable torque applications, the worst operating condition is at the highest oper-ating speed. For constant torque applications, the worst operating condition is at the lowest operating speed. The motor sizing criteria, described above, should be used to determine the HP rating of the motor. Figure 1500-25 can also be used to deter-mine the need for increasing the motor HP rating above the standard HP rating. The following two examples will show how to size motors for variable torque and constant torque applications.

Example 1 - Variable Torque Application. Size a motor for a pelleter application with a 6:1 speed range and the speed torque conditions given in Figure 1500-27, below. This is a variable torque application with a maximum speed operating condi-tion above synchronous speed for a six pole motor.

Fig. 1500-26 Constant Torque Characteristics for Induction Motors. 1995 IEEE. Used with permission from IEEE 95-CH35840-b/95/0000-0231.



For this variable torque application, size the motor HP rating based on the highest operating speed, which is 1500 rpm and 158 lb-ft of torque. The HP rating is given by the following formula:

Select a 50 HP motor to accommodate the maximum speed condition (and HP requirement of 45 HP). The motor should meet the requirements of DRI-MS-1824 and IEEE Std. 841-1994. By meeting the requirements of DRI-MS-1824, the winding temperature rise at the service rating must not exceed 90°C, and per IEEE Std. 841, the bearing temperature rise must not exceed 45°C.

Example 2 - Constant Horsepower, High Torque Application. Size a motor for an agitator application with a 6:1 speed range with the speed torque conditions and expected operating hours given in Figure 1500-28, below.

For this application, size the motor HP rating based on two methods described below and compare the pros and cons of each:

1. On an equivalent 60 Hz (900 rpm) basis, at the lowest operating speed, and a load torque of 600 lb-ft.

The HP rating should also be based on operating the motor at Class F tempera-ture rise. Using a Class F rise provides no design margin at the worst case, minimum speed. However, since the motor operates only 75 hours per year (less than 1 percent of the time) at this condition, this is an acceptable margin.

Fig. 1500-27 Speed vs. Torque Requirements for Motor-Sizing—Example 1

Operating Condition Speed (rpm) Torque (lb-ft)

Maximum Speed 1500 158

Normal Highest Speed 1200 131

Medium Speed 800 98

Minimum Speed 200 26

HPTorque Speed×

5250--------------------------------------=

HP158 1500×

5250--------------------------- 45 HP= =

Fig. 1500-28 Speed vs. Torque Requirements for Motor-Sizing—Example 2

Operating Condition Speed (rpm) Torque (lb-ft) Operating Hrs/Year

Normal Maximum Speed 855 300 6000

Normal Minimum Speed 425 570 2200

Safe Off (Worst Case Minimum Speed Speed

150 600 75



2. On an actual HP requirement for the worst HP case and use a motor with an external blower to cool the motor at low speed.

Method 1 (Example 2):

Based on the motor manufacturer’s allowances for limited cooling at 150 rpm, and additional heating due to harmonics, a 150 HP motor is chosen, with the following characteristics: 900 rpm, TEFC, 1.15 SF, Class F, premium effi-ciency.

Method 2 (Example 2):

The HP requirements for the three operating cases are calculated and shown in Figure 1500-29. For the normal operating speed range (425 - 855 rpm) the HP load is constant. For the unusual, safe-off condition, high output torque is required.

The HP required for the lowest speed is 17 HP, however the inverter output voltage at this speed (based on a constant V/Hz output) is 460/6 = 77 volts. The amount of load current for 17 HP at a motor terminal voltage of 77 volts is approximately 125 amperes, equivalent to the full load current of a 100 HP motor. Choose a 100 HP, premium efficiency, TEFC, 1.15 SF motor, with an external blower.

Discussion For Example 2. The 100 HP motor with the external blower will cost about two-thirds the price of the 150 HP motor and should be chosen. If there is concern about the reliability of the external blower, the motor and drive should be specified to operate with the external blower on all of the time and alarm if it fails. A spare blower should also be ordered, to improve the mean time to repair.

Many drive and motor manufacturers offer motors with a 1.15 service factor (SF) as a standard for drive applications. When appropriate, 1.0 SF motors are preferred, however, 1.15 SF machines are acceptable, if the winding temperature rise at SF load does not exceed 90°C (Class B, service-factor temperature rise). See DRI-MS-1824, Section 5.4, for a discussion of service factor temperature rise. In this case, the 1.15 SF allows for a small margin for machines that are sized right at the stan-

HP600 900×

5250------------------------ 103 HP= =

Fig. 1500-29 Speed vs. Torque Requirements for Motor-Sizing—Example 2, Method 2

Operating Condition Speed (RPM) Torque (lb-ft) HP

Normal Max Speed 855 300 49

Normal Min Speed 425 570 46

Safe Off (Worst Case Min Speed)

150 600 17



dard motor rating. When 1.15 SF motors are specified, the service factor tempera-ture rise of 90°C should be clearly stated on the motor data sheet.

Most 3600 rpm (and lower) motors up to 900 HP operate below their first lateral critical (synchronous) speed. A lateral critical rotor dynamic analysis is therefore not required for these motors. However, the driven equipment may have a lateral natural frequency in the operating speed range. This should be checked and verified by the driven equipment manufacture. Torsional analysis should also be considered for motors above 500 HP. Refer to Section 1560 for guidance on when to perform rotor dynamic studies.

1539 Drive Retrofit ApplicationsRotating machinery considerations and branch circuit cable type are two of the most important issues for retrofit applications. Fixed speed machinery (motor and driven equipment) may not run properly over the variable speed range. Special considerations must be taken when applying an inverter to an existing motor. At slower speeds, cooling is not as effective due to reduced fan speed, and damage could occur due to overheating. In situations where the load requires high torque at slow speeds, the minimum speed might not provide adequate cooling, in which case the next higher HP motor may be necessary. Figure 1500-30 shows a curve, plotting acceptable torque versus speed for retrofit applications. Note that for a safety margin, the curve shows no more than 90 percent motor rated torque be applied for the ASD application. If torque requirements at slow speeds continuously exceed the values shown in the curve, a motor rated for inverter operation should be specified.

Operating above or below 60 Hz may damage bearings or rotating parts. Slow speeds may not provide sufficient lubrication for bearings, oil filled gear boxes, speed reducers, or other machinery with journal or sleeve bearings, or other compo-nents with lubricated, nominally sliding bearing or force transmitting surfaces. The

Fig. 1500-30 Torque vs. Speed for Retrofit Applications. Courtesy of Toshiba International.



first or second lateral critical natural frequency may also be within the operating speed range. Operating on or near a critical speed can cause high vibration and can damage bearings and rotating equipment. The drive may also produce harmonic currents that excite a torsional critical natural frequency. Computer simulated lateral and torsional analyses are required to identify natural frequencies and correc-tive actions, if necessary. See Section 1560 for more discussion on rotordynamic studies. A computer simulated harmonic analysis is also required to identify any possible effects that the drive-created harmonics may have on the electrical distribu-tion system. See Section 1550 for a detailed discussion of electrical distribution system considerations.

Often, a motor on a fixed speed application can be directly applied to an ASD. If a new motor must be substituted for an existing machine, Figure 1500-31 can assist in determining if the existing motor is adequate, or assist in sizing the new motor. Premium efficiency motors should be selected for all ASD applications, since they traditionally run cooler than less efficient machines. IEEE Std 841-1994 are preferred motors, since they have many inverter-duty features.

(1) Motor standard rating is based on 60 Hz sine-wave power. (2) High Efficiency Motors exceed the standard efficiency motors supplied by the manufacturer. (3) Premium Efficiency Motors meet the Energy Policy Act of 1992 (NEMA MG-1-1993 refers to PE motors as "energy efficient").

Electrostatic shielded cable may be necessary if sensitive equipment or analog instrumentation and control circuits are located near the drive-output cable route. All existing THHN cable should be replaced with UL-44 listed cable. See Section 1536 for more details on the inverter output.

1540 Applying Medium Voltage DrivesMedium voltage drives consist of both induction and synchronous types. There are three common induction-motor drive types. One uses a silicon controlled rectifier (SCR) inverter bridge with a large output capacitor (for commutation), called a load commutated inverter (LCI) induction motor (IM) drive. The second type is one

Fig. 1500-31 Minimum Motor Sizes for LV ASD/Retrofit Applications

Speed RangeMotor Size(1)

Variable Torque ApplicationMotor Size(1)

Constant Torque Application

2:130 - 60 Hz

TEFC Motor W/ 1.0 SF TEFC Motor W/ 1.0 SF

3:120 - 60 Hz

High Efficiency (2) TEFC Motor W/ 1.0 SF High Efficiency TEFC Motor W/ 1.15 SF

4:115 - 60 Hz

Premium Efficiency (3) TEFC Motor W/ 1.0 SF

High Efficiency TEFC Motor W/ 1.15 SF, one size above Standard Motor

6:110 - 60 Hz



10:16 - 60 Hz

Premium Efficiency TEFC Motor W/ 1.15 SF, one size above Standard Motor

High Efficiency TEFC Motor W/ 1.15 SF, two sizes above Standard Motor



using gate turn-off (GTO) thyristors in the inverter bridge, called a GTO drive. The third type is a drive that uses a low-voltage power cell, connected in series, to provide the desired voltage output, called a Harmony Power Cell drive. See Section 1513 for a basic description of medium voltage induction-motor drives.

MV induction-motor drives range in sizes from 400 HP to 15,000 HP. High-speed (super synchronous) drives have also been applied up to 12,000 rpm. As the speed of the drive increases, the HP size that can be applied, decreases due to rotor fabri-cation limitations. The Company has applied conventional speed (up to 3600 rpm) induction-motor drives up to 10,000 HP and high speed drives up to 3,500 HP and 11,000 rpm.

Synchronous-motor drives are load commutated inverter (LCI) types, using SCR converter bridges. The field on the synchronous machine is controlled by the ASD control system, to vary the motor terminal voltage in order to commutate the machine-converter thyristors. See Section 1510 for a basic description of the synchronous-motor LCI drives.

Figure 1500-32 provides an HP versus speed application envelope of MV induction and synchronous-motor drives that have been applied in industry.

1541 Induction-Motor Drive TypesThe GTO and LCI IM drives both use the same line and machine converters, normally either 6-pulse or 12-pulse bridges, with thyristors. The Harmony Power Cell drive uses a low voltage power section with a diode line converter and an

Fig. 1500-32 Induction and Synchronous Motor Drive HP vs Speed Application Envelope



IGBT output (single-phase) converter. The power cells are connected in series to develop the necessary output medium voltage. All drive-types use either air or liquid for cooling the power section.

GTO Type Induction-Motor DriveThe GTO drive has power ratings up to 15,000 HP and 6,900 volts. The maximum speed for the GTO drive is 9,000 rpm (and increasing) as the GTO thyristor tech-nology continues to grow. GTO drives can be either current-source or voltage source inverters. Most drive manufacturers use PWM technology to switch the GTO thyristors.

The standard GTO drive uses a 6- or 12-pulse line converter. Each leg of the recti-fier bridge consists of a sufficient number of SCRs in series to reliably block the input voltage. The recommended design margin is a working voltage equal to one half the repetitive reverse blocking voltage. Equal (dc) voltage sharing among the rectifier devices is accomplished with voltage dividing resistors in parallel with each thyristor. Rate-of-rise voltage (dv/dt) is controlled by R-C snubber circuits in parallel with each thyristor. DC link reactors are used to smooth the current ripple on the DC bus. Normally two dc link inductors are used, one on the + dc bus and one on the - dc bus. The inductors are air or iron core, dry type, and air cooled reac-tors.

Each leg of the inverter bridge consists of a sufficient number of GTO devices in series to reliably block the DC bus voltage. Voltage dividing resistors and unidirec-tional R-C snubber circuits, for dv/dt control, are connected in parallel with each GTO. The GTO device has two gate inputs, one to turn the device on and the other to turn the device off (or force commutate). Several amperes is all that is required to turn on a GTO, however, as high as a thousand amperes, applied for several micro seconds, is necessary to turn off a GTO. The inverter utilizes a current source controlled bridge to provide a variable frequency and variable voltage source to an induction motor. The GTO converter can handle power flow in either direction.

The GTO inverter uses a pulse width modulated (PWM) control mode, which can selectively reduce the electrical harmonics to the motor. By the correct selection of switching points, particular harmonics can be eliminated in the inverter output wave. This is done at the expense of an increase in some higher order harmonics, which can be filtered out. A relatively small size capacitor filter on the output of the drive removes most of the higher order harmonics and produces an almost sinuso-idal current waveform to the motor. This makes the GTO type drive particularly well suited for retrofit applications. However, motor thermal heating, stator winding voltage stresses, lateral and torsional rotor dynamics, and source and load harmonics all need to be evaluated for retrofit applications.



GTO thyristors come in a variety of voltage and current ratings. A typical rating and its characteristics are shown below:

GTOs are primarily classified by their repetitive peak reverse voltage and gate turn-off current rating, such as 4500V - 800A GTO. For improved reliability, the working voltage of a GTO is one-half of its peak reverse voltage. Typically there may be three of these devices in series per leg of an inverter for a 1,500 HP 4000V motor. Selecting the number of devices in series can be determined as follows.

Peak applied voltage is:

1.414 x 4160V = 5,900VPEAK.

GTO working voltage is:

4,500VPEAK ÷ 2 = 2500VPEAK.

The minimum desired number of devices is:

5,900VPEAK ÷ 2,500VPEAK = 2.4, or three devices in series.

A graphical symbol for a GTO is shown in Figure 1500-2.

LCI Type Induction-Motor DriveThe LCI induction motor (IM) drive has power ratings up to 12,000 HP and 6,900 volts. The maximum speed for the LCI IM drive is currently (1996) approximately 12,000 rpm. The LCI IM drive uses a current-source drive technology. The line converter controls the DC bus voltage, and therefore the current, to provide the torque necessary to satisfy the motor shaft load. The inverter switches the DC bus current from phase to phase at the necessary frequency to provide the necessary V/Hz input to the motor.

• Repetitive Peak Off-Stateand Reverse Voltage

4500V

• RMS On-State Current 300A

• Turn-Off Gate Current 260A

• Peak Gate Turn-Off Current 800A

• Gate Turn-On Current 2.5A

• Mounting Force 1200Kg

• Junction Diameter 34mm

• Gate Turn-On Time 8µSec

• Gate Turn-Off Time 17µSec

• Critical dv/dt 900V/µSec

• Minimum di/dt 200 A/µSec

• Peak One Cycle SurgeOn-State Current

4500A



The rectifier bridge for the LCI IM drive is configured the same as for the GTO (see above).

Each leg of the inverter bridge consists of a sufficient number of SCR devices in series to reliably block the DC bus voltage. Voltage dividing resistors and R-C snubber circuits, for dv/dt control, are connected in parallel with each SCR. The SCR device has a single gate input, to turn the device on. An SCR can only be turned on if two conditions are met: if a forward voltage bias (anode to cathode) is present and if a gate signal is present. Several amperes is all that is required to be applied to the gate to turn on an SCR. The SCR is turned off by reverse biasing the device and removing the gate signal. The device turns off when the current goes to zero. The reverse bias voltage comes from the load, and since an induction motor’s terminal voltage does not provide adequate biasing voltage, a capacitor is installed on the output of the inverter to provide a steady and adequate biasing voltage for commutation.

SCRs come in a variety of voltage and current ratings. A typical rating and its char-acteristics are shown below:

SCRs are primarily classified by their repetitive peak off-state and reverse voltage and average forward on-state current rating, such as 3,300V - 1000A SCR. For improved reliability, the working voltage of an SCR is one-half of its peak reverse voltage. Typically, for a 7,000 HP, 4000V motor there may be five of these devices (in an N+1 configuration) in series per leg. Selecting the number of devices in series for an N+1 configuration can be determined as follows.

Peak applied voltage is:

1.414 x 4160V = 5,900VPEAK.

• Repetitive Peak Off-State andReverse Voltage

3200V

• Average Forward On-StateCurrent

1000A

• Junction Diameter 43 mm

• Mounting Force 5,000-6,000 lb

• DC Gate Trigger Current 200mA

• Gate Turn-On Time 10µSec

• Circuit Commutated Turn-OffTime

125µSec

• Critical dv/dt 1000V/µSec

• Critical di/dt 100A/µSec

• Peak One Cycle SurgeOn-State Current

15,000A



The minimum desired number of devices is:

5,900VPEAK ÷ 1,600VPEAK = 3.7 or four devices in series. Five devices are used in an N+1 leg configuration.

Harmony Power Cell DriveThe Harmony Power Cell (HPC) drive has power ratings up to 10,000 HP and 6,600 volts. The maximum drive output frequency, furnished to date (May 1996), is 120 hertz. The existing drive technology can accommodate higher output frequen-cies. The HPC drive uses a non-conventional PWM technology, in that the single-phase output of each cell is controlled using PWM technology. However, the single-phase outputs in each phase are synchronized such that total output is a 3-phase, sine-wave voltage whose frequency is controlled to get the desired motor speed. This differs from all other 6- or 12-pulse converters, in which only two phases conduct simultaneously. The advantage of the HPC drive technology is that output torque pulsations are very low, throughout the speed range, with a peak magnitude less than 0.1 percent of rated torque and an average of 0.01 percent of rated torque. In addition, total harmonic current distortion on the input and output is very low, well below IEEE limits. The magnitude is dependent upon the number of power cells used to develop the output voltage. The 2,400V ASD uses an 18-pulse line converter and equivalent machine converter; the 4,160V ASD uses 30-pulse converter; and the 6,600V ASD uses 48-pulse converter. The lowest harmonic for the 2400V drive is the 17th harmonic, for the 4160V drive is the 29th harmonic, and the 6600V drive is the 47th harmonic.

To illustrate the HPC drive, consider a 4160V ASD consisting of five sets (or cells) of 6-pulse converters, phase shifted so as to form a 30-pulse input. The topology of the 4160V HPC drive is similar to the 2300V ASD, shown in Figure 1500-9. Two more power cells are used per phase for the 4,160V drive. The input line converters are each supplied with a 480V, 3-phase voltage from individual windings in the isolating transformer. The isolating transformer is mounted inside the ASD cubicle and is furnished as part of the drive. The supply voltage can be any voltage up to 13.8kV. With this configuration, the input line current has considerably less than 5 percent total harmonic current distortion (as measured on the input terminals of the drive). The total harmonic voltage distortion, as measured at the input of the drive, is considerably below 3 percent, even for a source impedance as high as 10 percent on the ASD’s own KVA base. The harmonic current and voltage distortion will be even less at other locations on the electrical distribution system.

Each 6-pulse line-converter bridge feeds an inverter bridge which has a single-phase output. The inverters are connected in series on each phase to form a three-phase, sine-wave voltage output. At any frequency, a sine-wave current is flowing in all 3 phases to the motor. The motor current duplicates the current which flows in a three-phase motor fed from a 60 Hz source, except the frequency varies. Any motor, even an existing motor, can be used with the HPC drive. A 1.15 SF is not required, nor is extra motor stator winding insulation.



1542 LCI Synchronous-Motor DriveIt is usually not economic to consider using synchronous-motor drives until the application reaches about 10,000 HP. Synchronous-motor drives are current-source, load commutated inverter (LCI) type and uses a line and machine converter that is the same as the LCI induction drive (see Section 1541). Thyristors are used in both the line and machine converters. Design margins for applying the power section components are the same as for the induction-motor drive.

The significant difference between the induction and synchronous-motor LCI is the field control on the synchronous-motor ASD. The field control system normally uses a 3-phase low voltage (e.g., 480V) source, to a voltage controller. The field supply voltage controller consists of back-to-back thyristors on each phase leg and a field control circuit board that controls the gating signal and the voltage output. The ASD field-control circuit supplies an output voltage to the exciter to produce an ASD drive (inverter) output V/Hz pattern depending upon the motor load.

It is common to use a 12-pulse converter on the line converter, due to the high magnitude of harmonic currents associated with the large HP drives. A 12-pulse machine converter is also desirable to limit the harmonic currents and motor stator and rotor heating.

Drive cooling is either air or liquid (glycol) with liquid cooling the preferred method for applications above 15,000 HP.

Drive controls should be fully digital with fiber optics for the thyristor gating signals. Fiber optics provide two benefits, elimination of noise contamination on the gate signal and voltage isolation between the medium voltage bridge and the control system.

1543 MV Drive ConfigurationsSeveral drive configurations are shown below for medium voltage drives. These are the basic building blocks for more complex or sophisticated configurations.

Figure 1500-33 shows a 12-pulse/12-pulse LCI synchronous-motor drive, with two 6-pulse bridges combined in series. The input transformer (not shown) provides a 30-degree phase shift between the two rectifiers, which then produce a total of 12 pulses for each cycle of line power frequency. The motor has two three-phase wind-ings displaced by 30 electrical degrees from each other, which allows the two inverters to produce a 12-pulse output.

Figure 1500-34 shows a 6-pulse/6-pulse GTO drive configuration for controlling multiple motors. Each drive controls two (or more motors), which reduces the capital costs of the installation. Some additional complexity is necessary for the drive and pump controls. This configuration can be used for water injection applica-tions or pipeline applications, in which the system pressure is controlled by multiple pumps. Motors can be put into service or taken out of service sequentially. As an example, M1 is started and brought up to speed to satisfy the pressure controller set point. If the set point is not met with the capacity of pump #1, then M1 is switched to the fixed-speed bus and M2 is started by the common ASD.



1544 MV Drive SpecificationAn MV drive specification and data sheets should always be used to purchase an ASD. There are many similar specification requirements for both induction and synchronous medium voltage drives. This makes it suitable for a single model speci-fication to be used as the basis for a purchase specification for either induction or synchronous applications. At this time, a Company specification and data sheets do not exist for medium voltage drives. However, a model specification, ELC-MS-

Fig. 1500-33 12 Pulse/12 Pulse Configuration. Courtesy of Ansaldo Ross Hill.

Fig. 1500-34 6 Pulse/6 Pulse GTO Drive Configuration for Multiple Motors



5008, can be found in Volume 2 of the Electrical Manual. Unique features and requirements can be added to the model specification to make it specific for the application.

Parameters to Determine for Drive EquipmentDrive equipment includes: input or output transformers, input or output filters, drive and motor. In order to accurately specify drive equipment, you must complete suffi-cient front-end engineering to determine all of the following parameters:

• HP size• speed range• load characteristic (variable or constant torque)• process control strategy• input and output harmonic filtering needs• voltage transformation needs• motor type

Data SheetsOnce you have determined these parameters, complete the appropriate data sheets. Completed data sheets should accompany the specification to identify specific drive, motor and driven equipment application features. Drive data sheet items should include:

• site conditions• input power source voltage and source impedance• drive requirements• control options• metering• alarm and protection features• testing requirements

A single-line diagram and an impedance diagram (if available) should also accom-pany the data sheets and include the entire electrical distribution system, beginning with the utility source. The diagram should also include all downstream distribution equipment.

For the purchase of new motors and driven equipment, data sheets, based on the applicable industry standard (API-541 or 546), should be completed and accom-pany the drive specification.

For new or retrofit applications, motor and driven equipment data sheets should include:

• HP• voltage• ampere• power factor• rpm



• stator and rotor inductances• magnetizing inductance• insulation temperature class and voltage ratings• breakdown torque• lateral critical speeds

The driven equipment data sheets should include:

• equipment type (fan, compressor, pump, etc.)• type of motor connection (coupling or gear)• manufacturer• model number• BHP• full load speed• load wk2

• starting torque• speed versus torque curve• lateral critical speeds

1545 Considerations for MV Drive ApplicationsMedium voltage drive applications, unlike LV drives, are customized-engineered systems. As the HP size gets larger, the degree of customization increases. Experi-ence has shown that a high degree of Company involvement is necessary to success-fully apply drive systems. By success is meant a drive that meets the requirements of the intended service with trip-free operation, without adversely affecting other equipment on the system. If the drive were installed in a lab, under controlled condi-tions, the manufacturer could independently apply the product successfully without much outside involvement. However, conditions are not ideal in an operating facility. A highly integrated application effort by the drive and driven equipment manufacturers, the ASD application engineer, and Company personnel (familiar with the facility) is required. All of the steps identified in Figure 1500-21 should be done.

Each of these steps often has intra-disciplinary overlaps that must be thoroughly evaluated. For example, if on a compressor application, anti-surge protection is applied on the compressor, the entire system must be evaluated to ensure that the drive and all other systems will successfully perform during an impending surge condition. This calls for evaluation by many disciplines: all of the equipment suppliers (compressor, drive, surge controller) and all of the application engineers (control systems, drive, mechanical, process). Finally, to verify that the design is correct, a commissioning field test must be done to prove that the designed system works. Commissioning always uncovers unanticipated effects or flaws in the design. Through testing, the flaws and other unanticipated effects can be corrected.

Harmonics can be especially troublesome to the power system supplying large MV drives, especially if there is sensitive electronic equipment (computers, analyzers, process controllers) supplied from the same power source as the drive. An engineer,



specializing in harmonic analysis, should be consulted on all large ASD applica-tions. Some form of harmonic filtering should always be applied, if there is a doubt about the harmonic effects. This is discussed in more detail in Section 1550.

General Application ConsiderationsThere are many common application considerations for all types of MV drives. These considerations are discussed below. Unique application considerations for the three types of induction-motor drives and the synchronous-motor LCI drive are discussed after this section.

Drive Input. MV drives should always be applied with a rectifier-duty input trans-former. The transformer can be either a two or three winding transformer depending upon harmonic considerations and should be equipped with an electro-static shield. Three-winding transformers with a 12-pulse rectifier are recom-mended.

Selection of the transformer impedance is an important consideration, since it will affect the following design requirements: commutation impedance of the line converter, the short circuit duty applied to the line converter, the voltage notch depth of the input source, and the harmonic voltage distortion. The drive designer must resolve these competing requirements and a compromise must be made to satisfy the overall system requirements. The higher the transformer impedance, the lower the short circuit duty on the line converter and the smaller the voltage notch depth that the drive imposes on the system voltage; both of which are desirable effects. The adverse effects of a high impedance are less commutation margin and higher harmonic voltage distortion on the transformer secondary. The impedance should be chosen to limit the voltage notch depth, at the input transformer primary, to a maximum of 20 percent as defined in IEEE Std. 519. It should also meet the specified voltage harmonic distortion limits (See Section 1550). In addition, the short circuit requirements and the drive design margins must be met. Input filters are often utilized to meet the harmonic distortion design criteria.

Undervoltage ride-through is the most important reliability feature of MV drives, especially if the input source from the utility is affected by lightning strikes, switching transients and brown-out conditions. In order to accommodate voltage transients, both the drive power and the control sections should be set up to ride-through a power interruption of zero volts for a minimum of 0.5 seconds and a voltage sag of 50 percent of rated voltage for a minimum of two seconds. In most applications this is sufficient to get through disturbances that traditionally cause most of the drive trips. To verify that the setup is proper, the drive should be tested during commissioning by simulating a voltage interruption while the motor and drive are in operation.

Power Converter Section. The voltage, current and thermal margins for the compo-nents used in the line and machine converters should be applied at no more than 50 percent of their ratings.

Control Section. To improve the reliability of the system, an uninterruptible power supply (UPS) should be used to provide power to the control section. The control section should be completely digital with alarm and diagnostic functions to warn of



impending trouble and provide self monitoring of the drive condition. Constant-voltage transformers (CVTs) should be used to provide control power to the power supplies and other drive equipment. CVTs provide some immunity to voltage tran-sients on the load side of the UPS. The UPS provides effective conditioning of power due to voltage transients on the line side of the UPS. For critical applica-tions, consider using dual control modules to increase reliability of the drive. Self diagnostics monitor the health of the system. If a control system failure is detected, a transfer to the backup module is initiated. A drive trip and switchover is normally required to transfer to the backup, and can take several seconds to complete. The motor will coast down, but after the switchover a flying restart can be performed. If the process can tolerate a 3 second slowdown, this option should be considered.

When setting up control section software parameters, special attention must be paid to the scaling factors. For drives manufactured overseas primarily for the 50 Hz market, the scaling factors must be adjusted for 60 Hz supply systems. The same consideration applies for drives manufactured in 60 Hz markets and applied in 50 Hz locations. Another potential scaling factor problem is alarm and trip settings that have been specially modified and programmed for factory testing. The scaling factors need to be reset and field tested as part of the final commissioning plan.

Drive Output. Sine-wave motor voltage and current produces the best torque, lowest losses, and lowest audible noise in the motor.

Drive Diagnostics. A separate and comprehensive drive monitoring, diagnostic, and fault tracing system should also be considered for troubleshooting and preventing unplanned shutdowns of the ASD system.

Electrical Distribution System. For MV drives, especially large HP applications, the harmonics originating from the drive will have a considerable effect on the elec-trical distribution system. Harmonic filters should be considered for all MV drives whose size is greater than or equal to one-fifth the size of the supply system. Harmonic effects are discussed in more detail in Section 1550.

Rotordynamics. All MV drives larger than 500 HP or with high inertia loads should be analyzed for rotordynamics. See Section 1560.

Motor. Motors applied with MV drives are more susceptible to the heating effects of harmonics due to the high harmonic currents in relation to the rated motor currents. Rotor cage design modifications are often necessary to accommodate harmonic currents. Drives that produce sine-wave output do not require any motor modifications, except for low speed constant torque applications.

Factory Testing. Factory testing should be witnessed for all MV drives. Section 1570 provides guidance for factory testing.

FMEA or RCM Analysis. Early in the design of the drive system, a failure modes and effects analysis or a reliability centered maintenance analysis should be consid-ered for large HP MV drives. Either or both of these studies will reduce failure modes and improve reliability.

The FMEA is best done with the drive manufacturer. Two days should be devoted to this review. The FMEA is really an abbreviated study that has been done on



some applications. In one case, the review discovered over a dozen single-point failure components or systems that were corrected. This is expected to greatly improve the MTBF of the system.

The RCM is best done with the facility engineers, using the drive manufacturer as a resource, to answer specific questions. In addition to improving the MTBF of the system, RCM assists in the training of plant personnel. Additional benefits are improved spare parts selection and a reduced MTTR.

If several drives are being installed with a staggered startup schedule, a Post Startup Review of the commissioning plan and the results of the first unit’s startup can be beneficial in identifying modifications for the other drives and additional checks and evaluations to include in the commissioning plan.

Driven Equipment Surge Protection. Often, ASDs are unable to handle the rapid power swings associated with the compressor surge. Unplanned shutdowns as well as thyristor failures can occur. Protective features can be incorporated in the drive controls and in the thyristor firing circuit to prevent compressor surges from damaging the drive. These have included a “safe fire circuit” to turn-on a thyristor if the blocking voltage exceeds a maximum value. Another feature is to take a signal from the surge controls to automatically change the beta angle (SCR firing angle on the machine converter) to a safe point on an approach to surge.

Considerations for specific applications are given next.

Considerations for GTO Drive Applications

Harmonic Reduction Technique. A 12-pulse output inverter bridge can signifi-cantly reduce the 5th, 7th, 17th, 19th, and other higher order harmonics. In practice, these harmonics can be reduced by 80-90 percent. This also greatly reduces the 6th and 18th harmonic torsional excitation frequencies (See Section 1560). Certain lower order harmonics can also be selectively eliminated by operating the inverter bridge in PWM mode at the correct switching frequency. This is done at the expense of an increase in some higher order harmonics, which can be filtered out. With three pulses per half cycle, one harmonic, usually the 5th can be eliminated. Elimination of additional harmonics requires two extra pulses for each harmonic eliminated. The degree of harmonic elimination is limited by the output frequency and the maximum switching rate for the device. The maximum switching frequency is further determined by device characteristics, reliability margins in the switching rate, and switching losses.

Motor and Capacitor Resonance. A capacitor filter on the output of the drive removes most of the higher order harmonics and produces an almost sinusoidal current waveform to the motor. Care must be taken in the selection of the compo-nent values, due to two possible resonance conditions. The first is a parallel reso-nance between the output capacitor and the stator and rotor series inductances. The second resonance condition is that between the capacitor and the motor magne-tizing inductance, resulting in excessive self-excitation during an input power trip. This condition can be avoided by putting the drive output contactor downstream of the capacitors and opening the contactor on an input trip.



Considerations for LCI Induction-Motor Drive Applications

Motor And Capacitor Resonance. The capacitor on the output of the LCI IM drive is quite large, with a KVAR rating equal in size to the HP rating of the motor. This makes the first resonance condition, described above, unlikely. However, the self-excitation condition is possible, but can be avoided by putting the drive output contactor downstream of the capacitors and opening the contactor on an input trip. This same self-excitation condition can occur on a drive pause, when the output contactor is kept closed. One method to limit self-excitation voltage is by circu-lating current in the drive during periods when input voltage is too low. Alterna-tively, a saturable reactor can be used to limit the self-excitation voltage. During a normal drive shutdown, the applied voltage to the motor is gradually lowered and during a trip, the output isolating device is opened to eliminate any overexcitation condition.

High Speed Motor Application. The high speed motor is designed with low magnetic flux levels to keep iron core losses low at high operating frequencies. This causes the motor to self-excite to a greater percentage of rated voltage as compared to a normal 60 Hz motor. To avoid this problem, it is necessary to add a saturable reactor in parallel with the motor and capacitor to limit the self excitation voltage to less than 200 percent of rated voltage.

Considerations for Harmony Power Cell Drive Applications

Input. Since the input waveform is a sine-wave current, there are no harmonic considerations, no derating of the input transformer, no harmonic filters, and no harmonic losses in transformers or motors on the power-source distribution system. The HPC drive can be powered from any bus even if that bus also supplies harmonic sensitive loads. Also, if an existing bus has other harmonic sources, the HPC drive will contribute such low additional harmonics to the system, that it is unlikely that the harmonic distortion problem will be worse. No harmonic analysis is required, prior to installing the HPC drive. However, harmonic baseline data should be collected prior to installing the drive and again after startup to confirm acceptable harmonic distortion levels.

Maintenance. The power cells are mounted on rollers. A faulty cell can be removed and a new one installed in less than 30 minutes.

Output. Since the output waveform is a sine-wave current, there is no extra heating in the motor due to harmonics, no electrically-induced torque pulsations, no HV standing wave at the motor terminals (normally associated with PWM IGBT drives), no common-mode voltages requiring higher ground-wall stator insulation, and no limitations on using an existing motor.

Reliability. For additional reliability, the HPC drive has an optional feature called a “cell by-pass”. With this option, a 4,160V ASD can drive a cubic load (blower, fan, centrifugal pump, etc.) at any speed up to 90 percent of full speed with one cell bypassed due to failure, if the drive does not have to overcome a system with a high back pressure or high differential head. Self diagnostics and bypass can be accom-plished on the run, without an outage.



The HPC drive has a completely digital control system and the power section can be equipped with N+1 devices for additional reliability of the power switching devices.

Considerations for Synchronous-Motor Drive ApplicationsFor high HP applications (above about 10,000 HP), LCI synchronous-motor drives are simpler and less costly than induction-motor drives. Below 10,000HP, the synchronous drive and motor system is more expensive, due to the higher cost differential of the synchronous motor versus the induction motor.

Field Supply. Synchronous machines require a power source for the field. The field supply system for ASD applications is often not given the careful consideration that the rest of the drive system is given. This inattention to detail has resulted in several incidents and plant shutdowns. One area to evaluate during the design is the insula-tion voltage rating of the stator windings of the motor exciter. The output voltage of the drive field supply will have voltage spikes created by the back-to-back thyris-tors. The standard voltage rating of the exciter stator windings is normally 1000VPEAK and may not be adequately rated for the transient voltage spikes.

The motor exciter voltage rating should be compatible with the supply voltage for the field controller. One example of incompatibility is with a European manufac-tured drive and motor that uses a 150V exciter, installed in a US plant with a 480V supply to the field controller. A failure of a leg thyristor on the field controller, will apply 480V to the 150V rated exciter.

Another feature to evaluate is the rating of the varistors on the output of the field supply, and the size of the snubber circuits across the thyristors. Undersized varis-tors may fail in service and result in a drive trip.

During factory testing of the motor and drive, the voltage waveform of the exciter supply should be inspected and a hard copy of the waveform provided as part of the test documentation.

Redundant power supplies for the field controller have been applied on drives. This can greatly improve the MTBF of the system, since auxiliary systems tend to have relatively higher failure rates than the main drive system.

1546 Motor ConsiderationsMotor considerations for applications with large ASDs include:

• Rotor and stator heating due to inverter output harmonic currents, especially at low speeds

• Common mode voltage stresses of the stator windings due to the shifting neutral phenomena because of devices conducting on only two phases at a time

• Lateral critical speed of the rotor and the operating speed range of the motor

• Torsional resonances of the rotating system and the air-gap harmonic ripple torque developed in the motor



Synchronous Motor Design For LCI Drives

Rotor Design. The design of the rotor is based on providing for a low impedance path for harmonic currents flowing in the rotor wedges from end to end. The cylin-drical rotor configuration for ASD applications is as an amortisseur winding, using either a continuous wedge or a segmented wedge design with wedge-to-wedge inter-connects to provide for the electrical continuity. The retaining ring is a non-magnetic steel material for near elimination of induced currents and to facilitate current flow from the wedges, with its reduced resistivity. A rotor isometric is shown in Figure 1500-35.

Stator Design. Synchronous motor manufacturers usually have a limited series of design selections to choose from when beginning a machine design. The design will be based on the outer diameter of the stator magnetic core and/or the outer diameter of the rotor. Completing the electrical and magnetic design involves selec-tion of the number of stator slots, which will also be the number of stator coils. Once you know the number of stator slots, then you can determine the length of the stator and rotor, dimensions of the slots, number of separate turns in the coils, and the number and size of strands of wire in each turn.

Since the motor supply voltage and frequency are determined by the machine converter, the motor voltage can be fixed for varying speed operation (constant voltage) or follow a constant or variable ratio of volts/hertz (V/Hz) over the speed range. Constant voltage converter operation improves power factor and reduces harmonic currents induced into the utility supply, during lower speed, but requires increasing levels of magnetic flux in the rotor and stator of the motor. Constant voltage operation is not normally feasible below two-third of rated speed. Below this speed the converter operating characteristic must be in a V/Hz mode.

Fig. 1500-35 Rotor Isometric for Synchronous Motor. Courtesy of Electric Machinery.



To accommodate the higher voltages to ground (common-mode voltages) experi-enced with LCI drives, the inverter section is generally high-resistance grounded. This transfers the highest voltages to ground to the transformer side of the circuit, which is suitably insulated to handle the additional voltage stress. However, during inverter SCR switching, at any instant in time (excluding the commutation overlap), two of the motor stator terminals are, in effect, connected to ground potential. The stator terminals of the open-circuit phases of each winding will be raised to a voltage greater than the normal line voltage levels. The stator winding insulation system must be increased to handle this higher voltage stress.

Other electrical considerations in stator design include the length of the air gap between the rotor and stator which affects the motor pullout torque, or “electrical stiffness”, and establishes the levels of rotor field current. Selection of various mate-rials mitigates some of the effects of the harmonic currents. Construction tech-niques such as slitting the stator teeth at the ends of the core are used to reduce local heating due to the fringing effect of the magnetic flux in the air gap.

Ventilation of the machine is also of great concern since the volume and effective-ness of cooling air will be reduced as the speed is reduced. The design of the motor for ASD application can result in a larger machine than is normally expected for the horsepower application. Also, the machine-stator-ventilation plan may also need to be modified.

1550 Considerations for Electrical Distribution SystemThere are two main considerations for the electrical distribution system. The first is the effect the electrical distribution system will have on the drive and the reliability of the drive operation. The second is the effect the drive will have on the electrical system and other equipment on the system.

1551 Effects on the DriveThe electrical system can adversely affect the drive operation for most system-imposed conditions. A design or application modification can mitigate these effects. ASD reliability is most affected by short duration power interruptions (voltage goes to zero) and voltage sags. The drive can be configured to ride-through these disturbances. Both the drive power and the control section should be set up to ride-through a power interruption of zero volts for a minimum of 0.5 seconds and a voltage sag of 50 percent of rated voltage for a minimum of one to two seconds. In most applications this is sufficient to get through disturbances that traditionally cause most of the drive trips. To verify that the setup is proper, the drive should be tested during commissioning by simulating a voltage interruption while the motor and drive are in operation.

Line transients and surges, from lightning strikes or capacitor switching, can adversely affect the line converter of the drive. Drives should be equipped with metal oxide varistors (MOV) on the input that protect the power semiconductor devices from the line surges. In some cases the varistors are not adequately rated for the energy of the transients. An MOV may protect the semiconductor devices



but fail during the process and result in a drive trip. This can be avoided by selecting the proper size varistor for the line condition. Consideration should be given to the energy of a single transient, usually a lightning surge and the cumula-tive effect of multiple, successive transient spikes, to properly apply the varistor. Capturing waveform disturbances can assist in sizing varistors.

1552 Effects on Other EquipmentDrives produce harmonics and other conditions that can adversely affect the elec-trical distribution system and electrical equipment in the system. Characteristic harmonics produced by a converter are determined by the relationship NP ±1 where N is any integer and P is the number of pulses. Using this relationship, character-istic harmonic currents for a 6-pulse converter are 5th, 7th, 11th, 13th, 17th, 19th, 23rd, 25th, etc., whereas the characteristic harmonic currents for a 12-pulse converter are 11th, 13th, 23rd, 25th, etc. The theoretical magnitude of each harmonic is inversely proportional to the order of the harmonic. For example, the 5th harmonic is 1/5 of the fundamental, the 7th harmonic is 1/7 of the fundamental, etc. Elimination of harmonics, notably the 5th and 7th, with the 12-pulse converter significantly reduces the harmonic distortion imposed on the electrical system. In practice, the canceled harmonics are not completely eliminated but continue to exist at low magnitudes. Where excessive harmonic distortion (see IEEE Std. 519) occurs, corrective actions must be taken to avoid potential equipment damage and associated reduction in system reliability.

Considerations Regarding IEEE Std. 519IEEE Std. 519 is a good resource for helping to identify potential problems. It also provides harmonic and voltage quality limits for the drive manufacturer, the utility company and the utility customer. It also provides a good tutorial on the drive-generated harmonics and how the electrical system responds to these harmonics. To use IEEE Std. 519 for industrial and commercial applications, several clarifications and adjustments should be made.

1. The point of common coupling (PCC) that is identified to describe voltage and harmonic distortion limits should be at the input of the drive or the primary of the input transformer, not at the utility delivery point. The total harmonic voltage distortion at this point, including the contribution from all existing harmonic generators, should not exceed 5 percent. The maximum individual frequency voltage harmonic should not exceed 3 percent.

2. Harmonic orders considered for limits and evaluation in IEEE Std. 519 should go through the 97th order and not be limited to the 35th order. In several drive applications, resonance conditions have involved cable capacitance where the system response was at the 49th harmonic order on one system and the 61st harmonic order on another. Harmonic analysis should be performed up to the 97th harmonic, in order to predict the system resonance frequencies.

3. Voltage notching limits, given in Table 10.2 of IEEE Std. 519 (for Low voltage Systems) should apply to medium voltage as well as low voltage systems. The notch depth should not exceed 20 percent as shown in Figure 1500-36.



Harmonics ConsiderationsHarmonics tend to be a potentially bigger problem with medium voltage drives (due to their HP size) and large LV drives, where the HP size is equal to or greater than 20 percent of the capacity of the substation. In most cases a properly designed harmonic filter, installed at the input of the drive can solve harmonic problems. When a harmonic filter is not part of the design, a much more detailed analysis is required in order to understand the effect, and to design the drive line converter and input transformer to prevent harmonic problems.

Harmonic problems that have the biggest effect on the electrical distribution system are:

1. Resonance conditions with power factor correction capacitors, cable capaci-tance, and surge or filter capacitors;

2. Harmonic heating in motors and generators and energy losses in transformers; and

3. Voltage notching and spikes related to commutation switching of the SCRs on the line converter.

Resonance conditions with capacitors can result in premature failure and rupture of the capacitor. IEEE Std 18 gives limitations on voltage, current, and reactive power for capacitor banks. A quick check for a possible capacitance resonance condition for a simple system with a single power factor correction capacitor is given by Equation 1500-2. A drive that produces a harmonic current at or near this frequency will excite the natural frequency of the system and result in high voltage stresses at the capacitor bank.

Fig. 1500-36 Voltage Notch Depth. 1993 IEEE. Used with permission from IEEE Std. S19-1992.



(Eq. 1500-2)

where:HNATURAL = the system natural harmonic order (i.e., 5, 6, 7, etc.) for a partic-

ular capacitor size.

KVA sc = short circuit duty in KVA

KVA cap = capacitor rating in KVAR

As an example, assume that a 100 KVAR capacitor bank is installed on a system with a 6-pulse drive and has a short circuit duty of 5000 KVAsc. The natural frequency of this system is near the 7th order multiple of the fundamental frequency. A 6-pulse converter will produce a 7th order harmonic current that will excite the natural frequency of this system and likely damage the capacitors and affect other system loads.

A major effect of harmonic voltages and currents in rotating machinery (induction and synchronous) is increased heating due to iron and copper losses at the harmonic frequencies. With transformers, the harmonic effects are twofold: current harmonics cause an increase in copper losses and stray flux losses, and voltage harmonics cause an increase in iron losses. High order harmonics can result in significant energy losses, especially in transformers. The only way to predict harmonic reso-nance problems and quantify harmonic heating and energy losses is to perform a computer simulated harmonic analysis of the entire electrical distribution system. Harmonic analysis is discussed in Section 1553, “Harmonic Analysis.”

Voltage Notching and SpikesVoltage spikes due to SCR commutation can cause overloading and failure of MOVs on the input of UPSs, power supplies, and electronic equipment, by either exceeding the voltage rating or energy rating of the varistor. Notching of the voltage waveform can also create additional “zero crossings” that adversely affect electronic equipment that rely on a pure sinusoid for timing circuits. Analyzer and instrumentation errors are classical problems that can be caused by drive harmonics. Commutation notching can also excite a resonance condition that normally will not be predicted by harmonic analysis. Voltage notching and spikes caused by SCR commutation can be controlled by proper selection of the imped-ance of the input transformer and/or by appropriate snubber circuit design of the line converter. The voltage notch depth should be limited to a maximum of 20 percent. The voltage notch depth can be calculated by Equation 1500-3 (refer to Figure 1500-37, a simplified impedance diagram).

% Notch Depth = × 100%

(Eq. 1500-3)

HNATURAL

KVA sc

KVA cap---------------------=

XsXs Xt+-------------------



1553 Harmonic AnalysisThe advice of a specialist familiar with harmonic analysis is recommended for all ASD applications.

The traditional electrical systems studies that are performed when installing new electrical equipment to a system should also be done when installing an adjustable speed drive. These include load flow, short circuit and coordination studies. In addi-tion to the traditional studies, a computer-simulated harmonic analysis should be performed for all drive applications. In some cases, for simple systems with a single small HP drive, the drive manufacturer can perform the study. For extensive, complicated systems that include PF correction capacitors, generators, significant shielded cable and a large drive, a specialist should be hired to perform the study.

The first thing to do, in preparation for a harmonic study, is to prepare an imped-ance diagram. The diagram should include the utility source and all electrical equip-ment data for the system. All harmonic generators (like drives and UPS), transformers, current limiting reactors, PF correction capacitors, and cable and line impedance should be included. Cable capacitance should be included in the imped-ance diagram and in the harmonic model. The plant load history and future load plans should also be identified. From the impedance diagram and the plant loading history, the computer model can be developed.

Harmonic acceptance criteria should be established for the input source to the drive. When establishing the limits, keep in mind the installation of future drives. The distortion limits should not be set so high that filters must be installed in the next drive to clean up past installations.

The computer model should be developed and various cases evaluated, including cases with maximum and minimum source impedance, and various drive loading conditions. The results should be verified by comparing computer results with field data. If the predicted results are higher than the criteria established, the computer model can also be used to design a harmonic filter.

Fig. 1500-37 Impedance Diagram



1560 Rotordynamic StudiesRotordynamic studies should be considered for all drive systems above 500 HP and for high inertia load applications. These studies traditionally consist of lateral crit-ical speed analysis and torsional analysis of the rotating equipment train. Additional studies to consider include structural dynamic studies (foundations and support structures), especially for offshore platform applications; and pulsation studies for all positive displacement applications. Positive displacement applications include rotary pumps and compressors (screw, sliding vane, eccentric rotor and gear type) and reciprocating pumps and compressors (piston and plunger type).

1561 Lateral Critical Speed AnalysisA lateral critical speed analysis must be performed for any ASD application where the motor or driven equipment either operates at speeds above the first lateral crit-ical speed or within 20 percent of any critical speed. In general, the need for this analysis should be considered for any ASD system rated 500 HP and above. Consult a mechanical equipment specialist for guidance.

A lateral critical speed is the natural resonant frequency of the rotor and support system which, when excited, causes a periodic oscillation perpendicular to the shaft. This concept is shown by the rotor diagram in Figure 1500-38.

The natural frequency is determined by the mass of the rotor and the stiffness of the shaft and support system. The support system includes the foundation, mounting skid, bearing pedestals, bearing shells, and oil film. The oil film usually has the dominating effect on support stiffness.

The rotor can be represented as a mass supported at each end by equivalent support springs. The natural frequency of the system is proportional to (K/M)1/2 where K is the spring stiffness constant and M is the rotor mass. The natural frequency increases as the stiffness increases, and decreases as the mass increases.

The rotor system has several natural frequencies which are referred to as the first critical, second critical, third critical, etc. In most applications the first (bouncing mode) and second (rocking mode) critical speeds are of principal concern, since the higher order criticals are usually well above the maximum operating speed.

Fig. 1500-38 Lateral Resonance of Two Bearing Rotor and Support System. 1994 IEEE. Used with permission from IEEE PCIC 94, CH-3451-2/94/0000-0261.



If the motor should be operated at or near one of its critical speeds, the conse-quences are usually excessive vibration levels. However, just as a mass supported by a spring does not oscillate until it is excited by an impact, the rotor must also have some residual unbalance to excite a critical frequency. Whether or not vibra-tion associated with operation near a critical is excessive depends on the degree of damping in the system and the amount of unbalance exciting force.

In addition to the rotor mass, the mass-moment of the coupling half must be included in the lateral analysis model. In this case, the overhung mass has the most significant effect on the second and higher modes.

The results of a lateral analysis will be illustrated by example. This example is the 15,000 HP synchronous motor ASD at the Pascagoula Aromax Plant. The normal speed range is 3100 to 5922 rpm. Figure 1500-39 shows an example undamped crit-ical speed map. From this figure, the frequencies of the first three modes are identi-fied. At a support stiffness of 2.0 x 106 lbs./in., the first critical is predicted at 2256 r/min, the second at 5431 r/min, and the third at 6382 r/min.

Figure 1500-40 shows the rotor mode shapes for the first three vibration modes from the example above. For this motor, the rotor is supported by three bearings, two for the main rotor and one for the exciter. The plot represents lateral displace-ment of the rotor versus position along the rotor when the particular mode is excited.

Fig. 1500-39 Undamped Critical Speed Map. 1994 IEEE. Used with permission from IEEE PCIC 94, CH-3451-2/94/0000-0261.



The rotor response is calculated using unbalance weights defined in the applicable specifications (API 546, in this example), to excite the rotor system resonances. The damped rotor responses are calculated, with the rotor unbalances as follows: applied in-phase at each end of the main rotor, 180 degrees out-of-phase at each end of the main rotor, and on the coupling. For our example, the worst case is with the unbalances applied 180 degrees out-of-phase and is shown by Figure 1500-41. This figure shows the predicted vibration amplitude in displacement versus speed at each of the three bearings and the coupling.

For this example, API 546 requires each critical speed to be separated from an oper-ating speed by 15 percent, unless the response is well damped. “Well damped” means the vibration amplitude cannot exceed 1.5(12000/N)1/2 in mils peak-to-peak displacement (one mil = 0.001 inches) where N is the maximum operating speed in r/min. In this case, the amplitude limit is 2.2 mils.

The highest amplitude responses are above 7500 r/min, well outside the maximum operating speed of 5922 r/min. However, the predicted response at the intermediate bearing (opposite drive end) can exceed the allowed 2.2 mils. At this location, the peak response is 2.9 mils at 6900 r/min, which can be tolerated because it is much

Fig. 1500-40 Lateral Critical Speed Analysis with Mode Shapes. 1994 IEEE. Used with permission from IEEE PCIC 94, CH-3451-2/94/0000-0261.



less than the minimum bearing clearance (7.0 mils). On this basis, this rotor lateral response is acceptable.

Although this example focused on the motor, a similar-type analysis must also be performed for the driven equipment to avoid operating at a rotor system resonance producing unacceptably high vibration.

1562 Torsional AnalysisA torsional analysis is required for all large ASD systems. The definition of “large” depends on the nature of the driven equipment, i.e. pump, compressor, fan, gear, etc. In general, consider performing a torsional analysis for any system rated 500 HP and above. Consult a mechanical equipment specialist, familiar with torsional analysis, for guidance on all large systems.

Figure 1500-42 depicts the motor, coupling, and compressor rotating mass system. Torsional vibration is the periodic oscillation, in the form of twisting torques, of the rotating system components. Damaging torques can occur if the system is excited at one of its natural frequencies. Because of the many potential torsional excitations in an ASD system, it is essential that torsional analysis be performed for large systems, carefully including all sources of excitation. Torsional excitations which must be considered include: harmonic torques caused by the ASD, dynamic torques from the motor, and transient torques from electrical short circuits. These excita-tions must be examined for both startup and normal operating conditions.

Fig. 1500-41 Calculated Rotor Response with Unbalance Weights Applied 180° Out-of-Phase at Each End of Rotor. 1994 IEEE. Used with permission from IEEE PCIC 94, CH-3451-2/94/0000-0261.



As a partial example of the torsional analysis, the Pascagoula Aromax ASD will be used again. Harmonic torques produced by the ASD during normal operation are multiples of the converter 12-pulse output, i.e., 12X, 24X, 36X, and 48X electrical output frequency. (For a 6-pulse converter, the harmonic torques would be 6X, 12X, 18X, 24X, etc.) Excitation at the fundamental mechanical frequency and one and two the times electrical frequency must also be considered. A computer simulated torsional analysis of the entire rotating system (motor, coupling, and compressor and gear, when appropriate) is used to predict the torsional natural frequencies. The interference diagram shown in Figure 1500-43 identifies where the excitation frequencies intersect with the torsional natural frequencies. For example, note the intersection of the fundamental mechanical and electrical frequency (1X) with the first torsional natural frequency at 964 r/min (16.07 Hz). This is an operating speed to avoid.

For evaluation of torsional excitation caused by short circuits, a phase-to-phase fault normally represents the worst case due to the combined fundamental and second order frequency components. The excitation frequencies are 1X and 2X elec-trical frequency, the 2x being caused by the unbalanced nature of the fault. Figure 1500-44 shows a sample of the coupling transient torque if a fault should occur while the ASD is operating at the first torsional natural frequency of 964 r/min. The torque shown is sufficient to cause coupling failure, so this speed must be avoided. Also, one half of this speed (482 r/min) must be avoided because of the potential 2X excitation of the first torsional resonance during a fault. The separation margin from these speeds must be maintained at plus or minus 10 percent per API 546.

This analysis found that torsional natural frequency separation margins and compo-nent stress levels associated with torsional excitation were within acceptable limits for the normal operating speed range. It also identified speeds to be avoided as noted above. The ASD can be set to block out the required speeds and accelerate quickly through them during startup.

Fig. 1500-42 Simplified Model for Torsional Analysis. 1994 IEEE. Used with permission from IEEE PCIC 94, CH-3451-2/94/0000-0261.



1563 Pulsation and Structural Resonance AnalysisThe advice of a specialist, familiar with pulsation and structural resonance analysis, is recommended for all positive displacement ASD applications.

Positive displacement pumps and compressors include reciprocating and rotary-type machinery. This equipment needs special dynamic consideration, because multiple excitation frequencies may excite multiple system natural frequencies.

Excitation frequencies include:

• drive/motor torque harmonics• driven machine torque harmonics• pumpage fluid pressure pulsations• residual mechanical unbalance forces

System natural frequencies include:

• torsional natural frequencies• piping acoustical-response frequencies• piping and foundation structural natural frequencies

Excessive vibration or pulsations in an ASD may result if one or more excitation frequencies are near a system natural frequency. Use of ASDs in positive displace-

Fig. 1500-43 Torsional Resonance Interference Diagram. 1994 IEEE. Used with permission from IEEE PCIC 94, CH-3451-2/94/0000-0261.



ment applications is relatively rare, but it is an emerging technology. ASDs have been applied to some reciprocating compressor applications at 900 rpm.

Structural resonance analysis, associated with the design of offshore platforms, is commonly done as part of the platform design. Consideration should be given for structural resonance analysis when applying ASDs on offshore platforms.

The following is a summary of the precautionary studies likely to be needed. None of these items is a trivial undertaking, and each study is an order of magnitude more extensive than a fixed speed analysis.

• Piping pulsation analysis for complete speed range

• Piping mechanical structural vibration analysis for complete speed range and gas pressure pulsation induced vibration

• Foundation and structure vibration analysis for complete speed range (particu-larly important for offshore applications)

As a result of these studies, it is quite likely that significant portions of the planned speed range may not be available for steady state running due to potentially damaging resonances.

Fig. 1500-44 Typical Coupling Torsional Response Resulting from Phase-to-Phase Short Circuit with Motor Operating at First Torsional Natural Frequency. 1994 IEEE. Used with permission from IEEE PCIC 94, CH-3451-2/94/0000-0261.



1570 Miscellaneous Information

1571 System TestingPast problems encountered with ASD applications illustrate the importance of system testing. Unanticipated problems found and corrected at the factory before shipment to the plant avoid significant delays during commissioning, installation and startup. Although it is costly in both time and dollars to conduct a system test, it is always worth the cost if in-service problems can be avoided.

Thorough testing of the entire system is essential when applying ASDs in critical services. The objective is to avoid problems after startup. Thorough testing can help assure a reliable installation with minimum commissioning time. The ASD should first be tested without the motor, at the drive manufacturer’s factory. If multiple drive systems are built, back-to-back (BTB) testing at the motor manufacturer’s plant should be considered, after the drive and motor have had separate production tests. If a single unit is purchased, normally a unit test cannot be done in the factory. Final system tests should be conducted during commissioning at the plant site.

Tests for Transformers and ReactorsThe transformers and reactors, being proven equipment, should be given routine electrical tests required by applicable ANSI standards. Additional tests should be considered for special auxiliary equipment that may be unique to the application. An example is a heat run at rated frequency and a sound test conducted on a satu-rable reactor for a high speed LCI IM drive application. This special test is made to verify an acceptable temperature rise and noise level when the reactor is operating at high frequency (above 60 Hz).

ASD Production TestsProduction tests of the ASD, performed at the ASD factory, should include verifica-tion of control logic, protective features and alarms; heat run; and insulation high potential tests. A heat run for the LCI IM drive can be performed at reduced input voltage but with rated current and frequency by using the output capacitor as a load. Control logic tests are often conducted using the factory test facility motor. However, these tests are limited to the rating of the test facility motor. If the test facility motor is rated less than the drive, the protection and alarm scaling factors must be changed to perform the verification tests. This is an adequate testing method.

Back-to-Back TestingBTB testing is normally performed at the motor manufacturing facility. The motors are arranged in a back-to-back configuration as shown by Figure 1500-45 for load testing the ASD system. One ASD and motor is operated in the normal mode as a motor. The other ASD and motor is operated as a generator to provide the neces-sary load and to generate most of the power requirements of the test. The test facility generator provides only the system KW losses as well as substantial reac-



tive power. In this manner, both the ASD and motor can be operated at rated speed and power for testing purposes. The losses can be directly measured for deter-mining the efficiency of the ASD and the motor.

☞ Caution It should be noted that the back-to-back arrangement is an abnormal configuration for operating the drives, in that one drive is operating in the regenera-tive mode, a condition which will never exist in service. Also, the drives are being supplied by the test facility generator which has limited capacity. A sudden change in load could result in instability of the test system with substantial overvoltage due to reactive power changes on the relatively small test-stand generator. Thus, it is necessary to avoid tests which cause sudden load changes while operating in the back-to-back configuration.

Comprehensive testing of the ASD during BTB testing includes:

• Complete startup checklist (prepared by the drive and motor manufacturers)

• Verify protective features and alarms

• Verify V/Hz calibration, current balance, and load versus speed characteristics

• Verify drive stability and control under all load conditions

• Perform rated power and speed heat run and determine efficiency

Fig. 1500-45 Back-to-Back Test Configuration



• Record input and output voltage and current waveforms and quantify harmonic current values on the line and machine converter, up to the 60th harmonic order

• Verify system voltage disturbance ride through

For Induction-motor drives, include the following checks:

• Determine motor/capacitor self excitation voltages• Verify diverter circuit cutoff frequency• Check effects of output resistor cutout

For Synchronous-motor drives:

• Check exciter supply waveform and transient voltage level

Resiliency to Voltage DisturbanceOne of the most important tests for the ASD is to test its ability to ride through a voltage disturbance. Voltage disturbances always occur on an electrical system, resulting from local or remote faults, motor starting, capacitor switching, etc. Reli-ability problems associated with many previous drive installations have included frequent trips due to system voltage disturbances. This test requires the drive to ride-through complete voltage interruptions of 0.5 seconds and a 50 percent sag of rated voltage for two seconds. The tests should also require a ride through of a voltage sag to 75 percent of rated voltage and immediately recover.

Motor TestsFor motors, the full complement of factory performance tests required by API Stan-dard 541 or 546 should be performed in accordance with IEEE and NEMA require-ments. These tests include:

• Stator sealed winding conformance test• Rotor residual unbalance verification• Measurement of winding resistance and no load current and speed• Determination of locked rotor current and power factor• Determination of efficiency, power factor, rated current, and slip• No load and rated temperature mechanical running tests• Rotor unbalance response test to verify critical speeds• Sound test • Insulation high potential, resistance, and polarization index tests• Bearing inspection and insulation resistance check

Rotor Unbalance Response TestA rotor unbalance response test should be performed for all ASD applications to verify the location of the rotor critical speeds and the vibration response as the rotor passes through each critical speed. This test involves intentionally unbalancing the rotor with prescribed weights to excite the rotor critical speeds. With the weights applied, the rotor is driven to approximately 120 percent of rated speed and allowed to coast down to stop. The vibration amplitude and phase angle versus speed from



each shaft proximity probe is recorded. The response will clearly indicate the actual location of the critical speed as well as the rotor response to a modest level of unbal-ance. The vibration response at each critical speed should be compared with the specified limits to determine if the vibration magnitude and separation margin meets the acceptable limits.

1572 Commissioning and StartupComprehensive commissioning and startup procedures should be developed and performed before the equipment is placed in service. These procedures, which are essential to minimize future reliability problems during operation, include:

• verification of ASD control performance • protective features • performance under expected load conditions • voltage disturbance ride through under load conditions

The commissioning plan and performance tests need to include the drive, motor, driven equipment, surge controls (if applied), and the process control system (PCS).

For compressor applications, if anti-surge controls are included to avoid surge, they should be thoroughly tested. If the drive is configured with a surge-protection feature, this system should also be verified.

In any ASD application, it is essential to consider both normal and unusual oper-ating conditions which may be experienced. It may be necessary to enhance the performance capability of the drive or to provide additional protective measures to reliably satisfy the demands of the particular application.

1573 TrainingTraining of technical and maintenance people involved with applying, servicing, maintaining, and troubleshooting drives is necessary for long-term reliable drive operation. In drive technology, both theory and equipment assembly is quite involved and generally requires continuing education. The more you know, the less complex it appears and the more successful the plant or facility will be at applying the technology. Often, after the ASD has been installed, it operates trouble free without the need for any troubleshooting or repair and requires only annual preven-tative maintenance. This should not result in a neglect of training. Refresher courses should be attended, either as in-house courses or informal manufacturer-sponsored short courses.

All manufacturers of drives provide training for both applying drives and main-taining and troubleshooting. The benefits of training those who apply drives will be in the form of reliable short term and long term drive operation. Maintenance and troubleshooting training will result in achieving the promoted mean-time-to-repair (MTTR) and mean-time-between failure (MTBF) figures.

Training also helps to bridge the gap between new technology and the acceptance to change, especially for electricians that are less familiar with solid state power



semiconductors. If training is not provided to the electricians that generally service and troubleshoot motor controls, it is likely that the drive equipment will be “orphaned”, and not maintained as specified by the manufacturer. This will surely affect reliability.

1574 Maintenance and Spare PartsMaintaining drives is usually limited to changing air filters, water filters, and deion-izers, and checking the drive diagnostic status on a periodic basis. Repair will usually be limited to replacing of printed circuit boards (PCBs) or power switching devices (diodes, SCRs or transistors), although the MTBF is normally quite high for both PCB and power switching devices. MTTR will always be a function of the spare parts on hand. Establishing a good stock of spare parts and maintaining the inventory will determine the repair time. Training will provide an electrician with the background knowledge necessary to troubleshoot a failed drive. Coaching from a factory representative can often provide the necessary guidance to identify the failed equipment and initiate the replacement.

All digital drives employ extensive diagnostics to aid in correcting many malfunc-tions that occur in the drive system. Often, drive diagnostic trouble codes are used to identify the problem via a liquid crystal display (LCD). For drives that use this method to display fault diagnostics, a maintenance handbook will be necessary to provide a description of the fault code. Many drives provide direct diagnostic displays through LCD screens.

Other troubleshooting aids include a true-rms digital multifunction meter capable of 1000 VDC ÷ 750VAC, with one megohm minimum input impedance; a clamp-on ammeter with current capability of 2x rated current; and a dual trace oscilloscope with differential capability, digital storage, two x10 and one x100 calibrated probes.

In order to obtain the best performance and to get the maximum service life from the ASD it is necessary to perform timely maintenance and replacement on some parts of the system, even though the equipment may still be functioning with no apparent problems. These parts include the equipment listed in Figure 1500-46.

Fig. 1500-46 Service Life of Replaceable Parts

Part Service Life

Air Filters 1 Year

Cooling Fan 3 Years

Large Capacity Electrolytic Capacitors 5 Years

Connect Relays 500,000 Operations

Connectors 100 Operations

Deionizer and Filters (Water-Cooled Systems) 6 Months

Resistivity Probes (Water-Cooled System) 1 Year

Rubber Hoses (Water-Cooled Systems) 5 Years


1600 Design of Electrical Systems for ESP Installations Guideline

AbstractThis guideline is intended to provide guidance unique to the design of electrical systems for oil-field Electrical Submersible Pump (ESP) installations. Downhole operating conditions are harsh and ESPs can have relatively short run lives. If appli-cation issues related to the electrical system are not sufficiently considered, they can contribute significantly to problems and unreliability of the ESP system.

Due to the large variation in downhole conditions (e.g., depth, temperature, pres-sure, fluid characteristics, liquid flow rates, and well injection fluids or gases) this guideline focuses on above ground design issues.

Contents Page

1610 Overview 1600-3

1620 Power Delivery System 1600-4

1621 Transmission Lines

1622 Service Voltage

1623 Offshore Systems

1630 Surface Design Considerations 1600-5

1631 Power System Disturbances and Surge Protection

1632 Typical ESP System Layout

1633 Main Power Transformers

1634 Lightning and Surge Protection

1635 Surface Power Cabling

1636 Drive Choices

1637 Grounding Design

1640 Sub-Surface Design Considerations 1600-22

1641 ESP Cables

1600 Design of Electrical Systems for ESP Installations Guideline Electrical Manual


1642 ESP Motor

1650 Reliability Considerations 1600-24

1651 Maintenance Programs

1660 Other Considerations 1600-26

1661 Downhole Monitoring Systems

1662 Supervisory Control and Data Acquisition (SCADA)

1663 Group Installations of ESPs (Variable Speed Drives)

1664 Generator Power Supply to ESPs


Electrical Manual 1600 Design of Electrical Systems for ESP Installations Guideline


1610 OverviewFigure 1600-1 shows a simplified representation of a typical onshore ESP installa-tion. Power is supplied to the site by an overhead transmission line. The major surface components of the installation include a power transformer, a motor controller (either constant speed or variable speed), perhaps a step-up transformer, interconnecting power cables, power cable junction box, the down-hole power cable and the wellhead cable penetration. The major subsurface components consist of power cable, cable splices, cable terminators, cable support strapping, the ESP motor and instrumentation.

Fig. 1600-1 Typical Onshore ESP Installation From API RP11S3. 2nd edition, March, 1999. Courtesy of the American Petroleum Institute.



1620 Power Delivery System

1621 Transmission LinesBecause oil fields are usually located in remote locations with the wells spread out over a large geographical area, it is common to provide power to the well site via overhead transmission lines. Whether the transmission lines are owned by the local utility or by Chevron, some consideration must be given to transmission line design.

If owned by the utility, they will provide service to the well site or field. Issues such as line capacity and routing to the site will be handled by the utility. Design consid-erations in this case would include:

• the voltage level of the service being provided

• any capacity limitations of the service

• the characteristics of the “next upstream” protective device (so the site can coordinate its protection with it)

• grounding requirements

• whether the power transformers are pole mounted or located on the ground (pad mounted.

If Chevron owns the overhead electrical transmission system, the design effort includes the above issues as well as the following:

• accessing the ability of the “source” to provide the additional power (the source may be local generation or a large, local utility substation)

• routing and right-of-way for constructing a transmission line service to the site

• designing and constructing the transmission line.

Because requirements for overhead line construction vary greatly from region to region, providing detailed design requirements here for overhead line construction is beyond the scope of this guideline. The engineer is encouraged to familiarize himself with local requirements governing overhead line construction. The Rural Electric Administration [2] provides a good reference book showing transmission line construction details. Refer to the Section 1670 References for more informa-tion.

1622 Service VoltageESP motors may range in horsepower from 20hp to 1000hp, and power supply delivery voltages have wide range too.The power system voltage levels range from 4.16 kV to 34.5 kV. The goal is to have voltage that:

• is high enough to supply system voltage within ± 5% of nominal under full load• keeps conductor size low, and



• still provides power enough to start a large ESP motor without affecting other equipment on the system (often referred to as stiffness).

Design optimization must meet the above goals, keep the system voltage low, and keep the cost of building the transmission line reasonable.

1623 Offshore SystemsRecently, Chevron has begun installing ESPs offshore. The power delivery system and ESP controllers are usually part of the overall platform electrical system or the power system and controllers may be part of a floating processing unit. The ESPs are installed through wellheads located on the platform. The ESPs would be connected by subsea cables and installed through subsea wellheads.

The power system usually consists of a group of generators and the main power supply switchgear. Power supply voltages range from 480 V to 4.16 KV.

Offshore installations differ from onshore installations by:

• the need for environmental protection from the offshore marine atmosphere;• drive controllers are usually concentrated into a small area or room;• the need for compactness (low weight and space) of the power supply and drive

system equipment;• local power generation is common practice.

1630 Surface Design ConsiderationsSome of the key electrical design considerations for ESP installations are as follows:

• reliability of the power supply• the ability of the electrical supply to power the load• control of power system surges and interruptions• power quality as a result of the ESP installation • adherence to local requirements and accepted standards• grounding of the installation.

These factors are discussed further in this section.

There are other design considerations that are not discussed in this section. They include:

• ESP pump and motor sizing• the suitability of materials of construction for the downhole conditions, and• fluid characteristics that affect reliability, e.g. sand or entrained gas.

For more information on these factors, refer to API RP 11S series. [4, 5, 6, 7]

The mechanical and fluid features of an ESP system contribute at least as much to unreliability as electrical systems but are beyond the scope of this design guideline.



The ESP manufacturers have computer programs for matching the appropriate type of downhole and surface equipment to the well characteristics.

Reliability of Power SupplyWhen planning an ESP installation, it is important to know the reliability of the power supply system — the ability of the utility to supply uninterrupted power over time. The reliability, or runtime, of the ESP installation will never be any better than the underlying electrical supply. Utilities experience overvoltages, undervoltages, short duration loss of power and long duration loss of power. These are caused by lightning strikes, switching operations and equipment failures. Utilities monitor and record these conditions and are able to report the number of problems that occur during a year and their duration.

On Chevron owned systems, outages are normally recorded and investigated; however, overvoltage, undervoltage and short duration loss conditions may not be. Lack of this information may indicate the need to install monitoring and recording equipment for a period of time to gather this data. On occasion, other utility equip-ment such as switches or capacitors may interact with the ESP installation to cause interruptions at the ESP installation. This is difficult to anticipate or predict unless other installations have experienced these problems.

Ability of Electrical Supply to Power the LoadAlong with reliable service, the electrical supply at the installation must be within reasonable voltage parameters, at least within ± 5% of the nominal service voltage or better. Also, the power supply must be of enough capacity to start and accelerate the ESP motor load with constant speed drives without affecting other loads nearby or on the system. ESP motors or pumps will often lock up due to downhole condi-tions and the controller will be used to try to “unlock” it. So, an adequate power system is often necessary in successful field operations. Significant voltage drop during starting conditions may result in some secondary problems such as causing lights to flicker or magnetic starters to drop out. Regardless of whether the supply is a utility or Chevron owned system, it is important to computer model the supply system for load flow, short circuit and motor starting conditions. Results of the modeling studies are used for conductor sizing and equipment rating selection later in the design phases.

Power Quality, Power Surges and Interruptions

Variable Speed Drives. Recent new electric submersible pump installations are almost exclusively variable speed drive. The ability to vary the speed of the ESP motor allows more optimal fluid lift and changing production conditions in the well over time can be met without pulling the pump.

Use of an adjustable speed drive, however, must be carefully incorporated into the power system design because they are a source of harmonics and voltage distur-bances both to the supply system and to the ESP motor. These can significantly affect power quality (both for the power system and your installation). Harmonics already on the supply system (from nearby facilities or loads) may interact with detriment to the ESP installation. Or, the new adjustable speed drive installation



may cause problems with nearby equipment if the harmonics are not sufficiently controlled. Adjustable speed drives may also cause a need for more capacity in isolated generator units since some ESP adjustable speed drives operate at such low power factor. These issues will be discussed in more detail later in these guidelines. A good reference for learning more about adjustable speed drives is the “Adjustable Speed Drive Guideline for Upstream, Oil-field Application.”

Installing Equipment to Control Power Disturbances. Just as important as antici-pating power system disturbances and harmonics is installing equipment to control these conditions and protect the ESP equipment. Installation of lightning and surge arrestors is normal for most installations. This may be dictated by the local utility or by analysis of isokaronic conditions for the area. Installation of transient voltage surge suppressors and harmonic filters is optional but they may be needed under the following circumstances:

• where lightning strikes or utility switching operation sometimes interrupts supply

• where the initial power system studies show harmonics are high or could be of concern

• where power system measurements show disturbances or harmonics are present• where motor controller design is shown to generate significant harmonics• where practical experience with similar ESP installations show some of the

above problems exist.

How transient voltage surge suppressors and harmonic filters work is discussed later in this section.

More information about harmonics associated with variable speed drives can be found in Section 1550.

Adherence to Local Requirements and Accepted StandardsIn the interest of safety, it is very important to adhere to local requirements and stan-dards of the utility or Chevron standards developed for the location. These stan-dards are designed to overcome anomalies in the area and to result in safe, consistent, reliable installations. An example of such a standard might be, because soil conditions in the area may be unusual, special grounding techniques are needed. Or, lightning strikes are so frequent as to require certain minimum equipment at service points.

Grounding the InstallationGrounding the installation is very important for personnel safety and safe operation of the pump site. Grounding techniques can be highly variable depending on the local custom and field location. This topic is very important and is discussed in more detail in Section 1637, “Grounding Design.”



1631 Power System Disturbances and Surge Protection

Types of DisturbancesThere is a wide and confusing array of power system disturbances that might occur. IEEE Std. 1100, “Emerald Book” [9] has an exhaustive list of different types of disturbances and provides definitions for them. Disturbances most often found in the oil fields are as follows:

• voltage sags — caused by faults often at remote locations; very short duration; rms voltage may drop to as low as 15%.

• surges — caused by lightning strikes (direct or induced), switching of remote electrical equipment, or faults or failures; very short duration, on the order of 10-100 microseconds.

• swells — an increase in the system voltage level, at normal power frequency; caused by capacitor bank switching, or operation of circuit breakers and other switching devices in the power system; duration from ½ cycle to a few seconds.

• overvoltage — an increase in the system voltage, at normal power frequency; caused by loss of large load or transformer tap changing; duration greater than a few seconds.

• outage — a complete loss of voltage for a period of time.

As variable speed drive controllers are applied more often in the oil field, the following disturbances will become more well known and more important:

• notch — a disturbance of the normal voltage wave form, lasting less than ½ cycle; initially of opposite polarity than the wave form and is thus subtractive from the peak value of the wave form; this includes complete loss of voltage for up to ½ cycle.

• voltage distortion — any deviation from the nominal sine waveform of the line voltage; distortion indicates the presence of harmonics.

• harmonics — the deviation from the sinusoidal waveform expressed in terms of the order and magnitude of the Fourier series terms describing the waveform; the order is expressed in multiples of the operating frequency, the magnitude is expressed as a percent of the fundamental. Often converter equipment or vari-able speed controllers are described by their characteristic harmonics so that the Fourier series expansion terms are known. This is by the following formula:

h = kq ± 1

k = any positive integer

q = pulse number of the converter

A six pulse converter will have characteristic harmonics of 5th, 7th, 11th, 13th, etc. Harmonics’ amplitudes may be measured using a frequency analyzer.



Controlling DisturbancesIn general, to control power system disturbances and reduce damage to equipment, the system must:

• conduct lightning stroke current to ground safely through shield grounding wires, grounding conductors or arrestors

• dissipate the energy into a low impedance ground system

• eliminate earth loops and differentials by creating an equi-potential grounding plane under transient conditions, and

• protect equipment from surges and transients with protective devices.

InsulationThe failures associated with power system disturbances and surges are always insu-lation integrity breakdowns somewhere in the system. The failure may be the result of a one-time significant overvoltage or the aggregate sum total of lesser overvolt-ages.

Insulation standards have been developed that recognize the need that insulation systems must be able to withstand a limited amount of excess voltage stress over the normal operating voltage. Insulation systems and equipment are tested and certified to the voltage levels specified in the standards. In all cases, a large portion of insula-tion’s ability to withstand applied voltage can be destroyed in the process of testing. So, take extreme care when selecting the voltage test levels and doing the testing.

The physical arrangement of an insulation system also reduces an insulation system’s ability to withstand over voltages. The voltage stress that appears across a single-turn in a multi-turn coil (i.e. motor) when a high-rate-of-rise voltage surge occurs is much higher than the single-turn operating voltage. So coils and motors often have the lowest withstand voltages in the system

The most commonly used measure of an insulation system’s voltage withstand capa-bility is BIL or Basic Impulse Level. BIL is defined as the crest voltage for a full-wave impulse test, where equipment is subjected to a voltage pulse that increases from zero to peak value in 1.2 micro-seconds and declines to one-half peak value in 50 micro-seconds (shorthand for this is 1.2 x 50). This type of testing is the best way so far to simulate equipments’ ability on large geographical power systems to withstand overvoltages and surges that may be seen during its operating life. A much more in-depth discussion of insulation system ratings and protections is contained in ANSI/IEEE Std 141, IEEE Red Book, Chapter 4, “Surge Voltage Protection.” [3]

There are several standard test impulses that are used to approximate transient conditions. They are mentioned here to illustrate the amplitude and the very short duration times of typical voltage transients. The 60,000 volt, 1.2 x 50 micro-second voltage impulse is considered a typical impulse associated with indirect or induced lightning strikes. The 10,000 amp, 4 x 10 micro-second current pulse is considered a typical impulse associated with a direct lightning strike. The 1500 amp, 8 x 20



micro-second current impulse is considered a typical impulse associated with a system switching operation.

One way to see why so many electrical failures occur where they do is to compare BIL values for equipment used in ESP systems (Figure 1600-2).

Just by glancing at this table you can see that without adequate protection from overvoltage or surge, the motors on the system are the weakest point. Therefore, protective devices such as lightning arrestors and surge suppressors are added strate-gically to the system to be the designated point of failure and protect the motor.

1632 Typical ESP System LayoutThe typical layout of surface located equipment for an ESP installation is shown in Figure 1600-1 and Figure 1600-3. Figure 1600-1 shows an installation where the ESP has a constant speed drive. Figure 1600-3 shows an installation where the ESP has a variable speed drive. The main difference between the two is the step-up transformer associated with the variable speed drive installation. Figure 1600-4 shows the plan view of a well site and the clearances that must be maintained between wellhead, surface equipment and overhead power lines.

Fig. 1600-2 Comparative BIL Values (Data from ANSI/IEEE 141, Red Book Tables 15-18.) Copyright 1999 by IEEE

Basic Impulse Level --- BIL

Nominal Voltage Rating AC Motors (1) (2)

Oil Filled Trans-formers

Enclosed Switch-gear Distribution Line

480 V 3.5 KV 45 KV 30 KV

2300 V 9.9 KV 60 KV 60 KV

4000 V 15.9 KV 75 KV 60 KV

12000 V 110 KV 95 KV

13800 V 110 KV 95 KV 400 KV

(1) Motor impulse strength can be obtained from the formula:1.25 x √2 x (2 X Nameplate Voltage + 1000)

(2) There are no established, standardized BILs for motors. This is more often referred to as Impulse Strength and is based on the crest value of the standard high-potential test voltages.



Fig. 1600-3 Typical Surface Located Equipment Layout



1633 Main Power TransformersDepending upon the size of the ESP, the main power transformer may be one of the following:

• a distribution type transformer bank mounted on the service pole• a distribution type transformer bank mounted above ground on braces between

poles (larger KVA banks), or • a power type transformer that is mounted on the ground (pad mounted).

Distribution transformers sizes typically range through 500 kVA (for example three 167 KVA transformers), while power transformers cover ranges above 500 kVA. The difference is whether the drop from the pole is low voltage, as would be the case with distribution transformer, or high voltage (distribution voltage) as would be the case with a transformer mounted on the ground.

Fig. 1600-4 Well Site Plan View



In oil fields that are equipped for overhead line work, the distribution type trans-former bank will be more economical.

The main power transformer(s) step the voltage down from distribution voltage, which can be from 4.16 KV to 34.5 KV, to 480 volts. Input voltage to most constant speed and most variable speed drive controllers is 480 volts. Medium voltage drives (2300 volts to 13.8 KV) are becoming available as ESP controllers but have gener-ally only been applied in special installations.

Some voltage drop is expected on the distribution system between the source point (say a substation bus) and the service or load. Taps are used to adjust the secondary voltage of the transformers up or down to within the nominal voltage range required by the load. Transformers are supplied with variable taps in the high voltage winding that allow you to adjust the secondary voltage ± 5%. A wider tap adjust-ment range, such as ± 10%, is available for slightly higher cost. Refer to Section 800 for more information about transformers.

Liquid Filled TransformersLiquid filled transformers are recommended for a couple of reasons:

• they are generally more suited to be mounted outdoors; and• the BIL of a liquid filled transformer is higher than for dry-type.

Liquid filled transformers may be filled with several types of liquid insulating fluids; mineral oil based insulating oil is recommended for most applications.

Delta-delta Transformer WindingsThe usual transformer windings connection for the main power transformer used with ESPs is delta-delta. This type of transformer connection continues to be used in the oil field despite other ways of achieving its main advantage.

The main advantage of delta-delta transformer windings connections is if one phase of the circuit (say the downhole motor cable) becomes faulted, the system will continue to operate until another phase becomes faulted.

The delta-delta connection historically gives longer run life than a solidly grounded bank of transformers in this way.

The disadvantages of delta-delta transformer windings are:

• the system is ungrounded so that personnel may be exposed to “touch potentials,” and

• under the single phase fault to ground conditions, the two remaining phase’s voltage can rise to 173% of normal line-to-line voltage.

Arcing ground faults can occur on ungrounded systems where voltages can rise to very high levels (500% or more of line voltage) and severely overstress insulation and equipment on the system. See “Alternative Grounding Method” later in this section for a discussion of an alternative method for connecting transformers and achieving the same first-fault tolerance.



Specifications and data sheets for purchasing power transformers are available in Volume 2 of the Electrical Manual.

Transformers Feeding Variable Speed DrivesFor installations where the main transformer bank feeds a variable speed drive system, some additional considerations should be given to the type of transformer selected:

• Transformer impedance should not exceed 6%.

This will help ensure good voltage regulation on the transformer secondary. Also, there will be less contribution to sine wave distortion if harmonics are present. If distribution transformers are used, single phase transformers may be connected in various combinations of size and impedance. This should be monitored and avoided if possible. Pad mount transformers generally have a standard impedance of 5.75%.

• Pad mount transformers where the transformer’s windings are on a single core are recommended by IEEE Std 1100 (9.17.6) as the better selection for a vari-able speed drive system.

• Banked single phase transformers saturate and overheat when harmonic currents are present on their neutral paths.

• Avoid unconventional connection of transformer banks, such as open deltas and tee connections, because they also saturate and overheat when harmonic currents are present on their neutral paths.

• Consider main power transformers with a K-factor rating where harmonics are expected and perhaps modeled as part of the system design.

K-factor Rated TransformersTransformers which have K ratings have design modifications which include:

• enlarging the primary winding to withstand the inherent harmonic circulating currents

• doubling the secondary neutral conductor size to carry the harmonic currents

• designing the magnetic core with a lower normal flux density by using higher grades of iron

• using smaller, insulated secondary conductors wired in parallel and transposed to reduce the heating from the skin effect and associated AC resistance, and/or

• designing multiple-secondary windings that are phase shifted for zero sequence harmonic current cancellation.

If equipment sensitive to harmonics (for example, a control system power supply) is connected to the main transformer bank along with a variable speed drive, trans-formers with K ratings should be considered.



The alternative to using a K-factor rated transformer is to derate (or oversize) the main transformer to compensate for the higher temperatures in the transformer due to the harmonics. The K-rating required can be calculated from formulas in IEEE Std 1100. Standard K-factor ratings are 4, 9, 13, 20, 30, 40 and 50. Practically, a transformer should have a K rating of no more than 9.

Alternative Grounding MethodAs mentioned earlier, the normal winding connections for the main power trans-formers are delta-delta. This is a long standing oil field practice but is not in step with good electrical system design practice. An alternative winding connection for the transformers that should be considered is delta primary, with a high resistance grounded secondary. The high resistance grounding achieves the advantages of the delta-delta (ungrounded) system — especially the ability to continue operating with a fault on one phase — and puts less stress on the system when a fault occurs.

Implementing a high resistance ground system involves installing a high resistance ground module either next to the service pole, very close to the distribution trans-former bank, or next to the controller (on a constant speed system). The module could be installed next to a pad mount transformer. A high resistance grounded system could be installed with a variable speed control system but there are addi-tional issues related to harmonics control to be considered.

One inherent problem with a grounded (solid or high resistance) system is it may “ground out” certain downhole instrumentation packages. In particular, those down-hole instrumentation packages that have “non-dedicated conductors” (they use the power conductors to carry the instrumentation signals to the surface). A solution is available for this problem but it is not yet proven.

If you are willing to consider or are considering using a high resistance grounded system to feed an ESP, please contact the CRTC Mechanical and Electrical Equip-ment Group.

1634 Lightning and Surge ProtectionAs shown in Figure 1600-2, the BIL for motors is very low as compared to other equipment on the system. The levels shown in the table are generally for surface mounted motors but it is generally felt that BILs for ESP motors may even be less. The physical limitations imposed by the diameter of the well bore result in a series of compromises in the winding design that are caused by the limited space. It is difficult to add more turn-to-turn insulation or winding insulation to help make the motor windings more robust like may be done in a surface mounted motor.

Also, the long length, downhole cables, variable speed drive controllers or other nearby equipment such as capacitors can amplify the surges or cause resonance at the high surge frequencies.

The best way to protect ESPs is to eliminate exposing the ESP and surface equip-ment to transients and surges. This is not feasible since some of these conditions are inherent with the equipment that is used in power systems. The more practical way



is to direct the surge energy to protective devices and dissipate the energy to ground. The two most commonly used devices are lightning arrestors and surge suppressors.

Lightning ArrestorsLightning arrestors should be installed on the primary side of distribution trans-former banks. This protects the transformers and connected equipment from high energy lightning strikes. If a pad mounted transformer is used, mount the lightning arrestors on the last pole (often called the service pole) before the circuit goes into the conduit feeding the transformer. The ANSI/IEEE Std 141, IEEE Red Book shows voltage ratings of lightning arrestors that are usually selected for three phase systems and has additional information for sizing lightning arrestors. (See Figure 1600-5.)

Surge SuppressorsA Surge Protection Device (SPD) should be installed on the secondary side of the transformer bank (API Recommended Practice 11S3 Second Edition, March 1999) [6]. SPDs are often referred to as Transient Voltage Surge Suppressors (TVSS). TVSSs operate much like lightning arrestors in that they absorb and divert energy from surges that exceed their voltage threshold. Surge suppressors are used for ESPs and are designed to handle high-energy surges such as direct lightning strikes. TVSSs are also designed to reduce the lower energy surges that make it through the lightning arrestors, transformers, and switching within the field. The majority of transients are usually due to remote switching and contactor operation. TVSS is also beneficial in protecting Variable Frequency Drives (VEDs) by keeping transient activity low to the input power and SCR gating from reflecting into the system. This reduces overall maintenance on VFDs, controllers and ESP cable/motors.

Fig. 1600-5 Voltage Ratings of Arrestors Usually Selected for Three-Phase Systems (From Table 21, for Metal Oxide arrestors)(1)

System Type

Nominal System VoltageUngrounded or Resistance

Grounded Solidly Grounded

Voltage Line to Line

Voltage Line to Ground Rating MCOV(2) Rating MCOV

2.4 1.38 2.7 2.2 2.7 2.2

4.16 2.4 4.5 3.7 3.0 2.54

12.5 7.2 12, 15 10.16,12.7

9.0 7.62

13.8 7.9 15 12.7 10 8.47

34.5 19.9 36 29.3 27 21.9

(1) All numbers in KV(2) MCOV = maximum continuous operating voltage



In general, lightning induced surges produce surges of the same polarity on all three-phase conductors. As a result, the line to ground surge values will be greater than the line to line surge values. To protect line to line and line to ground, TVSSs are installed between each phase conductor and ground and between each phase conductor and phase. TVSS must also protect line to line in order to limit associ-ated switching voltages.

TVSSs must be tested and rated according to UL-1449 second edition [13], which is applicable up to 600 volts. A registered laboratory should provide performance testing for higher voltages, such as 1000 volts to 4160 volts. When comparing and applying TVSS, specification properties should be considered: let through voltage, peak surge current capabilities, Joule energy, voltage ratings, frequency, etc. These ratings should be as tested values in accordance with UL 1449 second edition or authorized laboratory.

The clamping voltage of the TVSS should be in the range of 110%-125% of the nominal system voltage. Note that this is the nominal system voltage RMS. On an ESP, all systems are 3 phase, 3 wire plus ground, no neutral. Voltages vary depending on switchboard/motor or VFD/motor.

TVSSs installed with ESPs should have a very high surge current capacity. TVSSs with capacities of 100KA to 240KA should be used; or, the TVSS should be suit-able for a Category C environment per IEEE C62.41 [14]. Local conditions would normally dictate the capacity required for the TVSS, but measurements of the actual level may not be available. Also, the TVSS should be electrochemically encapsu-lated and must not deteriorate with surge activity.

Connections to the TVSS should be as short and straight as possible. Line imped-ance can affect performance of the SPD. Most TVSSs should be fused to ensure they are removed from service if leakage current gets too high.

1635 Surface Power CablingPower cable is used to conduct the power from the main transformer bank to the various equipment in the ESP system. Cable connects the main transformer bank to the controller, the controller to vented junction box, and the vented junction box through the wellhead penetrator downhole to the ESP motor. Different types of cables are used in these interconnections.

Main Transformer to ControllerThe power cable used to connect the main transformer bank to the controller usually operates at 480 volts. The cable is usually installed in conduit down the pole to the controller. Typical cables used for 600 volt service may be used. Common types are three, single conductor cables, or an armored cable such as type MC cable. Type MC cable is three single-conductor cables that are assembled together, each individ-ually insulated and enclosed in a metallic sheath or armor. The sheath is usually helically wound, interlocking aluminum. The cable has an overall PVC outer jacket. The three, single conductor cables or the three-conductor type MC cables each need



to be installed in conduit (for support) down the pole to the controller. The conduit may be rigid steel or plastic.

If the main transformer is pad mounted, the power cable from the overhead line to the transformer will need to be selected for the voltage of the overhead power line. These would typically be medium voltage cables of 15 KV, 25 KV or 35 KV class. Three single conductor cables of the appropriate voltage class would be installed in conduit and connect the overhead line to the pad mount transformer. If medium voltage cables are used, cables having a 133% insulation level should be used.

Controller to Vented Junction BoxThe cable connecting between the controller and the vented junction box is usually a short section of round cable or single conductor cables in conduit. The splice at the vented junction box allows any gas that might migrate up the downhole cable to “weather away” at the junction box rather than migrate to an enclosed box where an accumulation of gas might occur. The operating voltage of the cable is usually the same as the operating voltage for the ESP. The cable may be low-voltage cable operating between 400 volts and 600 volts or a medium voltage cable operating between 625 volts and 3300 volts. The higher the voltage, the lower the current flow for the same horsepower ESP, so the cables very often are medium voltage cables.

Cables normally used for this interconnection are: low voltage MC-type cable rated to 600 volts; medium voltage type MC-type cable rated to 5 KV; and, either low voltage or medium voltage single conductor cables installed in conduit. The medium voltage cables may be shielded or non-shielded; the cable most often used is non-shielded. Both the MC-type cable and conduit should be direct buried, espe-cially if drill rigs or other heavy equipment might need to travel over it. Give partic-ular attention to bonding equipment together properly and to the minimum bending radius of the cable whichever type of cable is used.

Vented Junction Box Through/To Wellhead PenetratorThis section of cable may be a short section of cable that terminates at the wellhead penetrator, or a continuing portion of the downhole cable that passes intact through the wellhead — like through a gland. The operating voltage of this cable is the same as the operating voltage of the ESP motor.

Normally this section of cable should be round. However, flat cable is often seen when this section is an extension of the downhole cable.

By code, this section of cable should not be downhole cable. Downhole cable is not approved for this “service.” However, practicality (usually the desire not to have a splice at the wellhead), often dictates that downhole cable be used. Code issues relating to this cable would generally center on providing adequate physical protec-tion for the cable. Too often, excess lengths of downhole cable are just coiled above ground, and just left on the top of the ground. Optimally, this cable section should be buried from the vented junction box to the edge of the wellhead cellar. Excess cable should be cut off and removed. If local practice is not to do this, the cable should at least be physically protected, such as by being placed in a trench, or covered as though it were a permanent installation.



1636 Drive Choices

Fixed Speed or Constant Speed Motor ControllersBy far the most utilized ESP motor starter used within Chevron is the across-the-line pump panel or controller. Since line frequency (60 hertz) from the power source is directly supplied to the pump, the pump will run at a constant speed. The pump panel or constant speed motor controller consists of a fused disconnect, a contactor, controls and monitoring devices and an overall outdoor type enclosure. The Centrilift Electrostart Pump Panel is an example of this type of controller. Voltage levels for pump panels range from 480 volts to 3300 volts.

The contactor within the controller gives the operator the ability to start and stop the ESP. The “brains” of the pump panel reside in the controller. The controller may range from basic — monitoring overload conditions and shutting down — to sophisticated. The sophisticated controllers are electronic and monitor motor condi-tions, such as overload, underload and current unbalance, and incoming power conditions, such as overvoltage, undervoltage, voltage unbalance and reverse phase rotation. A whole host of operating conditions may be monitored or prevented and operation information may be communicated to a control center over a local system control and data acquisition (SCADA) system from the controller itself.

Variable Speed DrivesIn most recent ESP applications, the petroleum engineers recommend that variable speed drives be used. Variable speed drives improve system efficiency when well productivity data is unreliable or uncertain and the ability to vary speed makes oper-ation more flexible to adapt to changing well productivity conditions. There are a number of application issues that need to be considered when variable speed drives are used.

Variable speed drives have been available for ESP use since the late 1970’s. These early drives are so-called “six pulse” drives. They are characterized by a three-phase rectifier bridge as shown in Figure 1600-6. “Pulse” refers to the number of pulses (or peaks) in the DC output voltage in one cycle of the supply voltage. The rectifier bridges were normally silicone controlled rectifiers (SCRs) and each one is switched on/off during each cycle. This switching causes notches in the voltage waveform, which in turn causes harmonics. The six pulse drives are noted for their very high harmonics content and very low power factors. Six pulse drives do not meet the requirements of IEEE-519, “IEEE Recommended Practices and Requirements for Harmonics Control in Electrical Power Systems” [10] as standalone units. However, when applied in power systems, sometimes the effects of their high harmonics can be controlled. Care must be taken however, if groups of six pulses drives may be used.

In the mid-1990’s, a new technology drive using Pulse Width Modulation (PWM), began to be used with ESPs. This technology improved on the harmonics issue compared with six pulse drives; their harmonics (as seen by the power system) are much less and in fact meet IEEE-519 as standalone drive units. But, there is more to be concerned about in the power waveform going to the ESP. The PWM uses very fast switching techniques on the drive output using Insulated Gate Bipolar Transis-



tors (IGBTs). These fast switching transistors also cause notches in the waveforms which result in harmonics. The amplitude of the harmonics is reduced but they occur (or are a concern) at higher frequencies (harmonic orders). These higher frequency harmonics can often excite resonance between the drive, the downhole cable and the ESP motor. When using PWM drives with ESPs, always check the cable length with the ESP supplier to see if harmful resonances may occur. The newer PWM drives have a means of tuning (raising or lowering the carrier frequency) to avoid system resonances.

One of the most common ways to reduce harmonics’ harmful effects on a power system is to increase the number of pulses for a drive. Twelve pulse drives are very common. Two input transformers or two windings from one transformer (Figure 1600-6) are used; one connected delta-delta and the other connected delta-wye. This causes some self-canceling of the harmonics and reduces the amplitude of

Fig. 1600-6 Three-Phase Rectifier Bridges



the harmonic orders. Drives are now available with much higher pulses (over 30) to reduce harmonics to negligible amounts.

The recommended drive to use will depend on a number of factors. If the plan is to have only one drive on a system, the six pulse drive can be used. If more than one ESP is planned, perhaps “grouped,” twelve pulse drives should be used. Any time grouping of ESPs is considered, do harmonic modeling to try to predict any harmful effects from the harmonics. The ESP supplier may recommend a PWM drive be used because of downhole conditions. PWM drives have better torque control at lower speeds and may have better success in starting and running in problematic wells.

1637 Grounding DesignGrounding at an ESP installation is very important. A low resistance ground is most important to allow the lighting and surge arrestors to adequately protect the installa-tion from external lightning and surges. A good grounding system will also provide personnel protection in the event of line to ground faults.

A typical grounding system for an ESP installation is shown in Figure 1600-7. The figure is based on NEC requirements, Chevron practices and IEEE Emerald Book, “IEEE Recommended Practice for Powering and Grounding Sensitive Electronic Equipment.”

A few guidelines for good grounding practice are as follows:

• Resistance to ground must be 5 ohms or less. Preferably closer to 1 ohm.

• If one ground rod does not achieve 5 ohms or less, use a triangular arrange-ment for ground rods in accordance with standard drawings to try to achieve low resistance. Or, use chemical treatment around the ground rods to achieve ground resistance as low as possible.

• Chevron’s practice is to ground conduit and equipment directly to the well casing as well as to a ground rod.

• Ground current should be checked periodically with a ground resistance tester.

• Exothermic grounding connections are preferred. However, bolted or compres-sion connections may be necessary. Periodically inspect bolted or compressed connections to be sure connection integrity is maintained.

• Minimum ground conductor size (not buried) should be #6 AWG. Buried grounding conductor should be #4/0 AWG.

• Ground wires to lightning arrestors should be as large diameter as feasible. Avoid sharp bends.

• Surge arrestor and TVSS recommended practice is for all leads to be short and avoid sharp bends in the conductors.



• Be careful of conduit and ground conductors near piping if the piping has insu-lating flanges. Contacting the pipe with the conduit or ground conductors may short out the effects of the insulating flanges.

For particularly sensitive installations, refer to the IEEE Emerald Book.

1640 Sub-Surface Design ConsiderationsIt is not within the scope of this guideline to discuss sub-surface design issues in detail. ESPs are normally selected jointly by the petroleum engineer and the manu-facturer based on well flow and field conditions. The main issues for the electrical engineer are the sizes of ESPs being evaluated and the ability of the local electrical service to start and run the ESP.

For more information on sizing and selecting an ESP for your application, refer to API-11S4, “Recommended Practice for Sizing and Selection of Submersible Pump Installations.” Also, refer to Centrilift’s “9 Steps,” [15] a brochure which takes you through Centrilift’s nine-step process for sizing and selecting ESPs. All the manu-facturers have computer programs that may be used for sizing ESPs. In fact, having the manufacturer review the design and select an ESP using the computer is recom-mended.

Fig. 1600-7 Typical Grounding System



1641 ESP CablesThe ESP cable is the cable which runs from the surface mounted controller or drive to the ESP motor downhole. This cable may be either round or flat, depending on the room left in the annulus between the tubing string and the well casing. The first choice cable should be round cable, since the supply voltage will remain balanced to the motor terminals. Where long lengths of flat cable are installed, the phases of the cable should be transposed along the length so as to keep the motor terminal voltage balanced.

The cable consists of a copper conductor, insulating material, a barrier or tape shield (optional), a jacket (over all three conductors in a round cable, over the individual conductors in a flat cable) and an overall jacket. All of the materials must be selected in order to be compatible with environmental conditions downhole. Resis-tance to organic chemical attack, gas attack and corrosion are paramount in selecting the cable.

Cable insulation is available in two types: thermoplastic (polypropylene being most common) and thermoset (ethylene-propylene diene monomer [EPDM] being most common). Cable insulation thickness for cable insulated with either type of insula-tion is as follows:

The maximum conductor operating temperatures for the cables are as follows:

Refer to IEEE Std. 1018, “IEEE Recommended Practice for Specifying Electric Submersible Cable-Ethylene-Propylene Rubber Insulation,” IEEE Std 1019, “IEEE Recommended Practice for Specifying Electric Submersible Pump Cable-Polypropylene Insulation,” and API RP1156: “Recommended Practice for Testing of Electrical Submersible Pump Cable Systems.”

Armor selection is just as important to a cable’s integrity as insulation selection. Armor is available in most any type of material from galvanized steel to Monel. Well conditions will dictate the appropriate material selection. The armor provides mechanical protection during installation and removal from the well. In round cable construction, armor provides mechanical strength to confine swelling of the cable

Wall Thickness, mil

Average Minimum

3 KV 75 68

5 KV 90 81

Maximum Conductor Operating Temperature(1)

(1) Note that this table shows the maximum conductor operating temperatures as noted in the IEEE standards. Manufacturers make cables that can operate at temperatures above these maximums; some are noted to be suitable up to 450°F.

Thermoplastic (Polypropylene) 205°F

Thermoset (EPDM) 284°F



during decompression as the cable is pulled. Banding of the cable to the production pipe or tubing supports the cable. The armor helps prevent the cable from being crushed under the bands.

Cables are also available which have capillary tubing incorporated into the armor. The tubing may be used for chemical injection or well monitoring purposes.

1642 ESP MotorAn ESP motor is unlike a motor you would see for use on the surface. It must be very small in diameter in order to fit into the well casing. Yet these motors can supply 400 HP and more. Some of these motors can be 30 feet in length. Each motor is filled with a light mineral oil in order to seal it, lubricate the bearings, elec-trically insulate the motor and conduct heat from within the motor. The well fluids passing the outside of the motor during operation provide cooling.

The motor has a seal section, which prevents entry of well fluids into the motor at the drive end, equalizes pressure inside the motor with the well bore pressure, and compensates for the expansion and contraction of motor oil due to heating and cooling when the motor is running or shutdown. The seal section also contains the thrust bearing for the pump and is the main connection point between the motor and the pump.

To connect the motor to the power supply, there is a special motor lead cable, which extends from the connection at the motor winding to above the end of the pump. This cable is normally flat and may have a special profile different from a flat downhole cable. The motor lead cable and the downhole power cable are spliced together above the pump where there is more room. Guards are usually placed over the motor lead cable to protect it from damage when the pump is raised or lowered into the well.

Like many surface motors, some ESP motor windings are epoxy filled in the slots and end turns. This provides more insulation and support (rigidity) for the winding. More importantly, the motors must have turn-to-turn insulation to give it better protection against voltage transients. Older motors or perhaps rebuilt motors may only have varnish coated windings and they may not have turn-to-turn insulation.

1650 Reliability ConsiderationsDownhole electric submersible pump systems normally have shorter run lives than their surface counterparts due to the hostile environments they are exposed to. Where surface equipment can be expected to run 8-10 years, ESPs average 2-4 year runs. Chevron experiences on average 2-2.5 years run lives in most fields. Interven-tion to pull and reinstall the pump and motor are costly and the industry is working hard to extend the run lives of downhole ESPs to improve the overall economics.

1651 Maintenance ProgramsThe most effective maintenance programs combine three efforts:



• the pump teardown and teardown reporting• a maintenance management system, usually computerized, and• operating information and failure outage information.

About 40% of ESP failures are mechanical, 40% are electrical and 20% are a host of things including design or application problems, changed fluid characteristics, scaling, tubing failures, etc. The mechanical failures and some of the electrical fail-ures lend themselves to being solved using modern maintenance monitoring and predictive maintenance techniques.

A few recommendations follow:

1. Root cause failure analysis is critical to the basic understanding of why the system is failing and provides information for solving the failure problem.

The teardown report is one way to approach root cause failure analysis. A tear-down reporting system is described in API Recommended Practice 11S1, “Recommended Practice for Electrical Submersible Pump Teardown Report.” This reporting system or something similar is widely used within Chevron.

2. Combining teardown reporting with a maintenance management system can resolve very difficult ESP problems.

Tracking materials, knowing what material is on-hand, and knowing what materials have failed in the past are critical to solving mechanical problems. Monitor electrical failures in the same way along with correlating failures with system disturbances at the surface. Formal reporting and documenting of power problems needs to be done. Electrical failures in the ESP are often the result of other power system problems.

3. Provide adequate power system disturbance protection for the ESP system as discussed in the sections above.

4. Before accepting new ESP equipment or rebuilt ESP equipment, test them for proper operation.

Often new equipment is not tested or run before equipment is shipped. Monitor the materials used and replaced during an ESP rebuild. A few testing standards exist such as API Recommended Practice 11S2, “Recommended Practice for Electric Submersible Pump Testing” and API Recommended Practice 11S6, “Recommended Practice for Testing of Electric Submersible Pump Cable Systems.”

5. Monitor re-installs of ESP systems.

Properly handling of the cable and tubing reels must be done in order to avoid damage and assure integrity. Using the right equipment is necessary also to avoid damage and to safely increase speed of the work. Monitor the cable splicing and reduce or eliminate splices from the run downhole. Install the correct number of bands. Do not tighten the bands so tight as to crush the cable. Use supports over the cable if required.



6. Cable and other equipment may be reused but it should be reconditioned and stored properly between uses.

Electrically test the cable to see if it could be reused. Do not cut downhole cable as it is removed and expect to reuse that cable with a lot of new splices.

1660 Other Considerations

1661 Downhole Monitoring SystemsESP systems often include downhole monitoring devices to provide information on pump or reservoir conditions. The preferred method of data transmission from these devices is in digital format. Electrical noise from the motor historically has inter-fered with analog data transmission, and electrical noise from any of the ESP equip-ment interferes with wireless data transmission.

The two methods used for downhole monitoring devices are DC power cable signal and dedicated data line. With the DC power cable signal, the sensing device infor-mation is impressed on the star point of the electric power cables at the motor. Filters or traps at the surface pick up the sensing device signal and provide a reading. These filters or traps are located within the drive unit or stepup transformer cable termination compartment. With a dedicated data line, a separate wire pair is run along the outside similar to the power cable. One of the benefits of this system is that monitoring devices are isolated from the ESP motor and electrical system.

The DC power cable signal system is the least expensive to install but it tends to have fewer data channels than the dedicated data line system. With the DC power cable type system, motor operating temperature can easily be one of the downhole measurements that are taken. With a dedicated data line system, since the monitors are separate from the ESP system, the motor can be meggered with this type of system.

The measurements most often taken with monitors (or gauges) are: downhole pres-sure, downhole temperature and motor operating temperature. Flowmeters down-hole are being installed in some offshore applications. An additional type of sensor being used monitors the dielectric strength of the oil in the motor. If water or well fluids enter the motor, the dielectric strength drops. When fluid intrusion is sensed, the motor may not fail immediately but failure is imminent.

For a more complete discussion and evaluation of downhole monitoring systems, refer to Chevron Technical Memorandum 99-16, CPTC 1999 Portfolio Deliverable (WP-11B Deliverable 3): “Evaluate Downhole Monitoring Systems” revised October 11, 1999. [20]

1662 Supervisory Control and Data Acquisition (SCADA)With ESP systems, it is starting to be recognized that near real time monitoring of the pumps and equipment is necessary to maintain production levels near optimum. This is particularly true if the ESP population is large or expanding. Data about ESP



operation is gathered by the SCADA system and then saved or displayed for engi-neering and management use.

The typical way for data to be transmitted is by radio over a field-wide monitoring system. Each ESP drive might have a radio terminal unit (RTU) installed which sends sensor and controller information back to a master station when it gets polled. The ESP may be only monitored (send information only) or the ESP may be moni-tored and controlled (send and receive information) by the master station. Other methods for data gathering could be fiber optic network or twisted pair network. Once the data is gathered it can be used in any number of ways to improve opera-tions. Each of the major ESP suppliers have their own controller/RTU system that can be supplied with the drive equipment and there are several suppliers who can provide the RTU and connect into anyone’s controller unit.

Not all information controlled and monitored by the ESP drive controller is gath-ered by the SCADA system. If pump problems develop or anomalies in the data are detected, operators usually go to the ESP location and review all the data within the controller historian. Some of the parameters most often gathered and used in a SCADA system are as follows:

As controllers continue to improve and SCADA system capacities continue to increase, eventually all the data gathered and evaluated by the controller will be able to be communicated back to the master station.

1663 Group Installations of ESPs (Variable Speed Drives)When groups of ESPs with variable speed drive controllers are installed or are planned to be installed, it is very important to be aware of harmonics and the need to control them. If not anticipated, failures of equipment such as transformers, moni-toring equipment and the drives may occur. It is important to know the harmonic output of the drive units that are selected and how they may interact when operated together. As mentioned earlier, the typical six-pulse drive does not meet the harmonic level requirements of IEEE 519 for a source without other mitigating considerations. It is important to understand the requirements of IEEE 519 with respect to Point of Common Coupling (POC) if the group of ESPs is connected to a utility.

Voltage A Phase Number of Starts

Voltage B Phase High Pressure Switch Status

Voltage C Phase Casing Pressure

Current A Phase Tubing Pressure

Current B Phase Fluid Temperature

Current C Phase Pump Status (On/Off)

Running Frequency Flow



When installing groups of ESPs, consider doing the following:

1. Have a harmonic power system model done to model the proposed system.

Worst case scenarios can be investigated and mitigation plans can be evaluated.

2. Use at least twelve pulse drives or connect the drives in such a way that the drive group looks like twelve pulse drives.

Connecting drives to look like twelve pulse drives involves installing isolation transformers that are phase shifting (this way some harmonics will cancel out). A delta-delta transformer has no phase shift, a delta-wye transformer has 30° phase shift and special transformers with 15° phase shift may be needed. Connecting drives to look like twelve pulse drives needs to be done with caution since harmonic content from a drive will vary with load. If the drives have significantly different loads (or transformer sizes vary) the harmonic problem may not be solved.

3. Even with twelve pulse drives, some additional filters may need to be installed on the power source to further reduce the harmonic levels.

4. Do not install power factor correcting capacitors without careful consideration.

In particular, a system model for harmonics should be done. Even though harmonics levels from the drives may be low, the capacitors may set up a reso-nance with the drives and both will fail.

For information on power system analysis and harmonic analysis, refer to Section 200 or Section 1553

1664 Generator Power Supply to ESPsOften ESP installations will be powered by an isolated power system supplied from generators (offshore platform), or, in remote locations, a single generator may feed an ESP at the well site. When ESPs with variable speed controllers are a significant portion of the load on a generator, there are two concerns: power factor of the vari-able speed controller and harmonics generated by the variable speed controller. Use caution and investigate further into the ratings of generators when the variable speed controller load is 25% or more of the generator capacity.

Six-pulse variable speed controllers operate at a particularly low power factor — 65% down to 40% — depending on load. At the optimum design point for the load the power factor will be the best. However, it then becomes important to know how often the ESP operates at its best design point. Under practical conditions this is probably not very often. The amount of VARs that a generator must supply to the ESPs then becomes the main sizing criteria. In some cases, installing power factor correction capacitors may be needed to improve the ability to match the generator size with the load. However, do this with caution and after some system modeling has been done to avoid problems with resonance. Selecting another type of drive, like a twelve pulse drive or a PWM drive, may be appropriate since they inherently operate at higher power factor and lower harmonics.



As with all electrical equipment discussed so far, harmonics can be harmful if they are not anticipated and the equipment is not made to handle them. Generators are no different. If harmonics are too high on a generator, excessive rotor heating will occur and insulation failures will occur. Also, the voltage regulator will fail or not operate properly due to the notching and spikes from the harmonics.

Some recommended generator design features to consider when drives are supplied by generators are as follows:

1. Generator rotors should be supplied with copper amortisseur bars. They should be oversized to mitigate the effects of skin effect heating and harmonic current heating.

2. Rotor bars should be fitted into copper end laminations so that there is a complete circumferential brazed or welded contact between each rotor bar and the end lamination.

3. Use larger copper bars to counteract torsionals from the 5th and 7th harmonics.

4. The stator should have form wound coils and be vacuum pressure impregnated (VPI) during fabrication.

5. Inter-turn taping must be included.

In general, the insulation system design should comply with API Standard 546, “Brushless Synchronous Machines — 500 KVA and Larger” [8] but it is up to the user whether or not the generator be tested to API 546.

6. The generator exciter should be brushless, with a permanent magnet unit and have three phase voltage sensing.

7. The voltage regulator should contain filtering to protect against system noise or higher order harmonics.

8. Often a harmonic filter may be required to further remove harmonic content and allow the generator to be a more standard design. For six pulse drives, line reactors may be required to limit notching effects. Also, the harmonics must be filtered to provide less than the equivalent of 30% negative sequence current.

9. For generator 150 KW and larger, the generator sub-transient reactance should be between 15% and 20%. For sizes smaller than 150 KW, the sub-transient reactance should be between 12.5% and 17.5%.

10. It is not uncommon to see generators sized 150% to 200% of full load current to compensate for the factors above.



1670 ReferencesNote Many overhead power system designs are available from past Chevron projects. Contact CRTC specialists for more information.

1. Westinghouse T&D Book

2. Rural Electrification Construction Guidelines

3. ANSI/IEEE Std 141, IEEE Recommended Practice for Electric Power Distribu-tion for Industrial Plants (IEEE Red Book)

4. API Recommended Practice 11S1, “Recommended Practice for Electrical Submersible Pump Teardown Report”

5. API Recommended Practice 11S2, “Recommended Practice for Electric Submersible Pump Testing”

6. API Recommended Practice 11S3, Section Edition, March 1999, “Recom-mended Practice for Electrical Submersible Pump Installations”

7. API Recommended Practice 11S6, “Recommended Practice for Testing of Electric Submersible Pump Cable Systems”

8. API Standard 546, “Brushless Synchronous Machines — 500 KVA and Larger”

9. IEEE Std 1100, IEEE Recommended Practice for Powering and Grounding Sensitive Electronic Equipment (IEEE Emerald Book)

10. IEEE Std 519, IEEE Recommended Practices and Requirements for Harmonic Control in Electrical Power Systems

11. Steve M. Dillard and Thomas D. Greiner, “Transient Voltage Protection for Induction Motors Including Electrical Submersible Pumps,” IEEE Transac-tions on Industry Applications, Vol. IA-23, No. 2, March/April 1987.

12. Gregory W. Massey, “Design Solutions for Harmonic Load Current Effects on Electrical Power Distribution Systems,” Power Quality Assurance Magazine, Article 28.

13. UL-1449

14. IEEE C62.41

15. Centrilift Publication, “9 Steps” (Nine step procedure for designing appropriate submersible pumping systems).

16. Keith Fangmeier and David Shipp, “Design and Implementation of a Reliable and Flexible ESP System for the Tohatamba Development,” 1998 ESP Work-shop.

17. Lance Grainger, Alfred Comeau, and Kelly Packard, “Power System Design Considerations When Applying Variable Frequency Drives,” 1996 ESP Round-table, SPE Gulf Coast Section.



18. Warren H. Lewis and Frederic P. Hartwell, “Quality Grounding and Power Quality,” EC&M Magazine, February 1996.

19. Kenneth Lacey, “Benefits of Properly Installed and Maintained Electrical Surface Equipment,” 1995 ESP Workshop.

20. Chevron Technical Memorandum 99-16, CPTC 1999 Portfolio Deliverable (WP-11B Deliverable 3): “Evaluate Downhole Monitoring Systems”

21. John P. McSharry, “Adjustable Speed Drive Guideline for Upstream, Oil-field Application,” 1997. Chevron document.

Chevron Corporation A-1 September 1990

Appendix A. Sizing of Automatic Transfer Switches

Part I and Part II, Asco Facts, Vol. 2, No. 12 (Part I) and Vol. 2, No. 13 (Part II), Automatic Switch Co., Florham Park, New Jersey

(Courtesy of the Automatic Switch Co.)

Appendix A Electrical Manual

September 1990 A-2 Chevron Corporation

Electrical Manual Appendix A


Appendix A Electrical Manual

September 1990 A-4 Chevron Corporation

Electrical Manual Appendix A


Chevron Corporation B-1 September 1990

Appendix B. Features of a Power System Incorporating Large AC Motors/Captive Transformers

Samuel P. Axe, F. A. Leinberger, and William R. Morton

Note 1973 IEEE. Adapted and reprinted with permission from IEEE Transac-tions on Industry Applications, Vol. IA-9, No. 3, pp. 262-267 (May/June 1973).

AbstractBoth synchronous and induction motors driving fans, pumps, and compressors (vari-able torque types of loads) may prove to be more economical and reliable when utilizing a lower voltage motor plus a captive transformer rather than a 13.8-kV motor. The economic factors, matching motor capabilities to load requirements, power system considerations, relaying and grounding systems possibilities, and operating experience with installed drives in Atlantic Richfield’s Philadelphia Refinery are covered.

Contents Page

B1.0 Introduction B-2

B2.0 General Description of the Electrical System B-2

B3.0 Power System Considerations B-3

B4.0 Why AC Motor/Captive Transformer Combination? B-4

B5.0 Matching Motor/Captive Transformers with Load B-9

B6.0 System Experience B-10

B7.0 References B-11

Paper TOD-72-134, approved by the Petroleum and Chemical Industry Committee of the IEEE Industry Applications Society for presentation at the Petroleum and Chemical Industry Technical Conference, Denver, Colo., September 10-13, 1972. Manuscript released for publication December 15, 1972.

S. P. Axe is with Atlantic Richfield Company, Philadelphia, Pa. 19145.

F. A. Leinberger is with the Industrial Sales Division, General Electric Company, Philadelphia, Pa. 19102.

W. R. Morton is with the Industrial Sales Division, General Electric Company, Schnectady, N.Y. 12345.

Appendix B Electrical Manual

September 1990 B-2 Chevron Corporation

B1.0 IntroductionThe primary objective of any industrial plant is to produce—consistently and economically. The ability to produce is dependent to a large degree on the adequacy and continuity of the electrical service. In many cases, the cost of service interrup-tions can be evaluated directly in terms of lost production. This cost may exceed the cost of the physical damage to the electric equipment that caused the interruption. Therefore, it is of prime importance that the electrical system be designed to serve continuously, reliably, and hopefully unnoticed. Since no two plants have identical requirements, a standard electrical distribution system is not universally applicable. Therefore, it is essential to analyze the specific requirements of each process system and then design an electrical system which will most adequately meet these requirements.

This paper briefly describes a highly reliable electrical system serving a complex of five processing units at Atlantic Richfield’s Philadelphia Refinery. The operating demand for this complex is 40 MW. For a system of this magnitude, it was deemed necessary to perform many studies such as voltage drop, short circuit, relay, and stability to determine the feasibility of the conceptual design. In this paper, it is the intention of the authors to highlight the use of captive transformers1 with large AC motors on this type of system.

1. A Captive transformer is one that is connected to and supplies only one large motor.

B2.0 General Description of the Electrical SystemThe electrical single-line diagram for the complex is shown in Figure B-1. Electric power is purchased from the utility company at 13.8 kV. Three lines, each consisting of single-conductor 2000 kcmil cables, operate in parallel to deliver power to a continuous operating load of 40 MW. If one line fails, or is removed from service for maintenance reasons, the remaining two lines are designed to deliver the full load on a short-time basis.

This power is distributed through a lineup of 13.8-kV metal-clad switchgear to the following loads:

1. Five large motors and their associated captive transformers:

2. 21,000 kVA of transformer capacity at a 2,400-V level distributed through a double-ended lineup of 2,400-V metal-clad switchgear to 16 motors ranging in size from 250 to 1,750 hp.

3. 7,000 kVA of transformer capacity at a 480-V level distributed through a double-ended lineup of 480-V metal enclosed switchgear to 12 motor starter

1 13,000 hp two-speed induction motor

1 8,000 hp induction motor

2 5,500 hp brushless synchronous motors

1 4,500 hp brushless synchronous motor

Electrical Manual Appendix B


racks. These racks supply power to 200 motors ranging in size from 1/2 to 200 hp. Small capacity transformers located throughout the complex for lighting and instrumentation power are also supplied from these racks.

B3.0 Power System ConsiderationsAtlantic Richfield’s Philadelphia Refinery is historically committed, through its growth pattern over the years, to the purchase of electric power. Experience has shown that it is imperative to develop the electrical system requirements early in the design stages to make it possible to correlate them with the utility company. In this case, the utility did have sufficient advance notice to permit them to modify their system to meet both normal-load and short-circuit requirements without delaying start-up.

Careful consideration was given to the following to determine the adequacy of the system under steady-state, motor starting, and fault conditions: 1) short-circuit capacity, 2) voltage drop limitations, 3) motor speed-torque requirements, 4) system stability, 4) system protective relaying, and 6) system grounding.

The first three of these considerations are interrelated. Starting a large motor gives rise to the considerations of the allowable voltage drop on the total system as well as satisfying the torque requirements of the drive system. To reduce the voltage drop on the high-voltage 13.8-kV system, it is necessary to reduce the magnitude of the motor inrush kVA and/or increase the system’s three-phase short circuit (S/C) kVA. This is shown by the following formula:

Fig. B-1 Single-line Diagram



% of system voltage drop

(Eq. B-1)

For example, for a desired maximum voltage drop of 15 percent, the inrush kVA through the system cannot exceed 17.6 percent of the system three-phase S/CkVA.

On this system, the electric utility had the capability for increasing the system three-phase S/CkVA from their initially proposed 150 MVA to 328 MVA. Also, by utilizing the captive transformer approach, it was possible to reduce the inrush kVA. Together these two changes resulted in an acceptable voltage drop on the 13.8-kV system.

System stability is dependent upon several factors: system three-phase short-circuit magnitude, relaying time, magnitude of impedances connecting various rotating devices to the source and to each other, WK2 of the rotating devices, and mechan-ical loads on the rotating devices. In the design of a system containing large motors, it is advisable to study the system stability under the most adverse conditions of fault locations and clearing time. A stability study was performed on this system utilizing a digital computer. The study revealed that all dynamic loads were stable for all ground faults but not stable for some three-phase bolted faults even with instantaneous fault removal.

Recognizing this limitation, the design of some system components was modified. To prevent a phase-to-ground failure escalating to a phase-to-phase fault, interphase barriers were installed in the cable terminating compartments and single-conductor metal-clad cables were specified. In addition, the relaying system was designed to remove ground faults within the critical switching time.

The 13.8-kV system is solidly grounded by the utility company at the source. To meet the previously mentioned requirement of increasing the three-phase short-circuit kVA, the electric utility removed some of the reactors in their incoming lines. This resulted in a considerable increase in the 13.8-kV ground fault current. Thus it was necessary to carefully consider the ampacity of the ground return paths and the ground fault clearing times.

B4.0 Why AC Motor/Captive Transformer Combination?As previously mentioned, it is the authors’ intention to highlight the use of the large AC motor/captive transformer combination in this system. One of the first ques-tions to be answered about the use of this combination on a 13.8-kV system is that of economics. The motor cost curves of Figure B-2 show the added dollars per horsepower for 13.8-kV motors over 2.3-kV motors. For motors above 2,500 hp, the curves apply for 2.3- or 4.0-kV motors. For motors above 10,000 hp, the curves apply up to a 6.6-kV motors.

The transformer cost curves in Figure B-2 show dollars per kVA for a 13.8-kV step-down transformer to obtain the selected motor voltage. Assuming 1 kVA/hp and

inrush kVA 100×system S/CkVA inrush kVA+-------------------------------------------------------------------------=



considering a 7,500-hp 1200-r/min induction motor drive, a cost comparison can be quickly obtained from the upper set of curves. The added cost for a 13.8-kV induc-tion motor is approximately $5.60/hp; whereas the cost for a step-down transformer is approximately $3.20/kVA. This results in a saving of $2.40/hp by using the motor/captive transformer combination or a total saving of $18,000. If a similarly rated synchronous motor was being considered, the comparable costs would be $3.60 and $3.20 for a saving of $0.40/hp or a total saving of $3,000.

The curves of Figure B-2 cannot be used to decide the economics of induction versus synchronous motors since they do not show total dollars cost for motors but only the added dollars for higher voltage. The curves do show, however, that for the majority of cases there is a potential dollar saving in using the motor/captive trans-former combination. In addition to the probable economic benefit, the combination inherently has many other major advantages. These advantages, as listed next, should be considered and evaluated even where the cost of the combination is equal or slightly higher.

1. Inrush Limiting : The use of the captive transformer introduces added imped-ance in series with the motor which reduces the inrush current to the motor/captive transformer combination from that of a motor started across the line as shown in Figure B-3. This reduces the mechanical forces on the motor windings and mechanical parts since these forces vary as the square of the inrush current.

Reducing the inrush current also reduces the speed-torque capabilities of the motor. This results in a longer acceleration time for a given load speed-torque requirement. As shown in Figure B-4, there is a greater margin in time between

Fig. B-2 Savings Using Captive Transformers



the acceleration time and the motor thermal limits when the captive trans-former is used.

The standard motor at this reduced voltage will usually produce adequate accel-erating torque for variable torque type loads such as fans, pumps, and centrif-

Fig. B-3 Speed-torque and Speed-current Curves

Fig. B-4 Acceleration and Thermal Limit Curves



ugal compressors starting unloaded. This, of course, must be checked, as will be described later, before going ahead with the application.

It should be noted that other steps may need to be taken in limiting inrush current where more severe restrictions are encountered. One alternative would be to specify higher than normal impedance in the transformer. Another would be to use a step-down transformer with load tap changing (LTC). With LTC, a lower than normal motor voltage can be selected during starting and accelera-tion and then rated voltage can be established when the drive is at full speed. Adding LTC would affect the economics discussed earlier more than added impedance, but both may be economically feasible.

2. Less System Voltage Drop During Starting: Since the system inrush current is reduced by the transformer/motor combination, there is less voltage drop on the 13.8-kV system. This consideration was of prime importance in this instal-lation.

3. Increased Motor Winding Strength: The lower voltage motor inherently requires a greater copper cross-section. This provides a greater structural rigidity of the coils and end turns. The higher copper to insulation ratio also results in a firmer coil.

4. Grounding: Statistically, the predominant initial mode of electrical failure in a motor is line-to-ground. Thus, in many cases, it is advantageous to severely limit ground fault current so as to:

a. decrease the possibilities of line-to-ground faults escalating into three-phase faults;

b. prevent widespread burning and subsequent replacement of stator lamina-tions;

c. eliminate the need for immediate tripping on the first ground fault with the resulting unscheduled outages of the process.

The captive transformer isolates the primary and secondary ground systems. This makes it possible to “tailor” the grounding system of each subsystem (captive trans-former secondary, bus duct, and associated motor) independent of the primary system grounding considerations.

The capacitance-to-ground of this subsystem is quite small. This gives the further option of utilizing a high-resistance grounding system that limits the resistive ground current to a value equal to the small subsystem charging current. The total ground fault current is the vector sum of these two and is also quite small, approxi-mately 1-2 A.

With this magnitude of ground fault current it is not imperative to trip immediately on the first ground fault. A voltage relay across the grounding resistor can detect, with a high degree of sensitivity, a ground fault in each subsystem. This relay can either initiate an alarm or trip. If one options to alarm, an unscheduled outage may be prevented.



5. Relaying: Motor relaying is designed to protect against some or all of the following abnormal conditions: a) overload (thermal), b) short circuit, c) under-voltage and reverse phase sequence, d) stalled rotor, e) ground faults, f) single phase, g) current unbalance, and h) underfrequency. Figure B-5 shows the relaying selected for the Atlantic Richfield installation.

With the motor/captive transformer combination, the determination of which complement of relays to utilize should be appraised with the possibility of equivalent or better protection for less cost. In making this appraisal, consider-ation should be given to the following:

a. The ground and ground relay alternative previously mentioned results in sensitive ground fault protection for the subsystem. With fast tripping on the first ground fault and recognizing the aforementioned fact that most electrical faults in motors originate as line-to-ground faults, consideration should be given to the elimination of motor differential protection.

b. If the no-trip option on the first subsystem ground fault is exercised, consideration should be given to using a self-balancing differential relaying system to protect against phase-to-phase faults in the motor.

c. To protect against internal transformer faults, consideration may be given to the use of a sudden pressure relay in lieu of a transformer differential protection.

Fig. B-5 Motor Protective Circuit



d. In a system of this nature, without single-pole opening devices, the need for a current balance relay should be questioned. If single-phase protection is deemed necessary, consideration should be given to the use of the less expensive negative sequence voltage relay.

These and many other points should be considered before investing in a protective system. The relaying shown in Figure B-5 was selected after careful consideration of the preceding options. After several years of trouble-free operation, it is the consensus of the authors that a less expensive relay system could have been used with comparable results.

6. Reduced Transient Impact Stresses: During abnormal system conditions, the voltage on the system might be severely reduced or completely lost. When the system voltage is returned to normal, the magnitude of the inrush current to the motor is reduced due to the added impedance of the captive transformer. This reduces the impact stresses applied to the motor.

7. Reduced Transient Voltage Stresses: The captive transformer acts as a buffer to any system voltage disturbance (lightning surges, switching surges, etc.) thus reducing abnormal stresses on the motor insulation system. With the motor starting contacts on the transformer primary, no switching surges are present directly at the motor terminals.

B5.0 Matching Motor/Captive Transformers with LoadAs mentioned earlier, the motor/captive transformer combination acts as a reduced voltage starter. While this is an advantage, it may also prove to be a problem. Consideration must always be given to the starting torque requirements of the mechanical load. It is fundamental that the motor must, at all speeds, be capable of delivering accelerating torque in excess of that required by the load. Typical curves for a compressor and the drive motor are shown in Figure B-3. The motor speed-torque and speed-current curves were obtained by use of a computer program using actual motor constants and with provision for including system impedance and transformer impedance ahead of the motor. The effect of the added transformer impedance can also be noted on these curves. In the event that the initial motor design does not provide adequate torque margin over the entire speed range, the computer program facilitates reshaping the torque curves.

Another important consideration is that of impact loading on the transformer during starting. In the motor/captive transformer combination, the transformer kVA rating closely approximates that of the motor kVA requirement. Under starting conditions this imposes a sizeable thermal and impact load on the transformer. Where one transformer serves many motors, the starting current of any one motor does not represent as much of an overload on the transformer. Figure B-6 shows a trans-former application curve for pulsating or short-time loads. This curve delineates the acceptable application limits. For applications outside these limits, either a more precise check should be made by the transformer designer or a larger transformer specified. For applications in this plant, the starting limitation is 2 times an hour but in actual practice starts are made only several times per year. In Figure B-3 the



starting motor current is shown as being approximately 3.75 times transformer full-load current and hence is in the approved operating area for a standard transformer. The application limits shown apply for pulsating or starting duty even though trans-formers are designed to withstand bolted short circuits on their secondary which exceed 4 per unit current. However, in the case of short circuits, it is not expected that they will be repetitive.

B6.0 System ExperienceFive years of very favorable experience with this system indicates that our original design concepts and ideas were correct. The operation of the motor/captive trans-former combination has been trouble free. The voltage drop considerations under actual starting conditions were as predicted. The few 13.8-kV faults that have occurred were in the cables and in the cable terminations. These were rapidly isolated without undue disturbance to the system. The interphase barriers proved effective during these fault conditions. In retrospect a very workable and nearly trouble-free system was achieved.

Fig. B-6 Transformer Application Curve



B7.0 ReferencesF. J. McCann and R. J. Ristow, “Problems of impact loading on unit transformers supplying chipper motors,” presented at the 16th Annu. Pulp and Paper Conf., June 1970.

Chevron Corporation C-1 September 1990

Appendix C. Short Circuit ABC: Learn It In an Hour, Use It Anywhere, Memorize No Formula

Moon H. Yuen

IEEE Conference Catalogue No. 73 CH0769-01A, Paper No. PCI-73-7

(From Short Circuit ABC by Moon H. Yuen, P. E. Used by permission of the Yuen Family. Courtesy of YEI Engineers, Inc.)

Appendix C Electrical Manual

September 1990 C-2 Chevron Corporation

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Electrical Manual

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Chevron Corporation D-1 September 1990

Appendix D. Minimum Requirements for Dry-Type Transformers

D1.0 General1. The transformer shall be totally enclosed in a non-ventilated, 10 gage, 316

stainless-steel, NEMA 4 enclosure (TENV). Gaskets shall be secured with 316 stainless-steel hardware.

2. The coils and the lead wires shall be made of copper.

3. Both the primary and the secondary lead wires shall have a minimum working length of 12 inches and shall be of the flexible, multi-strand type.

4. The wiring compartment shall be at the bottom of the enclosure and shall contain ample space for field connections. Front panels shall be separate for the wiring compartment and for the core and coil compartment.

5. The wiring compartment (not the cover) will be utilized by the Company for the installation of hubs.

6. The enclosure shall be provided with mounting brackets to allow (rack or floor) _________ mounting with a minimum of four bolts. These brackets shall be welded in place.

7. The enclosure shall have lifting eyes with closed holes to allow for either a one-point or a two-point lift. These lifting eyes shall be welded in place.

8. The transformer shall be provided with a nameplate of non-corrosive material, permanently attached with 316 stainless-steel hardware to the transformer exte-rior. The name plate will state the manufacturer, rated kilovolt-amperes, phases, frequency, primary and secondary voltage, percent internal impedance, polarity, model number, or equivalent, serial number, information on voltage taps, class of insulation, and the temperatures rise for the insulation system.

9. Epoxy-encapsulated units are not acceptable.

10. Terminal boards for the terminal leads and taps are not acceptable.

11. Properly-sized grounding lugs shall be provided both inside and outside the case.

D2.0 Ratings1. The transformer shall be capable of supplying a continuous load of

________kVA without exceeding an 80°C temperature rise above 40°C ambient temperature.

2. The transformer shall operate at 60 Hz.

3. Primary (high) voltage shall be ________.

Appendix D Electrical Manual

September 1990 D-2 Chevron Corporation

4. Secondary (low) voltage shall be ________.

5. Full Capacity taps for 90%, 95%, 100%, 105% and 110% rated voltage on the primary.

6. The transformer shall be subtractive polarity.

7. Audible sound levels shall be in accordance with NEMA guidelines.

8. Number of phases ________.

9. Connection type (wye/delta, etc.) ______.

D3.0 Insulation1. The transformer core and coil shall be vacuum pressure impregnated (VPI)

with a Class H temperature-rated silicone varnish insulating material and then baked in accordance with the procedures recommended by the varnish manu-facturer. Powdered mica held in a suspension of a silicone varnish will not be acceptable as an insulation material.

2. The lead wires shall have a 115°C silicone rubber insulation.

3. The insulation shall be resistive to the effects of salt water and alkaline mud or a combination of these two agents.

4. The temperature rise of the finished transformer shall not exceed 80°C over 40°C ambient when tested under full load in accordance with NEMA and ANSI standards.

D4.0 Shipment1. Each transformer shall be shipped in an individual wooden crate durable

enough to withstand normal shipping methods.

2. A wiring diagram, dimension print and approximate weight shall be approved by a Company Representative prior to manufacturing the transformer.

Chevron Corporation E-1 September 1990

Appendix E. Installation Practices for Cable Raceway Systems

The Okonite Company, 1988

(Courtesy of the Okonite Wire and Cable Company)

Appendix E Electrical Manual

September 1990 E-2 Chevron Corporation

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